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美国

证券交易委员会

华盛顿特区 20549

10-Q 表

☒ 根据《1934 年证券交易法》第 13 或 15(d) 条提交的季度报告

截至季度期末 2026 年 9 月 30 日

或

☐ 根据《1934 年证券交易法》第 13 或 15(d) 条提交的过渡报告

过渡期间：从 ____ 至 ____


委员会	注册人；				美国国税局雇主
档案编号	地址和电话号码		注册州		识别号码

1-3525	AMERICAN ELECTRIC POWER CO INC.		纽约		13-4922640
333-221643	AEP TEXAS INC.		特拉华州		51-0007707
333-217143	AEP TRANSMISSION COMPANY, LLC		特拉华州		46-1125168
1-3457	APPALACHIAN POWER COMPANY		弗吉尼亚州		54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY		印第安纳州		35-0410455
1-6543	OHIO POWER COMPANY		俄亥俄州		31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA		俄克拉荷马州		73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY		特拉华州		72-0323455
	河滨广场 1 号，	哥伦布，	俄亥俄州	43215-2373
	电话	(614)	716-1000

根据该法第 12(b) 条注册的证券：

注册人

各类别名称

交易代码

上市交易所名称

American Electric Power Company Inc.

普通股，面值 $6.50

AEP

纳斯达克股票市场有限责任公司

请勾选说明注册人是否 (1) 已在此前 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) 条规定须提交的所有报告，以及 (2) 在过去 90 天内是否一直受此类提交要求约束。

是

否

☐

请勾选说明注册人是否已通过电子方式提交根据 S-T 条例第 405 条（本章第 232.405 条）须提交的所有交互式数据文件，提交期间为此前 12 个月（或注册人须提交此类文件的较短期间）。

是

否

☐

请勾选说明 American Electric Power Company, Inc. 属于大型加速申报人、加速申报人、非加速申报人、较小报告公司还是新兴成长型公司。请参见《交易法》规则 12b-2 中“大型加速申报人”“加速申报人”“较小报告公司”和“新兴成长型公司”的定义。

大型加速申报人

加速申报人

☐

非加速申报人

☐

较小报告公司

☐

新兴成长型公司

☐

请勾选说明 AEP Texas Inc.、AEP Transmission Company, LLC、Appalachian Power Company、Indiana Michigan Power Company、Ohio Power Company、Public Service Company of Oklahoma 和 Southwestern Electric Power Company 是大型加速申报公司、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型公司。参见《交易法》Rule 12b-2 中“大型加速申报公司”“加速申报公司”“较小申报公司”和“新兴成长型公司”的定义。

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

☐

新兴成长型公司

☐

如果是新兴成长型公司，请勾选说明注册人是否已选择不使用《交易法》第 13(a) 条规定的、遵守任何新订或修订财务会计准则的延长过渡期。

☐

请勾选说明注册人是否为空壳公司（定义见《交易法》Rule 12b-2）。

是

☐

否

AEP Texas Inc.、AEP Transmission Company, LLC、Appalachian Power Company、Indiana Michigan Power Company、Ohio Power Company、Public Service Company of Oklahoma 和 Southwestern Electric Power Company 符合 Form 10-Q 一般说明 H(1)(a) 和 (b) 所列条件，因此依据 Form 10-Q 一般说明 H(2) 规定的简化披露格式提交本 Form 10-Q。


	截至下列日期注册人普通股流通股数
	2026年10月28日

American Electric Power Company, Inc.	544,526,330
	（面值 $6.50）
AEP Texas Inc.	100
	（面值 $0.01）
AEP Transmission Company, LLC (a)	不适用

Appalachian Power Company	13,499,500
	（无面值）
Indiana Michigan Power Company	1,400,000
	（无面值）
Ohio Power Company	27,952,473
	（无面值）
Public Service Company of Oklahoma	9,013,000
	（面值 $15）
Southwestern Electric Power Company	3,680
	（面值 $18）

(a)100% 股权由 AEP Transmission Holding Company, LLC 持有；该公司是 American Electric Power Company, Inc. 的全资子公司。

不适用不适用。

AMERICAN ELECTRIC POWER COMPANY, INC. 及其子公司

截至2026年9月30日的10-Q表季度报告目录

2026年9月30日

页

码

术语表

前瞻性信息

第一部分：财务信息

第1、2、3和4项——财务报表、管理层对财务状况和经营业绩的讨论与分析、有关市场风险的定量和定性披露以及控制与程序：

American Electric Power Company, Inc. 及其子公司：

管理层对财务状况和经营业绩的讨论与分析

有关市场风险的定量和定性披露

简明合并财务报表

AEP Texas Inc. 及其子公司：

管理层对经营业绩的叙述性讨论与分析

简明合并财务报表

AEP Transmission Company, LLC 及其子公司：

管理层对经营业绩的叙述性讨论与分析

简明合并财务报表

Appalachian Power Company 及其子公司：

管理层对经营业绩的叙述性讨论与分析

简明合并财务报表

Indiana Michigan Power Company 及其子公司：

管理层对经营业绩的叙述性讨论与分析

简明合并财务报表

Ohio Power Company 及其子公司：

管理层对经营业绩的叙述性讨论与分析

简明合并财务报表

Public Service Company of Oklahoma：

管理层对经营业绩的叙述性讨论与分析

简明财务报表

Southwestern Electric Power Company 合并报表：

管理层对经营业绩的叙述性讨论与分析

简明合并财务报表

102

注册人简明财务报表简明附注索引

108

控制与程序

197

第二部分. 其他信息

第1项

法律诉讼

198

第1A项

风险因素

198

第2项

未注册的股权证券销售及所得款项用途

198

第3项

优先证券违约

198

第4项

矿山安全披露

198

第5项

其他信息

198

第6项

附件

199

签名

200

本合并 Form 10-Q 由 American Electric Power Company, Inc.、AEP Texas Inc.、AEP Transmission Company, LLC、Appalachian Power Company、Indiana Michigan Power Company、Ohio Power Company、Public Service Company of Oklahoma 和 Southwestern Electric Power Company 分别单独提交。本文所含与任何单一注册人有关的信息由该注册人代表自身提交。除 American Electric Power Company, Inc. 外，各注册人均不对涉及其他注册人的信息作出陈述。

术语表

当以下术语和缩写出现在本报告正文中时，其含义如下。


术语		含义

AEGCo		AEP Generating Company，AEP 的一家电力公用事业子公司。
AEP		American Electric Power Company, Inc.（本公司），一家投资者所有的上市电力公用事业控股公司，包括 American Electric Power Company, Inc.（母公司）以及控股并纳入合并报表的子公司和纳入合并报表的关联公司。
AEP Credit		AEP Credit, Inc.，AEP 的一家纳入合并报表的可变利益实体，为关联电力公用事业公司应收账款及应计公用事业收入提供证券化融资。
AEP 东部公司		APCo、I&M、KGPCo、KPCo、OPCo 和 WPCo。
AEP Energy Supply, LLC		AEP 竞争性发电、批发和零售业务的非监管控股公司，也是 AEP 的全资子公司。
AEP OnSite Partners		AEP Energy Supply, LLC 的前部门，负责利用现有及新兴的分布式技术建设、拥有、运营和维护客户解决方案。


AEP T&D Services		AEP T&D Services, LLC 是 AEP 的非监管子公司，也是一家专业基础设施服务机构，为电力输电、配电及相关公用事业基础设施提供工程、项目管理、采购和施工服务。
AEP Texas		AEP Texas Inc. 是 AEP 的电力公用事业子公司。AEP Texas 从事电力输电和配电业务，为德克萨斯州西部、中部和南部的零售客户供电。
AEP Transmission Holdco / AEPTHCo		AEP Transmission Holding Company, LLC 是 AEP 的子公司，也是一家中间控股公司，拥有输电运营合资企业和 AEPTCo。

AEPEP		AEP Energy Partners, Inc. 是 AEP 的子公司，专注于批发营销与交易、对冲活动、资产管理，以及在放开管制的市场中面向商业和工业客户的销售。
AEPSC		American Electric Power Service Corporation 是 AEP 的服务类子公司，为 AEP 及其子公司提供管理和专业服务。
AEPTCo		AEP Transmission Company, LLC 是 AEP Transmission Holdco 的全资子公司，也是一家中间控股公司，拥有各州输电公司。
AEPTCo Parent		AEP Transmission Company, LLC，是 Midwest Transmission Holdings 和 AEPTCo 合并范围内各州输电公司的控股公司。

AFUDC		建设期间使用资金备抵。
AGR		AEP Generation Resources, Inc. 是 AEP 发电与营销业务板块中的竞争性子公司。
AI		人工智能。
ALJ		行政法法官。


AOCI		累计其他综合收益。
APCo		Appalachian Power Company 是 AEP 的电力公用事业子公司。APCo 从事电力发电、输电和配电业务，为弗吉尼亚州西南部和西弗吉尼亚州南部的零售客户供电。
阿巴拉契亚消费者费率救济融资		Appalachian Consumer Rate Relief Funding, LLC 是 APCo 的全资子公司，也是一个合并的可变利益实体（VIE），成立目的是发行和偿付与 ENEC 未充分回收的递延余额相关的证券化债券。
阿巴拉契亚恢复融资		Appalachian Recovery Funding, LLC 是 APCo 的全资子公司，也是一个合并的可变利益实体（VIE），成立目的是发行和偿付与某些弗吉尼亚州管辖范围内的 Amos 和 Mountaineer 不动产、厂房及设备余额以及递延风暴成本相关的证券化债券。

APSC		阿肯色州公共服务委员会。

ARO		资产弃置义务。

ASU		会计准则更新。
ATM		按市价发行。


术语		含义

Batch Zero		ERCOT制定并经PUCT于2026年批准的一次性过渡性并网流程，用于在全系统范围内评估符合条件的大型负荷并网申请、分配可用输电容量、确定必要的输电升级，并要求参与客户作出财务承诺。该流程主要适用于75 MW或以上的大型电力负荷，是ERCOT未来定期批次并网框架的前身。
BESS		电池储能系统。

CAA		《清洁空气法》。
CAMT		企业替代性最低税。


CCN		便利性与必要性证书。
CCR		燃煤残渣。
CEO		首席执行官。
CO2		二氧化碳及其他温室气体。


CODM		首席运营决策者。
Cook Plant		Donald C. Cook 核电站，一座由 I&M 所有的双机组核电站，装机容量为 2,296 MW。
Cost Recovery Funding		KPCo Cost Recovery Funding, LLC，KPCo 的全资子公司及合并 VIE，成立目的是发行和偿付与电厂退役成本、递延风暴成本、递延购电费用、未充分回收的购电附加费成本以及发行相关费用有关的证券化债券。

CPA		容量购买协议。
CPCN		公共便利性与必要性证书。
CSAPR		跨州空气污染规则。
CWIP		在建工程。
DCC Fuel		DCC Fuel XVII、DCC Fuel XVIII、DCC Fuel XIX、DCC Fuel XX、DCC Fuel XXI 和 DCC Fuel XXII 合并 VIE，成立目的是获取、拥有并向 I&M 租赁核燃料。
DHLC		Dolet Hills Lignite Company, LLC，SWEPCo 的全资褐煤开采子公司。DHLC 是 SWEPCo 的非合并 VIE。



Eastern Region		AEP 的东部服务区域包括 APCo、I&M、KGPCo、KPCo、OPCo 和 WPCo 从事电力发电、输电和配电并服务客户的地区。
EIS		Energy Insurance Services, Inc.，一家非关联自保保险公司，也是 AEP 的合并 VIE。
ELG		废水排放限制指南。
ENEC		扩展净能源成本。



ERCOT		德克萨斯州电力可靠性委员会区域输电组织。


ETR		有效税率。
ETT		Electric Transmission Texas, LLC，由 AEP Transmission Holdco 与 Berkshire Hathaway Energy Company 共同成立的权益合资企业，旨在拥有和运营 ERCOT 的电力输电设施。
Excess ADIT		超额累计递延所得税。
FAC		燃料调整条款。
FASB		财务会计准则委员会。
Federal EPA		美国环境保护署。
FERC		联邦能源监管委员会。
FGD		烟气脱硫或洗涤器。
FIP		联邦实施计划。
FTR		金融输电权，一种金融工具，使持有人有权获得补偿，以支付电网拥塞时因节点电价差异而产生的某些拥塞相关输电费用。


术语		含义

GAAP		美国公认会计原则。
GHG		温室气体。
Gigawatt AI		Gigawatt AI Inc.，一家股权合资企业，成立旨在为公用事业公司构建以 AI 为核心的操作系统。
G&M		发电与营销。
Grid Growth Ventures		Grid Growth Ventures, LLC，由 Transource Energy 和 First Energy Transmission, LLC 于 2025 年成立的控股公司，AEP 持有其 43.25% 的股权。
I&M		Indiana Michigan Power Company，AEP 的一家电力公用事业子公司。I&M 为印第安纳州北部和东部以及密歇根州西南部的零售客户提供发电、输电和配电服务。
IMTCo		AEP Indiana Michigan Transmission Company, Inc.，Midwest Transmission Holdings 的全资输电子公司。

IRP		综合资源计划。
IRS		美国国税局。
ITC		投资税收抵免。
IURC		印第安纳州公用事业监管委员会。
KGPCo		Kingsport Power Company，AEP 的一家电力公用事业子公司。KGPCo 为田纳西州东北部 Kingsport 及其周边八个社区的零售客户提供电力服务。
KPCo		Kentucky Power Company，AEP 的一家电力公用事业子公司。KPCo 为肯塔基州东部的零售客户提供发电、输电和配电服务。
KPSC		肯塔基州公共服务委员会。


kV		千伏。
KWh		千瓦时。
LPSC		路易斯安那州公共服务委员会。
MATS		汞和空气毒物标准。

Midcontinent Grid Solutions		Midcontinent Grid Solutions, LLC，由 Transource Energy 和伯克希尔哈撒韦能源旗下关联公司于 2025 年成立的控股公司，AEP 持有其 43.25% 的股权。
Midwest Transmission Holdings		Midwest Transmission Holdings, LLC，是 AEPTCo Parent 的子公司，持有 IMTCo 和 OHTCo 全部已发行及流通在外的股份。
MISO		中大陆独立系统运营商。
Mitchell Plant		一座位于西弗吉尼亚州蒙兹维尔的燃煤电厂，设有两台机组，装机容量为 1,560 MW。该电厂由 KPCo 和 WPCo 共同所有。
MMBtu		百万英热单位。
MPSC		密歇根州公共服务委员会。
MRBC		修正后的费率基数成本。
MTM		按市值计价。
MW		兆瓦。
MWh		兆瓦时。
NAAQS		国家环境空气质量标准。
NCWF		North Central Wind Energy Facilities，由 PSO 和 SWEPCo 联合开展的项目，包括三座位于俄克拉荷马州的风电设施，风力发电总装机容量约为 1,484 MW。

非公用事业资金池		AEP 用于满足某些非公用事业子公司短期现金需求的集中式融资机制。

NOLC		净经营亏损结转。
NOX		氮氧化物。

OATT		开放接入输电费率。
OCC		俄克拉荷马州公司委员会。

iii


术语		含义

ODEQ		俄克拉荷马州环境质量部。



OHTCo		AEP Ohio Transmission Company, Inc.，Midwest Transmission Holdings 的全资输电子公司。
OPCo		Ohio Power Company，AEP 的一家电力公用事业子公司。OPCo 在俄亥俄州向零售客户输送和配送电力。
OPEB		其他退休后福利。

OTC		场外交易。
OVEC		Ohio Valley Electric Corporation，AEP 持有其 43.47% 的股权。
母公司		American Electric Power Company, Inc.，AEP 合并范围内 AEP 子公司的权益所有者。

PBA		绩效认证。
PFD		决策提案。
PJM		宾夕法尼亚州—新泽西州—马里兰州区域输电组织。
PLR		私人函件裁定。
PM		颗粒物。
PPA		购电协议。
PSA		买卖协议。
PSO		Public Service Company of Oklahoma，AEP 的一家电力公用事业子公司。PSO 在俄克拉荷马州东部和西南部向零售客户发电、输电和配电。
PTC		生产税抵免。
PUCO		俄亥俄州公用事业委员会。
PUCT		德克萨斯州公用事业委员会。


注册子公司		AEP 的 SEC 注册子公司：AEP Texas、AEPTCo、APCo、I&M、OPCo、PSO 和 SWEPCo。
注册人		SEC 注册人：AEP、AEP Texas、AEPTCo、APCo、I&M、OPCo、PSO 和 SWEPCo。
恢复融资		AEP Texas Restoration Funding, LLC，AEP Texas 的全资子公司，也是合并范围内的 VIE，成立目的是发行和偿付与德克萨斯州风暴灾后恢复相关的证券化债券；该风暴主要由哈维飓风造成。
风险管理合同		交易性和非交易性衍生品，包括指定为现金流量套期和公允价值套期的衍生品。
罗克波特电厂		一座由 AEGCo 和 I&M 共同拥有的发电厂，位于印第安纳州罗克波特附近，由两台 1,310 MW 燃煤发电机组组成。
ROE		股本回报率。
RPM		可靠性定价模型。
RTO		区域输电组织，负责在大范围跨州区域输送电力。
Sabine		Sabine Mining Company，一家褐煤开采公司，是 AEP 和 SWEPCo 合并范围内的 VIE。

SEC		美国证券交易委员会。
SIP		州实施计划。
SNF		乏核燃料。
SO2		二氧化硫。
SPP		西南电力池区域输电组织。
SSO		标准服务报价。
州级输电公司		AEPTCo 全资拥有的五家和多数持股的两家受 FERC 监管、仅从事输电业务的电力公用事业公司，其地理位置与 AEP 现有的公用事业运营公司相一致。


术语		含义

风暴恢复融资		SWEPCo Storm Recovery Funding, LLC，是 SWEPCo 的全资子公司及合并可变利益实体，成立目的是发行和偿付与路易斯安那州风暴灾后恢复相关的证券化债券。
SWEPCo		Southwestern Electric Power Company，AEP 的一家电力公用事业子公司。SWEPCo 从事发电、输电和配电业务，为德克萨斯州东北部及狭长地带、路易斯安那州西北部和阿肯色州西部的零售客户供电。
SWTCo		AEP Southwestern Transmission Company, Inc.，AEPTCo 全资拥有的输电子公司。
TA		输电协议，于2010年11月生效，由 APCo、I&M、KGPCo、KPCo、OPCo 和 WPCo 签订，AEPSC 担任代理人。
税制改革		2017年12月22日，特朗普总统签署了被称为《减税与就业法案》（TCJA）的立法。TCJA 对《1986年国内税收法典》作出重大修改，包括将联邦企业所得税税率从35%降至21%，自2018年1月1日起生效。


T&D		输电和配电公用事业公司。
过渡融资		AEP Texas Central Transition Funding III, LLC，是 AEP Texas 的全资子公司及合并可变利益实体，成立目的是发行和偿付与德克萨斯州重组立法相关的证券化债券。
Transource Energy		Transource Energy, LLC，是为投资于按照 FERC 批准的费率开发、收购、建设、拥有和运营输电设施的公用事业公司而设立的合并可变利益实体。AEP 持有 Transource Energy 86.5% 的股权。



UPA		机组电力协议。
公用事业资金池		AEP 用于满足某些公用事业子公司短期现金需求的集中融资机制。
UTM		统一跟踪机制。

VIE		可变利益实体。
Virginia SCC		弗吉尼亚州公司委员会。
VIU		垂直一体化公用事业公司。
西部地区		AEP 的西部服务区域包括 AEP Texas、PSO 和 SWEPCo 从事发电、输电和配电并向客户供电的地区。
WPCo		Wheeling Power Company，AEP 的一家电力公用事业子公司。WPCo 为西弗吉尼亚州北部的零售客户提供电力服务。
WVPSC		西弗吉尼亚州公共服务委员会。
WVSC		西弗吉尼亚州最高法院。

前瞻性信息

本报告由注册人编制，其中包含前瞻性陈述；对于母公司以外的注册人，本报告包含《1934年证券交易法》第21E条所指的前瞻性陈述。许多前瞻性陈述出现在本季度报告“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”中，但本文其他部分也有相关陈述，可通过“预期”“预计”“意图”“计划”“相信”“将”“应当”“可能”“会”“预计”“继续”等词语及类似表述加以识别，其中包括反映未来业绩或指引以及展望的陈述。这些事项受到风险和不确定性影响，可能导致实际结果与预测结果存在重大差异。本文中的前瞻性陈述截至本文日期作出。除适用法律要求外，管理层不承担更新或修订任何前瞻性陈述的义务。可能导致实际结果与前瞻性陈述所述结果存在重大差异的因素包括：


•	AEP服务区域内经济状况、电力市场需求和人口模式的变化。
•	全球冲突加剧和贸易紧张局势升级造成的经济影响，以及经济制裁、关税、贸易限制或贸易政策变化的出台或扩大。
•	通胀或通缩导致的利率趋势。
•	新的、修改后的、废止的或暂停执行的联邦、州或地方立法、法规、政策或行政措施，这些措施可能改变监管框架；延迟或阻止审批或许可；影响已批准或计划中的投资；或阻碍成本和投资得到及时回收。
•	由扰乱性事件引发的金融市场波动和不稳定，包括财政和货币政策或银行业的不确定性；尤其是影响为新资本项目融资以及为现有债务再融资的资本可得性或成本的事态发展。
•	用于满足营运资金和资本需求的资金的可得性及成本，尤其是：(a)预期的资金来源（例如出售税收抵免所得款项和预期证券化融资）未能实现或未达到预期水平；以及(b)发生成本与收回成本之间的时间间隔较长且成本金额较大的时期。
•	电力需求的变化，包括大负荷合同承诺。
•	数据中心需求预计增长，但存在不确定性，可能无法如预期实现，或其发生的速度或规模可能与预期不同，从而影响我们的负荷预测、资本投资计划、成本回收预期和财务业绩。
•	与野火相关的风险和不确定性，包括野火造成的损失、各注册人与野火有关的责任范围、与法律程序、索赔或类似行动相关的调查和结果、无法通过保险或费率回收野火成本，以及对各注册人财务状况和声誉的影响。
•	极端天气条件、自然灾害以及风暴、飓风、野火和干旱等灾难性事件的影响，这些事件会带来重大风险，包括可能引发诉讼，以及无法收回已发生的重大损失和修复成本。
•	可用于承保自然灾害、野火或运营相关损失的保险金额和险种受到限制。
•	燃料及其运输成本、燃料供应方和运输方的信用状况及履约情况，以及储存和处置废燃料（包括煤灰和乏核燃料）的成本。
•	燃料和必要发电能力的可获得性，以及发电厂的运行表现。
•	通过受监管或竞争性电价收回燃料及其他能源成本的能力。
•	规划、开发、建设、收购或整合广泛的发电和储能资源以及相关输电和配电基础设施的能力；这还包括取得必要的监管批准、许可和激励措施，其时间安排取决于地方政策和监管部门的优先事项、要求、流程和决定；遵守成本上限及其他监管或合同要求；并在履行可靠性、可负担性、环境和客户服务义务的同时，收回相关成本并获得适当回报。
•	经济或市场状况、遵守潜在政府法规的成本、电力用量，以及自然灾害或其他事件导致的供应链问题、客户、服务提供商、供应商和供货商等因素对 AEP 业务运营造成的干扰。
•	影响当前或未来资本投资计划完成的建设和开发风险，包括劳动力、材料、设备或零部件短缺及延误；关键设备供应有限且交货周期较长，包括大型电力变压器和过渡电力解决方案。
•	美国联邦政府长期或反复停摆对 AEP 运营、监管审批和财务表现的影响，包括资本市场可能出现波动，从而中断我们获取资本的渠道。


•	新立法、诉讼或政府监管，包括税法和法规的变化、对核能发电的监管、不断演变的环境标准、能源商品交易，以及与硫、氮、汞、碳、烟尘或 PM 等物质排放相关的新要求或修订要求；这些可能影响发电厂及相关资产的持续运营、成本回收和/或盈利能力。
•	税收立法或美国财政部相关指导意见的影响，包括现有税收激励措施可能发生变化对资本计划、经营业绩、财务状况、现金流或信用评级造成的影响。
•	与发电所用燃料或此类燃料的副产品和废弃物（包括煤灰和乏核燃料）相关的发电前、发电过程中及发电后的风险。
•	待决及未来费率案件、谈判和其他监管决定的时间和结果，包括新建发电、配电和输电服务投资以及环境合规相关成本的费率回收或其他回收方式。
•	诉讼或监管程序、调查的结果。
•	高效管理并回收运营、维护和开发项目成本的能力。
•	批发市场中发电和售电的价格及需求。
•	技术变化，包括新的、正在发展的、替代性或分布式发电来源以及能源存储技术。
•	对于可能在此前预计使用寿命结束前退役的发电机组，回收其任何剩余未回收投资的能力。
•	煤炭及其他能源相关大宗商品市场的波动和变化，尤其是天然气价格的变化。
•	客户、监管机构、投资者和利益相关方不断变化的期望和要求所带来的影响，包括我们、客户及第三方供应商对 AI 的开发、采用和使用，以及不断演变的可持续发展相关期望。
•	客户负担能力方面的考量可能影响监管成本回收结果和未来费率设计。
•	公用事业监管、政策、评估和批准负荷并网的方法，以及 RTO 内部的成本分摊（包括 ERCOT、PJM 和 SPP）方面的变化，以及潜在市场变化或我们参与这些 RTO 所带来的影响。
•	具有合同安排的交易对手（包括能源交易市场参与者）的信用状况变化。
•	评级机构的行动，包括影响债务成本的评级变化。
•	地缘政治发展对全球能源市场的影响，包括燃料供应和价格、电力生产经济性以及客户需求模式的波动。
•	资本市场波动对养老金、OPEB 和核退役信托基金及专属保险实体所持投资价值的影响，以及此类波动对未来资金需求的影响。
•	会计准则制定机构定期发布的会计准则。
•	成功抵御网络安全威胁的能力。
•	其他风险和不可预见事件，包括战争和军事冲突、恐怖主义影响（包括安全成本增加）、禁运、影响重要供应链的劳工罢工、全球信息技术中断及其他灾难性事件。
•	吸引和留住所需劳动力及关键人员（包括高级管理层）的能力。

注册人的前瞻性陈述仅截至本报告日期或其作出之日。注册人明确声明，除法律要求外，不承担更新任何前瞻性信息的义务。有关这些因素的更详细讨论，请参阅截至2025年12月31日的财年 10-K 年度报告（“2025年年度报告”）第一部分“风险因素”以及本报告第二部分。

注册人可将 AEP 网站用作发布重要公司信息的渠道。有关注册人的财务及其他重要信息通常会发布在 AEP 网站上，并可通过 www.aep.com/investors/ 访问。此外，您访问 www.aep.com/investors/ 的“Email Alerts”部分登记电子邮箱地址后，即可自动接收有关注册人的电子邮件提醒及其他信息。

vii

公司网站及 SEC 文件的获取

我们的主要公司网站地址为 www.aep.com。我们网站上的信息未通过引用纳入本文，也不属于本 10-Q 表。我们会在相关文件向 SEC 以电子方式提交或提供后，在合理可行的最短时间内通过网站免费提供我们的 10-K 表年度报告、10-Q 表季度报告、8-K 表当前报告，以及根据《交易法》第 13(a) 或 15(d) 条提交或提供的上述报告修订文件。SEC 设有网站 www.sec.gov，其中包含有关 AEP 的报告、委托书和信息说明及其他信息。

viii

第一部分. 财务信息

AMERICAN ELECTRIC POWER COMPANY, INC. 及其子公司

管理层对财务状况及经营成果的讨论与分析

经营成果

执行摘要

AEP 合并经营成果

2026 年第三季度与 2025 年第三季度比较

AEP 普通股股东应占收益从 2025 年的 $1 billion 增至 2026 年的 $1.2 billion，主要原因包括：

•2026 年天气有利，推动住宅类别的销售量增加。

•输电资产投资带来收入和收益增加。

•AEP 各司法辖区的费率程序带来的增加。

•商业及工业客户类别的销售量增加，主要由新增数据处理负荷推动。

上述增幅部分被以下因素抵消：

•长期债务余额增加且利率上升，导致利息支出增加。

•向部分现有批发发电客户提供抵免，导致收益减少。

截至 2026 年 9 月 30 日的九个月与截至 2025 年 9 月 30 日的九个月比较

AEP 普通股股东应占收益从 2025 年的 $3 billion 降至 2026 年的 $2.8 billion，主要原因包括：

•收到 2025 年 6 月 FERC 关于在输电公式费率中处理 NOLC 的命令，产生 $480 million 的有利影响；但该影响被持续投资输电资产带来的经常性收入和收益增加部分抵消。

•长期债务余额增加且利率上升，导致利息支出增加。

•向部分现有批发发电客户提供抵免，导致收益减少。

•在 SWEPCo 2025 年德克萨斯州基本费率案中，Pirkey 电厂净账面价值可能被部分否认，导致收益减少。

上述降幅部分被以下因素抵消：

•因 AEP 在其各司法辖区的费率诉讼而增加。

•商业和工业客户类别的销售量增加，主要由新的数据处理负荷推动。

•出售 APCo 一项非公用事业土地投资所得收益。

有关各业务分部的更多信息，请参阅经营业绩部分。

非 GAAP 财务指标

AEP 按照 GAAP 报告财务业绩。AEP 通过某些非 GAAP 财务指标（如经营收益）补充财务信息报告。与经营收益最具可比性的 GAAP 指标是 GAAP 收益。经营收益可能不同于按照 GAAP 报告的收益，不包括某些收益和损失及其他特定项目，包括商品对冲活动的按市值计价调整，以及下文对账表所列其他项目；管理层认为这些项目不能反映 AEP 的持续经营业绩。

此信息旨在增进投资者对各期财务业绩的整体理解，并通过剔除管理层认为与业务持续运营没有直接关系的项目，提供 AEP 基准经营业绩的指示。此外，此信息是管理层用于评估业绩、分配资源、设定激励薪酬目标以及规划和预测未来期间的主要指标之一。这些非 GAAP 财务指标并非 GAAP 所定义的列报方式，且可能无法与其他公司的列报方式相比。这些非 GAAP 指标不应被视为比最具可比性的 GAAP 指标更有用，也不应被视为其替代品或替代选择。

GAAP 收益与经营收益的对账

下表列示了经营收益与最直接可比的 GAAP 指标之间的对账。


	截至 2026 年 9 月 30 日的三个月
	AEP		AEP Texas		AEPTCo		APCo	I&M		OPCo	PSO		SWEPCo
	（百万美元）
GAAP 收益 (a)	$	1,187			$	172		$	196		$	124			$	113		$	112	$	234	$	188
GAAP 收益调整项：
商品对冲活动的按市值计价影响 (b)	14			—			—		—		8			—			—		—
批发客户合同协议 (c)	22			—			—		—		—			—			—		22
特定项目的所得税影响 (d)	(7)			—			—		—		(2)			—			—		(4)
特定项目总额	29			—			—		—		6			—			—		18

经营收益（非 GAAP）	$	1,216			$	172		$	196		$	124			$	119		$	112	$	234	$	206

(a)指归属于普通股股东或 AEP 成员的收益（亏损）；对于没有非控股权益的注册人，则指净收益（亏损）。

(b)指经济对冲活动的按市值计价影响；为使其与相关对冲风险敞口的确认相一致，故将其剔除。

(c)指 SWEPCo 与某些现有批发客户签订的发电供应合同协议；根据这些协议，相关批发客户获得的抵免款已于 2026 年支付。

(d)除非另有说明，税务影响按法定税率计算。


	截至 2025 年 9 月 30 日的三个月
	AEP		AEP Texas		AEPTCo		APCo	I&M		OPCo	PSO		SWEPCo
	（百万）
GAAP 盈利（a）	$	972			$	166		$	179		$	81			$	150		$	101	$	130	$	189
GAAP 盈利调整项（b）：
商品套期保值活动的按市值计价影响（c）	(1)			—			—		—		(5)			—			—		—
俄亥俄州立法的影响（d）	(8)			—			—		—		—			(8)			—		—
指定项目总计	(9)			—			—		—		(5)			(8)			—		—

经营盈利（非 GAAP）	$	963			$	166		$	179		$	81			$	145		$	93	$	130	$	189

(a)指归属于普通股股东或 AEP 成员的盈利（亏损），或对于没有非控股权益的注册实体，指净利润（亏损）。

(b)除税务相关调整外，表中列出的所有项目均按法定税率进行税务调整，除非另有说明。

(c)指经济套期保值活动的按市值计价影响；剔除该影响是为了与相关套期风险敞口的确认保持一致。

(d)指俄亥俄州获批立法导致 OVEC 相关购电成本监管资产减少的影响。


	截至 2026 年 9 月 30 日的九个月
	AEP		AEP Texas		AEPTCo		APCo	I&M		OPCo	PSO		SWEPCo
	（百万）
GAAP 盈利（a）	$	2,774			$	405		$	571		$	369			$	358		$	338	$	303	$	330
GAAP 盈利调整项：
商品套期保值活动的按市值计价影响（b）	32			—			—		—		15			—			—		—
WVPSC 命令的影响（c）	(35)			—			—		(29)		—			—			—		—
Pirkey 电厂部分不予认可（d）	31			—			—		—		—			—			—		31
UTM 部分不予认可（e）	22			22			—		—		—			—			—		—
批发客户合同协议（f）	45			—			—		—		—			—			—		45
指定项目的所得税影响（g）	(20)			(5)			—		6		(4)			—			—		(15)
指定项目总计	75			17			—		(23)		11			—			—		61

经营盈利（非 GAAP）	$	2,849			$	422		$	571		$	346			$	369		$	338	$	303	$	391

(a)指归属于普通股股东或 AEP 成员的盈利（亏损），或对于没有非控股权益的注册实体，指净利润（亏损）。

(b)指经济套期保值活动的按市值计价影响；剔除该影响是为了与相关套期风险敞口的确认保持一致。

(c)指与 2024 年修订后的费率基数成本附加费更新申报相关的 WVPSC 命令影响。

(d)指在 2025 年德克萨斯州基本费率案件中，Pirkey 电厂净账面价值很可能被部分不予认可的估计影响。

(e)指 AEP Texas 的 UTM 申报中所含成本很可能被部分不予认可的估计影响。

(f)指 SWEPCo 与若干现有批发客户就发电供应合同达成的协议；因此向这些批发客户提供了抵免，并已于 2026 年支付。

(g)税务影响按法定税率计算，除非另有说明。


	截至 2025 年 9 月 30 日的九个月
	AEP		AEP Texas		AEPTCo		APCo	I&M		OPCo	PSO		SWEPCo
	（百万）
GAAP 盈利（a）	$	2,998			$	389		$	946		$	353			$	332		$	267	$	221	$	353
GAAP 盈利调整项（b）：
商品套期保值活动的按市值计价影响（c）	5			—			—		—		11			—			—		—
出售 AEP OnSite Partners（d）	10			—			—		—		—			—			—		—
俄亥俄州立法的影响（e）	19			—			—		—		—			19			—		—
FERC NOLC 命令（f）	(480)			—			(354)		(29)		(36)			—			(4)		(54)
指定项目总计	(446)			—			(354)		(29)		(25)			19			(4)		(54)

经营盈利（非 GAAP）	$	2,552			$	389		$	592		$	324			$	307		$	286	$	217	$	299

(a)指归属于普通股股东或 AEP 成员的收益（亏损），或对于没有非控股权益的注册人而言的净利润（亏损）。

(b)除与税务相关的调整外，表中所列各项均按法定税率进行税务调整，另有说明的除外。

(c)指经济套期保值活动产生的按市值计价影响；为与基础套期风险敞口的确认保持一致，该影响不予计入。

(d)指因合同营运资本调整而对出售 AEP OnSite Partners 的估计损失所作的调整。

(e)指俄亥俄州批准立法后，与 OVEC 相关的购电成本对应的监管资产减少。

(f)指 FERC NOLC Order 对 2021-2024 年的影响。

电力行业转型

AEP 持续将其服务区域内的大型负荷意向转化为已签署的客户财务承诺。这些承诺主要来自数据处理及其他能源密集型客户，预计将支持销售增长、扩大客户群，并提高 AEP 发电、输电和配电系统的利用率。2026 年新增的数据处理负荷推动了商业和工业销售增长，表明大型负荷新增已开始为经营业绩作出贡献。

为满足已承诺和预测的增长，AEP 制定了 1,004 亿美元的五年资本计划，重点加强输电基础设施、增加发电能力以支持现有客户和预测中的大型负荷增长，并持续提升配电系统可靠性。在这一投资周期内，AEP 仍将专注于客户可负担性，并预计利用新增负荷增长、费率设计、持续提高运营和维护费用效率，以及证券化等融资机制来帮助解决可负担性问题。

AEP 正利用其发电组合、输电网络和基础设施执行能力，以满足已承诺和预测的客户需求，包括：

•2026 年新增 1,859 MW 自有发电能力。

•2026 年签署协议，收购额外发电设施，容量为 5,099 MW。

•发布征求建议书，寻求约 14,400 MW 的发电能力。

•签订容量购买协议，以满足服务客户所需的容量备用率。

•与领先的基础设施服务公司签订长期协议，为计划中的输电基础设施扩建提供工程、项目管理和施工支持。

AEP 已在其各监管辖区推进大型负荷电价提案及相关修改，以促进客户接入，同时保护现有客户。已获批准和拟议的条款可能包括最长 20 年的合同期限、覆盖合同需求量 80% 至 90% 的照付不议最低用量、信用支持，以及由客户承担特定基础设施成本。截至 2026 年 9 月 30 日，AEP 已在八个辖区提交提案，其中六个已获批准，两个仍在俄克拉荷马州和 SWEPCo-德克萨斯州待审。AEP 将继续与监管机构、政策制定者、RTO、客户和供应商合作，接入大型负荷客户，同时提升其服务区域的可靠性、韧性和可负担性。

PJM 资源充足性改革

AEP 东部公司是 PJM 的成员。PJM 的公用事业公司可通过以下任一方式履行其容量义务：(a) 参与 PJM 管理的容量拍卖；或 (b) 采用固定资源要求（FRR）替代方案，由负荷服务实体通过自有或签约资源自行供应发电容量。除 OPCo 外，所有 AEP 东部公司均采用 FRR 替代方案。

2026 年 1 月，白宫、PJM 覆盖区域内全部 13 位州长以及联邦能源高级官员联合发布了《原则声明》。该声明旨在增加 PJM 市场可供大型负荷客户使用的容量，并确保相关资源的成本由大型负荷客户承担，以保护现有客户的可负担性。《原则声明》指示 PJM 举行一次性可靠性后备拍卖，加快容量市场改革以应对数据中心负荷前所未有的增长，并使新容量进入市场所产生的相关成本由需要这些资源的大型负荷客户承担。随后，在一项自 2025 年起待审的程序中，PJM 管理委员会发布决定函，启动对 PJM 容量市场和并网流程的调整。

2026 年 7 月，PJM 管理委员会批准了近期资源充足性改革，旨在应对与负荷预测大幅增长和容量短缺相关的预期可靠性问题。随后，PJM 于 2026 年 7 月和 8 月向 FERC 提交提案，拟建立可靠性后备采购（RBP）机制和临时资源充足性服务（IRAS）。RBP 将通过长期承诺采购新增容量，而 IRAS 将允许对某些未获得合格新增容量支持的新大型负荷实施紧急削减。PJM 提议将 FRR 实体排除在 RBP 采购目标和相关成本分摊之外。PJM 还提议将 FRR 负荷排除在 IRAS 削减服务之外。对于 FRR 服务区域内的新大型负荷，PJM 转而提议，将其对现有发电容量的依赖上限设为 2027 年 6 月 1 日之前拥有或签约的容量；这些负荷的额外容量需求须通过新增资源满足。

2026 年 9 月，FERC 接受了 RBP 提案并予以备案，但暂停其生效，直至 2027 年 2 月 28 日；在此期间，该提案须接受退款，并就成本分摊、输电所有者退出义务以及负荷服务实体的抵押品要求进一步审理。为加快实施，FERC 鼓励 PJM 于 2026 年 10 月 29 日前提交修订提案。PJM 表示有意提交修订提案。

FERC 认定，将 FRR 实体排除在 RBP 及相关成本分摊之外的提议公平合理。另据 PJM 提议，拟采取相关规定，防止输电所有者退出后，与已承诺 RBP 资源相关的成本转由 PJM 其余参与者承担。这些规定可能要求退出的输电所有者提前履行某些未来义务，或安排继续支付相关款项。FERC 对将这些义务分配给输电所有者，而非从采购中受益的负荷服务实体提出质疑，并指示就此问题进一步审理。

2026 年 10 月，FERC 接受了 PJM 对 Large Load 的定义及其 Large Load Registry，该定义和注册表于 2026 年 10 月 12 日生效，并指示在 30 天内提交合规备案。该注册表涵盖现有和未来的大型负荷，要求负荷服务实体履行信息报告义务，并在需要时由电力配电商提供支持信息。AEP 的运营公司，包括 FRR 和非 FRR 实体，均须遵守 Large Load Registry 报告要求。不过，FERC 驳回了 IRAS 备案的其余部分，包括拟议的限电框架、Bring Your Own New Capacity 要求及相关容量市场条款。FERC 指出了管辖权及其他方面的缺陷，并就 PJM 选择重新提交时的修订提案提供了指导。驳回 IRAS 还取消了上述拟议的 FRR 采购限制，包括用于确定可为新的大型负荷提供服务的现有发电容量数量的 2027 年 6 月 1 日截止日期。

额外或修订 tariff 条款的最终形式和时间安排，以及相关实施要求、成本回收机制和运营影响，仍不确定。目前，AEP 无法预测 FERC 后续程序的结果，也无法估计最终获批条款可能对其财务状况、经营业绩或现金流产生的任何影响（如有）。AEP 将继续关注这些事项。

德克萨斯州的大型负荷并网

2025年6月，德克萨斯州参议院第6号法案（SB 6）生效，并由德克萨斯州州长签署成为法律。SB 6 建立了 ERCOT 内大型负荷客户接入的标准化流程，旨在支持德克萨斯州的经济发展，同时降低基础设施成本无法回收的可能性。新法为大型负荷接入制定了标准，并指示 PUCT 确保这些大型负荷客户承担合理比例的分摊输电成本。PUCT 继续推进落实 SB 6 的规则制定工作，其中包括大型负荷接入标准、负荷预测、可靠性要求和输电成本分摊相关条款。PUCT 于 2026 年9月通过了《德克萨斯州行政法典》相关修订，2026 年10月生效，涉及大型负荷接入标准。修订要求大型负荷客户签署中间协议、提供某些披露信息，并在纳入 ERCOT 接入研究之前按每 MW 50,000 美元缴纳财务担保。新规要求大型负荷客户在 ERCOT 批次研究确定容量分配后签署标准化接入协议、提供某些披露信息，并除财务担保外，还需支付将其负荷直接接入更广泛系统所需的现金。新规还规定了撤回全部或部分申请或合同约定峰值需求的后果，明确了已送电的大型负荷客户获得财务担保返还的条款，并要求公用事业公司将作为财务担保缴纳的现金抵押品单独存放。2026 年10月，AEP Texas 根据新规将约 12 亿美元现金抵押品单独存放。

AEP Texas 已签署协议函，约定到 2031 年新增约 49 吉瓦负荷，其中包括寻求通过 ERCOT Batch Zero 流程进行评估的潜在负荷。ERCOT 的 Batch Zero 流程是 ERCOT 制定并经 PUCT 于 2026 年批准的一次性过渡性接入流程，旨在系统层面评估符合条件的大型负荷接入申请、分配可用输电容量、确定必要的输电升级，并要求参与客户作出财务承诺。该流程主要适用于 75 MW 或以上的大型电力负荷，是 ERCOT 未来定期批次接入框架的前置步骤。2026 年7月，AEP Texas 收到约 20 亿美元财务担保，形式包括现金抵押品、公司或母公司担保以及信用证，涉及截至 2032 年寻求参与 Batch Zero 流程的 45 吉瓦潜在负荷。

In August 2026, the Governor of Texas directed the PUCT and ERCOT to conduct a comprehensive verification of all Batch Zero loads and an audit of data center projects 25 MW and above advancing through ERCOT's interconnection process before any additional projects move forward. Following the governor’s direction, ERCOT announced that it would not meet an August 2026 deadline associated with the Batch Zero interconnection study process and received a good-cause exception from the PUCT regarding Batch Zero schedule and implementation requirements. ERCOT has currently paused Batch Zero classification and study activity and stated it will not authorize large loads to energize until verification is complete.

The recent activities of the PUCT and ERCOT are expected to provide greater clarity regarding large load interconnection requirements, transmission infrastructure needs and the timing and scale of future load growth. Accordingly, the amount, timing and cost responsibility associated with these prospective large load interconnections remain subject to ongoing ERCOT and PUCT actions.

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. Through the third quarter of 2026, AEP experienced higher customer demand, driven primarily by new data processing load added in the commercial and industrial customer classes. In addition, AEP experienced higher customer demand in the residential class, due to favorable weather in the third quarter of 2026 compared to the third quarter of 2025. The table below shows the percentage change in sales volume by customer class.

$\"6424\"$

(a)Percentage change for the three months ended September 30, 2026 as compared to the three months ended September 30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

(b)Percentage change for the nine months ended September 30, 2026 as compared to the nine months ended September 30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

New Generation Resources

The growth of AEP’s regulated generation portfolio reflects the Company’s focus on meeting increasing customer demand for power while balancing cost and reliability.

Acquired Generation Facilities

During 2026, AEP subsidiary companies acquired five generation facilities to support AEP’s portfolio and enhance reliability. These transactions reflect the companies’ continued focus on securing necessary generation to meet future customer demand. See the “Acquisitions” section of Note 6 for additional information. The table below summarizes these acquisitions:

Company

Plant Name

Fuel Type

Location

Acquisition Date

Net Maximum Capacity

(in MWs)

I&M

Oregon

Natural Gas

Oregon, OH

March 2026

870

APCo

Grover Hill

Wind

Paulding County, OH

May 2026

143

AGR

Wolf Hills

Natural Gas

Bristol, VA

August 2026

263

I&M

Big Sandy Peaker

Natural Gas

Kenova, WV

August 2026

318

PSO

Lazbuddie

Wind

Parmer and Castro Counties, TX

August 2026

265

Total Acquired Generation Facilities

1,859

Pending Generation Facilities

In April 2026, I&M entered into a PSA to acquire the Sycamore Riverside Energy Center (Sycamore Plant), a 918 MW natural gas and ultra-low sulfur distillate (dual-fuel)-fired generation facility located in Sullivan County, Indiana. I&M filed an application with the IURC in late April seeking a CPCN for approval of the estimated project costs and associated ratemaking and accounting treatment. A final order from the IURC is expected in December 2026.

In May 2026, APCo filed an application with the Virginia SCC seeking approval for two new solar PSAs including Skycrest (155 MWs) located in Jay County, Indiana, anticipated to be placed in service in December 2028, and Riverstart V (100 MWs) located in Randolph County, Indiana, anticipated to be placed in service in August 2028. The petition also included request for approval of two wind PPA extensions consisting of Beech Ridge (101 MWs) with an 8-year extension starting in 2030 and Camp Grove (150 MWs) with a 10-year extension starting in 2027.

In July 2026, AGR entered into a PSA to acquire the Longview Power Plant, a 710 MW coal-fired generation facility located in Monongalia County, West Virginia. The transaction is subject to customary closing conditions, including approval from the FERC and other required regulatory approvals. The agreement was signed to support growing energy demand in the region and strengthen AEP's ability to provide reliable power at affordable prices. The Company currently expects the acquisition to close in the fourth quarter of 2026 or the first quarter of 2027, although the timing and ultimate completion of the transaction are subject to receiving the required regulatory approvals and other closing conditions.

In July 2026, I&M filed an application for a CPCN with the IURC for approval to construct the Rockport Energy Center, a 1,520 MW combined-cycle natural gas facility to be located in Spencer County, Indiana. In the application, the Company seeks approval of the estimated costs of the project, the authority to recover costs in connection with its development and approval of specific ratemaking and accounting treatment. A final order from the IURC is expected in the first quarter of 2027.

In July 2026, I&M filed an application under its Expedited Generation Resource Plan (EGR Plan) requesting approval of amended contractual terms to the previously approved 245 MW Lake Trout Solar Project PSA. A final order is expected in November 2026.

In September 2026, SWEPCo filed applications for CCNs with the APSC, LPSC and PUCT, seeking regulatory approval for the acquisition of the Brantley Branch project, a 200 MW 6-hour BESS, located in Rusk County, Texas. Regulatory approvals are expected in the third quarter of 2027 and the project is expected to close and come into service in the fourth quarter of 2028.

In October 2026, KPCo entered into an amended agreement with TeraWulf Inc., for 1 GW of contracted demand. KPCo plans to file an application seeking approval of the agreement and the related generation investments in the fourth quarter of 2026.

Significant Approved Generation and Storage Filings

AEP received regulatory approvals from various state regulatory commissions to acquire approximately 2,327 MWs of owned generation and storage facilities, totaling approximately $2.3 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received regulatory approvals for 1,124 MWs of renewable PPAs. The following table summarizes regulatory approvals received for approved generation projects that are not yet in service as of September 30, 2026:

Company

Generation Type

Expected Commercial
Operation

Owned/PPA

Generating Capacity

(in MWs)

APCo

Solar

2027-2028

PPA

343

I&M

Solar

2027-2028

PPA

380

I&M

Wind

2027-2030

PPA

401

PSO

Solar

2027

Owned

150

PSO

BESS

2027-2028

Owned

224

PSO

Gas combustion turbines

2028

Owned

450

SWEPCo

Gas combustion turbines

2027-2028

Owned

1,503

Total Approved Projects

3,451

Significant Generation Requests for Proposal (RFP)

The table below includes active RFPs issued for both owned and purchased power generation. Projects selected will be subject to regulatory approval:

Company

Issuance Date

Resource Type

Projected
In-Service Dates

Generating
Capacity

(in MWs)

APCo

May 2026

Owned wind and solar

2029

800

APCo

May 2026

Purchased power from solar, wind and hydroelectric resources

2028/2029

300

APCo

August 2026

Contracted BESS

2029

300

APCo

August 2026

Owned BESS

2030

500

APCo

August 2026

Owned combined cycles

2031

1,500

I&M

October 2026

All-source

2033/2034

4,000

PSO

January 2026

All-source

2029

4,000

SWEPCo

May 2026

All-source

2031

3,000

Total Significant RFPs

14,400

Capacity Purchase Agreements

In addition to the generation projects discussed above, AEP enters into CPAs to satisfy operating companies’ capacity reserve margins to serve customers. The following table includes CPA amounts under contract as of September 30, 2026, by year, for the five-year period 2026-2030:


	APCo	I&M			PSO (a)	SWEPCo (a)
	Gas	Natural Gas		Wind			Natural Gas	Wind		Natural Gas	Wind
Delivery Start Year	(in MWs)
2026	—		—		73				460		86	150	87
2027	—		160		—				410		86	300	83
2028	198		1,151		—				724		—	461	88
2029	—		1,139		—				751		—	488	88
2030	—		996		—				789		—	225	88

(a)Seasonal average of volume contracted.

Regulatory Matters - Utility Rates and Rate Proceedings

The Registrants are involved in rate cases and other proceedings with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. Depending on the outcomes, these rate cases and proceedings can have a material impact on results of operations, cash flows and financial condition.

The following tables summarize the completed and pending base rate case proceedings. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

Annual

Previously

Base Revenue

Approved

New Rates

Company

Jurisdiction

Increase

ROE

Effective

(in millions)

APCo/WPCo

West Virginia

9.75%

August 2025

(a)

SWEPCo

Arkansas

9.5%

9.65%

February 2026

(b)

KPCo

Kentucky

9.75%

March 2026

(c)

OPCo

Ohio

9.7%

9.84%

April 2026

(a)In August 2025, in response to APCo’s and WPCo’s 2024 West Virginia Base Rate Case filing, the WVPSC originally approved a combined $76 million annual increase in base rates based upon a 9.25% ROE. In February 2026, the WVPSC issued an order on reconsideration of the 2024 West Virginia Base Rate Case, approving a revised ROE of 9.75%, resulting in a $15 million prospective annual increase in base rates, to arrive at an authorized annual increase of $91 million effective February 2026.

(b)See “2025 Arkansas Base Rate Case” section of Note 4 in the 2025 Annual Report for additional information.

(c)In March 2026, KPCo filed a request with the KPSC seeking rehearing on the vegetation management finding in the base case order in addition to certain other denied costs. In April 2026, the KPSC issued an order approving KPCo’s request for rehearing.

Pending Base Rate Case Proceedings

Annual

Base Revenue

Filing

Increase/ (Decrease)

Requested

Company

Jurisdiction

Date

Request

ROE

(in millions)

SWEPCo

Texas

October 2025

10.75%

PSO

Oklahoma

January 2026

299

10.5%

APCo

Virginia

May 2026

10.5%

I&M

Indiana

August 2026

(42)

10.1%

Other Significant Regulatory Matters

Piketon Transmission Project (Applies to AEP, AEPTCo and OPCo)

In August 2026, OHTCo, OPCo and an unaffiliated customer executed definitive agreements related to the construction of three 765 kV transmission lines by OHTCo to support the development of a proposed 10.4 GW data center campus in Piketon, Ohio. The three 765 kV transmission lines, each expected to provide approximately 3.2 GWs of incremental transmission capacity, have targeted in-service date goals of December 31, 2028, 2029 and 2030. The initial 800 MWs of load is expected to be served utilizing existing transmission capacity and does not require any additional regulatory approvals.

For the balance of the approximately 10.4 GW, and subject to applicable regulatory approvals and the terms of the definitive agreements, OHTCo is expected to recover approved transmission-related costs related to the new load through arrangements with OPCo, which will, in turn, recover such amounts from the customer pursuant to a retail service agreement designed to prevent any of the costs of the project from being allocated to other OPCo customers. Under the agreement, the customer is responsible for those costs, including the applicable return, with no allocation of those costs to other OPCo customers.

The definitive agreements related to the transmission investment to serve the load provide for a base ROE of 11.35%, which may increase to 11.99% or decrease to 10.71% based on the actual project costs as compared to budgeted costs and actual in-service dates as compared to targeted in-service dates for each transmission line, and include payment terms extending for 20 years following the applicable in-service dates. The agreements establish a budget for the project of approximately $5 billion. The Piketon Transmission Project requires regulatory approvals from PJM, the PUCO and the FERC. The equipment purchase agreement currently in effect requires the customer to fully collateralize OHTCo equipment purchases prior to receiving the required regulatory approvals. The ultimate scope, timing, cost recovery mechanisms and economics of the project are subject to regulatory review and approval.

2025 UTM Filing

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM. In March 2026, a Texas ALJ issued a PFD recommending partial disallowance of the requested amounts which was based on an interpretation of a later effective date for eligible UTM deferrals. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). In May 2026, the PUCT Chairman issued a Commissioner Memorandum agreeing with the ALJ’s PFD and ordered the PUCT staff to complete a calculation to confirm the final disallowance amount. Completion of the Commission-required calculation and final order were filed in the third quarter of 2026. In conjunction with the Commissioner Memorandum, AEP Texas recognized an unfavorable pretax impact of $23 million in May 2026 attributable to a portion of the deferrals included in the UTM application period.

UTM Regulatory Assets

As of September 30, 2026, AEP Texas has deferred, beginning August 2025, approximately $89 million of eligible costs as a regulatory asset for inclusion in future AEP Texas’ UTM applications. AEP Texas has also deferred approximately $34 million related to its system resiliency plan for inclusion in future UTM applications. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate case proceeding before the PUCT. If any of these deferred costs or investments are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

West Virginia Securitization

In March 2026, the WVPSC issued a financing order approving APCo’s and WPCo’s (the Companies) proposed securitization. In July 2026, the WVPSC approved an overall balance of $2.7 billion of eligible costs for securitization. The Companies are proceeding with the securitization bond issuance process and plan to complete the securitization in the fourth quarter of 2026, subject to market conditions. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

West Virginia Modified Rate Base Cost Surcharge

In April 2026, the WVPSC issued an order that adjudicated the Companies’ 2024 MRBC surcharge update filing. This order affirms previously approved MRBC revenue requirements and allows the Companies to perform a final true-up in an ENEC filing to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner during the four-year existence of the surcharge.

A group of APCo customers submitted an appeal to the WVSC alleging that the WVPSC erred in its April 2026 order approving a final MRBC true-up without sufficient record support. In September 2026, APCo and the WVPSC filed motions for the WVSC to dismiss this APCo customer appeal. See the “2026 ENEC Update Filing” and “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” sections of Note 4 for additional information.

West Virginia Inflation-Based Rate Adjustment

In April 2026, the WVPSC issued an order conditionally approving an annual Inflation-Based Rate Adjustment to current base rates of 4% for residential and commercial customers and 2.5% for industrial customers, provided that the Companies: (a) agree with proceeding with securitization, unless otherwise ordered by the WVPSC, (b) agree that the April 2026 Notice of Intent to file a 2026 West Virginia base rate case will be withdrawn and (c) agree that a new base rate case will not be filed prior to June 1, 2027. In April 2026, the Companies agreed to the terms of the Inflation-Based Rate Adjustment described above and filed revised tariff sheets reflecting a $40 million combined annual increase to base rates effective July 1, 2026.

A group of APCo customers submitted an appeal to the WVSC alleging that the WVPSC erred in its April 2026 order approving the Inflation-Based Rate Adjustment without adequate findings, evidentiary support or reasoned explanation demonstrating the approval of reasonable rates under WVPSC statutes. In September 2026, APCo and the WVPSC filed motions for the WVSC to dismiss the APCo customer appeal.

An intervening party submitted an appeal to the WVSC regarding the Inflation-Based Rate Adjustment alleging that the WVPSC: (a) failed to carry its burden of proving that the Companies’ existing rates were unreasonable and needed to be changed, (b) failed to adequately support its order with evidence of record and (c) violated the due process rights of the intervening party and the customers that it represents. See the “West Virginia Inflation-Based Rate Adjustment” section of Note 4 for additional information.

If any refund liabilities are imposed related to these West Virginia jurisdictional issues, it would reduce future net income and cash flows and impact financial condition.

Indiana House Enrolled Act 1002

On February 26, 2026, House Enrolled Act 1002 (HEA 1002) was signed into law in Indiana. This law requires Indiana’s investor-owned electricity suppliers to petition the IURC for approval of a multi-year rate plan (MYRP). When establishing an electricity supplier’s authorized return for its MYRP, Indiana law requires the IURC to consider any changes in risk to the electricity supplier and its customers that may result from implementing the MYRP. HEA 1002 also states that performance metrics and performance incentive mechanisms (PIM) will be applicable to each year of the electricity supplier’s MYRP with regards to affordability and service restoration.

In July 2026, the IURC launched two investigations applicable to all Indiana electric suppliers. One investigation considers the risks to the electricity suppliers and customers in Indiana as a result of the electricity supplier implementing an MYRP with respect to an electric suppliers’ authorized return. The second investigation considers the development of guidelines for electric suppliers and stakeholders to utilize in evaluating the future use of trackers under a MYRP framework. In October 2026, the IURC finalized the list of issues for its investigations into ROE and tracker mechanisms with stakeholder testimony due in December 2026 and hearings scheduled for February 2027.

Mitchell Plant Cooling Tower CPCN Requests

In February 2026, WPCo and KPCo filed CPCN and cost recovery requests (Mitchell CPCN) with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to: (a) construct a new mechanical draft cooling tower which would allow for continued operation of the 780 MW Mitchell Plant Unit 2 and (b) recover the related estimated investment of $191 million. WPCo and KPCo each own a 50% undivided interest in Mitchell Plant.

In June 2026, the Department of Energy awarded $51 million to support the WPCo and KPCo Mitchell Plant Cooling Tower investment.

In October 2026, the KPSC issued an order conditionally approving construction and cost recovery through a rider, subject to WVPSC CPCN approval and receipt of funding related to the June 2026 Department of Energy award. In addition, KPCo is required to provide the KPSC with written notice of any increase to estimated project costs that exceeds 5%. Additionally in October 2026, the WVPSC issued an order approving construction. Cost recovery will be addressed in a future filing. WPCo is required to provide the WVPSC with written notice of any increase to estimated project costs that exceeds 10%.

As of September 30, 2026, the net book value of Mitchell Plant Unit 2, before cost of removal and including CWIP and inventory, is estimated to be approximately $639 million ($382 million at WPCo and $257 million at KPCo). If AEP cannot ultimately recover Mitchell Plant Unit 2 costs, it would reduce future net income and cash flows and impact financial condition.

Federal Tax Legislation

In February 2026, the Department of Treasury and the IRS issued additional interim guidance on the application of CAMT, Notice 2026-7. This guidance allows taxpayers to deduct certain tax-deductible repairs when determining adjusted financial statement income for CAMT purposes. This guidance is expected to result in a reduction to applicable Registrants’ prior and future CAMT liabilities.

Additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions in recently enacted legislation. AEP will continue to monitor any issued guidance and evaluate the impact on AEP’s future net income, cash flows and financial condition.

Fuel Cell Agreements

In 2025, OPCo signed two contracts totaling approximately 98 MWs for electricity service from fuel cells. The PUCO approved the contracts in May 2025. In September 2025, an intervenor filed a request for rehearing with the Supreme Court of Ohio, opposing the PUCO's approval and claiming that the order was unlawful, anti-competitive, and discriminatory. In June 2026, the appeals were dismissed and the PUCO decisions are now final and non-appealable.

In January 2026, an unregulated subsidiary of AEP executed: (a) an unconditional purchase agreement to acquire a substantial portion of its 1 GW option for solid oxide fuel cells for the development and construction of a fuel cell generation facility for approximately $2.65 billion and (b) a 20 year offtake arrangement with a high investment grade third-party customer for 100% of the output of the fuel cell generation facility expected to be located near Cheyenne, Wyoming.

Grid Growth Ventures Investment (Applies to AEP)

In 2026, Transource Energy executed agreements to form Grid Growth Ventures, LLC (Grid Growth Ventures) with First Energy Transmission, LLC to participate in PJM’s 2025 Regional Transmission Expansion Plan (RTEP) competitive process. In February 2026, PJM selected the projects proposed by Grid Growth Ventures to address forecasted reliability and load growth requirements. The RTEP projects awarded by PJM were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $600 million. The RTEP projects awarded by PJM will be developed, owned and operated by Grid Ohio Growth EHV, LLC and Grid Growth Ohio, LLC, subsidiaries of Grid Growth Ventures.

In March 2026, subsidiaries of Grid Growth Ventures, Grid Growth Ohio EHV, LLC and Grid Growth Ohio, LLC, submitted to the FERC a request for acceptance of formula rates for each company, consisting of a formula rate template and implementation protocols, effective May 2026. The filing also requested approval of Federal Power Act Section 219 transmission incentive rate treatments for the projects awarded by PJM to the Grid Growth Ventures subsidiaries. The requested incentive rate treatments include: (a) recovery of abandonment costs if the projects are cancelled for reasons beyond Grid Growth Ventures’ control, (b) inclusion of CWIP in rates while the projects are in development, (c) use of hypothetical capital structure of 40% debt and 60% equity until the earlier of either December 31, 2032 or the date all of the projects are in service, after which Grid Growth Ventures will use its actual capital structure and (d) regulatory asset treatment for pre-commercial costs including carrying charges. The filing also proposed depreciation rates, requested a base ROE of 10.8% for both companies and requested authorization to replicate the formula rate and rate incentive treatments for any subsidiaries of Grid Growth Ventures. In July 2026, the FERC issued an order accepting the formula rate, subject to settlement proceedings which will determine the companies’ base ROE, cost of debt, formula rate template language and depreciation rates.

Midcontinent Grid Solutions Investment (Applies to AEP)

In 2025, Transource Energy and an affiliate of Berkshire Hathaway Energy formed Midcontinent Grid Solutions, LLC to participate in MISO’s 2024 Regional Transmission Expansion Plan competitive process. In January 2026, MISO selected the upgrades proposed by Midcontinent Grid Solutions to address forecasted reliability and load growth requirements. The projects awarded by MISO were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $500 million. The projects awarded by MISO will be developed, owned and operated by Midcontinent Grid Solutions Wisconsin, LLC (MGS Wisconsin), a subsidiary of Midcontinent Grid Solutions, LLC.

In September 2025, the FERC issued an order accepting the formula rates requested by Midcontinent Grid Solutions, LLC’s subsidiary, Midcontinent Grid Solutions Iowa, LLC (MGS Iowa), granting its requested effective date of July 2025 and the following: (a) regulatory asset treatment for pre-commercial and formation costs with carrying charges, (b) a hypothetical capital structure of 60% equity and 40% debt through the date of the company’s first transmission project being placed in service, (c) conditional approval of a 50-basis point ROE adder due to participation in an RTO, effective upon the date on which operational control transitions to MISO, and (d) authorization of the company’s request to replicate its formula rate and related treatments for future subsidiaries in MISO. The FERC also accepted MGS Iowa’s proposed use of a 9.98% base ROE, the MISO regional base ROE effective at the time of the FERC order, and the depreciation rates proposed by the company.

As an affiliate of MGS Iowa, MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate. A request was filed in April 2026 and included an additional incentive for the recovery of abandonment costs if the projects are cancelled for reasons beyond MGS Wisconsin’s control. In June 2026, the FERC approved MGS Wisconsin’s request.

NOLCs in Retail Jurisdictions - IRS PLRs

AEP’s utility subsidiaries have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail ratemaking. In April 2024, supportive PLRs for certain retail jurisdictions were received from the IRS, effective March 2024. The PLRs concluded NOLCs on a stand-alone ratemaking basis should be included in rate base and in the computation of Excess ADIT regulatory liabilities to be refunded to customers. As of September 30, 2026, there were four jurisdictions awaiting approval and two jurisdictions that have been approved but are subject to refund in their status of transitioning to stand-alone treatment of NOLCs in retail ratemaking. Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of September 30, 2026, AEP had NOLC regulatory assets of $92 million, of which $83 million are classified as pending final regulatory approval and $9 million are classified as approved for recovery.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.

Claims for Indemnification Made by Owners of the Gavin Power Station

AEP sold the Gavin Power Station to Gavin Power LLC and Lighthouse Generation LLC in 2017. Pursuant to the PSA for that transaction, AEP maintained responsibility to complete closure of the 300 acre unlined fly ash reservoir (FAR) pond in accordance with the closure plan approved by the Ohio Environmental Protection Agency and to indemnify the purchasers for that work. In November 2022, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. See “Claims for Indemnifications Made by Owners of the Gavin Power Station” section of Note 5 for additional information.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and potential future requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges. AEP is unable to predict changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions that may evolve.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. Management is engaged in the development of possible future requirements including the items discussed below.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations. As of September 30, 2026, AEP owned generating capacity of approximately 27,200 MWs, of which approximately 10,200 MWs were coal-fired. In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Since then, the Federal EPA has finalized actions revising or repealing portions of certain 2024 rules and has proposed additional revisions or repeals. Most recently, in September 2026, the Federal EPA finalized a partial repeal of the 2024 greenhouse gas standards for fossil fuel-fired electric generating units and concurrently proposed rescinding the remaining power-sector greenhouse gas findings and standards under Clean Air Act Section 111. Management continues to evaluate the impacts of the rules that are currently in effect on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for promoting compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

The regulatory requirements and associated costs of compliance may also change based on: (a) potential state rules that impose additional more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) regulatory and policy changes implemented by the President and the Federal EPA and (h) other factors.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states and localities implement and administer many of these programs and could impose additional or more stringent requirements. Primary CAA regulatory programs that continue to drive investments in AEP’s existing generating units include the following: (a) periodic revisions to NAAQS and the development of SIPs to achieve more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of GHG emissions from fossil generation under Section 111 of the CAA. Certain notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA, which in turn may require AEP to make investments in pollution control equipment at existing generating units or change how units are dispatched and operated. In February 2024, the Federal EPA finalized a new more stringent annual primary PM2.5 standard.

Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs. In November 2025, in connection with pending litigation challenging the new standards, the Federal EPA filed a motion asking the court to vacate the stricter PM2.5 standard. In June 2026, the United States Court of Appeals for the District of Columbia Circuit denied the request. In a separate case, in July 2026, the United States District Court for the Northern District of California ordered the Federal EPA to complete area designations under the Agency’s revised annual fine particulate matter (PM2.5) NAAQS by February 2027. In September 2026, the Federal EPA appealed the district court’s order to the United States Court of Appeals for the Ninth Circuit. The agency requested, and the Ninth Circuit granted, expedited consideration of the case. However, while the appeals are pending, the Federal EPA is taking the actions required under the CAA to meet the court’s February 2027 deadline. In October 2026, the Federal EPA issued notices to states, territories, and tribes describing its intended designation approach and requested additional information within 30 days. In October 2026, the Federal EPA also joined a broad coalition of states and associations in petitioning the United States Supreme Court to review the 2024 standard.

If the rule is not vacated by any further legal challenge, states must revise SIPs to attain the new standard. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require additional pollution controls or the implementation of operational constraints. At this time, management cannot reasonably estimate any impacts on AEP’s operations, cash flows, net income or financial condition.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which would require certain power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. The rules implementing the Regional Haze requirements of the CAA have been revisited over time. In January 2026, the Federal EPA published a final rule extending the due date for the next round of Regional Haze SIP submittals by states to July 31, 2031.

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the United States District Court for the District of Columbia Circuit entered a consent decree setting deadlines for the Federal EPA to rule on Regional Haze SIPs for 32 states, including Texas. In September 2024, the Federal EPA signed a proposed rule to partially approve and partially disapprove the Texas SIP revision. In May 2025, the Federal EPA proposed to withdraw the prior proposed rule, including the proposed partial disapproval of the Texas SIP revision, and instead proposed to approve the Texas Regional Haze SIP. In December 2025, the Federal EPA finalized its approval of the Texas and Oklahoma SIPs. The Federal EPA has recently approved Regional Haze SIP submissions for Ohio and West Virginia, both of which have been appealed by environmental groups. In February 2026, the Federal EPA proposed to approve the Regional Haze SIP for Oklahoma’s second implementation period. In August 2026, the Federal EPA proposed approval of an Oklahoma SIP revision submitted in March 2026 for the first implementation period, revising source-specific Regional Haze requirements applicable to Northeastern Power Station. Management will continue to monitor the rulemakings and litigation and cannot predict the outcome.

New Source Performance Standards

In January 2026, the Federal EPA finalized revisions to the New Source Performance Standards for stationary combustion turbine units that commenced construction, modification or reconstruction after December 13, 2024. The new standards for NOX require a level of performance equivalent to the application of selective catalytic reduction for large, high-utilization natural gas-fired turbines, but establish various levels of combustion controls as the best system of emission reductions for smaller and lower-utilization turbines. The rule does not change the SO2 limits applicable to combustion turbines. Management is evaluating the implications of the rule on new combustion turbine projects. Several environmental groups have challenged the rule and in April 2026, AEP and other utilities moved to intervene in support of the Federal EPA in that litigation.

Cross-State Air Pollution Rule

CSAPR is a regional trading program that the Federal EPA began implementing in 2015 to address interstate transport of emissions that contribute significantly to nonattainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM2.5 NAAQS in downwind states. CSAPR relies on SO2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted basis. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.

In February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states, including Texas, addressing the 2015 Ozone NAAQS. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR ozone season program in states to which the FIP applies. The FIP was the subject of judicial review in the United States Court of Appeals for the District of Columbia Circuit and has since been administratively stayed pending the Supreme Court lifting its June 2024 order staying enforcement of the Good Neighbor Plan, other courts lifting judicial orders staying the Federal EPA SIP disapproval actions as to SIPs submitted by several states, and the Federal EPA taking subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in April 2025, the court placed the challenges to the Good Neighbor Plan in abeyance pending further order of the court. The Federal EPA has indicated it intends to propose rulemaking to revise the rule. Management will continue to monitor the litigation and any further actions by the Federal EPA for any potential impact to operations.

Climate Change, CO2 Regulation and Energy Policy

In April 2024, the Administrator of the Federal EPA signed new GHG standards and guidelines for new and existing fossil-fuel fired sources. The rule relies on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and carbon capture and sequestration or limited utilization to reduce CO2 emissions from new gas turbines. The rule also offers early retirement of coal plants in lieu of carbon capture and storage as an alternative means of compliance.

Twenty-seven states, numerous companies, trade associations and others challenged the rule. AEP has joined with several other utilities to challenge the rule and has asked the court to stay the rule during the litigation, and the appeals have been consolidated. The court stayed the litigation pending rulemaking by the Federal EPA. In June 2025, the Federal EPA proposed to repeal the GHG emissions standards for fossil-fueled fired electric generating units based on a determination that GHG emissions from power plants do not significantly contribute to air pollution that may endanger public health or the environment. As an alternative, the Federal EPA proposed to eliminate GHG standards for existing coal and gas units and to keep only certain emission limits applicable to new sources. These proposals have not been finalized. In September 2026, the Federal EPA finalized a partial repeal of the 2024 standards, including the emission guidelines for existing fossil fuel-fired steam generating units, the carbon capture and sequestration-based standards for coal-fired steam generating units undertaking a large modification, and the Phase 2 carbon capture and sequestration-based standards for new base-load stationary combustion turbines. Concurrently, the Federal EPA issued a supplemental proposal to rescind the remaining greenhouse gas findings and standards for fossil fuel-fired power plants under Clean Air Act Section 111. Management is evaluating the final rule and supplemental proposal, including their effects on compliance planning, generation strategy and the pending litigation. The final rule will become effective 60 days after publication in the Federal Register. Management cannot predict the outcome of the supplemental proposal or related litigation. Future changes to greenhouse gas requirements could affect the timing and economics of investments in AEP's fossil generation fleet. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

AEP is committed to delivering reliable, affordable power and routinely submits IRPs in various regulatory jurisdictions to address future generation needs. Accordingly, AEP continues to focus on developing energy solutions that align with state and federal policy objectives, customer expectations, and reliability requirements. These energy solutions may include a range of generation and energy resources, depending on the needs and priorities of the jurisdictions. AEP remains committed to evaluating and pursuing generation strategies that support reliability, affordability and long-term energy needs where supported by regulators and customers. As an example, APCo and I&M are seeking early site permits to bring small modular reactors to Virginia and Indiana as part of their evaluation of future generation options. AEP’s performance will ultimately be driven by the needs and desires of the jurisdictions AEP serves and the company will continue to engage with regulators and policymakers to meet the energy needs while facilitating the delivery of reliable, affordable energy.

MATS Rule

In April 2024, the Federal EPA issued a revised MATS rule for power plants, which includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The rule also requires the installation and operation of continuous emissions monitors for PM. Several states and other parties have challenged the rule in the United States Court of Appeals for the District of Columbia Circuit, but management cannot predict the outcome of the litigation. The litigation is being held in abeyance. In February 2026, the Federal EPA finalized its repeal of the 2024 MATS rule, and the rule’s requirements reverted to the 2012 MATS rule emission standards. That repeal has been challenged by various groups. Management will continue to monitor the litigation but does not anticipate any challenges complying with the standards in the now-repealed 2024 rule should its repeal be reversed by the court.

CCR Rule

The Federal EPA’s CCR Rule regulates the disposal and beneficial use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. As originally promulgated in 2015, the rule applied to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers.

In August 2018, the District of Columbia Circuit Court vacated and remanded certain aspects of the 2015 CCR rule, including an exemption for legacy impoundments. Following this, the Federal EPA issued a final rule in August 2020, setting an April 11, 2021 deadline for unlined CCR impoundments to cease waste acceptance and commence closure. This rule permits a facility to request a deadline extension from the Federal EPA if alternative disposal capacity is unavailable or a compliant conversion or a plant retirement is in progress.

In January 2022, the Federal EPA made public statements in the context of a deadline extension request submitted by the Gavin Power Station suggesting more stringent closure requirements for CCR units. See “Claims for Indemnification Made by Owners of the Gavin Power Station” above for additional information. In April 2022, a petition was filed with the District of Columbia Circuit Court of Appeals, arguing that the Federal EPA could not enforce these new purported requirements without proper rulemaking. In June 2024, the District of Columbia Circuit Court dismissed these petitions, finding the statements were not amendments to existing regulations and thus the court lacked jurisdiction.

In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). That rule has been challenged in the District of Columbia Circuit Court. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the Legacy CCR Rule. In March 2025, the Federal EPA announced plans to make changes to the CCR Rule and to work with states to implement future CCR requirements. As a result, the litigation challenging the 2024 Legacy Rule is being held in abeyance. In November 2025, the Federal EPA proposed to extend by three years the compliance deadline applicable to certain facilities operating pursuant to alternative closure deadlines for unlined surface impoundments greater than 40 acres. In February 2026, the Federal EPA finalized a rule that provides additional time to meet facility evaluation requirements for identifying CCR management units and to comply with groundwater monitoring provisions. Additionally, this rule makes conforming changes to the remaining CCR management units compliance deadlines. In April 2026, the Federal EPA proposed revisions to the CCR Rule that would rescind requirements for CCR management units, revise requirements for beneficial use of CCR materials, allow expanded reliance on state-approved and other regulatory closures of legacy units, and introduce a new, permit-based, site-specific compliance pathway. In July 2026, the Federal EPA issued an advance notice of proposed rulemaking regarding the Federal CCR Permit Program. The Federal EPA is evaluating whether a general permit structure could support the site-specific compliance pathways proposed in April 2026. Management is evaluating the proposal and has participated in the rulemaking process.

Should additional corrective measures like groundwater treatment or ash removal be mandated at any of AEP’s coal-fired facilities, AEP could face substantial costs that could materially and adversely affect financial condition, results of operations and cash flows. See “Federal EPA’s Revised CCR Rule” section in Note 5 for additional information.

Clean Water Act Regulations

The Federal EPA’s ELG rule for generating facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A revision to the ELG rule, published in October 2020, established additional options for reusing and discharging small volumes of bottom ash transport water, provided an exception for retiring units and extended the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. For affected facilities required to install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain.

In April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit by December 31, 2025 to retire by 2034. Several petitions for review have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo also challenged the rule by filing a joint petition with a utility trade association in which AEP participates. The litigation challenging the ELG Rule is being held in abeyance while the new administration evaluates the rule. The Federal EPA has announced plans to reconsider the standards and deadlines established by the 2024 ELG rule.

In December 2025, the Federal EPA issued the Deadline Extension ELG Rule to extend the compliance deadlines in the 2024 ELG Rule by five years as well as to establish a site-specific mechanism for extending compliance deadlines for both the 2020 and 2024 ELG Rules. The Deadline Extension ELG Rule also extended the deadline to commit to cease coal combustion by 2034 from December 31, 2025 to December 31, 2031. Several environmental organizations filed petitions for review challenging the Federal EPA's December 2025 ELG Deadline Extension Rule. Those challenges were consolidated in the United States Court of Appeals for the Second Circuit, where the litigation remains pending. Management is evaluating the compliance alternatives in the ELG rule, taking into consideration the requirements of other rules and their combined impacts to operations. Management cannot predict the outcome of the pending litigation or any further rulemaking actions by the Federal EPA related to the ELG rule.

In January 2026, the Federal EPA proposed a rule titled Updating the Water Quality Certification Regulations. Through the proposed rule, the Federal EPA is attempting to clarify the Clean Water Act section 401 certification process for states and tribes. Under section 401, a federal agency cannot conduct any activity that may result in a discharge into waters of the United States without obtaining a permit from a State or authorized tribe in the location of the discharge certifying compliance with applicable water quality requirements. The proposed rule aims to reduce regulatory delays associated with the certification process. Management will monitor the rulemaking for any potential impacts to operations.

The definition of “waters of the United States” has been subject to rulemaking and litigation which has led to inconsistent scope among the states. In November 2025, the Federal EPA and the United States Army Corps of Engineers proposed a revised definition of “waters of the United States” to conform to a decision by the United States Supreme Court. In September 2026, the agencies issued a supplemental notice of proposed rulemaking seeking additional public comment on alternative approaches prior to issuing a final rule. The rulemaking remains pending. Management will continue to monitor developments in rulemaking and litigation for any potential impact to operations.

Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits. Management regularly evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

For generating facilities retired or planned for retirement in advance of the retirement date currently authorized for ratemaking purposes, with related accelerated depreciation regulatory assets pending regulatory approval, the table below summarizes the net book value and related regulatory asset balances recorded as of September 30, 2026:


Company	Plant	Net Investment (a)		Accelerated Depreciation Regulatory Asset				Actual/Projected Retirement Date	Current Authorized Recovery Period		Annual Depreciation (b)
		(in millions)						(in millions)
PSO	Northeastern Plant, Unit 3	$	50			$	259					2026		(c)	$	8


SWEPCo	Pirkey Plant	—			47		(d)			2023			(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	220			264					2028	(f)		(g)	43

(a)Net book value, including CWIP, excluding cost of removal and materials and supplies.

(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP, which the ODEQ has submitted. Federal EPA proposed to approve the revised Oklahoma SIP in August 2026. That proposal remains pending. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026.

(d)Represents Texas jurisdictional share.

(e)SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. See the “Regulated Generating Unit that has been Retired and Related Fuel Operations” section of Note 4 for additional information. In January 2026, the FERC issued an order providing recovery of the Pirkey Plant based on blended recovery periods determined by all SWEPCo jurisdictions including Texas.

(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. In February 2026, the APSC issued an order approving the application for a CCN. Additionally, in September and October 2026, the PUCT and the LPSC, respectively, issued orders approving the stipulation and settlement agreements related to the CCN applications.

(g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.

RESULTS OF OPERATIONS

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows:

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 8 - Business Segments for additional information on AEP’s segments.

The following discussion of AEP’s results of operations by segment provides a comparison of Earnings (Loss) Attributable to AEP Common Shareholders for the three months ended and nine months ended September 30, 2026 as compared to the three months ended and nine months ended September 30, 2025. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segments and Registrant Subsidiaries within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the three and nine months ended September 30, 2026 and 2025, see the discussions of Results of Operations by Registrant Subsidiary.

A detailed discussion of AEP’s 2025 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operations section included in the 2025 Annual Report.

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
	(in millions)
Vertically Integrated Utilities	$	697			$	578		$	1,443	$	1,335
Transmission and Distribution Utilities	284			267			743		656
AEP Transmission Holdco	219			200			653		1,013
Generation & Marketing	96			45			268		209
Corporate and Other	(109)			(118)			(333)		(215)
Earnings Attributable to AEP Common Shareholders	$	1,187			$	972		$	2,774	$	2,998

See Note 8 - Business Segments for additional information on Earnings (Loss) Attributable to AEP Common Shareholders by segment.

Heating Degree Days and Cooling Degree Days

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the Eastern Region have a larger effect on revenues than changes in the Western Region due to the relative size of the two regions and the number of customers within each region.

The actual heating degree days are calculated on a 55-degree temperature base and the actual cooling degree days are calculated on a 65-degree temperature base for Registrant Subsidiaries except AEP Texas. AEP Texas’ actual heating degree days are calculated on a 55-degree temperature base and actual cooling degree days are calculated on a 70-degree temperature base.

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	9,631		8,842		24,947	24,618
Commercial	8,475		7,355		22,540	19,548
Industrial	8,619		8,552		25,201	25,248
Miscellaneous	652		599		1,753	1,701
Total Retail	27,377		25,348		74,441	71,115

Wholesale (a)	5,088		4,217		12,183	12,451

Total KWhs	32,465		29,565		86,624	83,566

(a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Eastern Region
Actual – Heating	—		1		1,663	1,736
Normal – Heating	2		2		1,700	1,702

Actual – Cooling	841		722		1,222	1,104
Normal – Cooling	729		733		1,086	1,085

Western Region
Actual – Heating	—		—		632	966
Normal – Heating	—		—		911	903

Actual – Cooling	1,844		1,447		2,785	2,278
Normal – Cooling	1,413		1,415		2,190	2,186


Vertically Integrated Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders


(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Common Shareholders	$	578			$	1,335

Changes in Revenues:
Retail Revenues	408			759
Off-system Sales	5			52
Transmission Revenues	1			13
Other Revenues	1			(2)
Total Change in Revenues	415			822

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	47			68
Other Operation and Maintenance	(120)			(327)
Asset Impairments and Other Related Charges	—			(31)

Depreciation and Amortization	(112)			(193)
Taxes Other Than Income Taxes	(4)			(35)


Other Income	—			(2)
Allowance for Equity Funds Used During Construction	5			17
Non-Service Cost Components of Net Periodic Benefit Cost	(7)			(19)
Interest Expense	(61)			(168)
Total Change in Expenses and Other	(252)			(690)

Income Tax Benefit	(45)			(25)

Net Income Attributable to Noncontrolling Interests	1			1

2026 Earnings Attributable to AEP Common Shareholders	$	697			$	1,443

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $408 million primarily due to the following:

•A $261 million increase in base rate and rider revenues.

•A $99 million increase in weather-related usage primarily in the residential class driven by a 24% increase in cooling degree days primarily in the western region.

•A $45 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

These increases were partially offset by:

•An $18 million decrease at SWEPCo due to a credit to certain existing wholesale generation customers.

•Off-system Sales increased $5 million primarily due to Rockport Plant, Unit 2 merchant sales, economic hedging activity at I&M and margins in July 2026 attributable to increased PJM prices at APCo.

•Transmission Revenues increased $1 million primarily due to the following:

• A $15 million increase due to continued transmission investment.

This increase was partially offset by:

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by an equal amount of incremental SPP upgrade costs in Other Operation and Maintenance expenses.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $47 million primarily due to decreases at APCo and PSO, partially offset by increases at I&M and SWEPCo.

•Other Operation and Maintenance expenses increased $120 million primarily due to the following:

•A $63 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $32 million increase in employee-related costs.

•A $30 million increase in storm expenses.

These increases were partially offset by:

•A $24 million decrease due to the refund of SPP upgrade costs at PSO and SWEPCo.

•Depreciation and Amortization expenses increased $112 million primarily due to the following:

•A $79 million increase due to a higher depreciable base at I&M and PSO.

•A $28 million increase at APCo primarily due to a July 2026 order approving a final true-up to recover past West Virginia MRBC costs.

These increases were partially offset by:

•A $5 million decrease at I&M due to Michigan PTC deferral activity.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher AFUDC base and higher equity return rates at I&M and PSO.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $7 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $61 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $45 million primarily due to the following:

•A $42 million decrease due to a decrease in PTCs.

•A $35 million decrease due to an increase in pretax book income.

These decreases were partially offset by:

•A $16 million increase due to a decrease in flow-through expense.

•A $12 million increase due to a decrease in state taxes.

•A $7 million increase due to a decrease in flow-through CAMT expense.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $759 million primarily due to the following:

•A $632 million increase in base rate and rider revenues.

•A $157 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

•A $72 million increase in weather-related usage primarily in the residential class driven by a 19% increase in cooling degree days primarily in the western region.

These increases were partially offset by:

•A $107 million decrease in fuel revenues primarily due to decreases at APCo, PSO and SWEPCo, partially offset by an increase at I&M.

•A $41 million decrease at SWEPCo due to a credit to certain existing wholesale generation customers.

•Off-system Sales increased $52 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity at I&M and margins in July 2026 attributable to increased PJM prices at APCo.

•Transmission Revenues increased $13 million primarily due to the following:

•A $78 million increase due to continued transmission investment.

This increase was partially offset by:

•A $56 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by lower SPP upgrade costs in Other Operation and Maintenance expenses.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $68 million primarily due to decreases at APCo, PSO and SWEPCo, partially offset by an increase at I&M.

•Other Operation and Maintenance expenses increased $327 million primarily due to the following:

•A $137 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $63 million increase in employee-related costs.

•A $62 million increase in storm expenses.

•A $29 million increase in vegetation management costs.

•An $11 million increase in distribution-related expenses driven by system improvements, reliability programs, meters and transformers, customer driven third-party work and amortization of storm-related regulatory assets.

These increases were partially offset by:

•A $24 million decrease due to the refund of SPP upgrade costs at PSO and SWEPCo.

•Asset Impairments and Other Related Charges increased $31 million due to the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case at SWEPCo.

•Depreciation and Amortization expenses increased $193 million primarily due to the following:

•A $145 million increase primarily due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $26 million increase at APCo primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $8 million increase due to NOLC-related Excess ADIT deferrals recorded in 2025 and the amortization of these deferrals recorded in 2026 for IURC approved recovery through I&M’s Indiana tax rider.

These increases were partially offset by:

•An $11 million decrease at I&M due to Michigan PTC deferral activity.

•A $5 million decrease at SWEPCo primarily due to higher over-recovery of costs and allowable returns associated with generation rider recovery.

•Taxes Other Than Income Taxes increased $35 million primarily due to the following:

•A $21 million increase in property taxes at APCo, PSO and SWEPCo.

•A $7 million increase due to higher business and occupation taxes at APCo.

•Allowance for Equity Funds Used During Construction increased $17 million primarily due to a higher AFUDC base and higher equity return rates primarily at I&M, KPCo and SWEPCo.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $19 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $168 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $25 million primarily due to the following:

•A $114 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $28 million decrease due to an increase in pretax book income.

These decreases were partially offset by:

•A $70 million increase due to an increase in PTCs.

•A $31 million increase due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•A $12 million increase due to a decrease in state taxes.

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	8,726		8,256		21,377	21,566
Commercial	14,885		12,610		40,623	33,240
Industrial	8,084		7,009		23,060	20,813
Miscellaneous	218		209		555	553
Total Retail (a)	31,913		28,084		85,615	76,172

Wholesale (b)	2		552		901	1,683

Total KWhs	31,915		28,636		86,516	77,855

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Eastern Region
Actual – Heating	—		—		1,996	2,077
Normal – Heating	2		3		1,993	1,996

Actual – Cooling	794		734		1,115	1,076
Normal – Cooling	704		707		1,032	1,032

Western Region
Actual – Heating	—		—		144	296
Normal – Heating	—		—		215	208

Actual – Cooling	1,611		1,367		2,735	2,520
Normal – Cooling	1,347		1,348		2,382	2,369


Transmission and Distribution Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Common Shareholders	$	267			$	656

Changes in Revenues:
Retail Revenues	210			345
Off-system Sales	(32)			(13)
Transmission Revenues	14			66
Other Revenues	(14)			(4)
Total Change in Revenues	178			394

Changes in Expenses and Other:
Purchased Electricity for Resale	14			27
Purchased Electricity from AEP Affiliates	(8)			(13)
Other Operation and Maintenance	(141)			(258)

Depreciation and Amortization	(21)			(44)

Taxes Other Than Income Taxes	(11)			(37)


Other Income	4			3
Allowance for Equity Funds Used During Construction	12			27
Non-Service Cost Components of Net Periodic Benefit Cost	(3)			(1)
Interest Expense	(12)			(23)
Total Change in Expenses and Other	(166)			(319)

Income Tax Expense	6			14
Equity Earnings of Unconsolidated Subsidiary	(1)			(2)

2026 Earnings Attributable to AEP Common Shareholders	$	284			$	743

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $210 million primarily due to the following:

•A $141 million increase in rider revenues in Ohio and Texas.

•A $40 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $19 million increase in weather-related usage primarily due to an 18% increase in cooling degree days in Texas and an 8% increase in cooling degree days in Ohio.

•A $10 million increase in weather-normalized revenues primarily in the commercial and industrial classes in Ohio.

•Off-system Sales decreased $32 million primarily due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•Transmission Revenues increased $14 million primarily due to continued transmission investment in Ohio and Texas.

•Other Revenues decreased $14 million primarily due to the following:

•An $8 million decrease primarily due to lower third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

•A $5 million decrease primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity for Resale expenses decreased $14 million primarily due to the following:

•A $34 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•An $8 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

•A $2 million decrease in recoverable alternative energy rider expenses.

These decreases were partially offset by:

•A $36 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates increased $8 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $141 million primarily due to the following:

•An $86 million increase primarily due to an increase in recoverable PJM transmission expenses in Ohio.

•A $14 million increase in transmission and distribution expenses in Texas.

•A $14 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses in Ohio.

•A $7 million increase due to recoverable Transmission Cost Recovery Factor expenses in Texas.

•A $7 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization expenses increased $21 million primarily due to a higher depreciable base in Ohio and Texas.

•Taxes Other Than Income Taxes increased $11 million primarily due to higher property taxes in Ohio.

•Allowance for Equity Funds Used During Construction increased $12 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $12 million primarily due to the following:

•A $14 million increase due to higher long-term debt balances in Texas.

•A $10 million increase due to interest on customer deposits in Texas from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $6 million decrease due to an increase in the debt component of AFUDC in Texas.

•A $5 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $6 million primarily due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $345 million primarily due to the following:

•A $232 million increase in rider revenues in Ohio and Texas.

•A $99 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $33 million increase in weather-normalized revenues primarily in the residential and commercial classes in Ohio and Texas.

These increases were partially offset by:

•A $20 million decrease in weather-related usage primarily driven by a 4% decrease in heating degree days in Ohio and less extreme weather conditions in the first six months of 2026 compared to the same period in 2025 in Texas.

•Off-system Sales decreased $13 million primarily due to the following:

•A $32 million decrease due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

This decrease was partially offset by:

•An $18 million increase due to increased sales of OPCo’s OVEC purchased power in the first half of 2026 driven by higher market prices and volumes.

•Transmission Revenues increased $66 million primarily due to continued transmission investment in Ohio and Texas.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity for Resale expenses decreased $27 million primarily due to the following:

•A $57 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•A $52 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

These decreases were partially offset by:

•An $86 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates expenses increased $13 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $258 million primarily due to the following:

•A $151 million increase in transmission expenses primarily due to a $134 million increase in recoverable PJM transmission expenses and a $12 million increase in recoverable vegetation management expenses in Ohio.

•A $28 million increase in distribution expenses primarily related to recoverable vegetation management expenses and recoverable storm restoration costs in Ohio.

•A $22 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•An $18 million increase due to the partial disallowance of regulatory assets associated with the UTM deferrals in Texas.

•A $14 million increase in transmission and distribution expenses in Texas.

•A $13 million increase in administrative and general expenses primarily due to employee-related expenses in Texas.

•Depreciation and Amortization expenses increased $44 million due to a higher depreciable base in Ohio and Texas.

•Taxes Other Than Income Taxes increased $37 million due to the following:

•A $25 million increase due to higher property taxes in Ohio.

•An $8 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $27 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $23 million primarily due to the following:

•A $38 million increase due to higher long-term debt balances in Texas.

•An $11 million increase due to interest on customer deposits in Texas from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $15 million decrease due to an increase in the debt component of AFUDC in Texas.

•An $11 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $14 million primarily due to the following:

•A $23 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

•A $5 million decrease due to an increase in AFUDC equity.

This decrease was partially offset by:

•An $16 million increase due to an increase in pretax book income in Ohio.

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco


	September 30,
	2026		2025
	(in millions)
Plant in Service	$	18,629			$	16,877
Construction Work in Progress	2,990			2,376
Accumulated Depreciation and Amortization	2,224			1,891
Total Transmission Property, Net	$	19,395			$	17,362



AEP Transmission Holdco
Reconciliation of 2025 to 2026
Earnings Attributable to AEP Members from AEP Transmission Holdco
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	200			$	1,013

Changes in Transmission Revenues:
Transmission Revenues	42			(49)
Total Change in Transmission Revenues	42			(49)

Changes in Expenses and Other:
Other Operation and Maintenance	(12)			(39)
Depreciation and Amortization	(12)			(36)
Taxes Other Than Income Taxes	10			(14)
Interest and Investment Income	2			4

Allowance for Equity Funds Used During Construction	5			9
Non-Service Cost Components of Net Periodic Pension Cost	—			(1)
Interest Expense	(8)			(29)
Total Change in Expenses and Other	(15)			(106)

Income Tax Expense	(8)			(210)
Equity Earnings of Unconsolidated Subsidiaries	4			7
Net Income Attributable to Noncontrolling Interests	(4)			(2)

2026 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	219			$	653

Third Quarter of 2026 Compared to Third Quarter of 2025

The major component of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:

•Transmission Revenues increased $42 million primarily due to continued transmission investment.

Expenses and Other and Income Tax Expense:

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:

•A $6 million increase in employee-related costs.

•A $2 million increase in vegetation management and facility compliance costs.

•A $2 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $10 million primarily due to prior period adjustments in Ohio, partially offset by higher property taxes associated with increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher CWIP base.

•Interest Expense increased $8 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the decrease in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:

•Transmission Revenues decreased $49 million primarily due to the following:

•A $214 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This decrease was partially offset by:

•A $161 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense, Equity Earnings of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interest changed between years as follows:

•Other Operation and Maintenance expenses increased $39 million primarily due to the following:

•A $16 million increase in employee-related costs.

•A $12 million increase in vegetation management and facility compliance costs.

•A $7 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $36 million due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes associated with increased transmission investment, partially offset by prior period adjustments in Ohio.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher CWIP base and higher equity rates.

•Interest Expense increased $29 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $210 million primarily due to the following:

•A $254 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This increase was partially offset by:

•A $31 million decrease due to a decrease in pretax book income.

•A $5 million decrease due to a decrease in state taxes.

•Equity Earnings of Unconsolidated Subsidiaries increased $7 million primarily due to higher pretax earnings at ETT.

•Net Income Attributable to Noncontrolling Interests increased $2 million primarily due to the following:

•A $56 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

This increase was partially offset by:

•A $54 million decrease due to higher 2025 earnings for Midwest Transmission Holdings due to the impact of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

GENERATION & MARKETING



Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Common Shareholders	$	45			$	209

Changes in Revenues:
Retail, Trading and Marketing	116			384
Merchant Generation	64			108
Other Revenues	58			94
Total Change in Revenues	238			586

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(167)			(533)
Other Operation and Maintenance	(13)			2

Depreciation and Amortization	(1)			(2)

Interest and Investment Income	5			14

Non-Service Cost Components of Net Periodic Benefit Cost	—			(1)
Interest Expense	(1)			—
Total Change in Expenses and Other	(177)			(520)

Income Tax Expense	(10)			(7)



2026 Earnings Attributable to AEP Common Shareholders	$	96			$	268

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail, Trading and Marketing increased $116 million primarily due to higher market prices in 2026.

•Merchant Generation increased $64 million primarily due to higher realized prices in 2026.

•Other Revenues increased $58 million primarily due to continued progress on customer infrastructure projects in 2026.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $167 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses increased $13 million primarily due to continued progress on customer infrastructure projects in 2026, partially offset by renewable contract modification proceeds.

•Interest and Investment Income increased $5 million primarily due to an increase in interest income due to higher advances to affiliates.

•Income Tax Expense increased $10 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail, Trading and Marketing increased $384 million primarily due to higher market prices in 2026, partially offset by reduced MTM hedging gains.

•Merchant Generation increased $108 million primarily due to higher realized prices in 2026.

•Other Revenues increased $94 million primarily due to continued progress on customer infrastructure projects in 2026.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $533 million primarily due to an increase in energy costs in 2026.

•Interest and Investment Income increased $14 million primarily due to an increase in interest income due to higher advances to affiliates.

•Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

CORPORATE AND OTHER

Third Quarter of 2026 Compared to Third Quarter of 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $118 million in 2025 to a loss of $109 million in 2026 primarily due to:

•A $71 million increase in Income Tax Benefit primarily due to the following:

•A $44 million increase due to an increase in PTCs.

•A $10 million increase due to a decrease in pretax book income.

•A $9 million increase due to a decrease in state taxes.

This increase in earnings was partially offset by:

•A $36 million increase in interest expense primarily due to higher long-term debt balances.

•A $12 million increase in employee-related costs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $215 million in 2025 to a loss of $333 million in 2026 primarily due to:

•A $74 million increase in interest expense primarily due to higher long-term debt balances.

•A $12 million increase in employee-related costs.

•An $11 million decrease in the recognition of deferred revenues on completed contracts.

These decreases in earnings were partially offset by:

•A $20 million increase in Income Tax Benefit primarily due to the following:

•A $26 million increase due to a decrease in pretax book income.

•A $7 million increase due to an increase in PTCs.

These increases were partially offset by:

•A $17 million decrease due to an increase in state taxes.

AEP CONSOLIDATED INCOME TAXES

Third Quarter of 2026 Compared to Third Quarter of 2025

Income Tax Expense decreased $14 million primarily due to:

•A $22 million decrease due to an increase in flow-through benefits primarily driven by AFUDC equity.

•A $21 million decrease due to a decrease in state taxes.

•A $7 million decrease due to a decrease in flow-through CAMT expense.

•A $4 million decrease due to an increase in excess ADIT asset reversals.

•A $2 million decrease due to an increase in PTCs.

These decreases were partially offset by:

•A $46 million increase due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

Income Tax Expense increased $208 million primarily due to:

•A $368 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This increase was partially offset by:

•A $76 million decrease due to an increase in PTCs.

•A $31 million decrease due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $18 million decrease due to an increase in amortization of Excess ADIT.

•A $13 million decrease due to an increase in flow-through benefits primarily driven by AFUDC equity.

•A $13 million decrease due to favorable discrete adjustments.

FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization


	September 30, 2026		December 31, 2025
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	52,541			59.4	%		$	47,322		58.4	%
Short-term Debt	1,875			2.1			1,508			1.9
Total Debt	54,416			61.5			48,830			60.3
AEP Common Equity	32,775			37.1			31,138			38.4
Noncontrolling Interests	1,268			1.4			1,080			1.3
Total Debt and Equity Capitalization	$	88,459			100.0	%		$	81,048		100.0	%

AEP’s ratio of debt-to-total capital increased from 60.3% to 61.5% as of December 31, 2025 and September 30, 2026, respectively, primarily due to an increase in long-term debt to support AEP’s capital investment plan in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity for the next twelve months and for the foreseeable future. As of September 30, 2026, AEP had $8 billion of revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. In addition, market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2026, available liquidity was approximately $7.4 billion as illustrated in the table below:

Amount

Maturity

Commercial Paper:

(in millions)

Revolving Credit Facility

6,500

April 2031

Revolving Credit Facility

1,500

April 2029

Cash and Cash Equivalents

418

Total Liquidity Sources

8,418

Less:

AEP Commercial Paper Outstanding

975

Net Available Liquidity

7,443

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first nine months of 2026 was $2.1 billion. The weighted-average interest rate for AEP’s commercial paper for the nine months ended September 30, 2026 was 3.94%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under seven uncommitted facilities totaling $850 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2026 was $525 million with maturities ranging from October 2026 to September 2027.

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2028. As of September 30, 2026, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of September 30, 2026, this contractually defined percentage was 56.0%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under these credit agreements. This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

ATM Program

In November 2025, AEP filed a prospectus supplement under which it may sell up to $3.5 billion of its common stock through an ATM program. In the first quarter of 2026, two million shares of common stock were issued for $264 million in net proceeds. In addition to these issuances and sales of shares of common stock, AEP also may use the ATM program to enter into forward sale agreements. As of September 30, 2026, AEP had issued six million shares in forward sale agreements through its ATM program with expected proceeds of $684 million.

See “Forward Equity Agreements” section of Note 12 for additional information regarding shares issued or expected to be issued under forward sale agreements.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.97 per share in October 2026. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings. In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances, issuances of common stock and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper and bank term loans, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	268			$	246
Net Cash Flows from Operating Activities	5,767			5,131
Net Cash Flows Used for Investing Activities	(11,171)			(7,749)
Net Cash Flows from Financing Activities	5,643			3,479

Net Increase in Cash, Cash Equivalents and Restricted Cash	239			861
Cash, Cash Equivalents and Restricted Cash at End of Period	$	507			$	1,107

Operating Activities


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Net Income	$	2,868			$	3,091
Non-Cash Adjustments to Net Income (a)	3,162			2,517
Mark-to-Market of Risk Management Contracts	(116)			(193)
Pension Contributions to Qualified Plan Trust	—			(95)
Property Taxes	564			541

Deferred Fuel Over/Under-Recovery, Net	133			165


Change in Other Noncurrent Assets	(838)			(720)
Change in Other Noncurrent Liabilities	673			134
Change in Certain Components of Working Capital	(679)			(309)
Net Cash Flows from Operating Activities	$	5,767			$	5,131

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Asset Impairments and Other Related Charges and AFUDC.

Net Cash Flows from Operating Activities increased by $636 million primarily due to the following:

•A $539 million increase in cash from Change in Other Noncurrent Liabilities. This increase is primarily due to the increase in customer deposits, the timing of deferred revenue on customer infrastructure projects and changes in regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms.

•A $422 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $95 million increase in cash due to a discretionary contribution to the qualified pension plan made in 2025. See Note 7 - Benefit Plans for additional information.

•A $47 million increase in cash due to changes in risk management contract collateral positions.

These increases in cash were partially offset by:

•A $370 million decrease in cash from the Change in Certain Components of Working Capital. This decrease is primarily due to timing of accounts receivable collections and an increase in fuel, materials and supplies driven by higher coal inventory on hand, partially offset by the increase in customer deposits.

Investing Activities


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Construction Expenditures	$	(9,107)			$	(6,001)
Acquisitions of Generation Facilities	(2,394)			(1,657)
Acquisitions of Nuclear Fuel	(97)			(89)



Contribution in Aid of Construction Advances	572		148
Other	(145)			(150)
Net Cash Flows Used for Investing Activities	$	(11,171)			$	(7,749)

Net Cash Flows Used for Investing Activities increased by $3.4 billion primarily due to the following:

•A $3.1 billion increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $1.1 billion, Transmission and Distribution Utilities of $1 billion and AEP Transmission Holdco of $600 million.

•A $737 million increase primarily due to the acquisitions of five generation facilities in 2026. See “Acquisitions” section of Note 6 for additional information.

This increase was partially offset by:

•A $424 million decrease due to higher contributions in aid of construction primarily due to increases in Transmission and Distribution Utilities of $237 million and AEP Transmission Holdco of $185 million.

Financing Activities


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Issuance of Common Stock	$	417			$	187
Issuance/Retirement of Debt, Net	5,559			2,079


Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—			2,783
Dividends Paid on Common Stock	(1,558)			(1,498)
Security Deposits	1,199			—
Other	26			(72)
Net Cash Flows from Financing Activities	$	5,643			$	3,479

Net Cash Flows from Financing Activities increased by $2.2 billion primarily due to the following:

•A $1.7 billion increase due to changes in short-term debt.

•A $1.2 billion increase in security deposits primarily due to the collection of additional deposits under ERCOT’s Batch Zero process.

•A $970 million decrease in retirements of long-term debt. See Note 12 - Financing Activities for additional information.

•A $777 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $230 million increase in issuances of common stock primarily under AEP’s ATM Program. See Note 12 - Financing Activities for additional information.

These increases in cash were partially offset by:

•A $2.8 billion decrease due to proceeds from the 2025 Midwest Transmission Holdings Noncontrolling Interest transaction. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 6 for additional information.

See the “Financing Activities Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2026 through October 28, 2026, the date that the third quarter Form 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $15.6 billion of capital expenditures in 2026. For the five-year period, 2027 through 2031, management forecasts capital expenditures of $100.4 billion. Management’s forecasted capital expenditures reflect planned investments for transmission infrastructure and new generation resources to support existing customers and forecasted large load increases and continued improvements in distribution system reliability.

Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, technology advancements, inflation and the ability to access capital. Management has funded, or expects to fund, these capital expenditures through cash flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.

The 2027-2031 estimated capital expenditures by Business Segment are as follows:



Segment	2027-2031 Budgeted Capital Expenditures
	(in billions)
Vertically Integrated Utilities	$	52.2
Transmission and Distribution Utilities	23.6
AEP Transmission Holdco	18.1
Generation & Marketing	4.4
Corporate and Other	2.1
Total	$	100.4

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2025 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2025 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and asset retirement obligations.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards and SEC rulemaking activity.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a detailed discussion of AEP’s market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of AEP's Annual Report on Form 10-K for the year ended December 31, 2025. During the nine months ended September 30, 2026, there were no material changes to disclosures about market risk, inclusive of credit risk, value at risk associated with risk management contracts and interest rate risk. See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions, except per-share and share amounts)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,

	2026		2025		2026		2025
REVENUES
Vertically Integrated Utilities	$	3,923			$	3,511		$	10,338	$	9,531
Transmission and Distribution Utilities	1,853			1,680			5,015		4,638
Generation & Marketing	922			694			2,546		1,976
Other Revenues	134			126			398		416
TOTAL REVENUES	6,832			6,011			18,297		16,561

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	2,087			1,981			5,808		5,375

Other Operation	1,028			798			2,592		2,088
Maintenance	447			405			1,302		1,114


Asset Impairments and Other Related Charges	—			—			31		—


Depreciation and Amortization	1,025			879			2,842		2,566
Taxes Other Than Income Taxes	433			426			1,303		1,213
TOTAL EXPENSES	5,020			4,489			13,878		12,356

OPERATING INCOME	1,812			1,522			4,419		4,205

Other Income (Expense):


Other Income	6			12			26		35
Allowance for Equity Funds Used During Construction	81			59			226		173
Non-Service Cost Components of Net Periodic Benefit Cost	25			34			82		104

Interest Expense	(606)			(509)			(1,743)		(1,493)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	1,318			1,118			3,010		3,024

Income Tax Expense	125			139			221		13
Equity Earnings of Unconsolidated Subsidiaries	25			21			79		80





NET INCOME	1,218			1,000			2,868		3,091

Net Income Attributable to Noncontrolling Interests	31			28			94		93

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,187			$	972		$	2,774	$	2,998

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	544,431,979			534,867,357			543,566,814		534,186,206



TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2.18			$	1.82		$	5.10	$	5.61

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	550,103,235			537,988,799			549,270,434		536,364,715



TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2.16			$	1.81		$	5.05	$	5.59



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
Net Income	$	1,218			$	1,000		$	2,868	$	3,091

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $1 and $(4) for the Three Months Ended September 30, 2026 and 2025, Respectively, and $3 and $(7) for the Nine Months Ended September 30, 2026 and 2025, Respectively	5			(16)			12		(26)

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $1 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	1			—			3		1


TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	6			(16)			15		(25)

TOTAL COMPREHENSIVE INCOME	1,224			984			2,883		3,066

Total Comprehensive Income Attributable To Noncontrolling Interests	31			28			94		93

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,193			$	956		$	2,789	$	2,973

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	AEP Common Shareholders
	Common Stock				Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital	Retained Earnings			Noncontrolling Interests		Total
TOTAL EQUITY – DECEMBER 31, 2024	534		$	3,472		$	9,606			$	13,869			$	(3)		$	42	$	26,986

Issuance of Common Stock	1		7		68									75
Common Stock Dividends					(500)		(a)			(1)			(501)
Other Changes in Equity				(22)								(22)
Net Income					800					2			802
Other Comprehensive Income							24					24
TOTAL EQUITY – MARCH 31, 2025	535		3,479		9,652			14,169			21			43		27,364

Issuance of Common Stock	1		4		53									57
Common Stock Dividends					(499)		(a)			(1)			(500)
Other Changes in Equity				8								8

Midwest Transmission Holdings NCI Transaction				1,791						992			2,783
Net Income					1,226					63			1,289
Other Comprehensive Loss							(33)					(33)
TOTAL EQUITY – JUNE 30, 2025	536		3,483		11,504			14,896			(12)			1,097		30,968

Issuance of Common Stock	—		3		52									55
Capital Contributions from NCI									34			34
Common Stock Dividends					(499)		(a)					(499)
Dividends Paid to NCI									(69)			(69)
Other Changes in Equity				6								6

Net Income					972					28			1,000
Other Comprehensive Loss							(16)					(16)
TOTAL EQUITY – SEPTEMBER 30, 2025	536		$	3,486		$	11,562			$	15,369			$	(28)		$	1,090	$	31,479

TOTAL EQUITY – DECEMBER 31, 2025	542		$	3,523		$	12,138			$	15,441			$	36		$	1,080	$	32,218

Issuance of Common Stock	3		21		337									358
Capital Contributions from NCI									96			96
Common Stock Dividends					(520)		(a)					(520)
Dividends Paid to NCI									(35)			(35)
Other Changes in Equity				(28)								(28)

Net Income					874					29			903
Other Comprehensive Loss							(14)					(14)
TOTAL EQUITY – MARCH 31, 2026	545		3,544		12,447			15,795			22			1,170		32,978

Issuance of Common Stock	1		2		45									47
Capital Contributions from NCI									60			60
Common Stock Dividends					(519)		(a)					(519)
Dividends Paid to NCI									(54)			(54)
Other Changes in Equity				7								7

Net Income					713					34			747
Other Comprehensive Income							23					23
TOTAL EQUITY – JUNE 30, 2026	546		3,546		12,499			15,989			45			1,210		33,289

Issuance of Common Stock	—		1		11									12
Capital Contributions from NCI									113			113
Common Stock Dividends					(519)		(a)					(519)
Dividends Paid to NCI									(86)			(86)
Other Changes in Equity				10								10
Net Income					1,187					31			1,218
Other Comprehensive Income							6					6
TOTAL EQUITY – SEPTEMBER 30, 2026	546		$	3,547		$	12,520			$	16,657			$	51		$	1,268	$	34,043

(a) Cash dividends declared per AEP common share were $0.95 and $0.93 in 2026 and 2025, respectively.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	418			$	197
Restricted Cash (September 30, 2026 and December 31, 2025 Amounts Include $89 and $71, Respectively, Related to Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding and Cost Recovery Funding)	89			71
Other Temporary Investments (September 30, 2026 and December 31, 2025 Amounts Include $239 and $209, Respectively, Related to EIS)	252			220
Accounts Receivable:
Customers	1,421			1,166
Accrued Unbilled Revenues	422			421
Pledged Accounts Receivable – AEP Credit	1,600			1,272
Miscellaneous	101			60
Allowance for Credit Losses	(54)			(52)
Total Accounts Receivable	3,490			2,867
Fuel	506			576
Materials and Supplies	1,287			1,046
Risk Management Assets	588			352
Accrued Tax Benefits	344			85
Regulatory Asset for Under-Recovered Fuel Costs	504			426


Prepayments and Other Current Assets	362			212
TOTAL CURRENT ASSETS	7,840			6,052

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	27,674			28,388
Transmission	44,509			42,557
Distribution	35,251			33,364
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	9,843			8,635
Construction Work in Progress	10,907			7,635
Total Property, Plant and Equipment	128,184			120,579
Accumulated Depreciation and Amortization	27,956			28,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	100,228			92,374

OTHER NONCURRENT ASSETS
Regulatory Assets	4,967			4,804
Securitized Assets	2,221			933
Spent Nuclear Fuel and Decommissioning Trusts	5,256			4,916
Goodwill	53			53
Long-term Risk Management Assets	266			265
Operating Lease Assets	660			661
Deferred Charges and Other Noncurrent Assets	4,204			4,402
TOTAL OTHER NONCURRENT ASSETS	17,627			16,034

TOTAL ASSETS	$	125,695			$	114,460

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

September 30, 2026 and December 31, 2025

(in millions, except per-share and share amounts)

(Unaudited)


					September 30,		December 31,
					2026		2025
CURRENT LIABILITIES
Accounts Payable					$	3,944			$	3,429
Short-term Debt:
Securitized Debt for Receivables – AEP Credit					900			900
Other Short-term Debt					975			608
Total Short-term Debt					1,875			1,508
Long-term Debt Due Within One Year (September 30, 2026 and December 31, 2025 Amounts Include $201 and $207, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)		2,677		3,194
Risk Management Liabilities					209			132
Customer Deposits					770			507
Accrued Taxes					1,363			2,002
Accrued Interest					719			544
Obligations Under Operating Leases					95			100


Other Current Liabilities					3,634			1,898
TOTAL CURRENT LIABILITIES					15,286			13,314

NONCURRENT LIABILITIES
Long-term Debt (September 30, 2026 and December 31, 2025 Amounts Include $2,519 and $1,294, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)		49,864		44,128
Long-term Risk Management Liabilities					214			178
Deferred Income Taxes					11,721			10,951
Regulatory Liabilities and Deferred Investment Tax Credits		8,748		8,362
Asset Retirement Obligations					3,669			3,556
Employee Benefits and Pension Obligations					262			232
Obligations Under Operating Leases					584			578
Deferred Credits and Other Noncurrent Liabilities		1,228		905
TOTAL NONCURRENT LIABILITIES					76,290			68,890

TOTAL LIABILITIES					91,576			82,204

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)


Contingently Redeemable Performance Share Awards					76			38

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2026		2025
Shares Authorized	900,000,000		600,000,000
Shares Issued	545,692,925		542,048,288
(1,186,815 Shares were Held in Treasury as of September 30, 2026 and December 31, 2025, Respectively)		3,547		3,523
Paid-in Capital					12,520			12,138
Retained Earnings					16,657			15,441
Accumulated Other Comprehensive Income (Loss)		51		36
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY		32,775		31,138

Noncontrolling Interests					1,268			1,080

TOTAL EQUITY					34,043			32,218

TOTAL LIABILITIES AND EQUITY	$	125,695		$	114,460

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	2,868			$	3,091


Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	2,842			2,566

Deferred Income Taxes	515			124


Asset Impairments and Other Related Charges	31			—

Allowance for Equity Funds Used During Construction	(226)			(173)
Mark-to-Market of Risk Management Contracts	(116)			(193)

Pension Contributions to Qualified Plan Trust	—			(95)
Property Taxes	564			541

Deferred Fuel Over/Under-Recovery, Net	133			165




Change in Other Noncurrent Assets	(838)			(720)
Change in Other Noncurrent Liabilities	673			134
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(528)			(212)
Fuel, Materials and Supplies	(162)			151
Accounts Payable	603			327
Accrued Taxes, Net	(899)			(687)

Other Current Assets	(81)			38
Other Current Liabilities	388			74
Net Cash Flows from Operating Activities	5,767			5,131

INVESTING ACTIVITIES
Construction Expenditures	(9,107)			(6,001)

Purchases of Investment Securities	(2,530)			(2,407)
Sales of Investment Securities	2,443			2,349
Acquisitions of Generation Facilities	(2,394)			(1,657)
Acquisitions of Nuclear Fuel	(97)			(89)




Contribution in Aid of Construction Advances	572			148
Other Investing Activities	(58)			(92)
Net Cash Flows Used for Investing Activities	(11,171)			(7,749)

FINANCING ACTIVITIES
Capital Contribution from Noncontrolling Interest	269			34
Issuance of Common Stock	417			187
Issuance of Long-term Debt	7,026			6,249
Issuance of Short-term Debt with Original Maturities greater than 90 Days	—			320
Change in Short-term Debt with Original Maturities less than 90 Days, Net	367			(1,008)
Retirement of Long-term Debt	(1,834)			(2,804)

Redemption of Short-term Debt with Original Maturities Greater than 90 Days	—			(678)

Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—			2,783
Dividends Paid on Common Stock	(1,558)			(1,498)
Dividends Paid to Noncontrolling Interest	(175)			(71)

Security Deposits	1,199			—
Other Financing Activities	(68)			(35)
Net Cash Flows from Financing Activities	5,643			3,479





Net Increase in Cash, Cash Equivalents and Restricted Cash	239			861
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	268			246
Cash, Cash Equivalents and Restricted Cash at End of Period	$	507			$	1,107










See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	4,608		4,135		10,306	10,326
Commercial	5,684		5,219		15,452	14,037
Industrial	4,477		3,489		12,348	10,159
Miscellaneous	195		186		481	477
Total Retail (a)	14,964		13,029		38,587	34,999

(a)Represents energy delivered to distribution customers.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Actual – Heating	—		—		144	296
Normal – Heating	—		—		215	208

Actual – Cooling	1,611		1,367		2,735	2,520
Normal – Cooling	1,347		1,348		2,382	2,369


AEP Texas Inc. and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	166			$	389

Changes in Revenues:
Retail Revenues	38			31

Transmission Revenues	7			40
Other Revenues	(5)			10
Total Change in Revenues	40			81

Changes in Expenses and Other:
Other Operation and Maintenance	(24)			(46)
Depreciation and Amortization	(10)			(19)
Taxes Other Than Income Taxes	(3)			(3)

Interest Income	4			4

Allowance for Equity Funds Used During Construction	10			25
Non-Service Cost Components of Net Periodic Benefit Cost	—			1
Interest Expense	(13)			(23)
Total Change in Expenses and Other	(36)			(61)

Income Tax Expense	2			(4)

2026 Net Income	$	172			$	405

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $38 million primarily due to the following:

•A $27 million increase in rider revenues.

•A $14 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

•Transmission Revenues increased $7 million primarily due to continued transmission investment.

•Other Revenues decreased $5 million primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $24 million primarily due to the following:

•A $14 million increase in transmission and distribution expenses.

•A $7 million increase due to recoverable Transmission Cost Recovery Factor expenses.

•Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to a higher AFUDC base.

•Interest Expense increased $13 million primarily due to the following:

•A $14 million increase due to higher long-term debt balances.

•A $10 million increase due to interest on customer deposits from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $6 million decrease due to an increase in the debt component of AFUDC.

•A $5 million decrease due to the deferral of eligible costs related to the UTM.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $31 million primarily due to the following:

•A $34 million increase in rider revenues.

•A $13 million increase in weather-normalized revenues primarily in the residential and commercial classes.

These increases were partially offset by:

•A $7 million decrease due to Transition Funding customer refunds.

•A $6 million decrease in weather-related usage due to less extreme weather conditions in the first six months of 2026 compared to the same period in 2025.

•Transmission Revenues increased $40 million primarily due to continued transmission investment.

•Other Revenues increased $10 million primarily due to the following:

• A $16 million increase in the taxable portion of payments received from customers for large interconnection projects.

This increase was partially offset by:

•A $7 million decrease primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $46 million primarily due to the following:

•An $18 million increase due to the partial disallowance of regulatory assets associated with the UTM deferrals.

•A $14 million increase in transmission and distribution expenses.

•A $13 million increase in administrative and general expenses primarily due to employee-related expenses.

•Depreciation and Amortization expenses increased $19 million primarily due to the following:

•A $27 million increase due to a higher depreciable base.

This increase was partially offset by:

•A $5 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds.

•A $4 million decrease due to the deferral of eligible costs related to the UTM.

•Allowance for Equity Funds Used During Construction increased $25 million primarily due to a higher AFUDC base.

•Interest Expense increased $23 million primarily due to the following:

•A $38 million increase due to higher long-term debt balances.

•A $10 million increase due to interest on customer deposits from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $15 million decrease due to an increase in the debt component of AFUDC.

•An $11 million decrease due to the deferral of eligible costs related to the UTM.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended September 30,		Nine Months Ended September 30,
	2026		2025		2026		2025
REVENUES
Electric Transmission and Distribution	$	655			$	616		$	1,728	$	1,664
Sales to AEP Affiliates	2			1			5		4
Other Revenues	2			2			21		5
TOTAL REVENUES	659			619			1,754		1,673

EXPENSES

Other Operation	207			187			563		517
Maintenance	28			24			79		79
Depreciation and Amortization	123			113			348		329
Taxes Other Than Income Taxes	49			46			134		131
TOTAL EXPENSES	407			370			1,124		1,056

OPERATING INCOME	252			249			630		617

Other Income (Expense):
Interest Income	4			—			5		1

Allowance for Equity Funds Used During Construction	23			13			62		37

Non-Service Cost Components of Net Periodic Benefit Cost	6			6			18		17
Interest Expense	(79)			(66)			(223)		(200)

INCOME BEFORE INCOME TAX EXPENSE	206			202			492		472

Income Tax Expense	34			36			87		83

NET INCOME	$	172			$	166		$	405	$	389

The common stock of AEP Texas is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026		2025		2026		2025
Net Income	$	172			$	166		$	405	$	389

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	(1)			—			(1)		(1)




TOTAL COMPREHENSIVE INCOME	$	171			$	166		$	404	$	388

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	2,093			$	2,795			$	(3)	$	4,885



Net Income			102					102
Other Comprehensive Loss					(1)			(1)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	2,093			2,897			(4)			4,986

Capital Contribution from Parent	250							250

Net Income			121					121

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	2,343			3,018			(4)			5,357

Capital Contribution from Parent	201							201


Net Income			166					166

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025	$	2,544			$	3,184			$	(4)	$	5,724

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	2,546			$	3,283			$	(3)	$	5,826


Net Income			120					120

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026	2,546			3,403			(3)			5,946

Capital Contribution from Parent	1							1

Net Income			113					113

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026	2,547			3,516			(3)			6,060


Return of Capital to Parent	(1)							(1)

Net Income			172					172
Other Comprehensive Loss					(1)			(1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2026	$	2,546			$	3,688			$	(4)	$	6,230

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS

Restricted Cash (September 30, 2026 and December 31, 2025 Amounts Include $9 and $14, Respectively, Related to Restoration Funding)	$	9			$	14
Advances to Affiliates	389			7
Accounts Receivable:
Customers	298			189
Affiliated Companies	14			15
Accrued Unbilled Revenues	130			101
Miscellaneous	1			—

Total Accounts Receivable	443			305

Materials and Supplies	240			168



Prepayments and Other Current Assets	27			15
TOTAL CURRENT ASSETS	1,108			509

PROPERTY, PLANT AND EQUIPMENT
Electric:

Transmission	8,584			8,229
Distribution	7,382			6,835
Other Property, Plant and Equipment	1,305			1,239
Construction Work in Progress	2,577			1,766
Total Property, Plant and Equipment	19,848			18,069
Accumulated Depreciation and Amortization	2,294			2,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	17,554			15,864

OTHER NONCURRENT ASSETS
Regulatory Assets	470			402
Securitized Assets (September 30, 2026 and December 31, 2025 Amounts Include $76 and $94, Respectively, Related to Restoration Funding)	76			94

Operating Lease Assets	47			52
Deferred Charges and Other Noncurrent Assets	203			154
TOTAL OTHER NONCURRENT ASSETS	796			702

TOTAL ASSETS	$	19,458			$	17,075

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	—			$	188
Accounts Payable:
General	630			652
Affiliated Companies	45			60

Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $26 and $25, Respectively, Related to Restoration Funding)	26			75


Accrued Taxes	154			118
Accrued Interest	136			64
Security Deposits	1,151			87
Contribution in Aid of Construction Advances	247			67

Obligations Under Operating Leases	13			14


Other Current Liabilities	93			93
TOTAL CURRENT LIABILITIES	2,495			1,418

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $52 and $78, Respectively, Related to Restoration Funding)	7,660			6,941

Deferred Income Taxes	1,560			1,430
Regulatory Liabilities and Deferred Investment Tax Credits	1,257			1,286

Obligations Under Operating Leases	36			40
Deferred Credits and Other Noncurrent Liabilities	220			134
TOTAL NONCURRENT LIABILITIES	10,733			9,831

TOTAL LIABILITIES	13,228			11,249

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	2,546			2,546
Retained Earnings	3,688			3,283
Accumulated Other Comprehensive Income (Loss)	(4)			(3)
TOTAL COMMON SHAREHOLDER’S EQUITY	6,230			5,826

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	19,458			$	17,075

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	405			$	389
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	348			329
Deferred Income Taxes	105			68
Allowance for Equity Funds Used During Construction	(62)			(37)

Pension Contributions to Qualified Plan Trust	—			(12)



Change in Other Noncurrent Assets	(164)			(116)
Change in Other Noncurrent Liabilities	62			49
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(117)			(77)
Materials and Supplies	(72)			20
Accounts Payable	66			39

Accrued Taxes, Net	36			16
Accrued Interest	72			47

Other Current Assets	(11)			—
Other Current Liabilities	(39)			(20)
Net Cash Flows from Operating Activities	629			695

INVESTING ACTIVITIES
Construction Expenditures	(2,133)			(1,332)
Change in Advances to Affiliates, Net	(382)			(418)

Contribution in Aid of Construction Advances	283			56
Other Investing Activities	(2)			—
Net Cash Flows Used for Investing Activities	(2,234)			(1,694)

FINANCING ACTIVITIES
Capital Contribution from Parent	1			451
Return of Capital to Parent	(1)			—
Issuance of Long-term Debt – Nonaffiliated	741			1,294

Change in Advances from Affiliates, Net	(188)			(285)
Retirement of Long-term Debt – Nonaffiliated	(75)			(475)


Security Deposits	1,127			—
Other Financing Activities	(5)			(3)
Net Cash Flows from Financing Activities	1,600			982

Net Decrease in Cash, Cash Equivalents and Restricted Cash	(5)			(17)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	14			24
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9			$	7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	163			$	143


Construction Expenditures Included in Current Liabilities as of September 30,	404			259
Contributions in Aid of Construction Advances Included in Current Assets as of September 30,	21			—

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo


	As of September 30,
	2026		2025
	(in millions)
Plant In Service	$	18,078			$	16,471
Construction Work in Progress	2,791			2,098
Accumulated Depreciation and Amortization	2,165			1,840
Total Transmission Property, Net	$	18,704			$	16,729


AEP Transmission Company, LLC and Subsidiaries

Reconciliation of 2025 to 2026

Earnings Attributable to AEP Member
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Member	$	179			$	946

Changes in Transmission Revenues:
Transmission Revenues	36			(67)
Total Change in Transmission Revenues	36			(67)

Changes in Expenses and Other:
Other Operation and Maintenance	(9)			(37)
Depreciation and Amortization	(12)			(35)
Taxes Other Than Income Taxes	10			(14)
Interest Income	2			4
Allowance for Equity Funds Used During Construction	5			10
Interest Expense	(6)			(23)
Total Change in Expenses and Other	(10)			(95)

Income Tax Expense	(5)			(212)

Net Income Attributable to Noncontrolling Interest	(4)			(1)

2026 Earnings Attributable to AEP Member	$	196			$	571

Third Quarter of 2026 Compared to Third Quarter of 2025

The major component of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:

•Transmission Revenues increased $36 million primarily due to continued transmission investment.

Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $9 million primarily due to the following:

•A $7 million increase in employee-related costs.

•A $2 million increase in affiliated rent and shared services.

•A $2 million increase in vegetation management and facility compliance costs.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes decreased $10 million primarily due to prior period adjustments in Ohio, partially offset by higher property taxes associated with increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher CWIP base.

•Interest Expense increased $6 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $5 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the decrease in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:

•Transmission Revenues decreased $67 million primarily due to the following:

•A $214 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This decrease was partially offset by:

•A $147 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows:

•Operation and Maintenance expenses increased $37 million primarily due to the following:

•A $16 million increase in employee-related costs.

•A $12 million increase in vegetation management and facility compliance costs.

•A $7 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $35 million due to a higher depreciable base.

•Taxes Other than Income Taxes increased $14 million primarily due to higher property taxes associated with increased transmission investment, partially offset by prior period adjustments in Ohio.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to a higher CWIP base and higher equity rates.

•Interest Expense increased $23 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $212 million primarily due to the following:

•A $254 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This increase was partially offset by:

•A $34 million decrease due to a decrease in pretax book income.

•A $5 million decrease due to a decrease in state taxes.

•Net Income Attributable to Noncontrolling Interest increased $1 million primarily due to the following:

•A $55 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

This increase was partially offset by:

•A $54 million decrease due to higher 2025 earnings for Midwest Transmission Holdings due to the impact of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
REVENUES
Transmission Revenues	$	115			$	108		$	335	$	325
Sales to AEP Affiliates	501			450			1,448		1,350
(Provision for)/Reversal of - Revenue Refund – Affiliated	(21)			—			(26)		120
(Provision for)/Reversal of - Revenue Refund – Nonaffiliated	(3)			—			(6)		32
Other Revenues	2			—			9		—
TOTAL REVENUES	594			558			1,760		1,827

EXPENSES
Other Operation	49			41			135		106
Maintenance	11			10			29		21
Depreciation and Amortization	133			121			389		354
Taxes Other Than Income Taxes	76			86			250		236
TOTAL EXPENSES	269			258			803		717

OPERATING INCOME	325			300			957		1,110

Other Income (Expense):
Interest Income – Affiliated	3			1			7		3
Allowance for Equity Funds Used During Construction	27			22			75		65

Interest Expense	(67)			(61)			(196)		(173)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	288			262			843		1,005

Income Tax Expense (Benefit)	62			57			184		(28)


NET INCOME	226			205			659		1,033

Net Income Attributable to Noncontrolling Interest	30			26			88		87

EARNINGS ATTRIBUTABLE TO AEP MEMBER	$	196			$	179		$	571	$	946

AEPTCo is wholly-owned by AEP Transmission Holdco.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Noncontrolling Interest		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024	$	3,101			$	3,850			$	—	$	6,951

Capital Contribution from AEP Member	32							32
Dividends Paid to AEP Member			(42)					(42)
Net Income			211					211
TOTAL MEMBER'S EQUITY – MARCH 31, 2025	3,133			4,019			—			7,152

Capital Contribution from AEP Member	8							8

Dividends Paid to AEP Member			(2,836)					(2,836)
Midwest Transmission Holdings Noncontrolling Interest Transaction	1,791					992			2,783
Net Income			556			61			617
TOTAL MEMBER'S EQUITY – JUNE 30, 2025	4,932			1,739			1,053			7,724

Capital Contribution from AEP Member	2							2
Capital Contribution from Noncontrolling Interest					34			34
Dividends Paid to AEP Member			(184)					(184)
Dividends Paid to Noncontrolling Interest					(68)			(68)
Net Income			179			26			205
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2025	$	4,934			$	1,734			$	1,045	$	7,713

TOTAL MEMBER'S EQUITY – DECEMBER 31, 2025	$	4,962			$	1,651			$	1,030	$	7,643

Capital Contribution from AEP Member	233							233

Capital Contribution from Noncontrolling Interest					96			96

Dividends Paid to Noncontrolling Interest					(33)			(33)
Net Income			183			27			210
TOTAL MEMBER'S EQUITY – MARCH 31, 2026	5,195			1,834			1,120			8,149

Capital Contribution from AEP Member	16							16

Capital Contribution from Noncontrolling Interest					31			31
Dividends Paid to AEP Member			(141)					(141)
Dividends Paid to Noncontrolling Interest					(54)			(54)
Net Income			192			31			223
TOTAL MEMBER'S EQUITY – JUNE 30, 2026	5,211			1,885			1,128			8,224

Capital Contribution from AEP Member	137							137

Capital Contribution from Noncontrolling Interest					113			113

Dividends Paid to Noncontrolling Interest					(81)			(81)
Net Income			196			30			226
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2026	$	5,348			$	2,081			$	1,190	$	8,619

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Advances to Affiliates	$	193			$	71
Accounts Receivable:
Customers	127			94
Affiliated Companies	161			153

Total Accounts Receivable	288			247



Prepayments and Other Current Assets	20			4
TOTAL CURRENT ASSETS	501			322

TRANSMISSION PROPERTY
Transmission Property	17,481			16,542
Other Property, Plant and Equipment	597			571
Construction Work in Progress	2,791			2,005
Total Transmission Property	20,869			19,118
Accumulated Depreciation and Amortization	2,165			1,915
TOTAL TRANSMISSION PROPERTY – NET	18,704			17,203

OTHER NONCURRENT ASSETS

Regulatory Assets	87			73
Deferred Property Taxes	100			326
Deferred Charges and Other Noncurrent Assets	77			75
TOTAL OTHER NONCURRENT ASSETS	264			474

TOTAL ASSETS	$	19,469			$	17,999

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	269			$	143
Accounts Payable:
General	500			477
Affiliated Companies	166			164

Long-term Debt Due Within One Year – Nonaffiliated	425			425
Accrued Taxes	374			650
Accrued Interest	84			46
Contribution in Aid of Construction Advances	211			32
Obligations Under Operating Leases	1			1

Other Current Liabilities	15			9
TOTAL CURRENT LIABILITIES	2,045			1,947

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,412			6,174
Deferred Income Taxes	1,548			1,481
Regulatory Liabilities	815			708
Obligations Under Operating Leases	1			2
Deferred Credits and Other Noncurrent Liabilities	29			44
TOTAL NONCURRENT LIABILITIES	8,805			8,409

TOTAL LIABILITIES	10,850			10,356

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

MEMBER’S EQUITY
Paid-in Capital	5,348			4,962
Retained Earnings	2,081			1,651
TOTAL MEMBER’S EQUITY	7,429			6,613

Noncontrolling Interest	1,190			1,030

TOTAL EQUITY	8,619			7,643

TOTAL LIABILITIES AND EQUITY	$	19,469			$	17,999

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	659			$	1,033
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	389			354
Deferred Income Taxes	52			(145)
Allowance for Equity Funds Used During Construction	(75)			(65)
Property Taxes	226			213

Change in Other Noncurrent Assets	(19)			(61)
Change in Other Noncurrent Liabilities	(14)			(151)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(13)			(3)

Accounts Payable	26			18
Accrued Taxes, Net	(276)			(265)

Other Current Assets	(15)			6
Other Current Liabilities	44			4
Net Cash Flows from Operating Activities	984			938

INVESTING ACTIVITIES
Construction Expenditures	(1,740)			(1,145)
Change in Advances to Affiliates, Net	(122)			(37)


Contribution in Aid of Construction Advances	204			19
Other Investing Activities	(5)			2
Net Cash Flows Used for Investing Activities	(1,663)			(1,161)

FINANCING ACTIVITIES
Capital Contribution from AEP Member	386			42
Capital Contribution from Noncontrolling Interest	240			34

Issuance of Long-term Debt – Nonaffiliated	859			560
Retirement of Long-term Debt – Nonaffiliated	(623)			(90)

Change in Advances from Affiliates, Net	126			24
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—			2,783
Dividends Paid to AEP Member	(141)			(3,062)
Dividends Paid to Noncontrolling Interest	(168)			(68)

Net Cash Flows from Financing Activities	679			223

Net Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	—			—
Cash and Cash Equivalents at End of Period	$	—			$	—

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	154			$	140

Construction Expenditures Included in Current Liabilities as of September 30,	342			223


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	2,613		2,516		8,210	8,202
Commercial	1,595		1,530		4,536	4,495
Industrial	2,105		2,117		6,278	6,397
Miscellaneous	211		202		621	621
Total Retail	6,524		6,365		19,645	19,715

Wholesale (a)	1,133		966		2,118	2,269

Total KWhs	7,657		7,331		21,763	21,984

(a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Actual – Heating	—		—		1,382	1,433
Normal – Heating	1		1		1,361	1,360

Actual – Cooling	932		748		1,386	1,176
Normal – Cooling	812		818		1,212	1,211


Appalachian Power Company and Subsidiaries
Reconciliation of 2025 to 2026

Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	81			$	353

Changes in Revenues:
Retail Revenues	53			(3)
Off-system Sales	7			9
Transmission Revenues	10			32
Other Revenues	6			1
Total Change in Revenues	76			39

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	24			81
Other Operation and Maintenance	(32)			(60)


Depreciation and Amortization	(28)			(26)
Taxes Other Than Income Taxes	(1)			(14)
Interest Income	1			—

Allowance for Equity Funds Used During Construction	—			(2)
Non-Service Cost Components of Net Periodic Benefit Cost	(1)			(4)
Interest Expense	(21)			(38)
Total Change in Expenses and Other	(58)			(63)

Income Tax Expense	25			40

2026 Net Income	$	124			$	369

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $53 million primarily due to the following:

•A $53 million increase in base rate and rider revenues.

•A $21 million increase in weather-related usage due to a 25% increase in cooling degree days.

These increases were partially offset by:

•A $13 million decrease in fuel revenues.

•Off-system Sales increased $7 million primarily due to margins in July 2026 attributable to increased PJM prices.

•Transmission Revenues increased $10 million primarily due to continued transmission investment.

•Other Revenues increased $6 million due to an increase in sales of renewable energy credits.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $24 million primarily due to the following:

•A $40 million increase in Virginia FAC and West Virginia ENEC under-recoveries due to decreases in fuel revenues.

•A $39 million increase in West Virginia ENEC under-recoveries due to WVPSC orders for final recovery of West Virginia MRBC, Broadband and Vegetation Management under-recovery balances through ENEC rates.

These decreases were partially offset by:

•A $34 million decrease in Virginia FAC and West Virginia ENEC under-recoveries due to increased PJM revenues as a result of the performance of APCo’s generation during periods of high prices in July 2026.

•A $9 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting in March 2026.

•A $4 million increase in Virginia renewable compliance expense.

•A $3 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.

•Other Operation and Maintenance expenses increased $32 million primarily due to the following:

•An $8 million increase in employee-related costs.

•A $7 million increase in distribution expenses primarily due to vegetation management costs and storm restoration costs.

•A $6 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $5 million increase in steam generation expenses primarily due to increased plant maintenance.

•A $4 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

•Depreciation and Amortization expenses increased $28 million primarily due to a July 2026 order approving a final true-up to recover past West Virginia MRBC costs.

•Interest Expense increased $21 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $25 million primarily due to the following:

•A $12 million decrease due to an increase in flow-through benefits.

•A $7 million decrease due to a decrease in flow-through CAMT expense.

•A $4 million decrease due to an increase in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues decreased $3 million primarily due to the following:

•A $114 million decrease in fuel revenues.

•A $21 million decrease in weather-normalized revenues primarily in the residential class.

These decreases were partially offset by:

•A $110 million increase in base rate and rider revenues.

•A $15 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

•Off-system Sales increased $9 million primarily due to margins in July 2026 attributable to increased PJM prices.

•Transmission Revenues increased $32 million primarily due to the following:

•A $37 million increase due to continued transmission investment.

This increase was partially offset by:

•A $6 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $81 million primarily due to the following:

•A $152 million increase in Virginia FAC and West Virginia ENEC under-recoveries due to decreases in fuel revenues.

These decreases were partially offset by:

•A $57 million decrease in Virginia FAC and West Virginia ENEC under-recoveries due to increased PJM revenues as a result of the performance of APCo’s generation during periods of high prices in July 2026.

•A $21 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting March 2026.

•A $14 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.

•A $14 million decrease in West Virginia ENEC under-recovery as a result of the June 2025 FERC NOLC order.

•A $12 million increase in Virginia renewable compliance expense.

•Other Operation and Maintenance expenses increased $60 million primarily due to the following:

•A $33 million increase in distribution expenses primarily due to vegetation management costs and storm restoration costs.

•A $17 million increase in employee-related costs.

•A $15 million increase in steam generation expenses primarily due to increased plant maintenance.

•An $8 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

These increases were partially offset by:

•A $23 million gain from the sale of a non-utility investment in land.

•Depreciation and Amortization expenses increased $26 million primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•Taxes Other Than Income Taxes increased $14 million primarily due to the following:

•A $7 million increase due to higher business and occupation taxes.

•A $5 million increase in property taxes.

•Interest Expense increased $38 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $40 million primarily due to the following:

•A $25 million decrease due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $18 million decrease due to an increase in PTCs.

•A $7 million decrease due to a decrease in state taxes.

•A $6 million decrease due to an increase in amortization of Excess ADIT.

•A $5 million decrease due to a decrease in pretax book income.

These decreases were partially offset by:

•A $23 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	1,047			$	981		$	2,951	$	2,955
Sales to AEP Affiliates	81			71			254		209
Other Revenues	5			5			11		13
TOTAL REVENUES	1,133			1,057			3,216		3,177

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	350			374			991		1,072



Other Operation	226			206			646		639
Maintenance	117			105			320		267


Depreciation and Amortization	180			152			512		486
Taxes Other Than Income Taxes	47			46			139		125
TOTAL EXPENSES	920			883			2,608		2,589

OPERATING INCOME	213			174			608		588

Other Income (Expense):
Interest Income	1			—			3		3

Allowance for Equity Funds Used During Construction	4			4			11		13
Non-Service Cost Components of Net Periodic Benefit Cost	4			5			12		16
Interest Expense	(91)			(70)			(246)		(208)

INCOME BEFORE INCOME TAX EXPENSE	131			113			388		412

Income Tax Expense	7			32			19		59

NET INCOME	$	124			$	81		$	369	$	353

The common stock of APCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
Net Income	$	124			$	81		$	369	$	353

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—			—			(1)		(1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—			—			—		—

TOTAL OTHER COMPREHENSIVE LOSS	—			—			(1)		(1)

TOTAL COMPREHENSIVE INCOME	$	124			$	81		$	368	$	352

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)	Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2024	$	260			$	1,945		$	3,532	$	11	$	5,748


Common Stock Dividends					(50)				(50)
Net Income					165				165

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	260			1,945			3,647		11	5,863

Capital Contribution from Parent			7						7

Net Income					107				107
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	260			1,952			3,754		10	5,976

Capital Contribution from Parent			1						1

Net Income					81				81

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025	$	260			$	1,953		$	3,835	$	10	$	6,058

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2025	$	260			$	1,957		$	3,939	$	24	$	6,180

Capital Contribution from Parent			81					81

Net Income					195				195

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026	260			2,038			4,134		24	6,456


Common Stock Dividends					(700)				(700)
Net Income					50				50
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026	260			2,038			3,484		23	5,805




Net Income					124				124

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2026	$	260			$	2,038		$	3,608	$	23	$	5,929

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	4			$	5
Restricted Cash for Securitized Funding (September 30, 2026 and December 31, 2025 Amounts Include $60 and $18, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	60			18
Advances to Affiliates	45			17
Accounts Receivable:
Customers	184			171
Affiliated Companies	176			142
Accrued Unbilled Revenues	57			112

Allowance for Credit Losses	(2)			(2)
Total Accounts Receivable	415			423
Fuel	191			229
Materials and Supplies	171			139
Risk Management Assets	188			81

Regulatory Asset for Under-Recovered Fuel Costs	160			83

Prepayments and Other Current Assets	92			38
TOTAL CURRENT ASSETS	1,326			1,033

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,724			7,886
Transmission	5,431			5,277
Distribution	6,119			5,938
Other Property, Plant and Equipment	1,254			1,175
Construction Work in Progress	851			802
Total Property, Plant and Equipment	19,379			21,078
Accumulated Depreciation and Amortization	5,195			6,365
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	14,184			14,713

OTHER NONCURRENT ASSETS
Regulatory Assets	1,378			1,439
Securitized Assets (September 30, 2026 and December 31, 2025 Amounts Include $1,406 and $78, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	1,406			78
Employee Benefits and Pension Assets	260			251

Operating Lease Assets	101			95
Deferred Charges and Other Noncurrent Assets	177			183
TOTAL OTHER NONCURRENT ASSETS	3,322			2,046

TOTAL ASSETS	$	18,832			$	17,792

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(Unaudited)


	September 30,		December 31,
	2026		2025
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	—			$	209
Accounts Payable:
General	493			375
Affiliated Companies	158			173
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $66 and $30, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	1,316			1,131


Customer Deposits	98			94

Accrued Taxes	89			116

Obligations Under Operating Leases	16			15

Other Current Liabilities	370			271
TOTAL CURRENT LIABILITIES	2,540			2,384

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $1,361 and $62, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	6,106			5,128



Deferred Income Taxes	2,268			2,130
Regulatory Liabilities and Deferred Investment Tax Credits	1,092			1,111
Asset Retirement Obligations	744			707
Employee Benefits and Pension Obligations	26			26
Obligations Under Operating Leases	87			81
Deferred Credits and Other Noncurrent Liabilities	40			45
TOTAL NONCURRENT LIABILITIES	10,363			9,228

TOTAL LIABILITIES	12,903			11,612

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260			260
Paid-in Capital	2,038			1,957
Retained Earnings	3,608			3,939
Accumulated Other Comprehensive Income (Loss)	23			24
TOTAL COMMON SHAREHOLDER’S EQUITY	5,929			6,180

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	18,832			$	17,792

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	369			$	353
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	512			486
Deferred Income Taxes	77			25



Allowance for Equity Funds Used During Construction	(11)			(13)
Mark-to-Market of Risk Management Contracts	(91)			(57)


Deferred Fuel Over/Under-Recovery, Net	(64)			68

Change in Regulatory Assets	(95)			(153)
Change in Other Noncurrent Assets	(26)			33
Change in Other Noncurrent Liabilities	18			25
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	8			29
Fuel, Materials and Supplies	6			37

Accounts Payable	113			29
Accrued Taxes, Net	(38)			(80)
Other Current Assets	(37)			15
Other Current Liabilities	71			12
Net Cash Flows from Operating Activities	812			809

INVESTING ACTIVITIES
Construction Expenditures	(761)			(749)

Change in Advances to Affiliates, Net	(28)			(32)
Acquisitions of Assets	(352)			—

Other Investing Activities	42			13
Net Cash Flows Used for Investing Activities	(1,099)			(768)

FINANCING ACTIVITIES
Capital Contribution from Parent	81			8

Issuance of Long-term Debt – Nonaffiliated	1,364			593
Change in Advances from Affiliates, Net	(209)			(95)
Retirement of Long-term Debt – Nonaffiliated	(206)			(498)


Principal Payments for Finance Lease Obligations	(4)			(6)
Dividends Paid on Common Stock	(700)			(50)
Other Financing Activities	2			2
Net Cash Flows from (Used for) Financing Activities	328			(46)

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	41			(5)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	23			20
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	64			$	15

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	191			$	172


Noncash Acquisitions Under Finance Leases	4			3
Construction Expenditures Included in Current Liabilities as of September 30,	126			129

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	1,553		1,568		4,163	4,218
Commercial	2,699		1,866		7,221	4,552
Industrial	1,852		1,825		5,391	5,429
Miscellaneous	10		10		32	32
Total Retail	6,114		5,269		16,807	14,231

Wholesale (a)	1,874		1,423		5,425	5,366

Total KWhs	7,988		6,692		22,232	19,597

(a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Actual – Heating	—		—		2,233	2,335
Normal – Heating	6		6		2,363	2,371

Actual – Cooling	635		622		858	902
Normal – Cooling	581		582		866	867


Indiana Michigan Power Company and Subsidiaries

Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	150			$	332

Changes in Revenues:
Retail Revenues	78			327
Off-system Sales	(2)			42
Transmission Revenues	1			(12)
Other Revenues	5			(2)
Total Change in Revenues	82			355

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(4)			(80)
Purchased Electricity from AEP Affiliates	(21)			(14)
Other Operation and Maintenance	(60)			(110)

Depreciation and Amortization	(9)			(25)
Taxes Other Than Income Taxes	—			(2)
Other Income	2			9

Non-Service Cost Components of Net Periodic Benefit Cost	(2)			(5)
Interest Expense	(8)			(26)
Total Change in Expenses and Other	(102)			(253)

Income Tax Expense	(17)			(76)

2026 Net Income	$	113			$	358

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $78 million primarily due to the following:

•A $69 million increase in weather-normalized revenues primarily in the commercial class.

•A $26 million increase in fuel revenues.

These increases were partially offset by:

•A $24 million decrease in rider revenues.

•Other Revenues increased $5 million primarily due to an increase in River Transportation Division barging revenues.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity from AEP Affiliates expenses increased $21 million primarily due to an increase in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $60 million primarily due to the following:

•A $17 million increase in distribution expenses primarily due to an increase in storm restoration costs and vegetation management costs.

•A $12 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $10 million increase in steam generation expenses primarily due to the acquisition of generation facilities.

•A $10 million increase in employee-related costs.

•Depreciation and Amortization increased $9 million primarily due to the following:

•A $10 million increase due to a higher depreciable base.

•A $3 million increase due to the acquisition of generation facilities.

These increases were partially offset by:

•A $5 million decrease due to Michigan PTC deferral activity.

•Interest Expense increased $8 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $17 million primarily due to a decrease in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $327 million primarily due to the following:

•A $193 million increase in weather-normalized revenues primarily in the commercial class.

•A $91 million increase in fuel revenues.

•A $31 million increase in rider revenues.

•A $19 million increase due to a decrease in regulatory provisions for refund.

These increases were partially offset by:

•An $8 million decrease in weather-related usage primarily due to a 5% decrease in cooling degree days and a 4% decrease in heating degree days.

•Off-system Sales increased $42 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity.

•Transmission Revenues decreased $12 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $80 million primarily due to an increase in recoverable fuel and purchased power costs, partially offset by a decrease in Rockport Plant, Unit 2 merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates expenses increased $14 million primarily due to an increase in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $110 million primarily due to the following:

•A $38 million increase in transmission expenses primarily due to a $29 million increase in recoverable PJM expenses and a $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $24 million increase in distribution expenses primarily due to an increase in storm restoration costs and vegetation management costs.

•A $15 million increase in steam generation expenses primarily due to acquisitions of generation facilities.

•A $14 million increase in employee-related costs.

•Depreciation and Amortization expenses increased $25 million primarily due to the following:

•A $21 million increase due to a higher depreciable base.

•An $8 million increase due to NOLC-related Excess ADIT deferrals recorded in 2025 and the amortization of these deferrals recorded in 2026 for IURC-approved recovery through the Indiana tax rider.

•A $6 million increase due to acquisitions of generation facilities.

These increases were partially offset by:

•An $11 million decrease due to Michigan PTC deferral activity.

•Other Income increased $9 million primarily due to an increase in AFUDC driven by a higher AFUDC equity base and increased equity return rates.

•Interest Expense increased $26 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $76 million primarily due to the following:

•A $32 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $22 million increase due to an increase in pretax book income.

•An $18 million increase due to a decrease in PTCs.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	917			$	841		$	2,689	$	2,336
Sales to AEP Affiliates	4			4			11		10
(Provision for)/Reversal of - Revenue Refund – Affiliated	(1)			—			(5)		8
Provision for Refund – Nonaffiliated	(48)			(51)			(119)		(135)
Other Revenues – Affiliated	20			17			47		47
Other Revenues – Nonaffiliated	2			1			4		6
TOTAL REVENUES	894			812			2,627		2,272

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	162			158			546		466

Purchased Electricity from AEP Affiliates	93			72			228		214
Other Operation	231			189			621		537
Maintenance	89			71			245		219

Depreciation and Amortization	142			133			411		386
Taxes Other Than Income Taxes	23			23			73		71
TOTAL EXPENSES	740			646			2,124		1,893

OPERATING INCOME	154			166			503		379

Other Income (Expense):
Other Income	8			6			24		15



Non-Service Cost Components of Net Periodic Benefit Cost	3			5			10		15
Interest Expense	(46)			(38)			(138)		(112)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	119			139			399		297

Income Tax Expense (Benefit)	6			(11)			41		(35)

NET INCOME	$	113			$	150		$	358	$	332

The common stock of I&M is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
Net Income	$	113			$	150		$	358	$	332

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—			—			—		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—			—			—		—

TOTAL OTHER COMPREHENSIVE INCOME	—			—			—		—

TOTAL COMPREHENSIVE INCOME	$	113			$	150		$	358	$	332

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)	Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2024	$	57			$	1,012		$	2,328	$	—	$	3,397


Common Stock Dividends					(50)				(50)
Net Income					58				58

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	57			1,012			2,336		—	3,405

Capital Contribution from Parent			7						7

Net Income					124				124

TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	57			1,019			2,460		—	3,536

Capital Contribution from Parent			1						1


Net Income					150			150

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2025	$	57			$	1,020		$	2,610	$	—	$	3,687

TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2025	$	57			$	1,033		$	2,692	$	2	$	3,784



Net Income					148				148

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026	57			1,033			2,840		2	3,932

Capital Contribution from Parent			25						25
Common Stock Dividends					(50)				(50)
Net Income					97				97

TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026	57			1,058			2,887		2	4,004

Capital Contribution from Parent			3						3


Net Income					113				113

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2026	$	57			$	1,061		$	3,000	$	2	$	4,120

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	2			$	2
Advances to Affiliates	—			192
Accounts Receivable:
Customers	104			103
Affiliated Companies	102			90
Accrued Unbilled Revenues	—			17
Miscellaneous	19			2

Total Accounts Receivable	225			212
Fuel	54			61
Materials and Supplies	251			222
Risk Management Assets	26			10
Accrued Tax Benefits	47			32



Prepayments and Other Current Assets	77			53
TOTAL CURRENT ASSETS	682			784

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,353			5,483
Transmission	2,174			2,055
Distribution	4,012			3,823
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	1,604			1,058
Construction Work in Progress	701			403
Total Property, Plant and Equipment	14,844			12,822
Accumulated Depreciation, Depletion and Amortization	5,346			4,878
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,498			7,944

OTHER NONCURRENT ASSETS
Regulatory Assets	582			585
Spent Nuclear Fuel and Decommissioning Trusts	5,256			4,916

Operating Lease Assets	43			52
Deferred Charges and Other Noncurrent Assets	347			344
TOTAL OTHER NONCURRENT ASSETS	6,228			5,897

TOTAL ASSETS	$	16,408			$	14,625

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	284			$	—
Accounts Payable:
General	320			232
Affiliated Companies	121			125
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $75 and $117, Respectively, Related to DCC Fuel)	75			117

Customer Deposits	45			55
Accrued Taxes	58			112
Accrued Interest	40			42

Obligations Under Operating Leases	14			17
Regulatory Liability for Over-Recovered Fuel Costs	155			19
Other Current Liabilities	228			230
TOTAL CURRENT LIABILITIES	1,340			949

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,043			3,444

Deferred Income Taxes	1,249			1,219
Regulatory Liabilities and Deferred Investment Tax Credits	3,346			2,938
Asset Retirement Obligations	2,230			2,165
Obligations Under Operating Leases	30			37
Deferred Credits and Other Noncurrent Liabilities	50			89
TOTAL NONCURRENT LIABILITIES	10,948			9,892

TOTAL LIABILITIES	12,288			10,841

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	57			57
Paid-in Capital	1,061			1,033
Retained Earnings	3,000			2,692
Accumulated Other Comprehensive Income (Loss)	2			2
TOTAL COMMON SHAREHOLDER’S EQUITY	4,120			3,784

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	16,408			$	14,625

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	358			$	332
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	411			386

Deferred Income Taxes	7			(52)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	21			(40)


Allowance for Equity Funds Used During Construction	(20)			(13)
Mark-to-Market of Risk Management Contracts	(16)			8
Amortization of Nuclear Fuel	95			81

Deferred Fuel Over/Under-Recovery, Net	136			21
Change in Other Noncurrent Assets	(54)			(20)
Change in Other Noncurrent Liabilities	144			112
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	7			(1)
Fuel, Materials and Supplies	(15)			39

Accounts Payable	72			79

Accrued Taxes, Net	(69)			(19)


Other Current Assets	17			10
Other Current Liabilities	(26)			19
Net Cash Flows from Operating Activities	1,068			942

INVESTING ACTIVITIES
Construction Expenditures	(648)			(478)
Change in Advances to Affiliates, Net	192			(157)
Purchases of Investment Securities	(2,493)			(2,387)
Sales of Investment Securities	2,435			2,332
Acquisitions of Generation Facilities	(1,275)			—
Acquisitions of Nuclear Fuel	(97)			(89)

Other Investing Activities	12			31
Net Cash Flows Used for Investing Activities	(1,874)			(748)

FINANCING ACTIVITIES
Capital Contribution from Parent	28			8

Issuance of Long-term Debt – Nonaffiliated	640			249
Change in Advances from Affiliates, Net	284			(127)
Retirement of Long-term Debt – Nonaffiliated	(94)			(270)
Principal Payments for Finance Lease Obligations	(3)			(5)
Dividends Paid on Common Stock	(50)			(50)
Other Financing Activities	1			1
Net Cash Flows from (Used for) Financing Activities	806			(194)

Net Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	2			2
Cash and Cash Equivalents at End of Period	$	2			$	2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	129			$	111

Noncash Acquisitions Under Finance Leases	3			2
Construction Expenditures Included in Current Liabilities as of September 30,	107			75
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	—			1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	4,118		4,121		11,071	11,240
Commercial	9,201		7,391		25,171	19,203
Industrial	3,607		3,520		10,712	10,654
Miscellaneous	23		23		74	76
Total Retail (a)	16,949		15,055		47,028	41,173

Wholesale (b)	2		552		901	1,683

Total KWhs	16,951		15,607		47,929	42,856

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Actual – Heating	—		—		1,996	2,077
Normal – Heating	2		3		1,993	1,996

Actual – Cooling	794		734		1,115	1,076
Normal – Cooling	704		707		1,032	1,032


Ohio Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	101			$	267

Changes in Revenues:
Retail Revenues	172			314
Off-system Sales	(32)			(14)
Transmission Revenues	6			26
Other Revenues	(8)			(14)
Total Change in Revenues	138			312

Changes in Expenses and Other:
Purchased Electricity for Resale	14			27
Purchased Electricity from AEP Affiliates	(8)			(13)
Other Operation and Maintenance	(117)			(215)

Depreciation and Amortization	(12)			(25)
Taxes Other Than Income Taxes	(8)			(33)


Other Income	—			(1)
Allowance for Equity Funds Used During Construction	1			—
Non-Service Cost Components of Net Periodic Benefit Cost	(1)			2
Interest Expense	—			1
Total Change in Expenses and Other	(131)			(257)

Income Tax Expense	5			18
Equity Earnings of Unconsolidated Subsidiaries	(1)			(2)

2026 Net Income	$	112			$	338

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $172 million primarily due to the following:

•A $114 million increase in rider revenues.

•A $40 million increase due to higher prices for purchased power to serve SSO customers.

•A $10 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

•A $5 million increase in weather-related usage due to an 8% increase in cooling degree days.

•Off-system Sales decreased $32 million primarily due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•Transmission Revenues increased $6 million primarily due to continued transmission investment.

•Other Revenues decreased $8 million primarily due to lower third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity for Resale expenses decreased $14 million primarily due to the following:

•A $34 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•A $2 million decrease in recoverable alternative energy rider expenses.

These decreases were partially offset by:

•A $36 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates increased $8 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $117 million primarily due to the following:

•An $86 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $14 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

•A $7 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization increased $12 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes.

•Income Tax Expense decreased $5 million primarily due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $314 million primarily due to the following:

•A $198 million increase in rider revenues.

•A $99 million increase due to higher prices for purchased power to serve SSO customers.

•A $20 million increase in weather-normalized revenues primarily in the residential and commercial classes.

These increases were partially offset by:

•A $14 million decrease in weather-related usage driven by a 4% decrease in heating degree days.

•Off-system Sales decreased $14 million primarily due to the following:

•A $32 million decrease due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

This decrease was partially offset by:

•An $18 million increase due to increased sales of OVEC purchased power in the first half of 2026 driven by higher market prices and volumes.

•Transmission Revenues increased $26 million primarily due to continued transmission investment.

•Other Revenues decreased $14 million primarily due to the following:

•A $24 million decrease in third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

This decrease was partially offset by:

•A $4 million increase in affiliated rent revenue.

•A $3 million increase primarily due to customer-sited projects.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity for Resale expenses decreased $27 million primarily due to the following:

•A $57 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

These decreases were partially offset by:

•An $86 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates expenses increased $13 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $215 million primarily due to the following:

•A $151 million increase in transmission expenses primarily due to a $134 million increase in recoverable PJM transmission expenses and a $12 million increase in recoverable transmission storm restoration costs and vegetation management expenses.

•A $28 million increase in distribution expenses primarily related to recoverable vegetation management expenses and recoverable storm restoration costs.

•A $22 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $33 million primarily due to the following:

•A $25 million increase due to higher property taxes.

•An $8 million increase in state excise taxes due to increased billed KWhs.

•Income Tax Expense decreased $18 million primarily due to the following:

•A $30 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

This decrease was partially offset by:

•An $11 million increase due to an increase in pretax book income.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
REVENUES
Electricity, Transmission and Distribution	$	1,190			$	1,059		$	3,253	$	2,959
Sales to AEP Affiliates	13			8			40		24
Other Revenues	5			3			12		10
TOTAL REVENUES	1,208			1,070			3,305		2,993

EXPENSES
Purchased Electricity for Resale	231			245			654		681
Purchased Electricity from AEP Affiliates	26			18			62		49

Other Operation	449			341			1,132		958
Maintenance	81			72			228		187

Depreciation and Amortization	108			96			310		285
Taxes Other Than Income Taxes	153			145			457		424
TOTAL EXPENSES	1,048			917			2,843		2,584

OPERATING INCOME	160			153			462		409

Other Income (Expense):


Other Income	—			—			—		1
Allowance for Equity Funds Used During Construction	6			5			19		19
Non-Service Cost Components of Net Periodic Benefit Cost	3			4			15		13
Interest Expense	(40)			(40)			(117)		(118)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	129			122			379		324

Income Tax Expense	17			22			41		59
Equity Earnings of Unconsolidated Subsidiaries	—			1			—		2

NET INCOME	$	112			$	101		$	338	$	267

The common stock of OPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	321			$	1,020		$	2,543		$	3,884

Common Stock Dividends					(46)				(46)
Net Income					63				63

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	321			1,020			2,560			3,901

Capital Contribution from Parent			2						2
Common Stock Dividends					(25)				(25)
Net Income					103				103

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	321			1,022			2,638			3,981



Net Income					101				101

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025	$	321			$	1,022		$	2,739		$	4,082

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	321			$	1,030		$	2,800		$	4,151

Capital Contribution from Parent			39						39

Net Income					117				117

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026	321			1,069			2,917			4,307

Capital Contribution from Parent			65						65

Net Income					109				109

Noncash Distribution to Parent					(2)				(2)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026	321			1,134			3,024			4,479

Capital Contribution from Parent			5						5
Common Stock Dividends					(150)				(150)
Net Income					112				112

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2026	$	321			$	1,139		$	2,986		$	4,446

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	7			$	5

Accounts Receivable:
Customers	183			109
Affiliated Companies	126			132
Accrued Unbilled Revenues	3			29


Total Accounts Receivable	312			270
Materials and Supplies	220			191




Prepayments and Other Current Assets	31			25
TOTAL CURRENT ASSETS	570			491

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	4,069			3,916
Distribution	8,237			7,661
Other Property, Plant and Equipment	1,288			1,289
Construction Work in Progress	863			811
Total Property, Plant and Equipment	14,457			13,677
Accumulated Depreciation and Amortization	3,059			2,993
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,398			10,684

OTHER NONCURRENT ASSETS
Regulatory Assets	362			326

Operating Lease Assets	46			50
Deferred Charges and Other Noncurrent Assets	340			659
TOTAL OTHER NONCURRENT ASSETS	748			1,035

TOTAL ASSETS	$	12,716			$	12,210

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025

CURRENT LIABILITIES
Advances from Affiliates	$	240			$	79
Accounts Payable:
General	542			391
Affiliated Companies	222			197

Risk Management Liabilities	3			5
Customer Deposits	123			108
Accrued Taxes	458			858


Obligations Under Operating Leases	13			13
Other Current Liabilities	304			239
TOTAL CURRENT LIABILITIES	1,905			1,890

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,721			3,718
Long-term Risk Management Liabilities	19			28
Deferred Income Taxes	1,377			1,268
Regulatory Liabilities and Deferred Investment Tax Credits	876			893


Obligations Under Operating Leases	33			37
Deferred Credits and Other Noncurrent Liabilities	339			225
TOTAL NONCURRENT LIABILITIES	6,365			6,169

TOTAL LIABILITIES	8,270			8,059

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321			321
Paid-in Capital	1,139			1,030
Retained Earnings	2,986			2,800

TOTAL COMMON SHAREHOLDER’S EQUITY	4,446			4,151

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,716			$	12,210

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	338			$	267
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	310			285
Deferred Income Taxes	52			34


Allowance for Equity Funds Used During Construction	(19)			(19)
Mark-to-Market of Risk Management Contracts	(11)			(3)

Property Taxes	321			306
Customer Deposits	79			49
Change in Regulatory Assets	(45)			28
Change in Other Noncurrent Assets	(69)			11
Change in Other Noncurrent Liabilities	61			(60)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(26)			48
Materials and Supplies	(29)			(10)
Accounts Payable	176			131

Accrued Taxes, Net	(391)			(416)
Other Current Assets	(10)			3
Other Current Liabilities	(18)			(8)
Net Cash Flows from Operating Activities	719			646

INVESTING ACTIVITIES
Construction Expenditures	(963)			(747)
Change in Advances to Affiliates, Net	—			115
Contribution in Aid of Construction Advances	50			40
Other Investing Activities	6			5
Net Cash Flows Used for Investing Activities	(907)			(587)

FINANCING ACTIVITIES
Capital Contribution from Parent	109			2

Change in Advances from Affiliates, Net	161			13

Principal Payments for Finance Lease Obligations	(3)			(3)
Dividends Paid on Common Stock	(150)			(71)
Security Deposits	72			—
Other Financing Activities	1			1
Net Cash Flows from (Used for) Financing Activities	190			(58)

Net Increase in Cash and Cash Equivalents	2			1
Cash and Cash Equivalents at Beginning of Period	5			4
Cash and Cash Equivalents at End of Period	$	7			$	5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	90			$	91


Construction Expenditures Included in Current Liabilities as of September 30,	140			119


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	2,459		2,027		5,229	4,938
Commercial	1,842		1,706		4,702	4,512
Industrial	1,583		1,567		4,496	4,427
Miscellaneous	406		360		1,019	964
Total Retail	6,290		5,660		15,446	14,841

Wholesale (a)	96		168		150	253

Total KWhs	6,386		5,828		15,596	15,094

(a)Includes municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Actual – Heating	—		—		761	1,193
Normal – Heating	—		—		1,092	1,081

Actual – Cooling	1,913		1,353		2,763	1,982
Normal – Cooling	1,421		1,425		2,147	2,154


Public Service Company of Oklahoma
Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	130			$	221

Changes in Revenues:
Retail Revenues (a)	173			276

Transmission Revenues	7			3
Other Revenues	(6)			(8)
Total Change in Revenues	174			271

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	64			21
Other Operation and Maintenance	(4)			(67)
Depreciation and Amortization	(69)			(80)
Taxes Other Than Income Taxes	(3)			(10)
Interest Income	1			(1)

Allowance for Equity Funds Used During Construction	3			2

Non-Service Cost Components of Net Periodic Benefit Cost	(1)			(6)
Interest Expense	(8)			(35)
Total Change in Expenses and Other	(17)			(176)

Income Tax Benefit	(53)			(13)

2026 Net Income	$	234			$	303

(a)Includes firm wholesale sales to municipals and cooperatives.

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $173 million primarily due to the following:

•A $148 million increase in rider revenues, inclusive of $75 million of 2026 interim rate rider revenue.

•A $56 million increase in weather-related usage primarily due to a 41% increase in cooling degree days.

•A $6 million increase in weather-normalized revenues primarily in the industrial class, partially offset by a decrease in the residential class.

These increases were partially offset by:

•A $36 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•Transmission Revenues increased $7 million primarily due to continued transmission investment.

•Other Revenues decreased $6 million primarily due to lower associated business development revenues and lower gains on the sale of environmental credits.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $64 million primarily due to a $37 million decrease related to the impact on deferred fuel costs from decreased fuel revenues and a $25 million decrease in recoverable PTCs.

•Depreciation and Amortization expenses increased $69 million primarily due to a higher depreciable base.

•Interest Expense increased $8 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $53 million primarily due to the following:

•A $33 million decrease due to an increase in pretax book income.

•A $17 million decrease due to a decrease in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $276 million primarily due to the following:

•A $274 million increase in rider revenues, inclusive of $75 million of 2026 interim rate rider revenue.

•A $62 million increase in weather-related usage primarily due to a 39% increase in cooling degree days.

These increases were partially offset by:

•A $48 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•An $11 million decrease in weather-normalized revenues primarily in the residential class, partially offset by an increase in industrial class.

•Other Revenues decreased $8 million primarily due to lower associated business development revenues and lower gains on the sale of environmental credits.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to a $47 million decrease related to the impact on deferred fuel costs from decreased fuel and other revenues, partially offset by a $28 million increase in recoverable PTCs.

•Other Operation and Maintenance expenses increased $67 million primarily due to the following:

•A $30 million increase in generation expenses primarily due to acquisitions of generation facilities.

•A $13 million increase in employee-related costs.

•An $11 million increase in distribution expenses primarily due to overhead line maintenance.

•A $7 million increase in transmission expenses primarily due to:

•A $33 million increase in SPP expenses.

This increase was partially offset by:

•A $19 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $12 million decrease due to the refund of SPP upgrade costs.

•Depreciation and Amortization expenses increased $80 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $10 million primarily due to property taxes on acquired generation facilities.

•Interest Expense increased $35 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $13 million primarily due to the following:

•A $20 million decrease due to an increase in pretax book income.

•A $13 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

These decreases were partially offset by:

•A $21 million increase due to an increase in PTCs.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	864			$	686		$	1,815	$	1,542
Sales to AEP Affiliates	2			4			10		6
Other Revenues	2			4			3		9
TOTAL REVENUES	868			694			1,828		1,557

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	231			295			575		596


Other Operation	145			139			410		363
Maintenance	35			37			115		95
Depreciation and Amortization	136			67			283		203
Taxes Other Than Income Taxes	24			21			69		59
TOTAL EXPENSES	571			559			1,452		1,316

OPERATING INCOME	297			135			376		241

Other Income (Expense):
Interest Income	1			—			1		2

Allowance for Equity Funds Used During Construction	4			1			9		7

Non-Service Cost Components of Net Periodic Benefit Cost	1			2			—		6
Interest Expense	(48)			(40)			(134)		(99)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	255			98			252		157

Income Tax Expense (Benefit)	21			(32)			(51)		(64)

NET INCOME	$	234			$	130		$	303	$	221

The common stock of PSO is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
Net Income	$	234			$	130		$	303	$	221

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively.	—			—			—		(1)

TOTAL COMPREHENSIVE INCOME	$	234			$	130		$	303	$	220

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)	Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2024	$	157			$	1,042		$	1,484	$	3	$	2,686




Net Income					28				28
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2025	157			1,042			1,512		2	2,713

Capital Contribution from Parent			300						300

Net Income					63				63

TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2025	157			1,342			1,575		2	3,076

Capital Contribution from Parent			375						375

Net Income					130				130

TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2025	$	157			$	1,717		$	1,705	$	2	$	3,581

TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2025	$	157			$	1,718		$	1,736	$	2	$	3,613




Net Income					15				15

TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2026	157			1,718			1,751		2	3,628

Capital Contribution from Parent			113						113

Net Income					54				54

TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2026	157			1,831			1,805		2	3,795



Net Income					234				234

TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2026	$	157			$	1,831		$	2,039	$	2	$	4,029

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	4			$	2
Advances to Affiliates	70			—
Accounts Receivable:
Customers	108			109
Affiliated Companies	53			45
Miscellaneous	17			4

Total Accounts Receivable	178			158
Fuel	2			3
Materials and Supplies	157			119
Risk Management Assets	41			42

Accrued Tax Benefits	105			8
Regulatory Asset for Under-Recovered Fuel Costs	23			37
Prepayments and Other Current Assets	37			14
TOTAL CURRENT ASSETS	617			383

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,789			4,365
Transmission	1,511			1,433
Distribution	4,211			3,987
Other Property, Plant and Equipment	1,313			1,292
Construction Work in Progress	1,168			635
Total Property, Plant and Equipment	12,992			11,712
Accumulated Depreciation and Amortization	2,556			2,748
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,436			8,964

OTHER NONCURRENT ASSETS
Regulatory Assets	683			637

Employee Benefits and Pension Assets	96			95
Operating Lease Assets	140			126
Deferred Charges and Other Noncurrent Assets	34			13
TOTAL OTHER NONCURRENT ASSETS	953			871

TOTAL ASSETS	$	12,006			$	10,218

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(in millions, except per-share and share amounts)

(Unaudited)


	September 30,		December 31,
	2026		2025

CURRENT LIABILITIES
Advances from Affiliates	$	—			$	171
Accounts Payable:
General	386			339
Affiliated Companies	58			87
Long-term Debt Due Within One Year – Nonaffiliated	—			51
Risk Management Liabilities	29			27
Customer Deposits	355			115
Accrued Taxes	88			37
Accrued Interest	48			67
Obligations Under Operating Leases	12			11


Other Current Liabilities	133			104
TOTAL CURRENT LIABILITIES	1,109			1,009

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,462			3,475

Deferred Income Taxes	1,208			1,113
Regulatory Liabilities and Deferred Investment Tax Credits	746			717
Asset Retirement Obligations	165			136

Obligations Under Operating Leases	137			122
Deferred Credits and Other Noncurrent Liabilities	150			33
TOTAL NONCURRENT LIABILITIES	6,868			5,596

TOTAL LIABILITIES	7,977			6,605

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157			157
Paid-in Capital	1,831			1,718
Retained Earnings	2,039			1,736
Accumulated Other Comprehensive Income (Loss)	2			2
TOTAL COMMON SHAREHOLDER’S EQUITY	4,029			3,613

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,006			$	10,218

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	303			$	221
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	283			203
Deferred Income Taxes	83			31

Allowance for Equity Funds Used During Construction	(9)			(7)
Mark-to-Market of Risk Management Contracts	7			(34)

Property Taxes	(19)			(16)
Deferred Fuel Over/Under-Recovery, Net	14			42

Change in Other Regulatory Assets	(12)			(57)
Change in Other Noncurrent Assets	(41)			(35)
Change in Other Noncurrent Liabilities	156			14
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(20)			(34)
Fuel, Materials and Supplies	(37)			4
Accounts Payable	31			142
Customer Deposits	238			42
Accrued Taxes, Net	(46)			76
Other Current Assets	(16)			(2)
Other Current Liabilities	(23)			(19)
Net Cash Flows from Operating Activities	892			571

INVESTING ACTIVITIES
Construction Expenditures	(1,089)			(534)
Change in Advances to Affiliates, Net	(70)			232

Acquisitions of Generation Facilities	(608)			(1,657)
Other Investing Activities	1			7
Net Cash Flows Used for Investing Activities	(1,766)			(1,952)

FINANCING ACTIVITIES
Capital Contribution from Parent	113			675

Issuance of Long-term Debt – Nonaffiliated	986			793
Change in Advances from Affiliates, Net	(171)			40
Retirement of Long-term Debt – Nonaffiliated	(50)			(125)



Other Financing Activities	(2)			(1)
Net Cash Flows from Financing Activities	876			1,382

Net Increase in Cash and Cash Equivalents	2			1
Cash and Cash Equivalents at Beginning of Period	2			2
Cash and Cash Equivalents at End of Period	$	4			$	3

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	152			$	96



Construction Expenditures Included in Current Liabilities as of September 30,	187			91

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in millions of KWhs)
Retail:
Residential	2,267		2,016		5,114	4,984
Commercial	1,783		1,699		4,486	4,359
Industrial	1,376		1,375		3,959	3,883
Miscellaneous	17		16		50	50
Total Retail	5,443		5,106		13,609	13,276

Wholesale (a)	1,795		1,562		4,174	4,305

Total KWhs	7,238		6,668		17,783	17,581

(a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,	Nine Months Ended September 30,
	2026	2025		2026	2025
	(in degree days)
Actual – Heating	—		—		496	726
Normal – Heating	—		—		720	714

Actual – Cooling	1,771		1,545		2,809	2,589
Normal – Cooling	1,405		1,404		2,236	2,220


Southwestern Electric Power Company Consolidated

Reconciliation of 2025 to 2026
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to Common Shareholder	$	189			$	353

Changes in Revenues:
Retail Revenues (a)	63			105
Off-system Sales	—			1
Transmission Revenues	(16)			(6)
Other Revenues	(1)			4
Total Change in Revenues	46			104

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(13)			43
Other Operation and Maintenance	(3)			(60)
Asset Impairments and Other Related Charges	—			(31)
Depreciation and Amortization	(2)			(40)
Taxes Other Than Income Taxes	2			(6)
Interest Income	(2)			(4)
Allowance for Equity Funds Used During Construction	1			9
Non-Service Cost Components of Net Periodic Benefit Cost	—			(1)

Interest Expense	(25)			(61)
Total Change in Expenses and Other	(42)			(151)

Income Tax Benefit	(6)			23
Equity Earnings of Unconsolidated Subsidiary	1			—
Net Income Attributable to Noncontrolling Interest	—			1

2026 Earnings Attributable to Common Shareholder	$	188			$	330

(a)Includes firm wholesale sales to municipals and cooperatives.

Third Quarter of 2026 Compared to Third Quarter of 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $63 million primarily due to the following:

•A $31 million increase due to the Arkansas base rate case.

•A $29 million increase in rider revenues primarily in the Louisiana jurisdiction.

•A $20 million increase in weather-related usage primarily due to a 15% increase in cooling degree days.

These increases were partially offset by:

•An $18 million decrease due to a credit to certain existing wholesale generation customers.

•A $7 million decrease in weather-normalized revenues across all classes.

•Transmission Revenues decreased $16 million primarily due to a $12 million repayment of SPP upgrade credits, offset by an equal amount of incremental SPP upgrade costs in Other Operation and Maintenance expenses.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $13 million primarily due to increased gas generation and higher coal prices.

•Interest Expense increased $25 million primarily due to the following:

•A $19 million increase due to higher long-term debt balances.

•A $4 million increase attributable to the interest portion of credits owed to wholesale customers.

•Income Tax Benefit decreased $6 million primarily due to a decrease in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $105 million primarily due to the following:

•An $82 million increase in rider revenues primarily in the Louisiana jurisdiction.

•A $64 million increase due to the Arkansas base rate case.

•A $39 million increase in weather-normalized revenues across all classes.

These increases were partially offset by:

•A $53 million decrease in fuel revenue due to a $43 million refund of the Texas over-recovered fuel balance and a $10 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•A $41 million decrease due to a credit to certain existing wholesale generation customers.

•Transmission Revenues decreased $6 million primarily due to the following:

•A $27 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by lower SPP upgrade costs in Other Operation and Maintenance expenses.

These decreases were partially offset by:

•A $34 million increase due to continued transmission investment.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $43 million primarily due to the following:

•A $53 million decrease due to a decrease in the deferred fuel costs related to a $43 million Texas fuel refund and a $10 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•An $8 million decrease due to prior year Louisiana and Texas fuel disallowances.

These decreases were partially offset by:

•A $14 million increase in recoverable PTCs.

•An $11 million increase in non-recoverable fuel costs primarily in Louisiana.

•Other Operation and Maintenance expenses increased $60 million primarily due to the following:

•A $28 million increase in generation expenses primarily due to a $16 million increase related to the acquisition of the Wagon Wheel Wind Facility.

•A $17 million increase in distribution expenses primarily due to overhead line maintenance.

•A $9 million increase in employee-related costs.

•A $6 million increase due to the partial write-off of previously capitalized vegetation management costs as a result of SWEPCo’s FERC audit.

These increases were partially offset by:

•A $4 million decrease in transmission expenses primarily due to:

•A $12 million decrease due to the refund of SPP upgrade costs.

•A $12 million decrease in vegetation management costs.

•A $10 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

These decreases were partially offset by:

•A $32 million increase in SPP expenses.

100

•Asset Impairments and Other Related Charges increased $31 million due to the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case.

•Depreciation and Amortization expenses increased $40 million primarily due to the following:

•A $44 million increase due to a higher depreciable base including the Wagon Wheel Wind Facility.

This increase was partially offset by:

•A $5 million decrease primarily due to higher over-recovery of costs and allowable returns associated with generation rider recovery.

•Taxes Other Than Income Taxes increased $6 million primarily due to an increase in property taxes.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher AFUDC base.

•Interest Expense increased $61 million primarily due to the following:

•A $46 million increase due to higher long-term debt balances.

•A $7 million increase related to the Texas tax normalization rider amortization.

•A $4 million increase attributable to the interest portion of credits owed to wholesale customers.

•Income Tax Benefit increased $23 million primarily due to the following:

•A $48 million increase due to an increase in PTCs.

•A $10 million increase due to a decrease in pretax book income.

•A $7 million increase due to a decrease in state taxes.

These increases were partially offset by:

•A $42 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

101

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	769			$	694		$	1,906	$	1,761
Sales to AEP Affiliates	24			28			71		63

Provision for Refund – Nonaffiliated	(25)			(4)			(53)		(9)
Other Revenues	2			6			5		10
TOTAL REVENUES	770			724			1,929		1,825

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	205			192			532		575


Other Operation	128			122			372		327
Maintenance	52			55			155		140
Asset Impairments and Other Related Charges	—			—			31		—
Depreciation and Amortization	130			128			374		334
Taxes Other Than Income Taxes	34			36			106		100
TOTAL EXPENSES	549			533			1,570		1,476

OPERATING INCOME	221			191			359		349

Other Income (Expense):
Interest Income	2			4			5		9
Allowance for Equity Funds Used During Construction	8			7			23		14
Non-Service Cost Components of Net Periodic Benefit Cost	1			1			4		5

Interest Expense	(62)			(37)			(171)		(110)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	170			166			220		267

Income Tax Expense (Benefit)	(18)			(24)			(111)		(88)
Equity Earnings of Unconsolidated Subsidiary	1			—			1		1

NET INCOME	189			190			332		356

Net Income Attributable to Noncontrolling Interest	1			1			2		3

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	188			$	189		$	330	$	353

The common stock of SWEPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

102

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2026		2025		2026		2025
Net Income	$	189			$	190		$	332	$	356

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $1 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $1 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	5			—			5		—




TOTAL COMPREHENSIVE INCOME	194			190			337		356

Total Comprehensive Income Attributable to Noncontrolling Interest	1			1			2		3

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	193			$	189		$	335	$	353

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

103

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest		Total
TOTAL EQUITY – DECEMBER 31, 2024	$	—			$	1,550		$	2,352			$	3		$	—	$	3,905



Common Stock Dividends – Nonaffiliated								(1)			(1)

Net Income					48				1			49

TOTAL EQUITY – MARCH 31, 2025	—			1,550			2,400		3			—		3,953

Capital Contribution from Parent			450							450

Common Stock Dividends – Nonaffiliated								(1)			(1)
Net Income					116				1			117

TOTAL EQUITY – JUNE 30, 2025	—			2,000			2,516		3			—		4,519




Common Stock Dividends – Nonaffiliated								(1)			(1)
Net Income					189				1			190

TOTAL EQUITY – SEPTEMBER 30, 2025	$	—			$	2,000		$	2,705			$	3		$	—	$	4,708

TOTAL EQUITY – DECEMBER 31, 2025	$	—			$	2,151		$	2,740			$	8		$	—	$	4,899

Capital Contribution from Parent			128								128

Common Stock Dividends – Nonaffiliated								(1)			(1)

Net Income					56				1			57

TOTAL EQUITY – MARCH 31, 2026	—			2,279			2,796		8			—		5,083

Capital Contribution from Parent			81								81


Net Income					86				—			86

TOTAL EQUITY – JUNE 30, 2026	—			2,360			2,882		8			—		5,250

Capital Contribution from Parent			37								37


Common Stock Dividends – Nonaffiliated								(1)			(1)
Net Income					188				1			189
Other Comprehensive Income							5				5
TOTAL EQUITY – SEPTEMBER 30, 2026	$	—			$	2,397		$	3,070			$	13		$	—	$	5,480





See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

104

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	3			$	2
Restricted Cash (September 30, 2026 and December 31, 2025 Amounts Include $6 and $15, Respectively, Related to Storm Recovery Funding)	6			15
Advances to Affiliates	494			23
Accounts Receivable:
Customers	46			63
Affiliated Companies	84			91
Miscellaneous	15			10

Total Accounts Receivable	145			164
Fuel	75			83
Materials and Supplies (September 30, 2026 and December 31, 2025 Amounts Include $1 and $1, Respectively, Related to Sabine)	104			88
Risk Management Assets	43			35

Accrued Tax Benefits	149			17
Regulatory Asset for Under-Recovered Fuel Costs	68			115
Prepayments and Other Current Assets	32			14
TOTAL CURRENT ASSETS	1,119			556

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,612			6,621
Transmission	3,437			3,302
Distribution	3,421			3,242
Other Property, Plant and Equipment (September 30, 2026 and December 31, 2025 Amounts Include $0 and $125, Respectively, Related to Sabine)	947			942
Construction Work in Progress	1,210			712
Total Property, Plant and Equipment	15,627			14,819
Accumulated Depreciation and Amortization (September 30, 2026 and December 31, 2025 Amounts Include $0 and $125, Respectively, Related to Sabine)	3,580			3,478
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	12,047			11,341

OTHER NONCURRENT ASSETS
Regulatory Assets	913			903
Securitized Assets (September 30, 2026 and December 31, 2025 Amounts Include $303 and $315, Respectively, Related to Storm Recovery Funding)	303			315


Deferred Charges and Other Noncurrent Assets	448			409
TOTAL OTHER NONCURRENT ASSETS	1,664			1,627

TOTAL ASSETS	$	14,830			$	13,524

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

105

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

September 30, 2026 and December 31, 2025

(in millions, except per-share and share amounts)

(Unaudited)


	September 30,		December 31,
	2026		2025

CURRENT LIABILITIES

Accounts Payable:
General	$	484			$	392
Affiliated Companies	34			89
Short-term Debt – Nonaffiliated	—			3
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $17 and $17, Respectively, Related to Storm Recovery Funding)	417			917
Risk Management Liabilities	10			9
Customer Deposits	78			79
Accrued Taxes	132			68
Accrued Interest	83			49

Obligations Under Operating Leases	4			7

Provision for Refund	90			81

Other Current Liabilities	188			191
TOTAL CURRENT LIABILITIES	1,520			1,885

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $287 and $304, Respectively, Related to Storm Recovery Funding)	5,174			3,057
Long-term Debt – Affiliated	—			1,000

Deferred Income Taxes	1,547			1,458
Regulatory Liabilities and Deferred Investment Tax Credits	513			531
Asset Retirement Obligations	226			252
Employee Benefits and Pension Obligations	43			39

Obligations Under Operating Leases	193			195
Provision for Refund	8			47
Storm Reserve	62			108
Deferred Credits and Other Noncurrent Liabilities	64			53
TOTAL NONCURRENT LIABILITIES	7,830			6,740

TOTAL LIABILITIES	9,350			8,625

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 3,680 Shares
Outstanding – 3,680 Shares	—			—
Paid-in Capital	2,397			2,151
Retained Earnings	3,070			2,740
Accumulated Other Comprehensive Income (Loss)	13			8
TOTAL COMMON SHAREHOLDER’S EQUITY	5,480			4,899

Noncontrolling Interest	—			—

TOTAL EQUITY	5,480			4,899

TOTAL LIABILITIES AND EQUITY	$	14,830			$	13,524

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

106

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	332			$	356
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	374			334
Deferred Income Taxes	51			23
Asset Impairments and Other Related Charges	31			—
Allowance for Equity Funds Used During Construction	(23)			(14)
Mark-to-Market of Risk Management Contracts	(7)			(37)

Property Taxes	(26)			(23)
Deferred Fuel Over/Under-Recovery, Net	75			91
Change in Regulatory Assets	(81)			(44)

Change in Other Noncurrent Assets	(39)			(7)
Change in Other Noncurrent Liabilities	(43)			(104)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	19			(23)
Fuel, Materials and Supplies	(8)			6
Accounts Payable	(2)			136
Accrued Taxes, Net	(68)			69


Other Current Assets	(10)			1
Other Current Liabilities	31			(11)
Net Cash Flows from Operating Activities	606			753

INVESTING ACTIVITIES
Construction Expenditures	(1,022)			(654)
Change in Advances to Affiliates, Net	(471)			(267)

Other Investing Activities	23			11
Net Cash Flows Used for Investing Activities	(1,470)			(910)

FINANCING ACTIVITIES
Capital Contribution from Parent	246			450

Issuance of Long-term Debt – Nonaffiliated	2,134			1

Change in Short-term Debt – Nonaffiliated	(3)			2
Change in Advances from Affiliates, Net	—			(275)
Retirement of Long-term Debt – Nonaffiliated	(517)			(11)
Retirement of Long-term Debt – Affiliated	(1,000)			—


Dividends Paid on Common Stock – Nonaffiliated	(2)			(3)
Other Financing Activities	(2)			(1)
Net Cash Flows from Financing Activities	856			163

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(8)			6
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	17			5
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9			$	11

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	139			$	119



Construction Expenditures Included in Current Liabilities as of September 30,	261			116

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

107

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:

Note

Registrant

Page
Number

Significant Accounting Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

109

New Accounting Standards

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

111

Comprehensive Income

AEP

112

Rate Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

114

Commitments, Guarantees and Contingencies

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

133

Acquisitions, Dispositions and Impairments

AEP, AEPTCo, APCo, I&M, PSO, SWEPCo

137

Benefit Plans

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

141

Business Segments

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

144

Derivatives and Hedging

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

150

Fair Value Measurements

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

159

Income Taxes

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

173

Financing Activities

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

176

Variable Interest Entities

AEP, AEP Texas, APCo, I&M, OPCo, SWEPCo

184

Property, Plant and Equipment

AEP, PSO, SWEPCo

187

Revenue from Contracts with Customers

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

188

108

1. SIGNIFICANT ACCOUNTING MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2026 is not necessarily indicative of results that may be expected for the year ending December 31, 2026. The condensed financial statements are unaudited and should be read in conjunction with the audited 2025 financial statements and notes thereto, which are included in the 2025 Annual Reports.

Change in Presentation

In 2025, the Company changed its rounding presentation in the Registrant’s financial statements and accompanying tabular footnote disclosures to the nearest whole number in millions, except per share data. The change had no material impact on previously reported financial information, however, certain amounts reported for prior periods may differ by insignificant amounts due to the rounding presentation. In addition, historical percentages and per share amounts presented may not recalculate due to rounding. This change does not impact the comparability of the Registrant’s financial statements and related disclosures.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive securities. Dilutive securities are primarily related to forward sale of equity agreements and restricted stock units. See Note 12 - Financing Activities for more information regarding the forward sale of equity agreements.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:


	Three Months Ended September 30,
	2026		2025
	(in millions, except per share data)
			$/share			$/share
Earnings Attributable to AEP Common Shareholders	$	1,187				$	972

Weighted-Average Number of Basic AEP Common Shares Outstanding	544.4			$	2.18		534.9		$	1.82
Weighted-Average Dilutive Effect	5.7			(0.02)		3.1		(0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding	550.1			$	2.16		538.0		$	1.81


	Nine Months Ended September 30,
	2026		2025
	(in millions, except per share data)
			$/share			$/share


Earnings Attributable to AEP Common Shareholders	$	2,774				$	2,998

Weighted-Average Number of Basic AEP Common Shares Outstanding	543.6			$	5.10		534.2		$	5.61
Weighted-Average Dilutive Effect	5.7			(0.05)		2.2		(0.02)
Weighted-Average Number of Diluted AEP Common Shares Outstanding	549.3			$	5.05		536.4		$	5.59

109

Upon settlement of the ATM Forward maturing December 2026, the Company will issue three million shares of common stock. However, as the forward price was greater than the average market price of the common shares as of September 30, 2026, the shares were not included in the computation of diluted EPS because to do so would be antidilutive. There were no antidilutive shares outstanding as of September 30, 2025.

Restricted Cash (Applies to AEP, AEP Texas, APCo and SWEPCo)

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:


	September 30, 2026
	AEP		AEP Texas		APCo		SWEPCo
	(in millions)
Cash and Cash Equivalents	$	418			$	—		$	4	$	3
Restricted Cash	89			9			60		6
Total Cash, Cash Equivalents and Restricted Cash	$	507			$	9		$	64	$	9


	December 31, 2025
	AEP		AEP Texas		APCo		SWEPCo
	(in millions)
Cash and Cash Equivalents	$	197			$	—		$	5	$	2
Restricted Cash	71			14			18		15
Total Cash, Cash Equivalents and Restricted Cash	$	268			$	14		$	23	$	17

Supplementary Cash Flow Information (Applies to AEP)


	Nine Months Ended September 30,
Cash Flow Information	2026		2025
	(in millions)
Cash Paid for:
Interest, Net of Capitalized Amounts	$	1,548			$	1,315


Noncash Investing and Financing Activities:

Construction Expenditures Included in Current Liabilities as of September 30,	1,813			1,169
Contribution in Aid of Construction Advances in Current Assets as of September 30,	69			—


Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	—			1

110

2. NEW ACCOUNTING STANDARDS

The disclosures in this note apply to all Registrants unless indicated otherwise.

Management reviews the FASB’s standard-setting process and the SEC’s rulemaking activity to determine the relevance, if any, to the Registrants’ business. The following standards/rules will impact the Registrants’ financial statements.

SEC Climate Disclosure Rule

In March 2024, the SEC adopted final rules that would require registrants to disclose certain climate-related information in registration statements and annual reports. Litigation challenging the new rules was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. In March 2025, the SEC announced that it voted to end its defense of the final climate disclosure rules. In April 2025, 18 states filed a motion to intervene in the case and to hold the case in abeyance until the SEC takes action to amend or rescind the rules. In July 2025, the SEC filed a status report stating that it does not intend to review or reconsider the rules and asked the Court of Appeals to make a ruling on the case. In September 2025, the Court of Appeals issued an order holding the case in abeyance until the SEC either formally defends the rules or initiates a new rulemaking process for reconsideration. In May 2026, the SEC formally proposed to rescind its climate-related disclosure rules. The proposal is subject to notice-and-comment rulemaking before a final rule can be approved.

ASU 2024-03 “Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures” (ASU 2024-03)

In November 2024, the FASB issued ASU 2024-03, the intent of which is to improve financial reporting and respond to investor input by requiring public business entities to disclose additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation and intangible asset amortization included in each expense caption presented on the face of the income statement. Public business entities are required to include certain amounts that are already required to be disclosed under GAAP in the same disclosure as the other disaggregation requirements as well as a qualitative description of any amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. The new standard also requires disclosure of the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. An entity is not precluded from providing additional voluntary disclosures that may provide investors with additional decision-useful information.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in the new standard should be applied either prospectively to financial statements issued for reporting periods after the effective date or retrospectively to any or all prior periods presented in the financial statements. Management is evaluating the new standard and has not yet determined when, or the method by which, the Registrants will adopt its amendments.

ASU 2025-06 “Intangibles—Goodwill and Other—Internal-Use Software” (ASU 2025-06)

In September 2025, the FASB issued ASU 2025-06, the intent of which is to modernize the cost capitalization threshold for internal-use software development costs by removing all references to software project development stages and providing new guidance on how to evaluate whether the probable-to-complete recognition threshold has been met for the commencement of capitalization of eligible costs.

The amendments in the new standard may be applied on either a retrospective, prospective or modified prospective basis for public business entities for fiscal years beginning after December 15, 2027 with early adoption permitted. Management elected to early adopt this standard prospectively beginning on January 1, 2026. The adoption of the new standard did not have a material impact on the results of operations, statements of financial position or cash flows.

ASU 2026-02 “Environmental Credits and Environmental Credit Obligations” (ASU 2026-02)

In May 2026, the FASB issued ASU 2026-02, the intent of which is to improve the financial accounting for and disclosure of environmental credits and environmental credit obligations. The new standard establishes guidance on the recognition, measurement, presentation, and disclosure requirements for all public business entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted as of the beginning of an annual reporting period and should be applied on a retrospective basis. Management is currently evaluating the impact of this ASU on its consolidated financial statements and related disclosures.

111

3. COMPREHENSIVE INCOME

The disclosures in this note apply to AEP only. The impact of AOCI is not material to the financial statements of the Registrant Subsidiaries.

Presentation of Comprehensive Income

The following tables provide AEP’s components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.



	Cash Flow Hedges		Pension
Three Months Ended September 30, 2026	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of June 30, 2026	$	85			$	(1)		$	(39)	$	45
Change in Fair Value Recognized in AOCI, Net of Tax	16			5			—		21
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(20)			—			—		(20)


Amortization of Actuarial (Gains) Losses	—			—			1		1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(20)			—			1		(19)
Income Tax (Expense) Benefit	(4)			—			—		(4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(16)			—			1		(15)
Net Current Period Other Comprehensive Income	—			5			1		6
Balance in AOCI as of September 30, 2026	$	85			$	4		$	(38)	$	51



	Cash Flow Hedges		Pension
Three Months Ended September 30, 2025	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of June 30, 2025	$	92			$	—		$	(104)	$	(12)
Change in Fair Value Recognized in AOCI, Net of Tax	(17)			—			—		(17)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	3			—			—		3
Interest Expense (a)	—			(1)			—		(1)


Reclassifications from AOCI, before Income Tax (Expense) Benefit	3			(1)			—		2
Income Tax (Expense) Benefit	1			—			—		1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	2			(1)			—		1
Net Current Period Other Comprehensive Loss	(15)			(1)			—		(16)
Balance in AOCI as of September 30, 2025	$	77			$	(1)		$	(104)	$	(28)

112



	Cash Flow Hedges		Pension
Nine Months Ended September 30, 2026	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2025	$	78			$	(1)		$	(41)	$	36
Change in Fair Value Recognized in AOCI, Net of Tax	61			5			—		66
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(68)			—			—		(68)


Amortization of Actuarial (Gains) Losses	—			—			4		4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(68)			—			4		(64)
Income Tax (Expense) Benefit	(14)			—			1		(13)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(54)			—			3		(51)
Net Current Period Other Comprehensive Income	7			5			3		15
Balance in AOCI as of September 30, 2026	$	85			$	4		$	(38)	$	51



	Cash Flow Hedges		Pension
Nine Months Ended September 30, 2025	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2024	$	99			$	3		$	(105)	$	(3)
Change in Fair Value Recognized in AOCI, Net of Tax	(15)			(1)			—		(16)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(9)			—			—		(9)
Interest Expense (a)	—			(3)			—		(3)

Amortization of Actuarial (Gains) Losses	—			—			1		1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(9)			(3)			1		(11)
Income Tax (Expense) Benefit	(2)			—			—		(2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(7)			(3)			1		(9)
Net Current Period Other Comprehensive Income (Loss)	(22)			(4)			1		(25)
Balance in AOCI as of September 30, 2025	$	77			$	(1)		$	(104)	$	(28)

(a)Amounts reclassified to the referenced line item on the statements of income.

113

4. RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

As discussed in the 2025 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2025 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2026 and updates the 2025 Annual Report.

Regulated Generating Units (Applies to AEP, PSO and SWEPCo)

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management regularly evaluates cost estimates of complying with these regulations in balance with reliability and other factors, which has resulted in, and in the future may result in, a proposal to retire generating facilities earlier than their currently estimated useful lives.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could reduce future net income and cash flows and impact financial condition.

Regulated Generating Unit that has been Retired and Related Fuel Operations

SWEPCo

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or is seeking recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of September 30, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $167 million, including materials and supplies, net of cost of removal. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions.

As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment of the Pirkey Plant net investment. SWEPCo requested recovery including a weighted average cost of capital carrying charge in its 2025 Arkansas Base Rate Case. In January 2026, the APSC approved a settlement agreement providing for the recovery of the Pirkey Plant net investment over 10 years with a 3% return, and the agreement also included a provision that the retirement of the Pirkey Plant was prudent.

As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032.

In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. In April 2025, the LPSC determined the retirement of the Pirkey Plant was reasonable and prudent and authorized continued recovery of and on the remaining balance of the Pirkey Plant at SWEPCo’s weighted average cost of capital through 2032.

In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the July 2023 PFD conclusion. SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. In April 2026, a unanimous settlement in principle was reached related to the 2025 Texas Base Rate Case. In September 2026, a unanimous stipulation and settlement agreement was filed with the PUCT. The agreement provides for partial recovery of the remaining net book value of the Pirkey Plant over 19 years with no return on the unamortized balance. Due to the settlement in principle reached in April, in the first quarter of 2026, SWEPCo recorded approximately $31 million for a probable, partial regulatory disallowance of the Pirkey Plant. See the “2025 Texas Base Rate Case” section below for additional information. As of September 30, 2026, the Texas jurisdictional share of the net book value of the Pirkey Plant was $47 million. To the extent the PUCT does not accept the settlement and any costs included in this filing are not approved for recovery as a result of the final PUCT order, it could reduce future net income and cash flows and impact financial condition.

114

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. Following the 2024 Oklahoma Base Rate Case, PSO continues to recover Northeastern Plant, Unit 3 through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP, which the Federal EPA has proposed to approve. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026. In the first quarter of 2026, PSO retired $325 million of coal-related assets at Northeastern Plant, Unit 3, resulting in a decrease to both Total Property, Plant and Equipment and Accumulated Depreciation and Amortization. As of September 30, 2026, the unrecovered value of these assets was $152 million, inclusive of ARO costs, which PSO is currently collecting in rates.

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. In February 2026, the APSC issued an order approving the application for a CCN. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. In September 2026, the PUCT issued an order approving the stipulation and settlement agreement with a modification establishing a seven-year validity period for the order. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation agreement and term sheet with the LPSC agreeing the application for a CCN should be approved. In October, the LPSC issued an order approving the joint stipulation agreement.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2026, of generating facilities planned for retirement:


Plant	Net Book Value		Accelerated Depreciation Regulatory Asset				Cost of Removal Regulatory Liability		Projected Retirement Date			Current Authorized Recovery Period		Annual Depreciation (a)
	(dollars in millions)
Northeastern Plant, Unit 3	$	50			$	259				$	22		(b)		2026		(c)	$	8

Welsh Plant, Units 1 and 3	220			264				56		(d)		2028	(e)		(f)	43

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with the removal of Northeastern Plant, Unit 3, after retirement.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.

(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.

(e)Represents projected retirement date of coal assets.

(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

115

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except OPCo)


		AEP
		September 30,		December 31,
		2026		2025
Noncurrent Regulatory Assets		(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation		$	264			$	220
UTM Deferred Costs		89			56
System Resiliency Plan Deferred Costs - Texas		73			17
Plant Retirement Costs - Unrecovered Plant, Pirkey - Texas, FERC		61			93








Storm-Related Costs		46			43

Other Regulatory Assets Pending Final Regulatory Approval		7			6
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (a) (b)		376			363
Plant Retirement Costs – Asset Retirement Obligation Costs (c)		289			257
NOLC Costs (d)		83			89

Deferred Pension and OPEB Costs		40			27
Vegetation Management Costs		37			—
Other Regulatory Assets Pending Final Regulatory Approval		169			136
Total Regulatory Assets Pending Final Regulatory Approval	$	1,534			$	1,307

(a)In March 2026, the WVPSC issued a financing order approving a securitization that included $40 million of West Virginia jurisdictional storm operation and maintenance costs that are subject to a final review by the WVPSC after bond pricing.

(b)In May 2026, APCo issued securitization bonds that included $141 million of Virginia storm operation and maintenance costs.

(c)Includes ARO adjustment related to the revised CCR Rule to be addressed in future regulatory proceedings. See the “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(d)Approved for collection through rates, subject to refund, for the Oklahoma and SWEPCo-Texas jurisdictions.


	AEP Texas
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
UTM Deferred Costs	$	89			$	56
Storm-Related Costs	41			41

System Resiliency Plan Deferred Costs	34			17

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	51			31
Deferred Pension and OPEB Costs	40			27




Other Regulatory Assets Pending Final Regulatory Approval	9			9
Total Regulatory Assets Pending