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美國
證券交易委員會
華盛頓特區20549
形式 10-Q

根據1934年《證券交易法》第13或15(d)條的季度報告
截至季度 2024年9月30日
根據1934年《證券交易所法》第13或15(d)條提交的過渡報告
從_到_的過渡期
委員會 註冊人; 國稅局僱主
文件號 地址和電話號碼 成立州 識別號
     
1-3525 美國電力有限公司紐約 13-4922640
333-221643AEP德克薩斯公司德拉瓦51-0007707
333-217143 AEP傳輸公司德拉瓦 46-1125168
1-3457 阿巴拉契亞電力公司維吉尼亞 54-0124790
1-3570 印第安納密西根電力公司印第安納 35-0410455
1-6543 俄亥俄電力公司俄亥俄 31-4271000
0-343 俄克拉荷馬州公共服務公司 俄克拉 73-0410895
1-3146 西南電力公司德拉瓦 72-0323455
  河濱廣場1號哥倫布,俄亥俄43215-2373  
  電話(614)716-1000  

根據該法第12(b)條登記的證券:
Registrant 每個班級的標題 交易符號註冊的每個交易所的名稱
美國電力公司 普通股,面值6.50美金 AEP納斯達克證券市場有限責任公司
通過複選標記確定登記人是否(1)在過去12個月內(或在登記人被要求提交此類報告的較短期限內)提交了1934年證券交易法第13或15(d)條要求提交的所有報告,以及(2)在過去90天內是否已遵守此類提交要求。
是的x沒有
通過勾選來驗證註冊人是否已在過去12個月內(或在註冊人被要求提交此類文件的較短期限內)以電子方式提交了根據S-t法規第405條(本章第232.405條)要求提交的所有交互數據文件。
是的x沒有
通過勾選標記檢查美國電力公司是否是大型加速文件夾、加速文件夾、非加速文件夾、小型報告公司或新興成長型公司。 請參閱《交易法》第120條第2條中「大型加速申報人」、「加速申報人」、「小型報告公司」和「新興成長型公司」的定義。
 
大型加速文件夾 x加速編報公司非加速歸檔
      
小型上市公司新興成長型公司
通過勾選AEP Texas Inc.,AEP輸電公司、阿巴拉契亞電力公司、印第安納州密西根電力公司、俄亥俄州電力公司、俄克拉荷馬州公共服務公司和西南電力公司是大型加速申報機構、加速申報機構、非加速申報機構、小型報告公司或新興成長型公司。 請參閱《交易法》第120條第2條中「大型加速申報人」、「加速申報人」、「小型報告公司」和「新興成長型公司」的定義。
 
大型加速文件夾加速編報公司非加速歸檔x
      
小型上市公司新興成長型公司 
如果是新興成長型公司,請通過勾選標記表明註冊人是否選擇不利用延長的過渡期來遵守根據《交易法》第13(a)條規定的任何新的或修訂的財務會計準則。
通過勾選註冊人是否是空殼公司(定義見《交易法》第120條第2款)。是的沒有x
AEP德克薩斯公司,AEP Transaction Company,LLC、阿巴拉契亞電力公司、印第安納州密西根電力公司、俄亥俄電力公司、俄克拉荷馬州公共服務公司和西南電力公司滿足10-Q表格一般說明H(1)(a)和(b)中規定的條件,因此提交本表格10-Q,並採用一般說明H(2)至表格10-Q中規定的簡化披露格式。



股份數目
普通股
傑出的
註冊人截至
2024年11月6日
 
美國電力公司532,565,335 
 (面值6.50美金)
AEP德克薩斯公司100 
(面值0.01美金)
AEP變速箱公司(a)NA
阿巴拉契亞電力公司13,499,500 
 (no面值)
印第安納密西根電力公司1,400,000 
 (no面值)
俄亥俄州電力公司27,952,473 
 (no面值)
俄克拉荷馬州公共服務公司9,013,000 
 (面值15美金)
西南電力公司3,680 
 (面值18美金)

(a)100%權益由美國電力公司的全資子公司AEP Transmission Holding Company,LLC持有。
NA 不適用因



美國電力公司及附屬公司
表格10-Q季度報告索引
2024年9月30日
   
  頁面
  Number
術語彙編
   
前瞻性資料
   
第一部分.財務資料
   
 第1、2、3和4項-財務報表、管理層對財務狀況和經營結果的討論和分析、關於市場風險和控制以及程式的定量和定性披露:
   
美國電力公司和子公司: 
 管理層對財務狀況和經營成果的討論和分析
 簡明綜合財務報表
   
AEP德克薩斯公司和子公司:
管理層的敘述性討論和經營結果分析
簡明綜合財務報表
AEP傳輸公司、LLC及其子公司: 
 管理層的敘述性討論和經營結果分析
 簡明綜合財務報表
阿巴拉契亞電力公司及其子公司: 
 管理層的敘述性討論和經營結果分析
 簡明綜合財務報表
   
印第安納密西根州電力公司及其子公司: 
 管理層的敘述性討論和經營結果分析
 簡明綜合財務報表
   
俄亥俄州電力公司及其子公司: 
 管理層的敘述性討論和經營結果分析
 簡明綜合財務報表
   
俄克拉荷馬州公共服務公司: 
 管理層的敘述性討論和經營結果分析
 簡明財務報表
   
西南電力公司合併: 
 管理層的敘述性討論和經營結果分析
 簡明綜合財務報表
   
登記人簡明財務報表簡明注釋索引
   
控制和程式



第二部分. 其他信息 
     
 項目1. 法律訴訟
 項目1A. 危險因素
 項目2. 股權證券的未登記銷售和收益的使用
項目3. 優先證券
 項目4. 礦山安全披露
 項目5. 其他信息
 項目6. 展品
     
簽名  
     
     
該合併表格10-Q由美國電力公司單獨提交,AEP德克薩斯公司,AEP輸電公司、阿巴拉契亞電力公司、印第安納州密西根電力公司、俄亥俄州電力公司、俄克拉荷馬州公共服務公司和西南電力公司。 此處包含的與任何個人註冊人有關的信息均由該註冊人代表其自己提交。 除美國電力公司外,每個註冊人不對與其他註冊人相關的信息做出任何陳述。



術語表

當以下術語和縮寫出現在本報告文本中時,其含義如下。
Term意義
   
AEGCO AEP發電公司,AEP電力公司的子公司。
AEP 
美國電力公司是一家投資者擁有的電力公用事業控股公司,包括美國電力公司(母公司)和持有多數股權的合併子公司和合並附屬公司。
AEP積分 
AEP Credit,Inc.,AEP的合併VIE,將關聯電力公用事業公司的應收賬款和應計公用事業收入證券化。
AEP能源供應有限責任公司
不受監管的控股公司,經營AEP的競爭發電、批發和零售業務,以及AEP的全資子公司。
AEP可再生能源
AEP Energy Supply LLC的一個部門,開發和/或收購大型可再生專案,這些專案有與信譽良好的交易對手簽訂的長期合同作為後盾。
AEP德克薩斯州AEP德克薩斯公司,AEP電力公司的子公司。
AEP傳輸控股公司 
AEP傳輸控股公司,AEP的全資子公司。
AEPEP
AEP Energy Partners,Inc.是AEP的子公司,致力於在放鬆管制的市場中從事批發營銷和交易、對沖活動、資產管理以及商業和工業銷售。
AEPSC 
美國電力服務公司是一家AEP服務子公司,為AEP及其子公司提供管理和專業服務。
AEPTCo
AEP Transaction Company,LLC是AEP Transaction Holdco的全資子公司,是一家擁有State Transcos的中間控股公司。
AEPTCo母公司
AEP Transaction Company,LLC是AEPTCo合併中State Transcos的控股公司。
AFUDC建設期間使用的股權基金津貼。
ALJ
行政法法官。
澳磁 累計其他綜合收入。
APCO 阿巴拉契亞電力公司,AEP電力公司的子公司。
阿巴拉契亞消費者利率救濟基金
阿巴拉契亞消費者稅率救濟基金有限責任公司是APCo的全資子公司,也是一家合併VIE,旨在發行和服務與回收不足的擴大淨能源成本遞延餘額相關的證券化債券。
APSC阿肯色州公共服務委員會。
Aro資產報廢義務。
ASU會計準則更新。
ATM在市場上。
CAA清潔空氣法。
CAMT企業替代最低稅。
CCR煤炭燃燒殘渣。
CO2
 二氧化碳和其他溫室氣體。
CODM首席運營決策者。
庫克工廠 Donald C.庫克核電站是一座兩機組、2,296 MW核電站,由I & m擁有。
CSAPR跨州空氣污染規則。
信使 建築工程正在進行中。
LCC燃料
BCC Fuel XV、BCC Fuel十六、BCC Fuel XVII、BCC Fuel XVIII、BCC Fuel XIX和BCC Fuel XX合併了為收購、擁有和向I & m租賃核燃料而成立的VIE。
DHLC 
Dolet Hills Lignite Company,LLC是SWEPCo的全資無煙煤開採子公司。 DHLC是SWEPCo的非合併VIE。
DIR分銷投資騎手。
i


Term意義
   
EIS
能源保險服務公司,一家非附屬專屬保險公司和AEP的合併VIE。
ELG廢水限制準則。
ENEC擴大淨能源成本。
能源供應
AEP Energy Supply LLC是AEP競爭性發電、批發和零售業務的一家不受監管的控股公司,也是AEP的全資子公司。
股權單位
AEP的股票單位於2020年8月發行。
ERCOT 德克薩斯州區域輸電組織電力可靠性委員會。
ESP 
電力安全計劃是PUCO要求電力公司通過向PUCO提交文件來調整費率。
ETR
有效稅率。
ETT
Electric Transaction Texas,LLC是AEP Transaction Holdco和Berkshire Hathaway Energy Company之間的股權合資企業,旨在擁有和運營ERCOt的輸電設施。
過多的ADIT超額累計遞延所得稅。
FAC燃油調整條款。
FASB 財務會計準則委員會。
聯邦環保局美國環境保護局。
FERC 聯邦能源監管委員會。
FGD 廢氣淨化或洗滌器。
FIP聯邦實施計劃。
FTR
金融輸電權是一種金融工具,使持有人有權就電網擁堵導致地點價格差異時產生的某些與輸電相關的輸電費用獲得補償。
GAAP 美國普遍接受的會計原則。
溫室氣體溫室氣體。
I & M 印第安納密西根電力公司,AEP電力公司的子公司。
IRA
2022年8月16日,拜登總統簽署了通常稱為「通貨膨脹削減法案」(IRA)的立法。
IRP綜合資源計劃。
美國國稅局 國稅局。
國貿中心投資稅收抵免。
IURC印第安納州公用事業監管委員會。
KGPCo
Kingsport Power Company是AEP電力公司的子公司。
KPCo 
肯塔基電力公司,AEP電力公司的子公司。
KPSC肯塔基州公共服務委員會。
千瓦時
千瓦時。
LPSC 
路易斯安那州公共服務委員會。
汞和空氣有毒標準。
MISO 
中部獨立系統運營商。
米切爾工廠
位於西維吉尼亞州蒙茲維爾的一座兩台機組、1,560 MW燃煤發電廠。 該工廠由KPCo和WPCo共同擁有。
MMBtu 
百萬英國熱量單位。
MPSC
密西根州公共服務委員會。
MTM 
按市場計價。
MW 
兆瓦。
兆瓦時 
兆瓦時。
ii


Term含義
   
NAAQS
國家環境空氣質量標準。
NCWF
North Central Wind Energy Facilities是PSO和SWEPCo的聯合項目,其中包括俄克拉荷馬州的三個風電設施,總髮電量約爲1,484 MW。
NRRD
新墨西哥州可再生髮展有限責任公司。
非公用事業資金池 
AEP使用集中融資機制來滿足某些非公用事業子公司的短期現金需求。
NOLC淨營業虧損結轉。
不是的x
氮氧化物。
OCC 俄克拉荷馬州公司委員會。
Opco 俄亥俄電力公司,AEP電力公司的子公司。
OPEB 其他退休後福利。
場外交易 非處方藥。
OvEC 俄亥俄谷電氣公司,AEP持有該公司43.47%的股份。
父級
美國電力公司,AEP合併中AEP子公司的股權所有者。
PFD
決定提案。
PJM 賓夕法尼亞州-新澤西州-馬里蘭州區域傳播組織。
PLR私人信件裁決。
下午三點半 顆粒物。
PPA購買電力和銷售協議。
變壓吸附
買賣協議。
粒子群優化算法 俄克拉荷馬州公共服務公司,AEP電力公司子公司。
PTC生產稅收抵免。
PUCO 俄亥俄州公用事業委員會。
PUCT 德克薩斯州公用事業委員會。
註冊子公司 
作爲SEC註冊人的AEP子公司:AEP Texas、AEPTCo、APCo、I & m、OPCo、PSO和SWEPCo。
註冊人
SEC註冊人:AEP、AEP Texas、AEPTCo、APCo、I & m、OPCo、PSO和SWEPCo。
恢復資金
AEP Texas Restoration Funding LLC是AEP Texas的全資子公司,也是一家合併VIE,旨在發行和服務與主要由颶風哈維造成的德克薩斯州風暴恢復相關的證券化債券。
風險管理協議 
交易性和非交易性衍生品,包括指定爲現金流和公允價值對沖的衍生品。
羅克波特工廠
由AEGCo和I & m共同擁有的發電廠,由印第安納州羅克波特附近的兩臺1,310 MW燃煤發電機組組成。
股權回報率。
每分鐘轉速可靠性定價模型。
RTO 
區域輸電組織,負責在大型州際地區輸送電力。
Sabine 
Sabine Mining Company是一家無煙煤採礦公司,是AEP和SWEPCo的合併VIE。
美國證券交易委員會美國證券交易委員會。
SIP州實施計劃。
SnF 乏核燃料。
所以2
 二氧化碳。
SPP 西南電網區域輸電組織。
SSO 標準服務提供。
iii


Term含義
   
州立運輸公司
AEPTCo的七家全資擁有、受FERC監管、僅限輸電的電力公用事業公司,在地理上與AEP現有的公用事業運營公司保持一致。
斯威普科 西南電力公司,AEP電力公司的子公司。
稅制改革
2017年12月22日,總裁·特朗普將被稱爲《減稅與就業法案》的立法簽署爲法律。TCJA包括對1986年《國稅法》的重大修改,包括從2018年1月1日起將企業聯邦所得稅稅率從35%降至21%。
過渡期資金 
AEP德克薩斯中央過渡基金III LLC是AEP德克薩斯的全資子公司,合併VIE成立的目的是發行和服務與德克薩斯州重組立法相關的證券化債券。
傳送源能源
TRANSOURCE Energy,LLC是一家合併的VIE,成立的目的是投資於公用事業公司,這些公用事業公司根據FERC批准的費率開發、收購、建造、擁有和運營輸電設施。
土耳其工廠 
小約翰·W·特克位於阿肯色州的650兆瓦燃煤電廠,Swepco持有該電廠73%的股份。
UPA單位功率協議。
公用事業資金池 
AEP使用集中融資機制來滿足某些公用事業子公司的短期現金需求。
VIE可變利息實體。
弗吉尼亞州SCC 弗吉尼亞州公司委員會。
該條例 Wheeling Power Company是AEP電力公司的子公司。
WVP SC西弗吉尼亞州公共服務委員會。
iv


前瞻性信息

註冊人所作的這份報告包含1934年證券交易法第21E節所指的前瞻性陳述。許多前瞻性陳述出現在本季度報告的第I部分--第2項管理層對財務狀況和經營結果的討論和分析中,但本文中還存在其他前瞻性陳述,這些陳述可以通過以下詞語來識別:「預期」、「預期」、「打算」、「計劃」、「相信」、「將」、「應該」、「可能」、「將會」、“項目,「繼續」和類似的表述,包括反映未來結果或指導和展望的陳述。這些事項受風險和不確定性的影響,可能導致實際結果與預測的結果大不相同。本文檔中的所有前瞻性陳述均爲截至本文件之日的陳述。*除非適用法律要求,否則管理層沒有義務更新或修訂任何前瞻性陳述。可能導致實際結果與前瞻性陳述中的結果大不相同的因素包括:
AEP服務地區的經濟條件、電力市場需求和人口結構的變化。
全球衝突和貿易緊張局勢加劇帶來的經濟影響,以及採取或擴大經濟制裁、關稅或貿易限制。
通貨膨脹或通貨緊縮的利率趨勢。
任何原因引發的金融市場波動和中斷,包括與聯邦預算或債務上限問題有關的動盪或銀行業的不穩定;特別是影響到爲新資本項目融資和爲現有債務再融資的資金供應或成本的事態發展。
資金的可獲得性和成本,以滿足營運資本和資本需求,特別是(A)如果出售資產、子公司和稅收抵免以及預期證券化的預期資本來源沒有實現或沒有實現預期水平,以及(B)在產生成本和收回成本之間的時間間隔很長且成本很大的情況下。
不斷變化的電力需求。
極端天氣條件、自然災害以及風暴、乾旱條件和野火等災難性事件造成的重大風險的影響,包括潛在的訴訟和無法追回所產生的重大損害和恢復費用。
對可用於賠償與自然災害或業務有關的損失的保險金額和類型的限制或限制。
燃料及其運輸成本、燃料供應方和運輸方的信譽和表現,以及儲存和處置用過燃料的費用,包括煤灰和SNF。
燃料的可獲得性和必要的發電能力以及發電廠的性能。
通過管制或競爭性電價收回燃料和其他能源成本的能力。
建設或購買發電(包括可再生能源)、輸電線路和設施的能力(包括獲得任何必要的監管批准和許可的能力),以滿足以可接受的價格和條件滿足電力需求的能力,包括優惠的稅收待遇、監管機構對發電項目實施的成本上限和對監管委員會和客戶的其他運營承諾,以及收回所有相關成本。
由於對經濟或市場狀況的影響、遵守潛在政府法規的成本、電力使用、供應鏈問題、大流行、自然災害或其他事件導致的客戶、服務提供商、供應商和供應商造成的業務運營中斷。
新的立法、訴訟或政府法規,包括修改稅收法律和條例、監督核能發電、能源商品交易以及減少硫、氮、汞、碳、煙塵或PM以及其他可能影響發電廠和相關資產持續運營、成本回收和/或盈利能力的物質的新的或更高的排放要求。
聯邦稅收立法對經營結果、財務狀況、現金流或信用評級的影響。
發電前、發電期間和發電後與所使用的燃料或這種燃料的副產品和廢物有關的風險,包括火山灰和SNF。
未決和未來電價案件的時間和解決、談判和其他監管決定,包括髮電、配電和輸電服務以及環境合規方面的新投資的電價或其他回收。
解決訴訟或監管程序或調查。
能夠有效地管理運營和維護成本。
發電和批發銷售的價格和需求。
技術的變化,特別是在能源存儲和新的、開發中的、替代的或分佈式發電來源方面。
通過費率收回可能在之前預計使用壽命結束前退役的發電機組的任何剩餘未收回投資的能力。
v


煤炭和其他與能源有關的商品市場的波動和變化,特別是天然氣價格的變化。
客戶、監管機構、投資者和利益相關者不斷變化的預期和需求的影響,包括與環境、社會和治理問題相關的不斷變化的預期。
公用事業監管的變化和包括ERCOT、PJM和SPP在內的RTO的費用分配。
訂立合同安排的交易對手,包括能源交易市場參與者的信譽變化。
評級機構的行動,包括改變債務評級。
資本市場波動對養卹金、對外經濟夥伴關係、專屬自保保險實體和核退役信託基金所持投資價值的影響,以及這種波動對未來資金需求的影響。
會計準則制定機構定期發佈的會計準則。
其他風險和不可預見的事件,包括戰爭和軍事衝突、恐怖主義的影響(包括安全成本增加)、禁運、網絡安全威脅、影響材料供應鏈的勞工罷工、全球信息技術中斷和其他災難性事件。
吸引和留住必要的勞動力和關鍵人員的能力。

註冊人的前瞻性陳述僅適用於本報告日期或截至其發佈日期。 註冊人明確否認更新任何前瞻性信息的任何義務,法律要求的除外。 有關這些因素的更詳細討論,請參閱2023年年度報告第一部分和本報告第二部分中的「風險因素」。

註冊人可以使用AEP的網站作爲重要公司信息的分發渠道。 有關注冊人的財務信息和其他重要信息通常會發布在AEP網站www.aep.com/investors/上並可訪問。 此外,當您通過訪問www.aep.com/investors/上的「電子郵件提醒」部分註冊您的電子郵件地址時,您可能會自動收到電子郵件提醒和有關注冊人的其他信息。

公司網站和SEC文件的可用性

我們的主要公司網站地址是www.aep.com。 我們網站上的信息並未以引用的方式納入本文,也不是本表格10-Q的一部分。 在此類文件以電子方式提交或提供給SEC後,我們將在合理可行的範圍內儘快通過我們的網站免費提供我們的10-k表格年度報告、10-Q表格季度報告、8-k表格當前報告以及根據《交易法》第13(a)或15(d)條提交或提供的報告的修訂。 SEC維護一個網站www.sec.gov,其中包含報告、代理和信息聲明以及有關AEP的其他信息。
vi


第一部分. 財務資料

美國電力公司及附屬公司
管理層對財務狀況和財務狀況的討論與分析
行動的結果

高管概述

AEP歸屬於普通股股東的合併收益

2024年第三季度與2023年第三季度相比

歸屬於AEP普通股股東的盈利保持穩定,從2023年的9.54億美元小幅增加至2024年的96000萬美元。

截至2024年9月30日的9個月與截至2023年9月30日的9個月

歸屬於AEP普通股股東的盈利從2023年的187200萬美元增加到2024年的230300萬美元,主要原因是:

2024年收到PLR的有利影響與零售費率制定中NOLC的處理有關。 有關更多信息,請參閱下面的「零售司法管轄區的NOLC- IRS PLR」部分。
AEP各個司法管轄區的優惠利率訴訟。
有利的天氣和商業客戶類別負荷增加推動銷量增加。
輸電資產投資,帶來了更高的收入和收入。
2023年競爭性合同可再生能源組合的銷售出現虧損。

這些增加被以下因素部分抵消:

與SWEPCo 2012年德克薩斯州基本稅率案件和土耳其工廠相關的收入退款準備金。
由於聯邦環保局於2024年5月最終確定了修訂後的MCR規則,運營費用增加。
2024年4月宣佈的自願遣散計劃產生的遣散費應計。

請參閱「經營業績」部分,了解按經營分部列出的更多信息。
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客戶需求

AEP使用按客戶類別分類的銷量作爲衡量客戶需求的重要驅動因素的一種方法。 下表顯示了按客戶類別劃分的銷量百分比變化:

549755886479
(a)截至2024年9月30日止三個月與截至2023年9月30日止三個月的百分比變化。
(b)截至2024年9月30日止九個月與截至2023年9月30日止九個月的百分比變化。
(c)商業銷售額的增長主要是由於新的數據處理器負載和經濟發展。

2024年重大事件和交易

MCR規則修訂

2024年4月,聯邦環保局最終完成了對《MCR規則》的修訂,以擴大該規則的範圍,將不活躍設施的不活躍蓄水池包括在內,並對涉及直接放置MCR的目前豁免的固體廢物管理單元制定要求土地上。 2024年第二季度,AEP評估了該規則對當前和以前工廠的適用性,並記錄了ARO增加了67400萬美元。 有關更多信息,請參閱下文環境問題中的「MCR規則」部分。

自願遣散計劃

2024年4月,管理層宣佈了一項自願離職計劃,旨在減少AEP的員工規模。在AEP的16,800名員工中,約有7,400人有資格參加該計劃。大約有1,000名員工選擇接受自願離職方案,幾乎所有員工都在2024年7月終止了就業。遣散費計劃爲每一年的服務提供兩週的基本工資,最低爲四周,最高爲52周的基本工資。受自願離職計劃影響的某些職位已經並將繼續得到補充,以維持安全、有效和高效的運營。該計劃的淨節省將有助於抵消不斷增加的運營費用和高昂的利息成本,以保持客戶負擔得起的電力成本。AEP在2024年第二季度記錄了12200美元的萬稅前支出,與這一自願離職計劃有關。登記人在2024年第三季度支付了11100美元的萬遣散費。更多信息見附註13--自願離職計劃。


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零售司法管轄區的NOLC- IRS PLR

登記人已向州委員會提交費率備案,以過渡到零售費率制定中對NOLC的獨立處理。 註冊人於2024年之前完成了田納西州、西弗吉尼亞州和弗吉尼亞州的過渡,並於2024年7月完成了密歇根州的過渡。 在最近的KPCo、I & m(印第安納州管轄區)、PSO和SWEPCo基本利率案件中,這些公司申請過渡到獨立利率制定,這取決於IRS的支持PLR。

2024年4月,從國稅局收到了某些零售司法管轄區的支持性PLR,自2024年3月起生效。 PLR得出的結論是,在獨立利率制定基礎上的NOLC應納入利率基礎中,並且還應納入將退還給客戶的超額ADIT監管責任的計算中。 基於這一結論,I & m、PSO和SWEPCo確認了與將從客戶收取的收入要求金額相關的監管資產,減少了超額ADIT監管負債,並對2024年第一季度淨利潤產生了有利影響,如下表所示:

公司確認監管資產帶來的稅前收入增加減少所得稅發票(a)淨收入增長
(in數百萬)
I & M$20.2 $49.5 $69.7 
粒子群優化算法12.1 44.7 56.8 
SWEPCO35.4 101.1 136.5 
AEP總計$67.7 $195.3 $263.0 

(a)主要涉及超額ADIT監管負債的22400萬美元重新計量,部分被確認監管資產產生的稅前有利收入的2900萬美元稅收費用抵消。

2024年第二季度,印第安納州、俄克拉荷馬州和德克薩斯州提出了尋求爲這些監管資產建立收回機制的請求。 在印第安納州和俄克拉荷馬州,某些干預者對監管資產的復甦提出了質疑,或者提出了將抵消監管資產復甦的利率制定處理方法。 2024年第三季度,德克薩斯州的PUCT工作人員和某些干預者要求舉行聽證會,SWEPCo於2024年10月提交了直接證詞。

AEP現場合作夥伴的處置

2023年4月,AEP啓動了AEP Onsite Partners所有權的銷售流程。 AEP Onsite Partners瞄準了分佈式太陽能、供熱發電、能源存儲、廢熱回收、能源效率、峯值發電和其他能源解決方案方面的機會。 2024年5月,AEP簽署了一項協議,將AEP Onsite Partners出售給非附屬第三方。 2024年9月,AEP完成了向非附屬第三方的出售,並收到了約31800萬美元的現金收益(扣除稅款和交易成本)。 收益用於償還短期債務。 有關更多信息,請參閱註釋6的「AEP現場合作夥伴的處置」部分。

聯邦稅收立法

2022年8月,拜登總統簽署人力資源5376成爲法律,通常稱爲2022年《通貨膨脹削減法案》(IRA)。 最值得注意的是,這項預算協調立法對調整後財務報表收入(CAMT)設定了15%的最低稅,擴大並增加了PTC和ITC的價值,增加了核能和清潔氫PTC、能源存儲ICT,並允許向第三方出售或轉讓稅收抵免以獲取現金。 由於預計財政部和國稅局將對IRA的稅收規定提供進一步的重要指導,AEP將繼續監控任何已發佈的指導並評估對未來淨利潤、現金流和財務狀況的影響。

2024年9月,財政部和國稅局發佈了有關CAMt應用的擬議法規。 AEP及其子公司須遵守CAMt,預計將在2024年產生負債。 然而,預計產生的任何CAMt現金稅將被監管復甦、稅收抵免的利用以及出售稅收抵免產生的現金流入部分抵消。 稅收抵免的出售在現金流量表的經營部分中列示,與已付現金稅款的列示一致。 AEP列出通過所得稅費用出售稅收抵免的損失。

2024年4月,美國國稅局發佈了與稅收抵免轉讓相關的最終規定。 2023年,AEP代表PSO、SWEPCo和AEP Energy Supply LLC與非附屬方簽訂了可轉讓協議,出售2023年產生的PTC,產生現金收益約1.74億美元,2023年收到1.02億美元,6200萬美元
3


已於2024年第一季度收到,其餘1000萬美元已於2024年第二季度收到。 2024年第三季度,AEP代表PSO、SWEPCo和APCo與非附屬方簽訂了可轉讓協議,出售2024年產生的PTC,這將產生約1.37億美元的現金收益,其中約9100萬美元於2024年第三季度收到,其餘美元預計2024年第四季度和2025年第一季度將收到4600萬美元。 AEP預計將繼續探索通過第三方轉讓協議有效地將其稅收抵免貨幣化的能力。

I & M的庫克工廠有資格獲得可轉讓的核PTC,該技術適用於2024年至2032年開始的納稅年度。核PTC是根據發電量和出售給第三方的電力計算的,並且隨着設施的總收入增加到一定閾值以上,就會受到「削減金額」的影響。 2024年第三季度,AEP和I & m已將估計價值6400萬美元的核PTC納入其年化ETR中。 在沒有具體IRS指導的情況下,AEP和I & M估計的2024年核PTC是使用庫克工廠2024年總收入和預測年發電量計算的。 如果IRS最終發佈指導,則如有必要,估計的核PTC值將更新以反映此類指導。 有關更多信息,請參閱註釋11 -所得稅。

新一代支持可靠性

AEP受監管發電組合的增長反映了該公司滿足客戶能源和容量需求同時平衡成本和可靠性的承諾。

重要的批准一代文件

AEP已獲得各州監管委員會的監管批准,收購約2,505兆瓦的自有可再生能源發電設施,總額約60億美元。 這些設施的估計成本已包含在下文財務狀況部分的預算資本支出披露中。 此外,AEP還獲得了792兆瓦的可再生能源購買電力協議的監管批准。下表總結了截至2024年9月30日活躍可再生能源項目收到的監管批准:

公司一代類型預期商業運營擁有/PPA發電量
(in MW)
APCO太陽能2024-2027PPA339 
APCo(a)2025-2026擁有344 
I & M太陽能2026PPA100 
I & M太陽能2027擁有469 
I & M風能/太陽能2025-2027PPA280 
PSO(b)太陽能2025-2026擁有340 
PSO(b)2025-2026擁有553 
SWEPCo(c)太陽能2025PPA73 
SWEPCo(c)2024-2025擁有799 
已批准的可再生項目總數3,297 

(a)APCo發佈通知,將繼續建設204兆瓦的風電容量。
(b)PSO發佈通知,繼續建設兩個風電設施和一個太陽能設施,總容量爲477兆瓦。 這些設施反映了PSO新增可再生能源發電總量893兆瓦內考慮的第一個批准項目。
(c)包括APSC和LCSC對已開工建設的799兆瓦自有風電項目的批准。 此外,LCSC批准了彈性選項,允許SWEPCo爲路易斯安那州客戶提供額外服務,並收回被PUCT拒絕的部分項目。

2024年6月,PSO與PSA達成協議,收購位於俄克拉荷馬州的795 MW聯合循環發電設施。 此次收購須經BCC預先批准,包括附加條款的批准,以允許在未來利率情況下納入基本利率之前進行資產回收。 此次收購還需要FERC根據《哈特-斯科特-羅迪諾法案》的批准和許可。 如果獲得這些批准,PSO預計將於2025年6月30日完成交易。
4


除了上面討論的發電項目外,AEP還簽訂了容量購買協議(CPA),以滿足運營公司爲客戶服務的容量儲備利潤率。 下表包括2024-2028年五年期間當前合同下的CPA金額(按年份):

I & MKPCoPSO SWEPCO該條例
天然氣天然氣天然氣天然氣
交付開始年份(in MW)
2024230 314 74 80 1,114 29 425 57 72 
2025— 440 — 85 1,150 29 500 157 — 
2026— — — — 980 86 350 100 — 
2027— 210 — — 260 86 300 100 — 
2028— 1,050 — — 260 — 300 — — 

重大世代提案請求(RFP)

下表包括爲自有和購買發電發佈的有效RFP。 除非另有說明,否則發佈的RFPs是對認證能力的全來源招標。 選定的項目將獲得監管機構的批准。

公司發行日期預計
在職日期
發電量
(in MW)
KPCo(a)2023年9月2026/20271,300 
粒子群優化算法2023年11月2027/20281,500 
SWEPCO2024年1月20282,100 
APCo(b)2024年5月20281,100 
I & m(c)2024年9月20294,000 
重要的RFP總數10,000 

(a)RFP僅尋求PPA提案。
(b)RFP正在尋求風能、太陽能、獨立電池儲能系統和可再生能源證書。
(c)RFP從間歇性(風能、太陽能)、非間歇性(可調度)和新興技術資源中尋求高達4,000 MW(累計)。


5


監管事項-公用事業費率和費率訴訟程序

註冊人參與監管委員會的費率案件和其他程序,以制定公平和適當的電力服務費率,以收回成本並賺取公平的投資回報。 根據結果,這些費率案件和訴訟可能會對運營結果、現金流甚至可能對財務狀況產生重大影響。 AEP目前參與以下關鍵程序:

下表顯示了登記人在2024年已完成和懸而未決的基本費率案件程序。 有關更多信息,請參閱註釋4 -費率很重要。

已完成的基本利率案件訴訟程序

年度
基本收入核可新費率
公司管轄權增加有效
(in數百萬)
粒子群優化算法俄克拉荷馬州$131.0 (a)9.3%2024年1月
APCO維吉尼亞127.0 (b)9.5%2024年1月
KPCo肯塔基州60.0 (c)9.75%2024年1月
I & M印第安納州62.0 (d)9.85%2024年5月
I & M密西根17.0 9.86%2024年7月
AEP德克薩斯州德克薩斯州70.0 9.76%2024年10月

(a)更多信息請參閱2023年年度報告注4的「2022年俄克拉荷馬州基本利率案例」部分。
(b)更多信息,請參閱2023年年度報告注4的「2020-2022年弗吉尼亞三年期回顧」部分。
(c)更多信息請參閱2023年年度報告注4的「2023年肯塔基州基本利率和證券化案例」部分。
(d)印第安納州稅率分兩步上調,從2024年5月起每年上漲2800萬美元,其餘3400萬美元的年度上漲將於2025年1月起生效,具體取決於I & M截至2024年12月31日的發電廠運營水平,與I & M 2024年預測測試年相比。

懸而未決的基本利率案件訴訟程序

每年一次
歸檔基本收入請求
公司管轄權日期增加請求
(in數百萬)
粒子群優化算法俄克拉荷馬州2024年1月$218.0 (a)10.8%
APCO維吉尼亞2024年3月64.0 (b)10.8%
APCO西弗吉尼亞2024年11月250.5 10.8%
(a)2024年10月,PSO、OSC和某些干預者與OSC提交了一份聯合規定和和解協議,其中包括基於9.5%的ROE,年淨收入增加12000萬美元。 2024年10月,BCC舉行了聽證會,PSO實施了臨時年度基本利率提高12000萬美元,但在BCC做出最終命令之前退款。 預計將於2024年第四季度下達訂單。
(b)2024年9月,APCO提交了對其弗吉尼亞州基本案例的修正案,將之前要求的年度基本利率從9500萬美元減少到6400萬美元。 或者,如果年度環境合規消耗品費用通過APCo的環境費率調整條款從基本費率轉爲回收費率,則該請求將減少至4500萬美元。 預計將於2024年第四季度下達訂單。

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其他重大監管事項

俄亥俄州電除塵器文件

2023年1月,OPCO向PUCO提交了一份申請,要求批准一項ESP,其中包括擬議的費率調整、擬議的新乘客以及某些現有乘客的延續和修改,包括DIR,有效期爲2024年6月至2030年5月。該提案包括某些股東的資本成本的普通股權益回報率爲10.65%。2023年6月,干預者提交了證詞,反對CO的各種新車手計劃和對現有車手的修改,包括DIR。2023年9月,OPCO和某些干預者向PUCO提交了一份解決ESP申請的和解協議。和解協議包括從2024年6月到2028年5月的四年期限,淨資產收益率爲9.7%,並繼續包括DIR在內的一些附加條件,但有收入上限。2024年4月,PUCO發佈了一項命令,批准了和解協議。2024年5月,干預者就批准的和解協議向PUCO提出重審申請,2024年6月,PUCO拒絕了干預者的重審申請。

SWEPCo 2012德克薩斯州基本利率案例

2012年,Swepco向PUCt提出了提高年基本費率的請求,主要原因是土耳其工廠的完工。2013年,PUCt發佈了一項命令,肯定了土耳其工廠的審慎,但確定土耳其工廠在之前的便利和必要性證書案件中設定的德克薩斯州管轄資本成本上限,除了限制其收回現金建築成本外,還限制了Swepco對AFUDC的回收。在2014年的重審中,PUCt推翻了最初的裁決,裁定AFUDC被排除在土耳其工廠德克薩斯州管轄資本成本上限之外。2017年,德克薩斯州地區法院維持了PUCT 2014年的命令,干預者向德克薩斯州第三上訴法院提起上訴。2021年8月,德克薩斯州第三上訴法院推翻了德克薩斯州地區法院的裁決,確認了PUCT對AFUDC的命令,結論是PUCT最初2008年命令的措辭打算將AFUDC納入德克薩斯州司法資本成本上限,並將案件發回PUCt進行未來訴訟。2021年11月,Swepco和PUCt向德克薩斯州最高法院提交了複審請願書。2022年10月,德克薩斯州最高法院駁回了Swepco和PUCt提交的複審請願書。2022年12月,Swepco和PUCt向德克薩斯州最高法院提出了重新審理的請求。2023年6月,德克薩斯州最高法院拒絕了Swepco的重審請求,將案件發回PUCt進行未來的訴訟。2023年10月,Swepco在發回訴訟中向PUCt提交了證詞,建議不退款或不予退款。

2023年12月,PUCT批准了一項初步命令,稱PUCT不會滿足SWEPCo的請求,該請求將允許PUCT找到理由允許SWEPCo在當前的還押程序中超過德克薩斯州管轄權資本成本上限。 由於PUCT批准了初步命令,SWEPCo在2023年第四季度記錄了8600萬美元的稅前非現金免稅額。

PUCT在2023年12月對初步訂單的批准決定,它將在正在進行的PUCT還款程序中解決未來PUCT訂單可能要求向客戶退還的任何潛在收入。2024年3月8日,干預者和PUCt工作人員向PUCt提交了一項動議,要求撤銷Swepco 2023年10月的部分直接證詞和2024年3月的補充直接證詞。2024年4月,干預者和PUCt工作人員提交了證詞,建議客戶在2023年12月之前退款,金額從1.49億美元到1.97億美元不等,包括運費,退款期限從18個月到48個月不等。2024年第二季度,根據PUCT的決定,Swepco記錄了1.6億美元的一次性收入退款撥備,包括利息,與2013年2月至2023年12月收取的收入相關。根據和解協議,Swepco將在兩年內退還與2013年2月至2023年12月收取的收入相關的1.48億美元,包括利息,並將超過德克薩斯州管轄資本成本上限的AFUDC從費率基數中刪除。


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FERC 2021 PJm和SPP傳輸公式速率挑戰

註冊人從2022年預計輸電收入要求開始,並根據2021年實際輸電收入要求調整,在其PJm和SPP輸電公式費率中過渡到對NOLC的獨立處理,並在向FERC提交的信息文件中提供了這一變化的通知。 對於傳播公式費率的NOLC的獨立處理使2024年、2023年、2022年和2021年的年收入需求分別增加了5200萬美元、6100萬美元、6900萬美元和7800萬美元。

2024年1月,FERC發佈了兩項命令,批准某些非關聯客戶在PJM和SPP內擁有AEP變速器的子公司的2021年傳輸公式費率中對NOLC的獨立處理提出正式挑戰。FERC指示AEP變速器擁有PJM和SPP的子公司提供2021年利率年度收取的所有金額的利息退款,並將此類退款反映在下一個利率年度的年度更新中。因此,在2024年第三季度,SPP內擁有AEP變速器的子公司提供了2021年費率年退款的一部分,其餘退款預計將在2025年提供。PJM內部擁有AEP變速器的子公司預計將在2025年提供各自2021年度的退款。2024年2月,AEPSC代表AEP變速器在PJM和SPP內擁有的子公司提出了重新審理的請求。2024年3月,FERC根據法律的實施拒絕了AEPSC關於重新審理2024年1月命令的請求,並表示它可能會在未來的命令中解決重新審理的請求。2024年3月,AEPSC向FERC提交了退款遵守情況報告,該報告保留了FERC 2024年1月命令的非終局性,等待重審和上訴的進一步程序。2024年4月,AEPSC向FERC提交了文件,要求FERC:(A)重新開放記錄,以便FERC可以將2024年4月收到的關於在制定稅率時對待獨立NOLC的IRS PLR作爲證據,並在重審時在實質性命令中進行審議,以及(B)擱置其2024年1月的命令和相關合規備案和退款,以便爲審議2024年4月的IRS PLR提供時間。2024年5月,AEPSC向美國哥倫比亞特區巡迴上訴法院提交了複審請願書,要求對FERC 2024年1月和2024年3月的裁決進行復審。2024年7月,FERC發佈命令,批准AEPSC重新開放記錄的請求,目的是將美國國稅局的PLR納入記錄,並建立額外的簡報程序。2024年8月,AEPSC向FERC提交了簡報,要求委員會修改或推翻其最初的訂單。

由於2024年1月FERC命令,註冊人的資產負債表反映了可能退還2024年、2023年、2022年和2021年傳輸公式費率中包含的所有NOLC收入(含利息)的負債。 註冊人尚未被指示進行與2024、2023或2022年利率年度相關的現金退款。 向附屬和非附屬客戶的可能退款在資產負債表上反映爲遞延信貸和其他非流動負債,但預計將在一年內退還的金額除外,該金額反映在其他流動負債中。 附屬公司可能收到的退款(導致附屬傳輸費用減少)被推遲作爲資產負債表上監管負債的增加或監管資產的減少,如果管理層預計退款將通過授權的零售管轄區附加機制返還給零售客戶。

土耳其工廠的商業部分

SWEPCo在阿肯色州建造了Turk Plant,這是一臺基本負荷600 MW(淨最大容量650 MW)的燃煤超臨界發電機組,於2012年12月投入使用,並被納入垂直綜合公用事業部門。 SWEPCo擁有土耳其工廠73%(440兆瓦/477兆瓦)的股份並運營該設施。 截至2024年9月30日,土耳其工廠的淨資產爲13億美元,未扣除包括快遞和庫存在內的拆除成本。

目前,在阿肯色州,Swepco大約20%的土耳其工廠產量不受基於成本的費率回收的影響。工廠的這部分產量正被賣到批發市場。大約80%的土耳其工廠投資是通過德克薩斯州、路易斯安那州基於零售成本的費率回收,以及通過Swepco的批發客戶按照FERC批准的費率收回的。2022年11月,Swepco向APSC提交了公共便利性和必要性證書,以批准運營土耳其工廠,爲阿肯色州客戶提供服務,並通過成本回收附加條款收回相關成本。土耳其工廠的基於成本的恢復將有助於Swepco的近期產能需求,並支持遵守SPP 2023年增加產能規劃的備用按金要求。2023年4月,干預者提交證詞,建議APSC拒絕公共便利和必要性證書,理由是土耳其工廠不是成本最低的替代方案。2024年3月,APSC發佈了一項命令,拒絕了Swepco關於允許土耳其工廠的商家部分爲阿肯色州客戶服務的請求。由於APSC 2024年3月的訂單,Swepco對淨收入產生了3200萬美元的有利影響,這是因爲與土耳其工廠Extra Adit的商戶部分相關的監管責任減少了。
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肯塔基州證券化案

2024年1月,KPSC發佈了一項融資令,批准了KPCO在證券化債券發行時將某些監管資產餘額證券化的請求,並得出結論,通過證券化要求收回的成本是謹慎發生的。KPSC的融資命令包括與證券化債券結構、營銷、配售和發行相關的某些額外要求,這些要求沒有反映在KPSC的提案中。根據肯塔基州的法定要求和融資命令,證券化債券的發行將在債券定價後由KPSC進行最終審查。KPCO預計將繼續進行證券化債券發行進程,並根據市場狀況在2025年上半年完成證券化進程。截至2024年9月30日,預計通過證券化收回的監管資產餘額總計4.85億美元,其中包括:(A)2.97億美元的工廠退役成本,(B)與2020、2021年、2022年和2023年大風暴相關的7900萬美元的遞延風暴成本,(C)4900萬美元的遞延購買電力支出,(D)5800萬美元的未充分收回的購買電力騎手成本和(E)200萬美元的遞延發行相關支出,包括KPSC顧問費用。如果這些成本中的任何一項無法收回,可能會減少未來的淨收益和現金流,並影響財務狀況。

KPCo的服務、費率和設施調查

2023年6月,KPCC發佈命令,指示KPCo說明爲何不應因未能在其服務區域內提供足夠服務而受到肯塔基州法定補救措施(包括罰款和處罰)的原因。 KPAC的說明原因令沒有對KPCo服務的充分性做出任何決定。 2023年7月,KPCo對演出原因令做出回應,證明其已提供充分的服務。 2023年12月和2024年2月,KPCo和某些干預者向KPAC提交了證詞。 KCSC的聽證會此前計劃於2024年6月舉行。 聽證會被推遲,尚未重新安排。如果KPCo因演出原因令而被處以任何罰款或處罰,可能會減少淨收入和現金流並影響財務狀況。

KPCo燃油調整條款(FAC)審查

2023年12月,KPCo在截至2022年10月31日的兩年期FAC審查中收到了干預者證詞,建議取消其總計4.32億美元的購電成本回收中的4,400萬至6,000萬美元,原因是擬議修改電價制定方法(限制通過FAC收回的購電成本)。 聽證會於2024年2月舉行,KCSC可能會在2024年第四季度或2025年初發布命令。 如果任何燃料成本無法收回或被勒令退款,可能會減少未來的淨利潤和現金流並影響財務狀況。

弗吉尼亞州燃油調整條款(FAC)審查

2023年,APCo向弗吉尼亞州SCC提交了年度燃料成本申請。 弗吉尼亞州臨時FAC費率於2023年11月實施。 在APCo 2022年弗吉尼亞州燃料更新文件中,弗吉尼亞州工作人員命令弗吉尼亞州工作人員開始對APCo截至2019年12月31日、2020年、2021年和2022年的燃料成本進行審計。 弗吉尼亞州的工作人員分析了APCO 2019年至2022年的燃料採購活動,得出的結論是採購做法合理且謹慎,並建議不存在任何折扣。 2024年5月,弗吉尼亞州SCC發佈命令,批准對APCo 2019年和2020年燃料成本的審計,但得出的結論是,對APCo 2021年和2022年燃料成本的審查仍有待進一步評估。 截至2024年9月30日,APCO弗吉尼亞州管轄區未充分回收的燃料餘額爲1.64億美元。 如果任何燃料成本無法收回或被勒令退款,可能會減少未來的淨利潤和現金流並影響財務狀況。

俄亥俄州衆議院第6號法案(HB 6)

2019年7月,俄亥俄州州長簽署了爲零碳排放或減少碳排放的發電設施提供激勵措施的HB 6,使其成爲法律。截至2020年12月31日,HB 6終止了能效計劃,包括OPCO每年2,600美元的共享節省收入萬,並在2026年後逐步取消可再生能源任務。HB 6還規定在可繞過的基礎上到2032年繼續收回現有的可再生能源合同,幷包括一項在2030年之前繼續收回OVEC成本的條款,該條款在不可繞過的基礎上分配給俄亥俄州的所有配電公用事業客戶。OPCO的OVEC公司間電力協議將於2040年6月終止。2020年7月,美國檢察官辦公室領導的一項調查導致聯邦大陪審團起訴俄亥俄州衆議院議長拉里·豪斯霍爾德和其他四人,以及註冊爲501(C)(4)社會福利組織的實體現在世代,他們與涉嫌與收養HB 6有關的敲詐勒索陰謀有關。該案的某些被告此前已認罪,2023年3月,聯邦陪審團判定拉里·豪斯霍爾德和另一人蔘與敲詐勒索陰謀。2024年2月,俄亥俄州大陪審團的起訴書指控某些前FirstEnergy高管和前PUCO董事長及相關實體犯有各種罪行,包括賄賂。2021年,四名AEP股東提起衍生品訴訟,聲稱代表AEP對某些AEP高管和董事提出索賠。2024年4月,AEP與四名股東達成協議,全面和
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最終解決了衍生訴訟,這些訴訟的和解於2024年10月獲得批准。 有關更多信息,請參閱下面訴訟的「與俄亥俄州衆議院第6號法案相關的訴訟」部分。

2021年3月,俄亥俄州州長簽署了一項立法,其中包括廢除了之前根據HB 6授權向俄亥俄州核電站非附屬所有者付款的規定。 新立法即衆議院第128號法案於2021年5月生效,但HB 6中有關能源效率計劃、可再生能源成本回收和OvEC成本回收的其他條款保持不變。 如果法律發生變化或OPCo:(a)無法在2032年底之前以可規避的方式收回可再生能源合同的成本,(b)無法在2030年之後收回DVEC的成本或(c)產生與衍生行爲相關的重大成本,可能會減少未來的淨收入和現金流並影響財務狀況。

颶風海倫

2024年9月下旬,颶風海琳的餘波嚴重影響了APCO的弗吉尼亞州和西弗吉尼亞州的服務區域,導致約26萬客戶停電和APCO電網受損。風暴恢復工作一直持續到10月初,APCO爲2024年10月6日之前失去電力的所有客戶完成了恢復工作。截至2024年9月30日,APCO產生了約1,900萬美元(1,300萬美元涉及弗吉尼亞州司法管轄區,600萬美元涉及西弗吉尼亞州司法管轄區)的增量其他運營和維護費用,以及約800萬美元的資本支出。APCO推遲了1600萬美元的增量其他運營和維護費用作爲監管資產,因爲這些成本被認爲未來有可能收回。根據現有信息,APCO估計風暴恢復總成本約爲1.4億美元,其中70%預計將作爲監管資產遞延,其餘30%成本預計將作爲資本支出。如果與颶風海倫相關的任何成本無法收回,可能會減少未來的淨收入和現金流,並影響財務狀況。

供應鏈中斷和通貨膨脹

註冊人經歷了由多個因素導致的某些供應鏈中斷,包括國際緊張局勢和地區衝突的後果、通貨膨脹、某些行業的勞動力短缺以及某些原材料的供應短缺。 這些供應鏈中斷並未對註冊人的淨收入、現金流和財務狀況產生重大影響,但延長了某些商品和服務的交貨時間,並導致燃料、材料、勞動力、設備和其他所需商品的價格上漲。 管理層已實施風險緩解策略,旨在限制這些供應鏈中斷的影響。

美國經濟經歷了高水平的通脹,導致近期經濟活動前景的不確定性增加,包括通脹速度是否會繼續放緩。 供應鏈和通脹干擾的嚴重性長期持續或進一步加劇可能會導致某些商品、服務和資本成本進一步增加,並進一步延長交貨時間,從而減少未來的淨收入和現金流並影響財務狀況。
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訴訟

在正常業務過程中,AEP涉及就業、商業、環境和監管訴訟。 由於難以預測這些訴訟的結果,管理層無法預測任何損失、罰款或處罰的最終解決方案、時間或金額。 管理層評估每項意外情況的損失可能性,並在可以估計損失的情況下對可能發生損失的情況承擔責任。 這些程序中的不利結果有可能減少未來的淨利潤和現金流並影響財務狀況。 有關更多信息,請參閱注4 -費率問題和注5 -承諾、保證和或有事項。

與俄亥俄州衆議院第6號法案(HB 6)相關的訴訟

2019年,俄亥俄州採用並實施了HB 6,該HB 6授權對某些成本(包括可再生能源合同和DVEC的燃煤發電機組)進行費率回收,從而使OPCo受益。 OPCo在與血紅蛋白6相關的立法過程中進行了遊說工作並提供了證詞。 2020年7月,美國檢察官辦公室領導的一項調查導致聯邦大陪審團對俄亥俄州一名立法者及其同事提出起訴,指控他們涉嫌涉及收養HB 6的敲詐勒索陰謀。 在AEP得知俄亥俄州立法者和其他與血紅蛋白6有關的刑事指控後,AEP在外部顧問的協助下對該法案通過的情況進行了審查。 管理層不認爲AEP參與了與血紅蛋白6通過有關的任何不當行爲。

2020年8月,AEP的一名股東向美國俄亥俄州南區地方法院提起集體訴訟,指控AEP及其某些高管涉嫌違反證券法。 2021年12月,地方法院發佈意見和命令,以偏見駁回證券訴訟投訴,確定投訴未能就任何可訴的虛假陳述或遺漏提出抗辯。 原告沒有對該裁決提出上訴。

2021年1月,AEP的一名股東向美國俄亥俄州南區地區法院提起派生訴訟,聲稱代表AEP對某些AEP高管和董事提出索賠。2021年2月,第二名AEP股東向俄亥俄州富蘭克林縣普通訴訟法院提起了類似的衍生品訴訟。2021年4月,第三名AEP股東向美國俄亥俄州南區地區法院提起類似的衍生品訴訟,第四名AEP股東向紐約州拿騷縣最高法院提起類似的衍生品訴訟。這些衍生品指控稱,這些高管和董事的失實陳述和遺漏,與針對AEP提起的假定證券集體訴訟中的指控類似。衍生品訴訟(統稱爲「衍生品訴訟」)合計提出的申索包括:(A)違反受託責任、(B)浪費公司資產、(C)不當得利、(D)違反內幕交易責任及(E)違反1934年證券交易法第10(B)及21D條的責任;以及尋求金錢賠償及改變AEP的企業管治及內部政策,以及其他形式的救濟。法院在紐約州法院的派生訴訟中發出了一項時間表命令,擱置了案件,但就駁回動議的簡報除外。AEP於2022年4月提交了實質性和基於論壇的動議以駁回。2022年6月,俄亥俄州法院發佈了一項命令,繼續擱置該案,直到俄亥俄州聯邦地區法院懸而未決的合併衍生品訴訟的最終解決方案。2022年9月,紐約州法院批准了以偏見爲基礎的駁回動議,原告隨後向紐約上訴法院提交了上訴通知。2023年1月,紐約州原告提出動議,要求干預俄亥俄州聯邦法院懸而未決的訴訟,並撤回了他在紐約的上訴。在俄亥俄州聯邦地區法院待決的兩起衍生品訴訟已被合併,合併訴訟中的原告提出了修改後的申訴。AEP提交了一項動議,要求駁回修改後的申訴,隨後提交了一份簡報,反對紐約州原告提出的干預俄亥俄州合併訴訟的動議。2023年3月,聯邦地區法院發佈命令,批准以偏見駁回動議,並駁回紐約原告的干預動議。2023年4月,其中一名原告向美國俄亥俄州聯邦地區法院第六巡迴上訴法院提交上訴通知,駁回合併訴訟並否認干預。

2021年3月,AEP收到了代表AEP所謂股東的律師的訴訟請求信。訴訟要求函針對AEP董事會(AEP董事會),幷包含涉及HB 6的事實指控,這些指控與向州和聯邦法院提起的衍生品訴訟中的指控大體一致。發出這封信的股東後來撤回了訴訟要求,現在已經終止,沒有進一步的效力。2023年4月,AEP收到了代表AEP所謂股東的律師的訴訟要求函,該律師向紐約州法院提起了被駁回的衍生品訴訟,並試圖干預俄亥俄州聯邦法院的合併衍生品訴訟(Litigation Demand),但未獲成功。訴訟要求是針對AEP董事會的,幷包含涉及HB 6的事實指控,這些指控與衍生訴訟中的指控大體一致。訴訟要求要求(其中包括)AEP董事會對某些現任和前任董事和高級管理人員的涉嫌違法行爲進行獨立調查,並要求AEP開始民事訴訟,主張與衍生訴訟中聲稱的索賠類似的索賠。AEP董事會審議了訴訟要求,併成立了董事會委員會(要求審查委員會),以
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調查、審查、監控和分析訴訟需求,並就合理、適當的回應向AEP董事會提出建議。

於2024年4月,AEP與四名股東達成協議,以全面及最終解決衍生訴訟及訴訟要求,以及任何AEP股東基於所稱事實、以和解文件(和解文件)所載方式及條款及條件而提出或本可提出的所有索償。2024年7月,美國地區法院初步批准了這項和解。和解協議包括支付45美元的萬律師費,以及實施和解協議中概述的某些治理改革,其中許多改革已經到位。和解協議不包括承認任何責任。2024年10月,地方法院發佈了批准和解的命令和判決,並批准了帶有偏見的駁回令。根據和解協議,所有衍生品訴訟已經或將被駁回,訴訟要求已被撤回,這些事項和索賠已根據和解條款得到解決。

2021年5月,AEP收到美國證券交易委員會執行部的傳票,要求提供各種文件,包括與HB 6通過有關的文件,以及與AEP的政策、財務流程和控制有關的文件。2022年8月,美國環保署收到美國證券交易委員會的第二次傳票,要求提供與其正在進行的調查有關的各種額外文件。美國環保局正在全力配合美國證券交易委員會的調查,調查包括聽取某些個人的證詞,就賦權俄亥俄州經濟公司進行調查,俄亥俄州經濟公司是一家501(C)(4)社會福利組織,以及相關披露。美國環保局和美國證券交易委員會正在就美國證券交易委員會的調查和根據證券法可能提出的索賠進行討論。根據上述討論,在2024年第三季度,美國航空公司在其損益表中的其他運營費用中記錄了1,900萬美元的或有虧損,並在美國航空公司的資產負債表中的其他流動負債中應計了相應的負債。調查或索賠的解決可能會使AEP受到民事罰款,金額可能與記錄的金額不同;然而,管理層認爲任何此類解決方案都不會是實質性的。

加文發電站業主提出的賠償索賠

2022年11月,聯邦環保局發佈了一項最終決定,拒絕了Gavin Power LLC的請求,即允許Gavin Power Station的CCR地面蓄水在2021年4月11日之後繼續接收CCR和非CCR廢流,直到2023年5月4日(Gavin拒絕)。作爲Gavin否認的一部分,聯邦環保局做出了幾項與CCR規則相關的斷言(有關更多信息,請參閱下面的「CCR規則」部分),包括一項斷言,關閉300英畝無襯砌的飛灰庫(FAR)在多個方面不符合CCR規則。Gavin發電站以前由AEP擁有和運營,並於2017年出售給Gavin Power LLC和Lightstone Generation LLC。根據PSA,AEP繼續負責按照俄亥俄州環保局批准的關閉計劃完成FAR的關閉,該計劃於2021年7月完成。PSA包含賠償條款,根據這些條款,Gavin發電站的所有者已通知AEP,他們認爲他們有權就這些索賠可能導致的任何損害獲得賠償,包括因聯邦環保局判定不遵守與Gavin否認一致的CCR規則的各個方面而導致的任何未來執法或訴訟。Gavin發電站的所有者還要求賠償土地所有者據稱因對FAR進行改造而造成的財產損失。管理部門不認爲Gavin發電站的所有者根據PSA向AEP提出任何有效的賠償或其他索賠要求。此外,Gavin Power LLC、幾家AEP子公司和其他各方已向美國哥倫比亞特區巡迴上訴法院提交了對Gavin否認的複審請願書,該法院於2024年6月因缺乏管轄權而被駁回。2024年1月,Gavin Power LLC還向俄亥俄州南區美國地區法院提出申訴,指控各種違反《行政程序法》的行爲,並聲稱聯邦環保局由於先前的不作爲,已經放棄並被禁止提出在Gavin否認案中提出的某些反對意見。管理層無法預測這場訴訟的結果。管理層無法確定合理可能發生的潛在損失範圍。

有關正義電煤合同的訴訟

2023年12月,APCo向富蘭克林縣俄亥俄州普通上訴法院提起訴訟,尋求宣告性判決,確認APCo有權終止與Justice Hot LLC(Justice Hot)的長期煤炭合同,理由是Justice Hot未能履行合同。 APCo於2024年1月終止了該合同,2024年4月,APCo提交了一份修改後的投訴,要求聲明終止是適當的,並要求對Justice Hot違反合同的損害賠償。 熱法官於2024年4月提出答覆和反訴,對合同終止的有效性提出質疑並提出反訴。 雙方簽訂了和解協議並解除訴訟,根據該協議,訴訟於2024年9月被駁回,但存在偏見,雙方免除了對方與合同或訴訟相關的所有索賠,因此此事已得到解決。
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環境問題

AEP擁有大量的資本投資計劃,併產生額外的運營成本以遵守環境控制要求。 將進行額外投資和運營變革,以響應減少化石發電排放的現有和預期要求,並響應管理煤炭燃燒副產品、清潔水的有益利用和處置的規則以及某些水排放的更新許可證。

AEP正在參與有關環境問題的訴訟,被告知可能有責任清理受污染場地,以及處置SNF和未來核機組退役所產生的費用。 管理層正在制定未來可能的需求,包括下文討論的項目。

AEP將通過受監管司法管轄區的費率尋求從客戶收回污染控制技術支出和相關成本。 環境規則可能會導致加速折舊、資產減損或監管免稅。 如果AEP無法收回環境合規成本,將減少未來的淨利潤和現金流並影響財務狀況。

環境合規對發電機組的影響

下文討論的規則和環境控制要求將對AEP的運營產生重大影響。 截至2024年9月30日,AEP擁有發電量約爲23,000兆瓦,其中燃煤發電量約爲10,700兆瓦。 2024年4月,聯邦環保局宣佈了針對化石燃料發電設施的四項主要新規則。 管理層繼續評估這些規則對AEP發電機隊未來計劃的影響,特別是對AEP化石發電機隊進行必要環境投資的經濟可行性。 AEP繼續完善遵守這些規則的成本估計,以確定最佳替代方案,以確保遵守所有規則,同時履行AEP提供可靠且負擔得起的電力的義務。

遵守新規則的成本也可能因以下原因而發生變化:(a)實施額外更嚴格標準的潛在州規則,(b)響應法院裁決的額外規則制定活動,(c)已安裝的污染控制技術的實際性能,(d)新污染控制成本的變化,(e)新發電技術的開發,(f)退役和更換的總兆瓦容量,包括此類替代容量的類型和數量以及(g)其他因素。

清潔空氣法要求

CAA制定了一項全面的計劃,以保護和改善國家的空氣質量並控制空氣排放源。 各州實施和管理其中許多計劃,並可能施加額外或更嚴格的要求。 繼續推動對AEP現有發電機組投資的主要監管計劃包括:(a)定期修訂NAAQS並制定SIPs以實現更嚴格的標準,(b)各州和聯邦環保局實施區域霧霾計劃,(c)根據MATS對危險空氣污染物排放進行監管,(d)CSAPR的實施和審查以及(e)聯邦環保局根據CAA第111條對化石發電溫室氣體排放的監管。 以下章節討論了影響AEP運營的重要CAA監管要求的顯着進展。

國家環境空氣質量標準

聯邦環保局定期審查和修改NAAQS中CAA規定的污染物標準。 修訂往往會提高標準的嚴格性,這反過來可能要求AEP投資現有發電機組的污染控制設備,或者,由於大多數機組已經得到了良好的控制,因此改變機組的調度和運營方式。 2024年2月,聯邦環保局敲定了更嚴格的新年度主要總理2.5 標準

空氣質量不符合新標準的地區將被聯邦環保局指定爲「未達標」,這將促使各州有義務修改其SIPs以納入額外要求,從而進一步減少排放,以確保達到新標準。 AEP的一些發電設施周圍的區域可能被視爲未達標,這可能需要這些設施安裝額外的污染控制或實施運營限制。 聯邦EPA的未達標指定以及受影響州隨後對SI的修訂將需要一些時間才能完成;因此,管理層無法合理估計對AEP運營、現金流、淨收入或財務狀況的影響。

地區霧霾

聯邦環保局於2005年發佈了清潔空氣能見度規則(CAVR),該規則可能要求發電廠和其他設施安裝最佳可用的改造技術,以解決聯邦公園和其他保護區的區域霧霾問題。 CAVR由各州通過TIP實施,或由聯邦EPA通過TIP實施。 2017年,聯邦環保局修訂了有關提交PIP以實施可見性計劃的規則。 審查最終規則修訂的請願書已於
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美國哥倫比亞特區巡迴上訴法院。 2018年初,聯邦環保局宣佈計劃重新審查請願人在行政複審請願書中提出的最終規則的某些方面,法院批准了聯邦環保局擱置訴訟的動議。

聯邦環保局不批准德克薩斯州地區霧霾計劃的部分內容,並最終敲定了一項允許參與CSAPR臭氧季節計劃的FIP,以滿足NOX德克薩斯州發電機組的地區霧霾義務。此外,聯邦環保局最終敲定了一項州內法案2基於CSAPR額度分配的排污權交易計劃。環保組織在第五巡迴法院和哥倫比亞特區巡迴法院對這些不同的規則制定提出了挑戰。管理層無法預測這起訴訟的結果,儘管管理層支持州內交易計劃,作爲特定來源控制的合規替代方案,並干預了第五巡迴訴訟,以支持聯邦環保局。2024年7月,美國哥倫比亞特區巡迴地區法院進入了一項同意法令,爲聯邦環保局設定了最後期限,要求聯邦環保局對包括德克薩斯州在內的33個州的地區性霧霾噴灑做出裁決。2024年9月,聯邦環保局簽署了一項擬議的規則,部分批准和部分不批准德克薩斯州的SIP修訂。這項擬議的規則於2024年10月發表在《聯邦紀事報》上,啓動了截至2024年11月14日的公衆評議期。聯邦環保局對德克薩斯州SIP採取最終行動的最後期限是2025年5月30日。

跨州空氣污染規則

CSAPR是聯邦環保局於2015年開始實施的一項區域貿易計劃,最初旨在解決州際排放物傳輸問題,這些排放物傳輸嚴重導致未達標並干擾1997年臭氧NAAQS以及1997年和2006年PM的維護2.5 NAAQS處於下風州。 CSAPR依賴SO2 也沒有X 補貼和個別國家預算,以迫使電力公司發電機組進一步減排。 允許州際津貼交易在有限制的基礎上進行。 自CSAPR交易計劃成立以來,聯邦環保局已多次修訂或更新。

2021年1月,聯邦環保局最終確定了修訂後的CSAPR,大幅減少了臭氧季節NOX 從2021年臭氧季節開始,多個州(包括AEP運營的州)的預算。 AEP在實施的頭幾年內就能夠滿足修訂後規則的要求,並正在評估後期預算進一步減少時的合規選擇。

此外,2023年2月,聯邦環境保護局局長敲定了包括德克薩斯州在內的19個州提交的州際運輸SIPs的不批准意見,涉及2015年臭氧NAAQS。此後不久,聯邦環保局不批准更多州提交的州際運輸SIPs。對SIPs的反對使聯邦環保局有權對這些州實施FIP,取代不獲批准的SIPs。2023年8月,一項FIP(好鄰居計劃)生效,進一步修訂了臭氧季節NOX在FIP適用的州的現有CSAPR方案下的預算。由於各州和行業各方在不同的聯邦法院提出了幾個單獨的法律挑戰,FIP的實施在AEP運營的所有州都被擱置了。2024年10月,聯邦環保局發佈了一項最終規則,在行政上暫停友好鄰里計劃要求的有效性,適用於該規則所涵蓋的所有尚未實施行政暫緩執行的來源。在23個州中的每一個州,好鄰居計劃對發電廠和其他工業設施的有效性的行政擱置將繼續有效,直到最高法院取消暫停執行好鄰居計劃的命令,其他法院取消任何暫停州政府不批准行動的司法命令,以及聯邦環保局隨後採取與任何關於是非曲直的司法裁決一致的規則制定行動。管理層將繼續監測這起訴訟的結果,以及對運營的任何潛在影響的sips的發展。

氣候變化,科羅拉多州2 監管和能源政策

2024年4月,聯邦環保局局長簽署了針對新的和現有的化石燃料來源的新的溫室氣體標準和指南。該規則依賴於碳捕獲和封存以及天然氣共燃作爲減少CO的手段2燃煤電廠的排放和碳捕獲和封存或有限的利用來減少CO2新燃氣輪機的排放。該規定還規定,作爲一種替代合規手段,燃煤電廠將提前退役,以取代碳捕獲和封存。聯邦環保局將現有燃氣輪機標準的最終確定推遲到2024年晚些時候。AEP正處於評估和確定遵守下面討論的這一規則和其他新規則的最佳戰略的早期階段,同時確保資源充足,以滿足客戶需求。這項規定受到了27個州、許多公司、行業協會和其他人的挑戰。AEP已與其他幾家公用事業公司一起挑戰這項規定,並要求法院在訴訟期間擱置該規定,上訴已合併。2024年7月,美國哥倫比亞特區巡迴上訴法院駁回了這些擱置動議,包括AEP和其他公用事業公司在內的幾個當事人向美國最高法院提出申請,要求緊急擱置。最高法院在2024年10月駁回了這些申請,訴訟將繼續在美國哥倫比亞特區巡迴上訴法院進行。遵守環境法規的成本過高,導致全國各地宣佈提前關閉工廠。聯邦環保局的新溫室氣體規則,以及下面討論的同時發佈的一系列其他新規則,都是針對化石--
14


燃料電力公用事業行業,並可能迫使AEP在其估計使用壽命之前關閉更多的燃煤發電設施。 如果AEP無法收回其投資成本,將減少未來的淨利潤和現金流並影響財務狀況。

AEP定期提交各個監管管轄區的IRP,以滿足未來的發電和容量需求。這些IRP考慮了經濟性、客戶需求、電網可靠性和恢復力、法規和RTO容量要求。IRPS的目標是推薦未來的發電和容量資源,爲客戶提供最具成本效益和最可靠的電力。根據這些減排方案的產出,2022年10月,環境保護署修改了其溫室氣體中長期減排目標。中期目標是到2030年將範圍1溫室氣體排放量減少80%(在2005年基線的基礎上),長期目標是到2045年實現範圍1和範圍2溫室氣體排放淨零。根據《溫室氣體議定書》,2023年美國環保署的1號範圍溫室氣體總排放量約爲4,340萬噸,根據《溫室氣體議定書》減少了68%,比美國環保局2005年1號範圍溫室氣體排放量減少了71%(包括因出售工廠而減少的排放量)。AEP預計其範圍1溫室氣體排放量每年都會有所不同,這取決於它自己發電的比例和用於爲客戶服務的購買電力以及系統上的負荷增長。

AEP在減少CO方面取得了重大進展2由於某些化石燃料發電機組的退役和能源效率的提高,預計其排放量將在長期內繼續下降,因爲監管機構對此類活動提供了支持。AEP實現其溫室氣體排放目標的能力以及未來此類目標的修改取決於多個因素,包括繼續向客戶提供最具成本效益和可靠性的電力、我們服務區域內負荷增長的變化、在不同司法管轄區提交的IRPS以及州監管機構和政策制定者對可調度或可再生髮電資源的偏好、不斷變化的RTO要求、無碳發電技術的發展、客戶對無碳能源的需求、潛在的關稅、碳政策和法規、可再生能源的運營表現、供應鏈成本和限制以及使用碳抵消的能力。根據AEP的最新分析,AEP目前預計,到2045年實現範圍1和範圍2淨零排放的長期目標將需要開發新的無碳發電技術,預測的客戶負荷下降,碳抵消的使用或其他未來變化。

墊子規則

2024年4月,聯邦環保局發佈了修訂後的發電廠MATS規則。 該規則包括對燃煤發電機組可過濾PM排放的更嚴格標準,以及對燃煤發電機組的新汞標準。 該規則還要求安裝和運行PM的連續排放監測器。 幾個州和其他當事方已向美國哥倫比亞特區巡迴上訴法院對該規則提出質疑,但管理層無法預測訴訟的結果。 管理層正在評估該規則的影響,但預計遵守該規則不會遇到任何重大挑戰。

MCR規則

聯邦環保局的MCR規則規範了MCR的處置和有益再利用,包括燃煤發電機組產生的飛灰和底灰以及一些燃煤發電廠產生的FVD石膏。 原始規則適用於活躍和非活躍的MCR垃圾填埋場以及活躍電力公司或獨立電力生產商設施的表面蓄水池。 隨着2024年4月宣佈的修訂,該規則的範圍大幅擴大,包括非活動設施的非活動蓄水池(「遺留的MCR表面蓄水池」),並對涉及直接放置MCR的目前豁免的固體廢物管理單元(「MCR管理單元」)制定要求。土地上。

2020年,聯邦環保局修改了最初的MCR規則,要求無襯裏的MCR儲存池在2021年4月11日之前停止運營並開始關閉。 修訂後的規則提供了兩種選擇,允許設施延長停止接收菸灰並關閉池塘的日期。

第一種選擇爲大多數單位提供延期,不遲於2023年10月15日停止接收MCR,對於少數單位子集,不遲於2024年10月15日;然而,聯邦環保局批准此類延期需要令人滿意地證明需要額外的時間來開發替代灰燼處理能力,並且將限制在技術上可行的最快時間內停止接收的MCR。 此外,每項請求都必須接受正式審查,包括公衆評論,並獲得聯邦環保局的批准。 AEP已多次提交申請,要求延長時間,以在各個工廠開發替代處置能力。 此後,AEP已停止接收受延期請求影響的池塘中的灰燼,完成了符合MCR規則的新設施的建設,並因無意義而撤回了這些申請。

2022年1月,聯邦環保局提議拒絕其他公用事業公司提出的多項延期請求,理由是這些公用事業公司不遵守MCR規則(1月行動)。 2022年11月,聯邦環保局最終確定了其中一項否認(加文否認,上文討論)。 聯邦環保局對不合規行爲的指控依賴於AEP和其他人認爲的對MCR規則要求的新解釋。 一月份的新解釋
15


聯邦EPA和Gavin Denial的行動在美國哥倫比亞特區巡迴上訴法院受到質疑,稱其爲非法規則制定,未經適當通知且沒有發表評論的機會修改了現有的MCR規則要求。 2024年6月,美國哥倫比亞特區巡迴上訴法院裁定,聯邦環保局1月份的行動和在加文否認案中做出的聲明不構成須接受法院審查的新機構規則。 法院因缺乏管轄權駁回了上訴。

根據延長2021年4月11日停止無襯蓄水池運營的最後期限的第二種選擇,發電設施可以繼續運營其現有的蓄水池,而無需開發替代的MCR處置,前提是該設施承諾在某個日期之前停止燃燒煤炭。 根據該選項,發電設施必須在2023年10月17日之前停止燃煤運營並關閉面積爲40英畝或以下的MCR儲存池,或者對於面積大於40英畝的MCR儲存池的設施,則必須在2028年10月17日之前關閉。 根據這一選擇,AEP通知聯邦環保局,其打算退役皮爾基工廠並停止在威爾士工廠使用煤炭。 2023年3月,皮爾基工廠退役。 迄今爲止,聯邦環保局尚未對威爾士工廠懸而未決的延期請求採取任何行動。

2024年4月,聯邦環保局完成了對CCR規則的修訂,以擴大該規則的範圍,將非活躍設施的非活躍蓄水包括在內(「遺留CCR地表蓄水」),併爲目前豁免的涉及直接在土地上放置CCR的固體廢物管理單位(「CCR管理單位」)確立要求。聯邦環保局要求遺留地表蓄水池的所有者和運營商遵守適用於現役設施中非活躍的CCR地表蓄水池的所有現有CCR規則要求,但位置限制和襯砌設計標準除外。該規則爲遺留地表蓄水設定了合規截止日期,以滿足監管要求,包括在最終規則生效日期後五年內啓動關閉的要求。該規則要求對具有一個或多個遺留地表蓄水的現役設施和非現役設施進行評估。封閉可通過在CCR材料上應用不透水覆蓋系統(「就地封閉」)來完成,或者CCR材料可被挖掘並放置在合規的垃圾填埋場(「移除封閉」)。未來三年的地下水監測和其他分析將提供有關計劃關閉方法的更多信息。AEP評估了該規則對當前和以前的廠址的適用性,並記錄了2024年第二季度的增量ARO,如下表所示,這是根據初步成本估算得出的,這主要反映了根據CCR規則關閉時對該規則的遵守情況和未來的地下水監測要求。

註冊人ARO增加世代財產增加(a)監管資產增加(b) 計入運營費用(c)
(in數百萬)
APCO$312.2 $75.6 $236.6 $— 
I & M85.7 — 72.3 13.4 
Opco52.9 — — 52.9 
粒子群優化算法33.7 33.7 — — 
SWEPCO23.8 23.8 — — 
非註冊者166.1 43.8 46.1 76.2 
$674.4 $176.9 $355.0 $142.5 

(a)ARO與運營發電設施中的遺留MCR地面蓄水或MCR管理單元有關。
(b)ARO與退役發電設施中的遺留MCR地面蓄水或MCR管理單元相關,支持根據「受監管運營」的會計指南確認監管資產。
(c)ARO與遺留的MCR地面蓄水或MCR管理單位有關,目前尚不支持根據「受監管運營」的會計指南確認監管資產。

隨着進一步地下水監測和其他分析的進行,管理層預計將完善記錄ARO時使用的假設和基本成本估計。 這些改進可能包括但不限於預期關閉方法的變更、每個地點的MCR估計數量的變更、新的MCR管理單位的識別等。 這些未來變化可能會對ARO產生重大影響,並大幅減少未來淨利潤和現金流,並進一步影響財務狀況。

AEP將通過監管費率尋求成本回收,包括在現有機制不適用的情況下提出新的成本回收監管機制。 如果AEP最終無法收回這些額外的合規成本,該規則可能會對淨收入、現金流和財務狀況產生額外的重大不利影響。 包括AEP及其一個行業協會在內的多個政黨已向美國華盛頓巡迴上訴法院提交了審查該規則的請願書。 其中一方還提出動議,要求在訴訟結果公佈之前暫緩執行該規則。 2024年11月,法院駁回了中止動議。 管理層無法預測訴訟的結果。
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《清潔水法》法規

聯邦環保局關於發電設施的ELG規則規定了對FGD廢水、飛灰和底灰輸送水以及煙氣汞控制廢水的限制,這些限制將通過每個設施的廢水排放許可證來實施。2020年10月公佈的ELG規則修訂本,爲重複使用和排放少量底灰運輸水確立了額外的備選方案,爲退役單位提供了例外,並將遵約截止日期延長至規則公佈後一年但不遲於2025年12月開始的儘快日期。管理層評估了爲遵守規則而增加和改造的技術,以及聯邦環保局的行動對允許FGD廢水和底灰輸送水的設施廢水排放的影響。對於需要安裝額外技術以滿足ELG規則限制的受影響設施,2021年1月提交了反映評估結果的許可證修改。AEP繼續與州機構合作,最終敲定許可證條款和條件。其他設施選擇提交計劃參與通知(NOPP),根據該通知,只要這些設施承諾在確定的日期前停止燃煤,它們就不需要安裝額外的控制來滿足ELG限制。2024年4月,聯邦環保局完成了對ELG規則的進一步修訂,建立了FGD廢水、底灰輸送水和受控燃燒殘餘滲濾液的零液體排放標準,以及對非受控燃燒殘餘滲濾液的更嚴格的排放限制。修訂後的規則提供了一個新的合規替代方案,將避免爲符合2020年規則控制技術要求並承諾在2034年12月31日之前退役的設施安裝零液體排放系統。管理層正在評估規則中的合規備選辦法,同時考慮到其他新規則的要求及其對業務的綜合影響。已經向多個聯邦法院提出了幾項上訴,對2024年ELG規則提出質疑。Swepco還通過與AEP參與的一個公用事業行業協會提起聯合上訴,對這一規定提出了挑戰。向美國第八巡迴上訴法院合併了各種上訴。Swepco和公用事業行業協會提出動議,要求在訴訟期間擱置該規則,但在2024年10月,法院駁回了這項動議。管理層無法預測訴訟的結果。

「美國水域」的定義一直受到規則制定和訴訟的影響,導致各州之間的範圍不一致。 管理層將繼續監控規則制定和訴訟的進展,以了解對運營的任何潛在影響。

環境監管對燃煤發電的影響

遵守廣泛的環境法規需要在環境監測、污染控制設備安裝、排放費、處置、補救和許可方面進行大量資本投資。 管理層不斷評估遵守這些法規的成本估計,這可能會導致決定在其當前估計的使用壽命之前退役燃煤發電設施。

下表總結了截至2024年9月30日在目前爲制定費率而授權的退役日期之前退役或計劃提前退役的發電設施的淨資產:
公司
投資(a)
監管資產加速折舊實際/預計
退休
日期
目前核定
恢復
期間
年折舊(b)
(in數百萬)(in數百萬)
粒子群優化算法東北工廠3單元$111.9 $181.2 2026(c)$15.7 
SWEPCO皮爾基工廠— 120.8 (d)2023(e)— 
SWEPCO威爾士工廠,1號和3號機組341.4 156.7 2028(f)(g)41.6 

(a)淨資產,包括快遞,不包括搬遷成本以及材料和用品。
(b)這些金額代表過去12個月期間從客戶處收取的年度折舊金額。
(c)東北工廠3號機組目前正在恢復到2040年。
(d)代表阿肯色州和德克薩斯州的管轄權份額。
(e)作爲2021年阿肯色州基本利率案的一部分,APSC給予SWEPCO監管資產待遇。 SWEPCo將要求追回,包括通過未來的程序收回資本持有費的加權平均成本。 SWEPCo的下一個基本稅率案件將解決Pirkey工廠的德克薩斯州份額。 有關更多信息,請參閱注4的「受監管發電機組」部分。
(f)2020年11月,管理層宣佈威爾士工廠將於2028年停止使用煤炭。 管理層正在評估這兩個裝置在2028年後向天然氣轉變的可能性。
(g)路易斯安那州司法管轄區的威爾士工廠1號機組將於2027年收回,阿肯色州和德克薩斯州司法管轄區將於2037年收回。 路易斯安那州司法管轄區的威爾士工廠3號機組將於2032年收回,阿肯色州和德克薩斯州司法管轄區將於2042年收回。

管理層正在或將在必要時尋求對工廠退役後剩餘的任何淨資產進行監管補償。 如果這些發電資產的淨資產被視爲不可收回,則可能會大幅減少未來的淨利潤、現金流並影響財務狀況。
17


行動的結果

AEP的可報告部分

AEP的主要業務是發電、輸電和配電。 在其垂直綜合公用事業部門,由於基於成本的費率和監管監督的重大影響,AEP集中調度發電資產並綜合管理其整體公用事業運營。 分部間銷售和轉讓通常基於基礎合同安排和協議。 AEP的可報告分部如下:

垂直集成公用事業
輸電和配電公用事業
AEP變速箱控股公司
生成與營銷

AEP的其餘活動列爲企業和其他活動,不被視爲可報告分部。 有關AEP部門的更多信息,請參閱註釋8 -業務部門。

以下對AEP按經營部門劃分的經營業績的討論提供了截至2024年9月30日止三個月和截至9月30日止三個月和截至2023年9月30日止三個月和截至9月30日止九個月的應歸屬於AEP普通股股東的盈利的比較。 對於AEP的垂直綜合公用事業部門和輸配電公用事業部門以及這些部門內的子公司註冊人,結果包括來自旨在回收燃料、購買電力和其他可收回費用的費率附加機制的收入,以便與這些項目相關的收入和費用通常會抵消且不會影響歸屬於AEP普通股股東的收益。 有關截至2024年9月30日和2023年9月30日的三個月和九個月財務業績的更多信息,請參閱子公司註冊人的經營業績的討論。

下表按部門列出了歸屬於AEP普通股股東的盈利(虧損):
止三個月止九個月
9月30日,9月30日,
 2024202320242023
 (in數百萬)
垂直集成公用事業$571.5 $512.5 $1,198.0 $1,051.6 
輸電和配電公用事業245.2 206.0 542.3 508.4 
AEP變速箱控股公司214.7 202.9 624.1 580.8 
生成與營銷93.3 130.7 226.1 (59.3)
公司和其他(165.1)(98.4)(287.5)(209.6)
歸屬於AEP普通股股東的收益$959.6 $953.7 $2,303.0 $1,871.9 
18


截至2024年9月30日的三個月
垂直集成公用事業輸電和配電公用事業AEP變速箱控股公司生成與營銷
(in數百萬)
收入$3,303.0 $1,575.4 $512.5 $499.1 
燃料、購電和其他1,100.4 213.2 — 413.6 
其他運營維護881.6 599.1 40.0 20.6 
折舊及攤銷530.6 212.8 110.5 4.0 
除所得稅以外之稅項138.1 181.6 81.2 0.8 
營業收入652.3 368.7 280.8 60.1 
其他收入5.7 4.0 3.4 8.2 
建設期間使用的股權資金津貼12.9 17.0 24.3 — 
淨定期效益成本的非服務成本組成26.5 11.3 1.4 5.9 
利息支出(189.9)(106.4)(56.2)(4.0)
所得稅前收入(福利)和股權收益507.5 294.6 253.7 70.2 
所得稅支出(福利)(64.6)49.4 60.9 (23.1)
未合併子公司的權益收益0.4 — 23.0 — 
淨收入572.5 245.2 215.8 93.3 
歸屬於非控制性權益的淨利潤1.0 — 1.1 — 
歸屬於AEP普通股股東的收益$571.5 $245.2 $214.7 $93.3 

截至2023年9月30日的三個月
垂直集成公用事業輸電和配電公用事業AEP變速箱控股公司生成與營銷
 (in數百萬)
收入$3,205.4 $1,544.1 $476.7 $566.7 
燃料、購電和其他1,137.5 298.8 — 406.6 
其他運營維護829.4 541.1 39.3 31.2 
折舊及攤銷480.7 206.9 101.9 8.3 
除所得稅以外之稅項131.9 181.3 75.5 1.6 
營業收入625.9 316.0 260.0 119.0 
其他收入5.9 0.6 2.1 11.5 
建設期間使用的股權資金津貼15.0 13.4 22.7 — 
淨定期效益成本的非服務成本組成31.6 14.1 1.5 6.6 
利息支出(197.1)(93.8)(53.6)(18.7)
所得稅前收入(福利)和股權收益(損失)481.3 250.3 232.7 118.4 
所得稅支出(福利)(32.4)44.3 51.1 (16.2)
未合併子公司的權益收益(損失)0.3 — 22.3 (1.8)
淨收入514.0 206.0 203.9 132.8 
歸屬於非控制性權益的淨利潤1.5 — 1.0 2.1 
歸屬於AEP普通股股東的收益$512.5 $206.0 $202.9 $130.7 

19


截至2024年9月30日的九個月
垂直集成公用事業輸電和配電公用事業AEP變速箱控股公司生成與營銷
(in數百萬)
收入$8,869.9 $4,501.5 $1,499.7 $1,530.1 
燃料、購電和其他 2,970.3 729.0 — 1,151.0 
其他運營維護2,720.1 1,639.0 122.8 94.5 
資產減損和其他相關費用13.4 52.9 — 76.2 
折舊及攤銷1,470.4 662.2 327.5 17.3 
除所得稅以外之稅項410.7 550.4 233.4 1.5 
營業收入1,285.0 868.0 816.0 189.6 
其他收入17.0 7.5 10.3 28.6 
建設期間使用的股權資金津貼37.4 50.9 64.7 — 
淨定期效益成本的非服務成本組成73.8 31.4 2.5 17.6 
利息支出(537.3)(298.4)(166.4)(14.9)
所得稅前收入(福利)和股權收益(損失)875.9 659.4 727.1 220.9 
所得稅支出(福利)(324.5)116.3 172.2 (4.3)
未合併子公司的權益收益(損失)1.1 (0.8)72.6 0.9 
淨收入1,201.5 542.3 627.5 226.1 
歸屬於非控制性權益的淨利潤3.5 — 3.4 — 
歸屬於AEP普通股股東的收益$1,198.0 $542.3 $624.1 $226.1 
截至2023年9月30日的9個月
垂直集成公用事業輸電和配電公用事業AEP變速箱控股公司生成與營銷
 (in數百萬)
收入$8,737.7 $4,348.5 $1,390.8 $1,225.1 
燃料、購電和其他2,989.0 970.5 — 1,116.0 
其他運營維護2,480.7 1,472.7 109.9 130.4 
競爭性合同可再生能源投資組合的銷售損失— — — 112.0 
折舊及攤銷1,411.3 576.2 297.9 34.7 
除所得稅以外之稅項390.8 519.1 222.0 6.1 
營業收入(虧損)1,465.9 810.0 761.0 (174.1)
其他收入20.2 1.9 7.0 32.2 
建設期間使用的股權資金津貼30.5 30.7 62.2 — 
淨定期效益成本的非服務成本組成94.9 42.1 4.6 19.7 
利息支出(565.1)(270.0)(153.7)(69.2)
所得稅前收入(損失)發票(福利)和股權收益1,046.4 614.7 681.1 (191.4)
所得稅支出(福利)(7.2)106.3 158.7 (127.3)
未合併子公司的權益收益1.0 — 61.2 1.9 
淨收益(虧損)1,054.6 508.4 583.6 (62.2)
歸屬於非控制性權益的淨利潤(損失)3.0 — 2.8 (2.9)
歸屬於AEP普通股股東的收益(損失)$1,051.6 $508.4 $580.8 $(59.3)
20


垂直集成公用事業

垂直集成公用事業的千瓦時能源銷售彙總
止三個月止九個月
9月30日,9月30日,
2024202320242023
 (in數百萬千瓦時)
零售業:    
住宅8,959 8,975 24,191 23,406 
商業6,910 6,686 18,763 17,781 
工業8,562 8,731 25,563 25,686 
雜類612 618 1,718 1,684 
零售業總25,043 25,010 70,235 68,557 
批發(a)3,559 3,876 10,498 10,620 
總千瓦時28,602 28,886 80,733 79,177 

(a)包括系統外銷售、市政當局和合作社、單位電力和其他批發客戶。
供暖天數和製冷天數是公用事業行業常用的指標,用於衡量天氣對收入的影響。 總體而言,由於兩個地區的相對規模以及每個地區內的客戶數量,東部地區的學位日變化對收入的影響大於西部地區的變化。

垂直一體化公用事業供暖和製冷度天數彙總
止三個月止九個月
9月30日,9月30日,
2024202320242023
 (in學位天數)
東部地區    
實際 供暖(a)
— — 1,302 1,253 
正常 供暖(b)
1,746 1,750 
實際 冷卻(c)
854 748 1,328 967 
正常 冷卻(b)
746 751 1,089 1,095 
西部地區    
實際供暖(a)
— — 743 657 
正常 供暖(b)
— 910 916 
實際 冷卻(c)
1,510 1,634 2,486 2,436 
正常 冷卻(b)
1,434 1,430 2,173 2,162 

(a)升溫程度天數以55度溫度爲基礎計算。
(b)正常供暖/製冷代表三十年來的平均度數天數。
(c)降溫天數以65度溫度爲基礎計算。
21


垂直集成公用事業
2023年至2024年歸屬於AEP普通股股東的盈利對賬
(in數百萬)
 
截至3月31日的三個月。
9月30日,
止九個月
9月30日,
2023年歸屬於AEP普通股股東的盈利$512.5 $1,051.6 
  
收入變化: 
零售收入42.6 36.6 
系統外銷售24.7 28.3 
傳輸收入24.4 39.0 
其他收入5.9 28.3 
收入總變化97.6 132.2 
  
費用及其他變化: 
購買用於發電的電力、燃料和其他消耗品37.1 18.7 
其他運營維護(52.2)(239.4)
資產減損和其他相關費用— (13.4)
折舊及攤銷(49.9)(59.1)
除所得稅以外之稅項(6.2)(19.9)
其他收入(0.2)(3.2)
建設期間使用的股權資金津貼(2.1)6.9 
淨定期養老金成本的非服務成本組成(5.1)(21.1)
利息支出7.2 27.8 
費用及其他總變化(71.4)(302.7)
  
所得稅優惠32.2 317.3 
未合併子公司的權益收益0.1 0.1 
歸屬於非控制性權益的淨利潤0.5 (0.5)
2024年歸屬於AEP普通股股東的盈利$571.5 $1,198.0 

2024年第三季度與2023年第三季度相比

收入增長的主要組成部分如下:

零售收入 增加4300萬美元主要原因:
APCo和WPCo的騎手收入增加了3000萬美元。
由於APCo的2020-2022年弗吉尼亞三年期審查,費率增加了2300萬美元。
KPCo的騎手收入增加了1900萬美元。
I & m的騎手收入增加了1500萬美元。
天氣正常化收入增加了1000萬美元,主要集中在住宅和商業類別,部分被工業類別的下降所抵消。
這些增加被以下因素部分抵消:
燃料收入減少5000萬美元,主要是由於PSO的授權燃油費率較低。
由於I & m的退款監管規定,減少了1200萬美元。
系統外銷售 增加2500萬美元,主要是由於經濟對沖活動和Rockport工廠,Unit 200萬。rchant在I & m的銷售額。
傳輸收入 增加2400萬美元,主要是由於輸電資產的持續投資。
其他收入 增加600萬美元,主要是由於可再生能源信貸銷售額和杆子附着收入的增加。
22


費用以及其他和所得稅福利逐年變化如下:

購買用於發電的電力、燃料和其他消耗品 減少3700萬美元,主要是由於PSO、SWEPCo和I & m的減少,部分被APCo的增加所抵消。
其他運營維護費用 增加5200萬美元主要原因:
PJm和SPP傳輸服務增加3700萬美元。
由於上一年保險單結算收益增加了2000萬美元。
折舊及攤銷 增加5,000萬美元,主要是由於APCo、PSO和SWEPCo的可折舊基數較高、與I & m確認核PTC相關的監管準備金增加以及PSO和SWEPCo的監管資產攤銷增加。
除所得稅以外之稅項 增加600萬美元,主要是由於APCo、KPCo和PSO的財產稅增加。
淨定期養老金成本的非服務成本組成 增加500萬美元,主要是由於之前計劃變更導致之前的服務信用攤銷到期,部分被2023年有利的資產回報導致的損失攤銷減少以及貼現率降低導致的利息成本降低所抵消。
利息支出 減少700萬美元,主要是由於SWEPCo風暴相關監管資產的上一年攤銷。
所得稅優惠 增加3200萬美元主要原因:
由於I & m的核PTC估計增加了6100萬美元。
這一增長被以下因素部分抵消:
由於超額ADIT攤銷減少,減少了2200萬美元。
由於稅前賬簿收入減少,減少了600萬美元。

截至2024年9月30日的9個月與截至2023年9月30日的9個月

收入增長的主要組成部分如下:

零售收入 增加3700萬美元主要原因:
APCo和WPCo的騎手收入增加了9100萬美元。
由於降溫天數增加12%,與天氣相關的使用量增加了9100萬美元,主要是住宅類。
由於2020-2022年弗吉尼亞三年期審查,APCo的費率增加了6000萬美元。
KPCo的騎手收入增加了4900萬美元。
PSO的基本費率和騎手收入增加了3200萬美元。
由於印第安納州和密歇根州實施新的基本利率,I & m的收入增加了1200萬美元。
I & m騎手收入增加900萬美元。
這些增加被以下因素部分抵消:
SWEPCo減少17600萬美元,主要是由於確認了與土耳其工廠和SWEPCo 2012年德克薩斯州基本利率案件相關的16000萬美元可能收入退款。
燃料收入減少10600萬美元,主要是由於PSO的授權燃油費率較低。
由於I & m的退款監管規定,減少了3400萬美元。
系統外銷售 增加2800萬美元,主要是由於經濟對沖活動和Rockport工廠,Unit 200萬。rchant在I & m的銷售額。
傳輸收入 增加3900萬美元,主要是由於輸電資產的持續投資。
其他收入 增加2800萬美元,主要是由於PSO和SWEPCo的相關業務開發收入以及APCo的杆子連接收入。

費用以及其他和所得稅福利逐年變化如下:

購買用於發電的電力、燃料和其他消耗品 費用減少1900萬美元,主要是由於PSO和SWEPCo的減少,部分被APCo和I & m的增加所抵消。
其他運營維護 費用增加23900萬美元主要原因:
PJm和SPP傳輸服務增加11100萬美元。
由於自願遣散計劃,與退休人員相關的費用增加了7600萬美元。
由於上一年保險單結算收益增加了2000萬美元。
由於LCSC於2024年4月批准的和解協議導致Dolet Hills發電站的剩餘淨資產被取消,因此增加了1400萬美元。
23


資產減損和其他相關費用 由於聯邦環保局修訂的MCR規則,增加了1300萬美元。
折舊及攤銷 費用增加5900萬美元 主要原因如下:
SWEPCo增加3100萬美元,主要是由於監管資產攤銷增加和可折舊基數增加,但部分被與NOLC相關的監管資產的確認所抵消。
APCo增加了2000萬美元,主要是由於可折舊基數較高。
PSO增加1400萬美元,主要是由於可折舊基數較高、實施新利率以及與NCWF相關的監管資產攤銷。
除所得稅以外之稅項 增加2000萬美元 主要是由於PSO、I & m和KPCo的財產稅增加以及APCo的弗吉尼亞州最低稅增加,部分被SWEPCo的財產稅減少所抵消。
建設期間使用的股權資金津貼 增加700萬美元 主要是由於Courier和AFUDC股票利率較高。
淨定期效益成本的非服務成本組成 增加2100萬美元,主要是由於先前計劃變更導致的先前服務信用攤銷到期,但部分被2023年有利的資產回報導致的損失攤銷減少以及貼現率降低導致的利息成本降低所抵消。
利息支出 減少2800萬美元,主要是由於在零售費率制定中收到有關獨立NOLC處理的IRS PLR,確認了債務附帶費用。
所得稅優惠 增加31700萬美元主要原因:
由於收到有關獨立NOLC處理的IRS PLR,I & m、PSO和SWEPCo的超額ADIT監管負債減少,增加了21200萬美元。
由於I & m的核PTC估計增加了6100萬美元。
由於APSC拒絕SWEPCo允許特克工廠的商業部分爲阿肯色州客戶提供服務的請求,超額ADIT監管責任減少,因此增加了3200萬美元。

24


傳輸和分配公用事業

輸配電公用事業千瓦時能源銷售彙總
止三個月止九個月
9月30日,9月30日,
2024202320242023
 (in數百萬千瓦時)
零售業:    
住宅8,206 8,442 21,079 20,618 
商業9,671 8,574 26,871 22,711 
工業6,725 6,601 20,363 19,800 
雜類213 220 573 565 
零售總額(a)24,815 23,837 68,886 63,694 
批發(b)504 485 1,347 1,366 
總千瓦時25,319 24,322 70,233 65,060 

(a)代表交付給分銷客戶的能源。
(b)主要是俄亥俄州根據合同義務購買的OREC電力出售給PJm。

供暖天數和製冷天數是公用事業行業常用的指標,用於衡量天氣對收入的影響。 總體而言,由於兩個地區的相對規模以及每個地區內的客戶數量,東部地區的學位日變化對收入的影響大於西部地區的變化。

輸配電公用事業供暖和製冷度天數彙總
止三個月止九個月
9月30日,9月30日,
2024202320242023
 (in學位天數)
東部地區    
實際 供暖(a)
— — 1,573 1,521 
正常 供暖(b)
2,056 2,080 
實際 冷卻(c)
844 625 1,266 809 
正常 冷卻(b)
699 697 1,008 1,005 
西部地區    
實際 供暖(a)
— — 162 143 
正常 供暖(b)
— — 198 197 
實際 冷卻(d)
1,457 1,719 2,801 2,945 
正常 冷卻(b)
1,401 1,387 2,487 2,454 

(a)升溫程度天數以55度溫度爲基礎計算。
(b)正常供暖/製冷代表三十年來的平均度數天數。
(c)東部地區降溫天數以65度氣溫爲基礎計算。
(d)西部地區降溫天數以70度氣溫爲基礎計算。
25


輸電和配電公用事業
2023年至2024年歸屬於AEP普通股股東的盈利對賬
(in數百萬)
  
截至3月31日的三個月。
9月30日,
止九個月
9月30日,
2023年歸屬於AEP普通股股東的盈利$206.0 $508.4 
  
收入變化: 
零售收入9.0 90.9 
系統外銷售(2.1)(11.7)
傳輸收入16.6 47.8 
其他收入7.8 26.0 
收入總變化31.3 153.0 
  
費用及其他變化: 
購買電力轉售
61.6 278.1 
從AEP附屬機構購買電力23.9 (36.6)
其他運營維護(57.9)(166.3)
資產減損和其他相關費用— (52.9)
折舊及攤銷(5.9)(86.0)
除所得稅以外之稅項(0.3)(31.3)
其他收入3.4 5.6 
建設期間使用的股權資金津貼3.6 20.2 
淨定期效益成本的非服務成本組成(2.8)(10.7)
利息支出(12.6)(28.4)
費用及其他總變化13.0 (108.3)
  
所得稅費用(5.1)(10.0)
未合併子公司的權益收益(損失)— (0.8)
  
2024年歸屬於AEP普通股股東的盈利$245.2 $542.3 

2024年第三季度與2023年第三季度相比

收入增長的主要組成部分如下:

零售收入 增加900萬美元主要原因:
費率騎手的收入增加了13000萬美元。
這一增長被以下因素部分抵消:
104美元 由於OPCo的NSO的客戶參與度下降,減少了100萬美元,部分被價格上漲所抵消。
俄亥俄州工業階層和德克薩斯州住宅階層的天氣正常化收入減少了2000萬美元。
傳輸收入 增加1700萬美元主要原因:
由於德克薩斯州輸電投資的增加,臨時費率增加了1000萬美元。
由於德克薩斯州負荷增加,增加了600萬美元。
其他收入 增加800萬美元主要原因:
增加1300萬美元,主要是由於第三方Legacy Generation Resource Rider的收入與收回DVEC成本相關。
這一增長被以下因素部分抵消:
德克薩斯州證券化收入減少500萬美元。
26


費用以及其他和所得稅發票在年度之間的變化如下:

購買電力轉售 費用減少6200萬美元,主要原因如下:
可收回拍賣購買量減少8000萬美元,主要是由於OPCo的NSO客戶參與度下降導致成交量下降。
這一減幅被以下各項部分抵銷:
可收回的DVEC成本增加1900萬美元。
從AEP附屬機構購買電力 費用減少2400萬美元,主要是由於OPCo的NSO中的可收回拍賣購買量減少。
其他運營維護 費用增加5800萬美元,主要原因如下:
傳輸費用增加3100萬美元,主要是由於可收回的PJm費用增加。
俄亥俄州和德克薩斯州的分配相關費用增加了1200萬美元。
1100萬美元的增加與俄亥俄州合格客戶的可回收能源援助計劃費用有關。
折舊及攤銷 費用增加600萬美元 主要是由於俄亥俄州可收回附加費可折舊資產增加。
利息支出 增加1300萬美元,主要是由於債務餘額和利率上升。
所得稅費用 增加500萬美元,主要是由於稅前賬簿收入增加。

截至2024年9月30日的9個月與截至2023年9月30日的9個月

收入增長的主要組成部分如下:

零售收入 增加9100萬美元主要原因:
費率騎手的收入增加了35200萬美元。
由於降溫天數增加56%,俄亥俄州與天氣相關的使用量增加了4400萬美元。
這些增加被以下因素部分抵消:
由於OPCo的NSO的客戶參與度下降,減少了30600萬美元,部分被俄亥俄州價格上漲所抵消。
系統外銷售 減少1200萬美元,主要是由於2023年PJm與冬季風暴埃利奧特有關的結算。
傳輸收入 增加4800萬美元主要原因:
由於德克薩斯州輸電投資增加,臨時費率增加了2900萬美元。
由於德克薩斯州負荷增加,增加了1800萬美元。
其他收入 增加2600萬美元主要原因:
由於第三方Legacy Generation Resource Rider收入與OREC成本回收相關,增加了3300萬美元。
這一增長被以下因素部分抵消:
俄亥俄州可再生能源信用的可回收銷售額減少了900萬美元。

費用以及其他和所得稅發票在年度之間的變化如下:

購買電力轉售 費用減少27800萬美元,主要原因如下:
可收回拍賣購買量減少34200萬美元,主要是由於OPCo NSO的客戶參與度下降導致成交量下降,部分被價格上漲所抵消。
俄亥俄州的可回收替代能源騎手費用減少了1600萬美元。
這些減幅被以下各項部分抵銷:
可收回的DVEC成本增加8100萬美元。
從AEP附屬機構購買電力 費用增加3700萬美元,主要是由於OPCo的NSO中可收回拍賣購買量減少。
其他運營維護 費用增加16600萬美元主要原因:
傳輸費用增加7300萬美元,主要是由於可收回的PJm費用增加。
由於自願遣散計劃,與退休人員相關的費用增加了3500萬美元。
由於德克薩斯州2023年5月通過的立法導致上一年的費用減少,該立法允許收回基於經濟的激勵措施,導致去年的費用減少。
俄亥俄州的分配費用增加了1900萬美元,主要與可恢復風暴恢復成本和可恢復植被管理費用有關。
增加1600萬美元與俄亥俄州合格客戶的可回收能源援助計劃費用有關。
資產減損和其他相關費用 由於聯邦EPA修訂的MCR規則,增加了5300萬美元。
折舊及攤銷 費用增加8600萬美元,主要是由於俄亥俄州和德克薩斯州的可折舊基數較高以及俄亥俄州的可收回附加費可折舊資產增加。
27


除所得稅以外之稅項 主要增加3100萬美元 由於以下原因:
由於 俄亥俄州輸電和配電資產的額外投資以及稅率變化推動了財產稅上漲。
由於2024年計費千瓦時增加,州消費稅將增加800萬美元。
這些增加被以下因素部分抵消:
減少1200萬美元,主要是由於稅率下降導致財產稅下降 得克薩斯
建設期間使用的股權資金津貼 增加了2000萬美元,主要是由於俄亥俄州和德克薩斯州的AFUDC基地增加。
淨定期效益成本的非服務成本組成 增加1100萬美元,主要是由於先前計劃變更導致的先前服務信用攤銷到期,部分被2023年有利的資產回報導致的損失攤銷減少以及貼現率降低導致的利息成本降低所抵消。
利息支出增加2800萬美元主要由於:
增加3400萬美元主要是由於債務餘額和利率上升。
這一增長被以下因素部分抵消:
由於AFUDC預付養老金和OPb的資本化增加,減少了600萬美元。
所得稅費用 增加1000萬美元主要是由於:
由於稅前賬簿收入增加,增加了900萬美元。
由於德克薩斯州超額ADIT攤銷減少,增加了600萬美元。
這些增加被以下因素部分抵消:
由於AFUDC股權減少,減少了400萬美元。
28


AEP傳輸控股公司
AEP輸電控股公司輸電資產投資彙總
9月30日,
20242023
(in數百萬)
正在使用的工廠$15,125.0 $14,042.9 
在建工程2,411.1 2,037.0 
累計折舊和攤銷1,555.5 1,261.2 
總傳輸財產,淨$15,980.6 $14,818.7 

AEP變速箱控股公司
2023年至2024年歸屬於AEP普通股股東的盈利對賬
(in數百萬)
截至3月31日的三個月。
9月30日,
止九個月
9月30日,
2023年歸屬於AEP普通股股東的盈利$202.9 $580.8 
傳輸收入的變化:
傳輸收入35.8 108.9 
輸電收入總變化35.8 108.9 
費用及其他變化:
其他運營維護(0.7)(12.9)
折舊及攤銷(8.6)(29.6)
除所得稅以外之稅項(5.7)(11.4)
利息和投資收入1.3 3.3 
建設期間使用的股權資金津貼1.6 2.5 
淨定期養老金成本的非服務成本組成(0.1)(2.1)
利息支出(2.6)(12.7)
費用及其他總變化(14.8)(62.9)
所得稅費用(9.8)(13.5)
未合併子公司的權益收益0.7 11.4 
歸屬於非控制性權益的淨利潤(0.1)(0.6)
2024年歸屬於AEP普通股股東的盈利$214.7 $624.1 

2024年第三季度與2023年第三季度相比

輸電收入增長(包括對附屬公司和非附屬公司的批發銷售)的主要組成部分如下:

傳輸收入 增加3600萬美元,主要是由於輸電資產的持續投資。

費用以及其他和所得稅發票在年度之間的變化如下:

折舊及攤銷 費用增加900萬美元,主要是由於可折舊基數較高。
除所得稅以外之稅項 增加600萬美元,主要是由於輸電投資增加導致財產稅上漲。
所得稅費用 增加1000萬美元,主要是由於稅前賬簿收入增加和州所得稅增加。
29


截至2024年9月30日的九個月與截至2023年9月30日的九個月相比

輸電收入增長(包括對附屬公司和非附屬公司的批發銷售)的主要組成部分如下:
 
傳輸收入 增加10900萬美元,主要是由於輸電資產的持續投資。

未合併子公司的費用和其他、所得稅發票和股權收益在年度之間變化如下:
其他運營維護 費用增加1300萬美元,主要是由於與僱傭相關的費用增加1100萬美元 由於自願遣散計劃。
折舊及攤銷 費用增加3000萬美元,主要是由於可折舊基數較高。
除所得稅以外之稅項 增加1100萬美元,主要是由於輸電投資增加推動財產稅上漲。
利息支出 增加1300萬美元,主要是由於長期債務餘額和利率上升。
所得稅費用 增加1400萬美元,主要是由於稅前賬簿收入增加。
未合併子公司的權益收益 增加1100萬美元,主要是由於ETT稅前利潤增加。




30


生成與營銷

2023年至2024年歸屬於AEP普通股股東的盈利對賬
(in數百萬)
  
截至3月31日的三個月。
9月30日,
止九個月
9月30日,
2023年歸屬於AEP普通股股東的盈利$130.7 $(59.3)
  
收入變化: 
商人一代(6.4)(13.4)
再生能源發電(13.0)(61.7)
零售、貿易和營銷(48.2)380.1 
收入總變化(67.6)305.0 
  
費用及其他變化: 
購買用於發電的電力、燃料和其他消耗品(7.0)(35.0)
其他運營維護10.6 35.9 
資產減損和其他相關費用— (76.2)
競爭性合同可再生能源投資組合的銷售損失— 112.0 
折舊及攤銷4.3 17.4 
除所得稅以外之稅項0.8 4.6 
其他收入(3.3)(3.6)
淨定期效益成本的非服務成本組成(0.7)(2.1)
利息支出14.7 54.3 
費用及其他總變化19.4 107.3 
  
所得稅優惠6.9 (123.0)
未合併子公司的權益收益(損失)1.8 (1.0)
歸屬於非控制性權益的淨利潤(損失)2.1 (2.9)
  
2024年歸屬於AEP普通股股東的盈利$93.3 $226.1 

2024年第三季度與2023年第三季度相比

收入減少的主要組成部分如下:

商人一代 減少600萬美元,主要是由於2024年實現價格下降。
再生能源發電 減少1300萬美元,主要是由於2023年8月出售了有競爭力的合同可再生能源組合。
零售、貿易和營銷 減少4800萬美元,主要是由於大宗商品價格變化推動的2023年經濟對沖活動未實現收益48億美元,以及2024年經濟對沖活動未實現虧損700萬美元。

費用以及其他和所得稅福利逐年變化如下:

購買用於發電的電力、燃料和其他消耗品 費用增加700萬美元,主要是由於2024年能源成本增加。
其他運營維護 費用減少1100萬美元,主要是由於2023年8月出售了有競爭力的合同可再生能源組合。
利息支出減少1500萬美元,主要是由於附屬公司的預付款減少。
所得稅優惠 增加700萬美元主要原因:
由於遞延ITCs攤銷增加,增加了1000萬美元。
由於稅前賬簿收入減少,增加了1000萬美元。
這些增加被以下因素部分抵消:
由於PTC減少,減少了900萬美元。
31


截至2024年9月30日的9個月與截至2023年9月30日的9個月

收入增長的主要組成部分如下:

商人一代 減少1300萬美元,主要是由於2024年實現價格下降。
再生能源發電 減少6200萬美元,主要是由於2023年8月出售了有競爭力的合同可再生能源組合。
零售、貿易和營銷 增加38000萬美元,主要是由於大宗商品價格變化推動的2023年經濟對沖活動未實現損失22100萬美元,以及2024年經濟對沖活動未實現收益8900萬美元。

費用以及其他和所得稅福利逐年變化如下:

購買用於發電的電力、燃料和其他消耗品 費用增加3500萬美元,主要是由於2024年能源成本增加。
其他運營維護 費用減少3600萬美元,主要是由於2023年8月出售了有競爭力的合同可再生能源組合。
資產減損和其他相關費用 由於聯邦環保局修訂的MCR規則,增加了7600萬美元。
競爭性合同可再生能源投資組合的銷售損失 由於2023年8月出售的稅前虧損,減少了11200萬美元。
折舊及攤銷費用減少1700萬美元,主要是由於2023年8月出售了有競爭力的合同可再生能源組合。
利息支出由於附屬公司的預付款減少,減少了5400萬美元。
所得稅優惠 減少12300萬美元主要原因:
由於稅前賬簿收入增加,減少了8600萬美元。
由於PTC減少,減少了4500萬美元。
這些減幅被以下各項部分抵銷:
由於遞延ITCs攤銷增加,增加了1000萬美元。
32


企業及其他

2024年第三季度與2023年第三季度相比

歸屬於AEP普通股股東的公司和其他盈利從2023年的9800萬美元虧損減少至2024年的16500萬美元虧損,主要原因是:

2024年記錄了與SEC調查相關的1900萬美元損失意外情況。
由於利率上升和利率互換取消,利息支出增加了1700萬美元。
保險準備金增加1700萬美元。
利息收入減少1200萬美元,主要是由於向聯屬公司的預付款減少。

截至2024年9月30日的9個月與截至2023年9月30日的9個月

歸屬於AEP普通股股東的公司和其他盈利從2023年的21000萬美元虧損減少至2024年的28800萬美元虧損,主要原因是:

利息收入減少6100萬美元,主要是由於向聯屬公司的預付款減少。
由於利率上升和利率互換取消,利息費用增加3100萬美元。
由於肯塔基州業務終止出售導致上一年調整,減少了2800萬美元。
2024年記錄了與SEC調查相關的1900萬美元損失意外情況。
保險準備金增加1700萬美元。
這些收入下降被以下因素部分抵消:
企業支出減少4600萬美元。
所得稅發票減少3000萬美元,主要是由於稅前賬簿收入減少。

AEP綜合所得稅

2024年第三季度與2023年第三季度相比

所得稅發票減少2700萬美元,主要原因是:
由於估計的核PTC,減少了5100萬美元。
由於州所得稅費用減少,減少了900萬美元。
這些減幅被以下各項部分抵銷:
由於超額ADIT攤銷減少,增加了3000萬美元。

截至2024年9月30日的9個月與截至2023年9月30日的9個月

所得稅發票減少20100萬美元主要原因:
減少21200萬美元,原因是I & m、PSO和SWEPCo收到有關零售費率制定中獨立NOLC處理的IRS PLR,導致I & m、PSO和SWEPCo的超額ADIT監管負債減少。
由於估計的核PTC,減少了5100萬美元。
由於APSC於2024年3月拒絕SWEPCo允許土耳其工廠商業部分爲阿肯色州客戶提供服務的請求,導致與土耳其工廠超額ADIT商業部分相關的監管責任被逆轉,因此減少了3200萬美元。
這些減幅被以下各項部分抵銷:
由於稅前賬簿收入增加,增加了4900萬美元。
由於超額ADIT的無保護攤銷減少,增加了2900萬美元。
33


財務狀況

AEP通過其資產負債表的強度和現金流提供的流動性來衡量財務狀況。

流動資金和資本資源

債務和股權資本化
 2024年9月30日2023年12月31日
 (百萬美元)
長期債務,包括一年內到期的金額$41,974.4 59.7 %$40,143.2 58.8 %
短期債務1,659.6 2.4 2,830.2 4.2 
債務總額43,634.0 62.1 42,973.4 63.0 
AEP普通股權26,617.4 37.9 25,246.7 37.0 
非控制性權益41.4 — 39.2 — 
債務和股權資本總額$70,292.8 100.0 %$68,259.3 100.0 %

截至2023年12月31日和2024年9月30日,AEP的債務與總資本之比分別從63.0%下降至62.1%,主要是由於2024年ATM計劃下發行的盈利和股權增加,部分被長期債務增加所抵消,以支持配電和輸電投資增長以及流動資金需求。

流動性

流動性是決定AEP財務穩定性的一個重要因素。AEP管理層認爲AEP擁有充足的流動性。截至2024年9月30日,AEP擁有60億循環信貸安排來支持其商業票據計劃。此外,來自運營的現金和應收賬款證券化協議提供了額外的流動性。AEP管理層致力於維持充足的流動性。AEP通常使用短期借款爲營運資金需求、房地產收購和建設提供資金,直到安排長期資金。長期資金來源包括髮行長期債務、長期資產證券化、租賃協議、混合證券或普通股。AEP及其公用事業公司通過商業票據和其他受利率波動影響的可變利率工具爲其運營提供資金。在利率上升的程度上,這可能會減少未來的淨收益和現金流,並影響財務狀況。

市場波動和金融市場流動性減少可能會影響AEP以合理條款籌集資本以滿足資本需求的能力,包括建設成本和到期債務再融資。 AEP繼續監控當前的銀行環境及其影響。 截至2024年9月30日的九個月內,AEP並未受到這些條件的重大影響。

淨可用流動性

AEP通過維持充足的外部融資承諾來管理流動性。 截至2024年9月30日,可用流動性約爲55億美元,如下表所示:

成熟度(a)
商業紙張備份:(in數百萬)
循環信貸安排$5,000.0 2029年3月
循環信貸安排1,000.0 2027年3月
現金和現金等價物245.8  
總流動性來源6,245.8  
減:AEP傑出商業票據755.0  
淨可用流動性$5,490.8  

(a)2024年3月,AEP將其40億美元的循環信貸額度增加至50億美元,並將到期日從2027年3月延長至2029年3月。 此外,2024年3月,AEP將其10億美元循環信貸額度的到期日從2025年3月延長至2027年3月。

34


AEP利用其商業票據計劃來滿足其子公司的短期借款需求。 該計劃爲公用事業資金池提供資金,爲AEP的公用事業子公司提供資金;非公用事業資金池,爲某些AEP非公用事業子公司提供資金;以及因監管或運營原因未參與資金池的子公司作爲直接借款人的短期債務要求。 2024年前9個月未償商業票據的最高金額爲29億美元。 2024年AEP商業票據的加權平均利率爲5.55%。

其他信貸安排

未承諾的信貸使信貸的發行人有權接受或拒絕根據該信貸提出的每項請求。 AEP代表子公司根據六項未承諾信貸發放信用證,總額爲45000萬美元。 截至2024年9月30日,註冊人對根據未承諾信貸發放的信用證的最高未來付款額爲23600萬美元,到期日爲2024年10月至2025年7月。

證券化帳戶收件箱

AEP Credit的應收賬款證券化協議爲銀行渠道提供了9億美元購買應收賬款的承諾,並於2026年9月到期。 截至2024年9月30日,附屬公用事業子公司符合協議的所有要求。

債務契約和借款限制

AEP的信貸協議包含某些契約,並要求其將債務與總資本之比保持在不超過67.5%的水平。*AEP的信貸協議中對未償債務和資本化的計算方法是合同定義的。循環信貸協議中定義的債務不包括證券化債券和AEP Credit的債務。截至2024年9月30日, 這一合同規定的百分比爲58.8%。此外,根據任何其他與超過10000美元萬未償債務有關的協議或工具,在到期前加速履行AEP的付款義務,或AEP某些主要子公司的債務,將導致這些信用協議下的違約事件。但這一條件也適用於AEP的大多數非交易所交易商品合約,也適用於更具限制性的5,000萬未償債務水平,並同樣允許貸款人和交易對手申報未償還金額。根據AEP的信貸協議,非交易所交易大宗商品合約的違約不會導致違約事件。

如果發生重大不利變化,循環信貸安排不允許貸方拒絕提取任何信貸。

公用事業資金池借款和外部借款不得超過監管命令授權的金額,AEP管理其借款以保持在這些授權限額內。

自動櫃員機計劃

AEP參與了ATM計劃,該計劃允許AEP不時發行其普通股股份,包括根據股權遠期銷售協議可能出售的普通股股份。 截至2024年9月30日,根據ATM計劃可發行約13億美元的股權。 有關更多信息,請參閱註釋12 -融資活動。

股息政策和限制

董事會於2024年10月宣佈季度股息每股0.93美元。 未來股息可能會根據AEP的利潤水平、運營現金流水平和資本要求以及當時存在的財務和其他業務狀況而有所不同。 母公司的收入主要來自其公用事業子公司盈利中的普通股權益。 各種融資安排和監管要求可能會對子公司以股息形式向母公司轉移資金的能力施加一定限制。 管理層認爲這些限制不會對其獲得現金以支付普通股股息的能力產生任何重大影響。 有關更多信息,請參閱注12的「股息限制」部分。

信用評級

AEP及其公用事業子公司沒有任何需要因信用降級而對付款時間表進行重大改變或終止的信貸安排,但其進入商業票據市場的機會可能取決於其信用評級。 此外,其中一家評級機構下調AEP的信用評級可能會增加其借貸成本。 交易對手對AEP或其公用事業子公司信用質量的擔憂可能會使AEP根據其衍生和非衍生能源合同下的充分保證條款面臨額外的抵押品要求。
35


現金流

AEP主要依賴運營、債務發行、ATM計劃下普通股發行的現金流及其現有現金和現金等值物爲其流動性和投資活動提供資金。 AEP的投資和資本要求主要是資本支出、償還長期債務和向股東支付股息。 AEP使用短期債務(包括商業票據和銀行定期貸款)作爲長期債務融資的橋樑。 由於長期債務融資的時間和現金流波動的影響,借款水平可能會出現顯着差異。
止九個月
9月30日,
 20242023
 (in數百萬)
期末現金、現金等值物和限制現金$379.0 $556.5 
經營活動產生的現金流量淨額5,076.9 3,675.7 
用於投資活動的淨現金流(4,769.5)(4,643.5)
(用於)融資活動產生的淨現金流量(387.2)818.4 
現金、現金等價物和限制性現金淨減少(79.8)(149.4)
期末現金、現金等值物和限制現金$299.2 $407.1 

經營活動
止九個月
9月30日,
20242023
(in數百萬)
淨收入$2,309.9 $1,874.8 
淨利潤的非現金調整(a)2,540.7 2,469.5 
風險管理合同的按市值計價(97.6)(82.8)
財產稅508.3 486.1 
延期燃油回收過度/不足,淨304.6 542.8 
其他非流動資產變動(244.0)(396.8)
其他非流動負債的變化193.8 (21.5)
流動資金某些組成部分的變化(438.8)(1,196.4)
經營活動產生的現金流量淨額$5,076.9 $3,675.7 

(a)淨利潤的非現金調整包括折舊和攤銷、遞延所得稅、競爭性合同可再生能源投資組合的銷售損失、資產減損和其他相關費用以及AFUDC。

經營活動產生的現金流量淨額 增加14億美元主要原因:
流動資本某些組成部分的變化使現金增加7.58億美元。 增加主要是由於手頭煤炭庫存減少、與僱員相關的福利以及出售可轉讓稅收抵免收到的收益導致燃料、材料和供應減少。 這些增加被應收賬款收款時間部分抵消。
非現金調整後,淨利潤現金增加50600萬美元。 更多詳細信息,請參閱運營結果。
其他非流動資產變動和其他非流動負債變動使現金增加3.68億美元。 這一增長主要是由於利率附加機制下向客戶收款和退款之間的時間差異導致監管資產和負債發生變化。
這些現金增加被以下因素部分抵消:
現金減少2.38億美元,主要是由於燃料和購買力相關收入和費用的時間安排。


36


投資活動
止九個月
9月30日,
 20242023
 (in數百萬)
建設支出$(5,168.6)$(5,767.1)
核燃料的收購(98.4)(60.9)
收購可再生能源設施— (154.0)
出售股權法投資收益114.0 — 
出售資產收益365.0 1,335.6 
其他18.5 2.9 
用於投資活動的淨現金流$(4,769.5)$(4,643.5)

用於投資活動的淨現金流 增加12600萬美元主要原因:
資產出售收益減少9.71億美元,主要是由於2023年出售了競爭性的合同可再生能源組合,部分被2024年出售AEP Onsite Partners所抵消。 有關更多信息,請參閱注6的「處置」部分。
現金減少被以下因素部分抵消:
建築支出減少5.99億美元,主要是由於垂直集成公用事業減少24300萬美元、輸電和配電公用事業減少21300萬美元以及AEP輸電控股公司減少12800萬美元。
由於2023年收購Rock Falls風電設施,現金增加1.46億美元。 有關更多信息,請參閱註釋6的「Rock Falls風電設施」部分。
股權出售法投資收益增加1.14億美元。 有關更多信息,請參閱注6的「NRRD的處置」部分。

融資活動
止九個月
9月30日,
 20242023
 (in數百萬)
普通股發行$513.0 $959.3 
債務的發行/償還,淨608.8 1,282.7 
普通股股息(1,407.4)(1,293.8)
其他(101.6)(129.8)
(用於)融資活動產生的淨現金流量$(387.2)$818.4 

(用於)融資活動產生的淨現金流量 減少12億美元主要原因:
長期債務退休金增加6.16億美元。 有關更多信息,請參閱註釋12 -融資活動。
普通股發行減少4.46億美元,主要是由於2023年股權單位結算,但部分被2024年ATM計劃下的發行所抵消。 有關更多信息,請參閱註釋12 -融資活動。
長期債務發行減少2.69億美元。 有關更多信息,請參閱註釋12 -融資活動。
這些現金減少被以下因素部分抵消:
由於短期債務變化,增加了2.11億美元。 有關更多信息,請參閱註釋12 -融資活動。

關於2024年9月30日至2024年11月6日(第三季度10-Q提交日期)之後發行、報廢和本金支付的長期債務和其他證券,請參閱註釋12的「長期債務後續事項」部分。


37


預算資本支出

管理層大致預測 85億美元 2024年資本支出。 管理層預測2025年至2029年這五年期間的資本支出爲 544億美元. 管理層對2025年至2029年資本支出的預測反映了輸電基礎設施和新一代資源投資的計劃增加,以支持預計的大幅負荷增加和配電系統可靠性的持續改進。

這些支出通常用於輸電、發電、配電、受監管的可再生能源以及遵守聯邦環保局規則所需的環境投資。 估計的資本支出會定期審查和修改,並且可能會根據監管限制、環境法規、商業機會、市場波動、經濟趨勢、供應鏈問題、天氣、法律審查、通貨膨脹和獲得資本的能力的持續影響而有所不同。 管理層預計通過運營現金流、戰略性資產出售和融資活動的收益爲這些資本支出提供資金。 通常,註冊人子公司使用資金池下的現金或短期借款來爲這些支出提供資金,直到安排長期資金。

按業務分部劃分的2025-2029年估計資本支出如下:
細分市場2025-2029年預算資本支出
(in數百萬)
垂直集成公用事業$30,972 
輸電和配電公用事業14,162 
AEP變速箱控股公司8,590 
生成與營銷112 
公司和其他553 
$54,389 


重大現金要求

2023年年度報告中包含了重大現金需求的摘要,除上文「現金流」部分討論的債務發行和退休外,與年底相比沒有重大變化。

關鍵會計政策、估計和會計標準

關鍵會計政策和估算

有關監管會計、收入確認、衍生工具、長期資產估值所需的估計和判斷的討論,請參閱2023年年度報告中「管理層對財務狀況和經營結果的討論和分析」中的「關鍵會計政策和估計」部分,養老金和其他退休後福利的會計以及新會計準則和SEC規則制定活動的影響。

Aros

ARO被認爲是與財產、廠房和設備報廢相關的法律義務。在記錄ARO時,如果能夠對公允價值做出合理估計,預計負債的現值應在發生或制定法律義務的期間確認。債務是隨着時間的推移而增加的。對於運營設施,負債的現值被加到相關資產的成本中,並在資產的剩餘壽命內折舊。對於報廢設施,負債的現值被計入費用,如果未來可能通過差餉收回,負債的現值隨後作爲監管資產遞延。初始ARO的現值和隨後的更新是基於貼現現金流的,其中包括對未來現金流時間、貼現率和成本升高率的估計。這些估計可能會發生變化。折舊費用將根據相關資產賬面金額的任何變化進行前瞻性調整。

會計準則

有關會計準則和SEC規則制定活動相關的信息,請參閱注2 -新會計準則。

38


關於市場風險的定量和定性披露

市場風險

作爲主要電力生產商,垂直綜合公用事業部門通過電力、煤炭、天然氣和營銷合同交易面臨一定的市場風險。 這些風險包括可能受到容量風險、信用風險以及利率風險的商品價格風險。 這些風險代表因基礎市場價格或利率變化而可能影響該分部的損失風險。

輸配電公用事業部門面臨能源採購風險和利率風險。

發電與營銷部門在ERCOt、PJm、SPP和MISO開展營銷、風險管理和零售活動。 作爲批發和零售電力的營銷者,該部門面臨一定的市場風險。 這些風險包括可能受到容量風險、信用風險以及利率風險的商品價格風險。 這些風險代表因基礎市場價格或利率變化而可能影響該分部的損失風險。 此外,發電和營銷部門作爲電力生產商以及通過批發電力、天然氣和營銷合同的交易也面臨某些市場風險。

管理層採用風險管理合同,包括實物遠期和金融遠期購銷合同。管理層從事電力、產能、煤炭、天然氣以及較小程度的取暖油、汽油和其他大宗商品合同的風險管理,以管理與能源業務相關的風險。因此,AEP受到價格風險的影響。承擔的風險由商業運營、能源供應和財務部門根據董事會財務委員會批准的既定風險管理政策確定。AEPSC的市場風險監督人員獨立監督風險政策。監管風險委員會由AEPSC首席財務官、首席商務官、常務副監管員總裁、首席行政官總裁、監管商業運營部高級副總裁和財務與風險部高級副總裁組成。競爭風險委員會由AEPSC首席財務官、首席商務官、財務與風險部高級副總裁及競爭性商業運營部高級副總裁組成。除非得到各自委員會的特別批准,否則頭寸將被修改,以降低在限制範圍內的風險。

下表總結了與2023年12月31日相比MTm總值變化的原因:

MTm衍生品合同淨資產(負債)
截至2024年9月30日的九個月
垂直
集成
公用事業
傳輸

分佈
公用事業
世代
&
營銷
 (in數百萬)
MTm風險管理合同總額-截至2023年12月31日的商品淨資產(負債)
$16.9 $(51.0)$92.4 $58.3 
期內實現/結算並在前期進入的合同損失1.5 5.2 38.6 45.3 
(a)期內簽訂新合同時的公允價值— — (47.1)(47.1)
期內因市場波動而導致的公允價值變化(b)(22.7)— 46.9 24.2 
分配給受監管司法管轄區的公允價值變化(c)102.3 (6.7)— 95.6 
MTm風險管理合同總額-截至2024年9月30日的商品淨資產(負債)
$98.0 $(52.5)$130.8 176.3 
利率MTm合同(9.6)
商品現金流對沖 合同
 94.9 
利率現金流對沖 合同
  (10.9)
公允價值對沖合同  (81.7)
擔保存款  (27.6)
截至2024年9月30日的MTm衍生品合約淨資產總額
  $141.4 
39


(a)主要反映拍賣或長期結構性合同的公允價值,這些合同通常與尋求固定定價以限制能源價格波動風險的客戶簽訂。 合同價格根據與交付地點和交付期限相關的市場曲線進行估值。 總頭寸的很大一部分已進行經濟對沖。
(b)市場波動歸因於供需、天氣等多種因素。
(c)與未反映在利潤表中的合同淨收益(損失)有關。 這些淨收益(損失)在資產負債表上記錄爲監管負債/資產或應付賬款。

有關風險管理合同相關的更多信息,請參閱註釋9 -衍生品和對沖和註釋10 -公允價值計量。 下表和討論提供了有關信用風險和市場波動風險的信息。

信用風險

通過在與潛在交易對手達成交易之前評估其信譽並持續評估其信譽,批發營銷和交易活動中的信用風險可以減輕。 管理層使用信用機構評級和當前基於市場的定性和定量數據以及財務報表來持續評估交易對手方的財務健康狀況。

AEP與衆多交易對手簽訂了風險管理合同(包括非衍生品合同)。 由於未平倉風險管理合同的估值基於相關商品的市場價格變化,因此風險敞口每天都在變化。 截至2024年9月30日,扣除次級投資級別交易對手方抵押品後的信用風險敞口約爲6.4%,以淨MTm資產、淨應收賬款和不受MTm約束的合同的淨未平倉頭寸(代表經濟風險,儘管可能不存在會計損失風險)表示。

截至2024年9月30日,下表基於商品、工具和法律實體(如適用)的淨額結算,估算了AEP的交易對手信用質量和風險敞口:
交易對手信用質量暴露
在此之前
信用
抵押品
信用
抵押品
網絡
暴露
數量
交易對手
>10%的
網曝
網曝

交易對手
>10%
 (in數百萬,交易對手數量除外)
投資級$590.6 $43.4 $547.2 $328.9 
分裂評級10.4 — 10.4 10.4 
非投資級別5.1 — 5.1 5.1 
無外部評級:    
內部投資等級19.6 — 19.6 13.2 
內部非投資級別81.9 47.3 34.6 23.9 
截至2024年9月30日總計$707.6 $90.7 $616.9 

上表中的所有風險均與AEPSC和AEPEP有關,因爲AEPSC是某些AEP子公司(包括註冊人子公司)的代理人並代表其進行交易,而AEPEP是其他AEP子公司的代理人並代表其進行交易。

此外,AEP還面臨與參與RTI相關的信用風險。 對於AEP參與的每個RTI,此風險通常根據指定時間段內成員總活動的比例份額確定。

與風險管理合同相關的風險價值(VaR)

管理層使用計算VAR的風險測量模型來測量風險管理組合中AEP的商品價格風險。 VAR基於方差-協方差法,使用歷史價格來估計波動性和相關性,並假設95%的置信水平和一天的持有期。 根據該VAR分析,截至2024年9月30日,大宗商品價格的短期典型變化預計不會對淨利潤、現金流或財務狀況產生重大影響。

管理層計算交易和非交易投資組合的VAR。 交易組合主要由與能源交易和營銷活動相關的合同組成。 非交易投資組合主要由發電和零售供應活動的經濟對沖組成。


40


下表顯示了所示期間通過VAR衡量的期末、高、平均和低市場風險:

VaR模型
交易組合
止九個月截至12個月
2024年9月30日2023年12月31日
端部平均端部平均
(in數百萬)(in數百萬)
$0.3 $1.7 $0.3 $0.1 $0.2 $0.9 $0.2 $0.1 

VaR模型
非交易投資組合
止九個月截至12個月
2024年9月30日2023年12月31日
端部平均端部平均
(in數百萬)(in數百萬)
$15.4 $98.6 $20.6 $7.6 $17.7 $32.7 $16.4 $6.1 

由於實際價格變動,管理層根據業績對VAR結果進行了回測。 根據假設的95%置信區間,預計實際價格變動導致的業績至少每20個交易日超過一次VAR。

由於VAR計算捕捉了最近的價格波動,管理層還定期對交易組合進行壓力測試,以了解AEP面臨的極端價格波動風險。 採用基於歷史的方法,當前的交易組合受到過去幾年的實際觀察價格變動的影響,以確定哪些歷史價格變動轉化爲最大的潛在MTm損失。 然後,管理層研究產生最重大風險的基礎頭寸、價格走勢和市場事件,並酌情向風險執行委員會、監管風險委員會或競爭風險委員會報告調查結果。

利率風險

AEP在正常業務運作過程中會受到利率市場波動的影響。在2022年之前,利率保持在低水平,聯儲局在2021年的大部分時間裏將聯邦基金目標區間維持在0.0%至0.25%。在2022年至2023年期間,聯儲局批准了11次加息,累計加息5.25%。鑑於通脹和風險平衡方面的進展,2024年9月,聯儲局將利率下調了0.50%。AEP有未償還的短期和長期債務,這些債務受到可變利率的影響。AEP通過將可變利率風險敞口限制在總債務的一定百分比、簽訂利率衍生品工具和監測市場利率變化的影響來管理利率風險。在截至2024年、2023年和2023年9月30日的九個月裏,美國環保署浮動利率債務基準利率每變動100個點子,每年將分別影響2,100美元萬和4,500美元萬的稅前利息支出。
41



美國電力公司及附屬公司
簡明合併損益表
截至2024年和2023年9月30日的三個月和九個月
(in百萬,每股和股數除外)
(未經審計)
止三個月止九個月
9月30日,9月30日,
2024202320242023
收入
垂直集成公用事業$3,248.8 $3,158.1 $8,722.0 $8,603.4 
輸電和配電公用事業1,568.5 1,535.2 4,480.5 4,321.3 
生成與營銷483.7 527.5 1,442.1 1,172.6 
其他收入119.1 120.9 380.4 307.8 
總收入5,420.1 5,341.7 15,025.0 14,405.1 
費用    
購買用於發電的電力、燃料和其他消耗品1,659.2 1,756.8 4,603.5 4,887.8 
其他操作805.8 719.9 2,385.4 2,031.1 
維修343.7 325.5 1,012.7 982.8 
競爭性合同可再生能源投資組合的銷售損失   112.0 
資產減損和其他相關費用  142.5  
折舊及攤銷852.7 792.3 2,461.7 2,309.4 
除所得稅以外之稅項407.2 393.9 1,211.2 1,149.2 
總費用4,068.6 3,988.4 11,817.0 11,472.3 
營業收入1,351.5 1,353.3 3,208.0 2,932.8 
其他收入(支出):    
其他收入28.5 11.9 55.2 41.0 
建設期間使用的股權資金津貼54.2 51.1 153.0 123.4 
淨定期效益成本的非服務成本組成46.5 55.2 129.0 165.9 
利息支出(498.8)(470.3)(1,400.0)(1,346.0)
扣除所得稅費用(福利)和股票收益前收入981.9 1,001.2 2,145.2 1,917.1 
所得稅支出(福利)37.5 64.2 (97.7)103.2 
未合併子公司的股權收益17.3 21.3 67.0 60.9 
淨收入961.7 958.3 2,309.9 1,874.8 
 
歸屬於非控制性權益的淨利潤2.1 4.6 6.9 2.9 
歸屬於AEP普通股東的收入$959.6 $953.7 $2,303.0 $1,871.9 
AEP基本普通股加權平均股數532,208,876 520,459,880 529,230,818 516,528,239 
歸屬於AEP普通股東的每股基本收益總額$1.80 $1.83 $4.35 $3.62 
稀釋AEP普通股的加權平均數量533,600,842 521,444,125 530,456,985 517,784,726 
分配給AEP普通股東的每股稀釋收益總額$1.80 $1.83 $4.34 $3.62 
請參閱第頁開始的註冊人簡明財務報表簡明註釋 108.
42


美國電力公司及附屬公司
簡明綜合全面收益表(損益表)
截至2024年和2023年9月30日的三個月和九個月
(in數百萬)
(未經審計)
止三個月止九個月
9月30日,9月30日,
2024202320242023
淨收入$961.7 $958.3 $2,309.9 $1,874.8 
其他綜合收入(損失),免稅    
現金流對沖,扣除稅款$(12.3)和$(0.3)分別截至2024年9月30日和2023年9月30日的三個月,以及$(8.0)和$(31.5)分別截至2024年9月30日和2023年9月30日的九個月
(46.3)(0.9)(30.1)(118.5)
養老金和BEP遞延成本攤銷,扣除稅款$(0.1)和$(0.8)分別截至2024年9月30日和2023年9月30日的三個月,以及$(0.3)和$(5.9)分別截至2024年9月30日和2023年9月30日的九個月
(0.6)(3.2)(1.3)(22.4)
KPCo養老金和OPEb監管資產的重新分類,扣除稅款美元0 和$0 分別截至2024年9月30日和2023年9月30日的三個月和美元0 和$4.4 分別截至2024年9月30日和2023年9月30日的九個月
   16.7 
其他綜合損失共計(46.9)(4.1)(31.4)(124.2)
綜合收益總額914.8 954.2 2,278.5 1,750.6 
歸屬於非控制性權益的綜合收益總額2.1 4.6 6.9 2.9 
歸屬於AEP普通股東的綜合收入總額$912.7 $949.6 $2,271.6 $1,747.7 
請參閱第頁開始的註冊人簡明財務報表簡明註釋 108.
43


美國電力公司及附屬公司
股票變動的濃縮合並報表
截至2024年9月30日和2023年9月30日的九個月
(in數百萬)
(未經審計)
AEP普通股股東
普通股積累
其他
全面
收入(虧損)
股份已繳費
資本
保留
盈利
非控制性
利益
股票總數-2022年12月31日525.1 $3,413.1 $8,051.0 $12,345.6 $83.7 $229.0 $24,122.4 
普通股發行0.8 5.1 36.0  41.1 
普通股分紅(428.8)(a)(3.0)(431.8)
其他股權變化(12.7)0.2 (12.5)
淨收入   397.0 3.4 400.4 
其他全面損失    (151.8)(151.8)
股票總數-2023年3月31日525.9 3,418.2 8,074.3 12,313.8 (68.1)229.6 23,967.8 
普通股發行0.5 3.3 33.2    36.5 
普通股分紅   (429.5)(a) (2.3)(431.8)
其他股權變化  3.3  3.3 
淨收益(虧損)   521.2  (5.1)516.1 
其他全面收入    31.7  31.7 
股票總數-2023年6月30日526.4 3,421.5 8,110.8 12,405.5 (36.4)222.2 24,123.6 
普通股發行0.4 2.8 878.9 881.7 
普通股分紅(429.7)(a)(0.5)(430.2)
其他股權變化6.7 6.7 
有競爭力的合同可再生能源投資組合的處置(186.4)(186.4)
淨收入953.7 4.6 958.3 
其他全面損失(4.1)(4.1)
股票總數-2023年9月30日526.8 $3,424.3 $8,996.4 $12,929.5 $(40.5)$39.9 $25,349.6 
股票總數-2023年12月31日527.4 $3,427.9 $9,073.9 $12,800.4 $(55.5)$39.2 $25,285.9 
普通股發行0.8 5.4 35.2 40.6 
普通股分紅(465.5)(b)(1.4)(466.9)
其他股權變化(14.8)(14.8)
淨收入1,003.1 2.6 1,005.7 
其他全面損失(6.8)(6.8)
股票總數-2024年3月31日528.2 3,433.3 9,094.3 13,338.0 (62.3)40.4 25,843.7 
普通股發行4.9 32.1 403.1 435.2 
普通股分紅(467.0)(b)(2.1)(469.1)
其他股權變化1.1 1.1 
淨收入340.3 2.2 342.5 
其他全面收入22.3 22.3 
股票總數-2024年6月30日533.1 3,465.4 9,498.5 13,211.3 (40.0)40.5 26,175.7 
普通股發行0.6 3.3 33.9 37.2 
普通股分紅(470.2)(b)(1.2)(471.4)
其他股權變化2.5 2.5 
淨收入959.6 2.1 961.7 
其他全面損失    (46.9) (46.9)
股票總數-2024年9月30日533.7 $3,468.7 $9,534.9 $13,700.7 $(86.9)$41.4 $26,658.8 

(a) 每股AEP普通股宣佈的現金股息爲美元0.83.
(b) 每股AEP普通股宣佈的現金股息爲美元0.88.
請參閱第頁開始的註冊人簡明財務報表簡明註釋 108.
44


美國電力公司及附屬公司
CONDENSED CONSOLIDATED BALANCE SHEETS
資產
2024年9月30日和2023年12月31日
(in數百萬)
(未經審計)
 9月30日,12月31日,
 20242023
流動資產  
現金和現金等價物$245.8 $330.1 
受限現金
(2024年9月30日和2023年12月31日金額包括美元53.4 和$48.9分別與過渡資金、恢復資金和阿巴拉契亞消費者利率救濟資金有關)
53.4 48.9 
其他臨時投資
(2024年9月30日和2023年12月31日金額包括美元216.3 和$205,分別與EIA和Transsource Energy相關)
228.6 214.3 
應收賬款:  
顧客963.6 1,029.9 
應計未開票收入303.2 179.5 
已抵押應收賬款- AEP信貸1,330.3 1,249.4 
雜類65.4 48.7 
壞賬準備(65.4)(60.1)
應收賬款總額2,597.1 2,447.4 
燃料704.0 853.7 
材料和用品981.7 1,025.8 
風險管理資產236.7 217.5 
累積稅收優惠125.4 156.2 
燃料成本管理不足的監管資產399.7 514.0 
預付款和其他流動資產448.4 274.2 
流動資產總額6,020.8 6,082.1 
財產、廠房和設備  
電動:  
世代24,504.5 24,329.5 
傳輸37,309.8 35,934.1 
分佈30,486.1 28,989.9 
其他財產、廠房和設備(包括煤炭開採和核燃料)6,829.2 6,484.9 
在建工程6,797.0 5,508.0 
財產、廠房和設備總計105,926.6 101,246.4 
累計折舊和攤銷25,852.8 24,553.0 
財產、計劃和設備總計-淨80,073.8 76,693.4 
其他非當前資產  
監管資產5,318.9 5,092.4 
證券化資產253.4 336.3 
乏核燃料和退役信託4,425.8 3,860.2 
商譽52.5 52.5 
長期風險管理資產258.3 321.2 
經營租賃資產572.9 620.2 
遞延費用和其他非流動資產3,142.7 3,625.7 
其他非當前資產總計14,024.5 13,908.5 
總資產$100,119.1 $96,684.0 
請參閱第頁開始的註冊人簡明財務報表簡明註釋 108.
45


美國電力公司及附屬公司
CONDENSED CONSOLIDATED BALANCE SHEETS
負債和權益
2024年9月30日和2023年12月31日
(in百萬,每股和股數除外)
(未經審計)
   9月30日,12月31日,
 20242023
流動負債  
應付帳款$2,265.6 $2,032.5 
短期債務:  
貸款證券化債務- AEP信貸900.0 888.0 
其他短期債務759.6 1,942.2 
短期債務總額1,659.6 2,830.2 
一年內到期的長期債務
(2024年9月30日和2023年12月31日金額包括美元190.7 和$207.2,分別與Sabine、BCC燃料、過渡資金、恢復資金、阿巴拉契亞消費者稅率救濟資金和Transsource Energy相關)
2,826.7 2,490.5 
風險管理負債152.0 229.6 
客戶存款410.6 423.7 
應計稅1,236.6 1,800.1 
應計利息584.4 410.2 
經營租賃下的義務96.7 115.7 
其他流動負債1,415.4 1,251.1 
流動負債總額10,647.6 11,583.6 
非流動負債  
長期債務
(2024年9月30日和2023年12月31日金額包括美元545.9 和$556.3,分別與Sabine、BCC燃料、過渡資金、恢復資金、阿巴拉契亞消費者稅率救濟資金和Transsource Energy相關)
39,147.7 37,652.7 
長期風險管理負債201.6 241.8 
遞延所得稅9,958.8 9,415.7 
監管責任和遞延投資稅收抵免8,366.2 8,182.4 
資產報廢債務3,687.7 2,972.5 
員工福利和養老金義務216.5 241.7 
經營租賃下的義務490.5 519.4 
遞延信貸和其他非流動負債677.9 545.8 
非流動負債總額62,746.9 59,772.0 
總負債73,394.5 71,355.6 
費率很重要(注4)
承付款和或有事項(附註5)
夾層股權
臨時可兌換績效分享獎勵65.8 42.5 
夾層總股本65.8 42.5 
股權  
普通股-面值-美元6.50 每股:
  
20242023  
授權股份600,000,000600,000,000  
已發行股份533,652,728527,369,157  
(1,184,572 分別於2024年9月30日和2023年12月31日以金庫持有股份)
3,468.7 3,427.9 
實收資本9,534.9 9,073.9 
留存收益13,700.7 12,800.4 
累計其他綜合收益(虧損)(86.9)(55.5)
AEP普通股東股票總額26,617.4 25,246.7 
非控制性權益41.4 39.2 
總股本26,658.8 25,285.9 
總負債、中間股權和總股權$100,119.1 $96,684.0 
請參閱第頁開始的註冊人簡明財務報表簡明註釋 108.
46


美國電力公司及附屬公司
簡明合併現金流量表
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20242023
OPERATING ACTIVITIES  
Net Income$2,309.9 $1,874.8 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization2,461.7 2,309.4 
Deferred Income Taxes89.5 171.5 
Loss on the Sale of the Competitive Contracted Renewables Portfolio 112.0 
Asset Impairments and Other Related Charges142.5  
Allowance for Equity Funds Used During Construction(153.0)(123.4)
Mark-to-Market of Risk Management Contracts(97.6)(82.8)
Property Taxes508.3 486.1 
Deferred Fuel Over/Under-Recovery, Net304.6 542.8 
Change in Other Noncurrent Assets(244.0)(396.8)
Change in Other Noncurrent Liabilities193.8 (21.5)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(131.8)114.0 
Fuel, Materials and Supplies188.5 (344.4)
Accounts Payable14.2 (163.0)
Accrued Taxes, Net(532.3)(566.7)
Other Current Assets(139.2)(91.5)
Other Current Liabilities161.8 (144.8)
Net Cash Flows from Operating Activities5,076.9 3,675.7 
INVESTING ACTIVITIES  
Construction Expenditures(5,168.6)(5,767.1)
Purchases of Investment Securities(2,398.0)(2,199.7)
Sales of Investment Securities2,343.5 2,140.1 
Acquisitions of Nuclear Fuel(98.4)(60.9)
Acquisitions of Renewable Energy Facilities (154.0)
Proceeds from Sales of Assets365.0 1,335.6 
Proceeds from Sale of Equity Method Investment114.0  
Other Investing Activities73.0 62.5 
Net Cash Flows Used for Investing Activities(4,769.5)(4,643.5)
FINANCING ACTIVITIES  
Issuance of Common Stock513.0 959.3 
Issuance of Long-term Debt3,748.5 4,017.8 
Issuance of Short-term Debt with Original Maturities greater than 90 Days376.6 791.7 
Change in Short-term Debt with Original Maturities less than 90 Days, Net(676.1)(1,044.7)
Retirement of Long-term Debt(1,969.1)(1,353.3)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(871.1)(1,128.8)
Principal Payments for Finance Lease Obligations(51.2)(53.9)
Dividends Paid on Common Stock(1,407.4)(1,293.8)
Other Financing Activities(50.4)(75.9)
Net Cash Flows from (Used for) Financing Activities(387.2)818.4 
Net Decrease in Cash, Cash Equivalents and Restricted Cash(79.8)(149.4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period379.0 556.5 
Cash, Cash Equivalents and Restricted Cash at End of Period$299.2 $407.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
47


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 EndedNine Months Ended
September 30,September 30,
 2024202320242023
 (in millions of KWhs)
Retail:  
Residential4,116 4,681 10,174 10,295 
Commercial4,283 4,021 11,733 10,208 
Industrial3,181 3,065 9,778 9,344 
Miscellaneous189 196 496 487 
Total Retail11,769 11,963 32,181 30,334 

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.

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
September 30,September 30,
 2024202320242023
 (in degree days)
Actual – Heating (a)— — 162 143 
Normal – Heating (b)— — 198 197 
Actual – Cooling (c)1,457 1,719 2,801 2,945 
Normal – Cooling (b)1,401 1,387 2,487 2,454 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 70 degree temperature base.











48


AEP Texas Inc. and Subsidiaries
Reconciliation of 2023 to 2024 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2023 Net Income
$125.5 $282.2 
  
Changes in Revenues:
Retail Revenues5.2 84.9 
Transmission Revenues16.1 47.3 
Other Revenues(4.7)(0.3)
Total Change in Revenues16.6 131.9 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(7.8)(48.7)
Depreciation and Amortization(1.1)(16.8)
Taxes Other Than Income Taxes3.8 11.5 
Interest Income2.6 4.2 
Allowance for Equity Funds Used During Construction2.7 15.2 
Non-Service Cost Components of Net Periodic Benefit Cost(1.1)(3.6)
Interest Expense(7.8)(15.4)
Total Change in Expenses and Other(8.7)(53.6)
  
Income Tax Expense(0.9)(19.9)
  
2024 Net Income
$132.5 $340.6 

Third Quarter of 2024 Compared to Third Quarter of 2023

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

Retail Revenues increased $5 million primarily due to the following:
A $25 million increase in revenue from rate riders.
This increase was partially offset by:
A $12 million decrease in weather-related usage primarily due to a 15% decrease in cooling degree days.
An $8 million decrease in weather-normalized revenues primarily in the residential class.
Transmission Revenues increased $16 million due to the following:
A $10 million increase in interim rates driven by increased transmission investments.
A $6 million increase due to increased load.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $8 million primarily due to the following:
A $4 million increase in distribution-related expenses.
A $4 million increase in employee-related expenses.
Interest Expense increased $8 million primarily due to higher debt balances and interest rates.

49


Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Retail Revenues increased $85 million primarily due to the following:
A $73 million increase in revenue from rate riders.
A $21 million increase in weather-normalized revenues primarily in the commercial and residential classes.
These increases were partially offset by:
A $10 million decrease in weather-related usage primarily due to a 5% decrease in cooling degree days.
Transmission Revenues increased $47 million due to the following:
A $29 million increase in interim rates driven by increased transmission investments.
An $18 million increase due to increased load.

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

Other Operation and Maintenance expenses increased $49 million primarily due to the following:
A $28 million increase due to a prior year decrease in expenses driven by legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.
A $20 million increase in employee-related expenses due to the voluntary severance program.
Depreciation and Amortization expenses increased $17 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes decreased $12 million primarily due to lower property taxes driven by decreased tax rates.
Allowance for Equity Funds Used During Construction increased $15 million primarily due to a higher AFUDC base.
Interest Expense increased $15 million primarily due to the following:
A $21 million increase due to higher debt balances and interest rates.
This increase was partially offset by:
A $6 million decrease due to an increase of capitalization of AFUDC on prepaid pension and OPEB.
Income Tax Expense increased $20 million primarily due to the following:
A $16 million increase due to an increase in pretax book income.
A $6 million increase due to a decrease in amortization of Excess ADIT.
50



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
  Three Months EndedNine Months Ended
September 30,September 30,
  2024 202320242023
REVENUES    
Electric Transmission and Distribution $569.2 $551.6 $1,569.9 $1,438.7 
Sales to AEP Affiliates 1.3 1.2 4.0 3.7 
Other Revenues 0.7 1.8 3.3 2.9 
TOTAL REVENUES 571.2 554.6 1,577.2 1,445.3 
 
EXPENSES     
Other Operation 164.7 154.4 453.3 395.2 
Maintenance 22.5 25.0 66.3 75.7 
Depreciation and Amortization 126.7 125.6 368.3 351.5 
Taxes Other Than Income Taxes 44.8 48.6 125.4 136.9 
TOTAL EXPENSES 358.7 353.6 1,013.3 959.3 
 
OPERATING INCOME 212.5 201.0 563.9 486.0 
 
Other Income (Expense):     
Interest Income 3.1 0.5 5.7 1.5 
Allowance for Equity Funds Used During Construction10.5 7.8 34.6 19.4 
Non-Service Cost Components of Net Periodic Benefit Cost3.7 4.8 10.8 14.4 
Interest Expense (67.7)(59.9)(188.5)(173.1)
 
INCOME BEFORE INCOME TAX EXPENSE 162.1 154.2 426.5 348.2 
 
Income Tax Expense 29.6 28.7 85.9 66.0 
NET INCOME $132.5 $125.5 $340.6 $282.2 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
51


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
2024202320242023
Net Income$132.5 $125.5 $340.6 $282.2 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2024 and 2023, Respectively, and $1.6 and $0.8 for the Nine Months Ended September 30, 2024 and 2023, Respectively
(0.1)(0.1)6.0 3.1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2024 and 2023, Respectively, and $0 and $(0.1) for the Nine Months Ended September 30, 2024 and 2023, Respectively
   (0.6)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(0.1)(0.1)6.0 2.5 
TOTAL COMPREHENSIVE INCOME$132.4 $125.4 $346.6 $284.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

52


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022
$1,558.2 $2,354.7 $(8.6)$3,904.3 
Capital Contribution from Parent100.0 100.0 
Net Income47.6 47.6 
Other Comprehensive Loss(0.6)(0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023
1,658.2 2,402.3 (9.2)4,051.3 
Capital Contribution from Parent175.3  175.3 
Return of Capital to Parent(4.3)(4.3)
Net Income 109.1  109.1 
Other Comprehensive Income  3.2 3.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2023
1,829.2 2,511.4 (6.0)4,334.6 
Capital Contribution from Parent250.5 250.5 
Net Income125.5 125.5 
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2023
$2,079.7 $2,636.9 $(6.1)$4,710.5 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023
$2,079.6 $2,725.1 $(8.6)$4,796.1 
Net Income79.7 79.7 
Other Comprehensive Income3.9 3.9 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024
2,079.6 2,804.8 (4.7)4,879.7 
Capital Contribution from Parent1.6 1.6 
Net Income 128.4 128.4 
Other Comprehensive Income 2.2 2.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2024
2,081.2 2,933.2 (2.5)5,011.9 
Return of Capital to Parent(0.7)(0.7)
Common Stock Dividends(150.0)(150.0)
Net Income132.5 132.5 
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2024
$2,080.5 $2,915.7 $(2.6)$4,993.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

53


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
  September 30,December 31,
  2024 2023
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(September 30, 2024 and December 31, 2023 Amounts Include $45.1 and $34, Respectively, Related to Transition Funding and Restoration Funding)
45.1 34.0 
Advances to Affiliates61.8 7.1 
Accounts Receivable:   
Customers 213.0 176.5 
Affiliated Companies 20.4 23.8 
Accrued Unbilled Revenues116.7 82.3 
Miscellaneous 0.3 0.8 
Allowance for Uncollectible Accounts(4.1)(4.9)
Total Accounts Receivable 346.3 278.5 
Materials and Supplies 178.6 190.4 
Insurance Receivable55.0  
Prepayments and Other Current Assets 17.5 10.0 
TOTAL CURRENT ASSETS 704.4 520.1 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Transmission
 7,180.8 6,812.6 
Distribution
 6,157.0 5,798.8 
Other Property, Plant and Equipment 1,172.2 1,145.9 
Construction Work in Progress 1,159.0 904.6 
Total Property, Plant and Equipment 15,669.0 14,661.9 
Accumulated Depreciation and Amortization 2,018.2 1,887.9 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 13,650.8 12,774.0 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 354.0 315.3 
Securitized Assets
(September 30, 2024 and December 31, 2023 Amounts Include $140.4 and $202.9, Respectively, Related to Transition Funding and Restoration Funding)
140.4 202.9 
Deferred Charges and Other Noncurrent Assets 195.5 178.4 
TOTAL OTHER NONCURRENT ASSETS 689.9 696.6 
 
TOTAL ASSETS $15,045.1 $13,990.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
54


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
  September 30,December 31,
  2024 2023
CURRENT LIABILITIES 
Advances from Affiliates $ $103.7 
Accounts Payable: 
General 273.5 192.3 
Affiliated Companies 29.3 27.7 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2024 and December 31, 2023 Amounts Include $63.9 and $95.9, Respectively, Related to Transition Funding and Restoration Funding)
113.9 96.0 
Accrued Taxes 152.9 99.1 
Accrued Interest
(September 30, 2024 and December 31, 2023 Amounts Include $1.4 and $2, Respectively, Related to Transition Funding and Restoration Funding)
97.1 49.2 
Obligations Under Operating Leases16.1 28.7 
Accrued Litigation Settlement55.0  
Other Current Liabilities 193.3 152.7 
TOTAL CURRENT LIABILITIES 931.1 749.4 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(September 30, 2024 and December 31, 2023 Amounts Include $102.1 and $125.9, Respectively, Related to Transition Funding and Restoration Funding)
6,365.5 5,793.8 
Deferred Income Taxes 1,306.6 1,227.8 
Regulatory Liabilities and Deferred Investment Tax Credits 1,283.0 1,261.4 
Obligations Under Operating Leases45.9 50.9 
Deferred Credits and Other Noncurrent Liabilities 119.4 111.3 
TOTAL NONCURRENT LIABILITIES 9,120.4 8,445.2 
 
TOTAL LIABILITIES 10,051.5 9,194.6 
 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5) 
 
COMMON SHAREHOLDER’S EQUITY   
Paid-in Capital 2,080.5 2,079.6 
Retained Earnings 2,915.7 2,725.1 
Accumulated Other Comprehensive Income (Loss)(2.6)(8.6)
TOTAL COMMON SHAREHOLDER’S EQUITY 4,993.6 4,796.1 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $15,045.1 $13,990.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
55


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2024 2023
OPERATING ACTIVITIES    
Net Income $340.6 $282.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 368.3 351.5 
Deferred Income Taxes 70.3 64.2 
Allowance for Equity Funds Used During Construction(34.6)(19.4)
Change in Other Noncurrent Assets (99.3)(118.0)
Change in Other Noncurrent Liabilities 32.0 26.7 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (67.8)(81.8)
Materials and Supplies 11.8 (32.1)
Accounts Payable 23.6 0.7 
Accrued Taxes, Net56.0 39.7 
Other Current Assets (9.1)(0.7)
Other Current Liabilities 43.8 (9.9)
Net Cash Flows from Operating Activities 735.6 503.1 
 
INVESTING ACTIVITIES   
Construction Expenditures (1,042.4)(1,175.1)
Change in Advances to Affiliates, Net(54.7)(42.1)
Other Investing Activities44.2 42.2 
Net Cash Flows Used for Investing Activities (1,052.9)(1,175.0)
 
FINANCING ACTIVITIES   
Capital Contribution from Parent1.6 525.8 
Return of Capital to Parent(0.7)(4.3)
Issuance of Long-term Debt – Nonaffiliated841.9 505.4 
Change in Advances from Affiliates, Net (103.7)(96.5)
Retirement of Long-term Debt – Nonaffiliated (256.5)(240.0)
Principal Payments for Finance Lease Obligations (5.6)(5.5)
Dividends Paid on Common Stock (150.0) 
Other Financing Activities1.4 1.2 
Net Cash Flows from Financing Activities 328.4 686.1 
Net Increase in Cash, Cash Equivalents and Restricted Cash  11.1 14.2 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 34.1 32.8 
Cash, Cash Equivalents and Restricted Cash at End of Period $45.2 $47.0 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $132.8 $135.9 
Net Cash Paid (Received) for Income Taxes (2.7)4.3 
Noncash Acquisitions Under Finance Leases 3.6 3.7 
Construction Expenditures Included in Current Liabilities as of September 30, 167.3 153.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
56


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,
20242023
(in millions)
Plant In Service$14,720.4 $13,638.0 
Construction Work in Progress2,188.6 1,902.1 
Accumulated Depreciation and Amortization1,509.4 1,221.2 
Total Transmission Property, Net$15,399.6 $14,318.9 

AEP Transmission Company, LLC and Subsidiaries
Reconciliation of 2023 to 2024 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2023 Net Income$179.2 $517.6 
Changes in Transmission Revenues:
Transmission Revenues34.5 106.0 
Total Change in Transmission Revenues34.5 106.0 
Changes in Expenses and Other:
Other Operation and Maintenance(0.7)(16.3)
Depreciation and Amortization(8.6)(29.6)
Taxes Other Than Income Taxes(5.9)(12.0)
Interest Income1.5 3.6 
Allowance for Equity Funds Used During Construction1.6 2.5 
Interest Expense(2.7)(13.0)
Total Change in Expenses and Other(14.8)(64.8)
Income Tax Expense(7.6)(10.6)
2024 Net Income$191.3 $548.2 

Third Quarter of 2024 Compared to Third Quarter of 2023

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

Transmission Revenues increased $35 million primarily due to continued investment in transmission assets.

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

Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes driven by increased transmission investment.
Income Tax Expense increased $8 million primarily due to an increase in pretax book income and an increase in state income taxes.
57


Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Transmission Revenues increased $106 million primarily due to continued investment in transmission assets.

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

Other Operation and Maintenance expenses increased $16 million primarily due to a $12 million increase in employee-related expenses driven by an $11 million increase associated with the voluntary severance program.
Depreciation and Amortization expenses increased $30 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $12 million primarily due to higher property taxes driven by increased transmission investment.
Interest Expense increased $13 million primarily due to higher long-term debt balances and interest rates.
Income Tax Expense increased $11 million primarily due to an increase in pretax book income.


58



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2024 2023 2024 2023
REVENUES
Transmission Revenues$103.3 $93.8 $299.0 $274.0 
Sales to AEP Affiliates404.4 374.7 1,188.2 1,097.9 
Provision for Refund – Affiliated(8.5)(4.8)(31.1)(17.9)
Provision for Refund – Nonaffiliated(2.2)(1.0)(3.9)(4.8)
Other Revenues0.2  3.0  
TOTAL REVENUES497.2 462.7 1,455.2 1,349.2 
EXPENSES    
Other Operation31.7 31.6 101.6 87.0 
Maintenance5.7 5.1 16.0 14.3 
Depreciation and Amortization108.2 99.6 320.8 291.2 
Taxes Other Than Income Taxes79.7 73.8 228.6 216.6 
TOTAL EXPENSES225.3 210.1 667.0 609.1 
OPERATING INCOME271.9 252.6 788.2 740.1 
Other Income (Expense):    
Interest Income – Affiliated3.1 1.6 9.3 5.7 
Allowance for Equity Funds Used During Construction24.3 22.7 64.7 62.2 
Interest Expense(54.3)(51.6)(160.5)(147.5)
INCOME BEFORE INCOME TAX EXPENSE245.0 225.3 701.7 660.5 
Income Tax Expense53.7 46.1 153.5 142.9 
NET INCOME$191.3 $179.2 $548.2 $517.6 
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
59


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
  Paid-in
Capital
Retained
Earnings
Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2022 $3,022.3 $2,850.7 $5,873.0 
  
Capital Contribution from Member25.0 25.0 
Dividends Paid to Member(55.0)(55.0)
Net Income 162.7 162.7 
TOTAL MEMBER'S EQUITY – MARCH 31, 20233,047.3 2,958.4 6,005.7 
Return of Capital to Member(8.6)(8.6)
Dividends Paid to Member(30.0)(30.0)
Net Income175.7 175.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 20233,038.7 3,104.1 6,142.8 
Capital Contribution from Member 2.9 2.9 
Dividends Paid to Member(30.0)(30.0)
Net Income 179.2 179.2 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2023 $3,041.6 $3,253.3 $6,294.9 
  
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2023 $3,043.4 $3,289.9 $6,333.3 
Capital Contribution from Member25.0 25.0 
Dividends Paid to Member(40.0)(40.0)
Net Income181.2 181.2 
TOTAL MEMBER'S EQUITY – MARCH 31, 20243,068.4 3,431.1 6,499.5 
  
Capital Contribution from Member9.6 9.6 
Dividends Paid to Member(31.0)(31.0)
Net Income175.7 175.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 20243,078.0 3,575.8 6,653.8 
Return of Capital to Member(4.5)(4.5)
Dividends Paid to Member(26.0)(26.0)
Net Income  191.3 191.3 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2024 $3,073.5 $3,741.1 $6,814.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
60


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
  September 30, December 31,
  2024 2023
CURRENT ASSETS    
Advances to Affiliates $181.8 $67.1 
Accounts Receivable: 
Customers 61.2 82.2 
Affiliated Companies 141.1 125.5 
Total Accounts Receivable 202.3 207.7 
Prepayments and Other Current Assets 12.5 4.0 
TOTAL CURRENT ASSETS 396.6 278.8 
 
TRANSMISSION PROPERTY   
Transmission Property 14,209.3 13,723.9 
Other Property, Plant and Equipment 511.1 501.4 
Construction Work in Progress 2,188.6 1,563.7 
Total Transmission Property 16,909.0 15,789.0 
Accumulated Depreciation and Amortization 1,509.4 1,291.3 
TOTAL TRANSMISSION PROPERTY – NET 15,399.6 14,497.7 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 0.9 3.1 
Deferred Property Taxes 90.1 286.4 
Deferred Charges and Other Noncurrent Assets 7.1 6.5 
TOTAL OTHER NONCURRENT ASSETS 98.1 296.0 
 
TOTAL ASSETS $15,894.3 $15,072.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
61


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 2024 and December 31, 2023
(Unaudited)
  September 30, December 31,
  2024 2023
(in millions)
CURRENT LIABILITIES    
Advances from Affiliates $42.8 $174.3 
Accounts Payable:  
General 322.5 274.7 
Affiliated Companies 94.8 107.9 
Long-term Debt Due Within One Year – Nonaffiliated185.0 95.0 
Accrued Taxes 418.9 568.6 
Accrued Interest 68.4 39.6 
Obligations Under Operating Leases1.2 1.3 
Other Current Liabilities 21.9 24.7 
TOTAL CURRENT LIABILITIES 1,155.5 1,286.1 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 5,677.3 5,319.4 
Deferred Income Taxes 1,236.9 1,147.7 
Regulatory Liabilities 857.1 783.7 
Obligations Under Operating Leases1.1 1.4 
Deferred Credits and Other Noncurrent Liabilities 151.8 200.9 
TOTAL NONCURRENT LIABILITIES 7,924.2 7,453.1 
 
TOTAL LIABILITIES 9,079.7 8,739.2 
 
Rate Matters (Note 4) 
Commitments and Contingencies (Note 5) 
 
MEMBER’S EQUITY   
Paid-in Capital3,073.5 3,043.4 
Retained Earnings 3,741.1 3,289.9 
TOTAL MEMBER’S EQUITY 6,814.6 6,333.3 
 
TOTAL LIABILITIES AND MEMBER’S EQUITY $15,894.3 $15,072.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
62


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  20242023
OPERATING ACTIVITIES 
Net Income $548.2 $517.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 320.8 291.2 
Deferred Income Taxes 75.7 64.2 
Allowance for Equity Funds Used During Construction (64.7)(62.2)
Property Taxes 196.3 184.4 
Change in Other Noncurrent Assets 0.8 5.8 
Change in Other Noncurrent Liabilities (40.1)7.7 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net 5.4 (37.1)
Materials and Supplies 10.4 
Accounts Payable (16.1)25.0 
Accrued Taxes, Net (149.9)(202.2)
Other Current Assets (1.9)(1.0)
Other Current Liabilities 22.2 21.7 
Net Cash Flows from Operating Activities 896.7 825.5 
 
INVESTING ACTIVITIES   
Construction Expenditures (1,042.9)(1,224.9)
Change in Advances to Affiliates, Net (114.7)(86.2)
Other Investing Activities 13.6 4.8 
Net Cash Flows Used for Investing Activities (1,144.0)(1,306.3)
 
FINANCING ACTIVITIES  
Capital Contribution from Member 34.6 27.9 
Return of Capital to Member(4.5)(8.6)
Issuance of Long-term Debt – Nonaffiliated445.7 689.0 
Change in Advances from Affiliates, Net (131.5)(112.5)
Dividends Paid to Member(97.0)(115.0)
Net Cash Flows from Financing Activities 247.3 480.8 
 
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 $128.0 $116.9 
Net Cash Paid for Income Taxes 5.7 55.0 
Construction Expenditures Included in Current Liabilities as of September 30, 221.3 219.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
63


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 EndedNine Months Ended
 September 30,September 30,
2024202320242023
 (in millions of KWhs)
Retail:    
Residential2,568 2,481 7,918 7,527 
Commercial1,553 1,537 4,482 4,286 
Industrial2,141 2,229 6,446 6,473 
Miscellaneous203 205 617 595 
Total Retail6,465 6,452 19,463 18,881 
Wholesale (a)550 691 1,768 1,694 
Total KWhs7,015 7,143 21,231 20,575 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

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.

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
2024202320242023
 (in degree days)
Actual – Heating (a)— — 1,029 928 
Normal – Heating (b)1,397 1,410 
Actual – Cooling (c)962 873 1,499 1,106 
Normal – Cooling (b)837 837 1,221 1,222 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.

64


Appalachian Power Company and Subsidiaries
Reconciliation of 2023 to 2024 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2023 Net Income$91.9 $247.3 
  
Changes in Revenues: 
Retail Revenues65.5 244.0 
Off-system Sales(0.8)(1.1)
Transmission Revenues0.7 1.8 
Other Revenues1.7 11.4 
Total Change in Revenues67.1 256.1 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation(15.2)(99.2)
Other Operation and Maintenance(28.4)(81.4)
Depreciation and Amortization(5.3)(19.7)
Taxes Other Than Income Taxes(0.8)(6.0)
Interest Income1.0 1.6 
Allowance for Equity Funds Used During Construction0.6 2.7 
Non-Service Cost Components of Net Periodic Benefit Cost(1.2)(4.0)
Interest Expense1.3 (2.7)
Total Change in Expenses and Other(48.0)(208.7)
  
Income Tax Expense(1.2)9.9 
  
2024 Net Income$109.8 $304.6 

Third Quarter of 2024 Compared to Third Quarter of 2023

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

Retail Revenues increased $66 million primarily due to the following:
A $28 million increase in rider revenues.
A $23 million increase in rates due to the 2020-2022 Virginia Triennial Review.
A $7 million increase in weather-related usage driven by a 10% increase in cooling degree days.
A $6 million increase in fuel revenues.

Expenses and Other changed between years as follows:

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $15 million primarily due to expensing of past under-recovered fuel deferrals in West Virginia to correspond with recovery of those deferrals in ENEC rates.
Other Operation and Maintenance expenses increased $28 million primarily due to the following:
A $13 million increase due to prior year proceeds received for insurance policy settlements.
An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
A $7 million increase in distribution expenses primarily due to an increase in vegetation management costs.
These increases were partially offset by:
A $7 million decrease due to the January 2024 completion of regulatory asset amortization related to under-earnings during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
65


Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Retail Revenues increased $244 million primarily due to the following:
An $88 million increase in rider revenues.
A $60 million increase in rates due to the 2020-2022 Virginia Triennial Review.
A $57 million increase in fuel revenues.
A $47 million increase in weather-related usage driven by a 36% increase in cooling degree days and an 11% increase in heating degree days.
Other Revenues increased $11 million primarily due to pole attachment revenue.

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

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $99 million primarily due to expensing of past under-recovered fuel deferrals in West Virginia to correspond with recovery of those deferrals in ENEC rates, increased non-recoverable wind purchases and the amortization of Excess ADIT through the ENEC.
Other Operation and Maintenance expenses increased $81 million primarily due to the following:
A $49 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
A $26 million increase in employee-related expenses due to the voluntary severance program.
A $16 million increase in distribution expenses primarily due to an increase in vegetation management costs.
A $13 million increase due to prior year proceeds received for insurance policy settlements.
These increases were partially offset by:
A $19 million decrease due to the January 2024 completion of regulatory asset amortization related to under-earnings during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses increased $20 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $6 million due to an increase in Virginia state minimum taxes.
Income Tax Expense decreased $10 million primarily due to an increase in amortization of Excess ADIT.






66



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2024202320242023
REVENUES    
Electric Generation, Transmission and Distribution$960.6 $896.0 $2,836.6 $2,573.0 
Sales to AEP Affiliates65.2 62.5 183.1 193.2 
Other Revenues3.1 3.3 12.4 9.8 
TOTAL REVENUES1,028.9 961.8 3,032.1 2,776.0 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation358.4 343.2 1,060.0 960.8 
Other Operation204.2 187.9 628.8 569.6 
Maintenance86.4 74.3 244.7 222.5 
Depreciation and Amortization149.0 143.7 444.5 424.8 
Taxes Other Than Income Taxes44.3 43.5 132.5 126.5 
TOTAL EXPENSES842.3 792.6 2,510.5 2,304.2 
OPERATING INCOME186.6 169.2 521.6 471.8 
Other Income (Expense):    
Interest Income1.8 0.8 3.8 2.2 
Allowance for Equity Funds Used During Construction4.2 3.6 11.4 8.7 
Non-Service Cost Components of Net Periodic Benefit Cost6.9 8.1 20.4 24.4 
Interest Expense(67.2)(68.5)(203.4)(200.7)
INCOME BEFORE INCOME TAX EXPENSE132.3 113.2 353.8 306.4 
Income Tax Expense22.5 21.3 49.2 59.1 
NET INCOME $109.8 $91.9 $304.6 $247.3 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
67


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months Ended September 30,Nine Months Ended September 30,
 
2024202320242023
Net Income$109.8 $91.9 $304.6 $247.3 
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2024 and 2023, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2024 and 2023, Respectively
(0.2)(0.2)(0.6)(0.6)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.2) for the Three Months Ended September 30, 2024 and 2023, Respectively, and $(0.2) and $(0.6) for the Nine Months Ended September 30, 2024 and 2023, Respectively
(0.2)(0.7)(0.8)(2.3)
TOTAL OTHER COMPREHENSIVE LOSS(0.4)(0.9)(1.4)(2.9)
TOTAL COMPREHENSIVE INCOME$109.4 $91.0 $303.2 $244.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
68


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2022$260.4 $1,828.7 $2,891.1 $(4.8)$4,975.4 
Net Income112.5 112.5 
Other Comprehensive Loss(1.0)(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023260.4 1,828.7 3,003.6 (5.8)5,086.9 
Capital Contribution from Parent4.3 4.3 
Net Income  42.9  42.9 
Other Comprehensive Loss   (1.0)(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2023260.4 1,833.0 3,046.5 (6.8)5,133.1 
Capital Contribution from Parent2.22.2 
Net Income91.9 91.9 
Other Comprehensive Loss(0.9)(0.9)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2023$260.4 $1,835.2 $3,138.4 $(7.7)$5,226.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2023$260.4 $1,834.5 $3,185.5 $(3.7)$5,276.7 
Capital Contribution from Parent100.0100.0 
Net Income136.5 136.5 
Other Comprehensive Loss(0.5)(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024260.4 1,934.5 3,322.0 (4.2)5,512.7 
Capital Contribution from Parent9.59.5 
Net Income58.3 58.3 
Other Comprehensive Loss(0.5)(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024260.4 1,944.0 3,380.3 (4.7)5,580.0 
Return of Capital to Parent(4.5)(4.5)
Common Stock Dividends(75.0)(75.0)
Net Income109.8 109.8 
Other Comprehensive Loss(0.4)(0.4)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2024$260.4 $1,939.5 $3,415.1 $(5.1)$5,609.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

69


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
September 30,December 31,
20242023
CURRENT ASSETS  
Cash and Cash Equivalents$6.5 $5.0 
Restricted Cash for Securitized Funding8.3 14.9 
Advances to Affiliates18.9 18.9 
Accounts Receivable:  
Customers183.0 170.3 
Affiliated Companies102.7 98.8 
Accrued Unbilled Revenues53.3 70.8 
Miscellaneous0.2 0.6 
Allowance for Uncollectible Accounts(2.0)(2.0)
Total Accounts Receivable337.2 338.5 
Fuel270.3 315.0 
Materials and Supplies130.9 148.4 
Risk Management Assets47.1 22.4 
Regulatory Asset for Under-Recovered Fuel Costs153.7 155.4 
Prepayments and Other Current Assets64.8 40.5 
TOTAL CURRENT ASSETS1,037.7 1,059.0 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation7,245.9 7,041.3 
Transmission4,912.9 4,711.8 
Distribution5,412.0 5,176.6 
Other Property, Plant and Equipment1,046.4 981.3 
Construction Work in Progress752.5 709.2 
Total Property, Plant and Equipment19,369.7 18,620.2 
Accumulated Depreciation and Amortization5,964.9 5,688.7 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET13,404.8 12,931.5 
OTHER NONCURRENT ASSETS  
Regulatory Assets1,312.4 1,155.1 
Securitized Assets113.0 133.4 
Employee Benefits and Pension Assets184.8 171.7 
Operating Lease Assets70.2 73.7 
Deferred Charges and Other Noncurrent Assets166.5 187.5 
TOTAL OTHER NONCURRENT ASSETS1,846.9 1,721.4 
TOTAL ASSETS$16,289.4 $15,711.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
70


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2024 and December 31, 2023
(Unaudited)
 September 30,December 31,
 20242023
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$0.9 $339.6 
Accounts Payable:  
General363.3 280.4 
Affiliated Companies124.8 121.3 
Long-term Debt Due Within One Year – Nonaffiliated748.6 538.8 
Risk Management Liabilities7.6 15.9 
Customer Deposits85.5 80.0 
Accrued Taxes129.5 117.6 
Accrued Interest95.6 58.9 
Obligations Under Operating Leases13.9 14.6 
Other Current Liabilities165.3 118.8 
TOTAL CURRENT LIABILITIES1,735.0 1,685.9 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated4,910.6 5,049.5 
Deferred Income Taxes2,020.8 2,011.9 
Regulatory Liabilities and Deferred Investment Tax Credits1,100.4 1,081.9 
Asset Retirement Obligations774.3 442.5 
Employee Benefits and Pension Obligations31.6 32.8 
Obligations Under Operating Leases56.9 59.8 
Deferred Credits and Other Noncurrent Liabilities49.9 70.9 
TOTAL NONCURRENT LIABILITIES8,944.5 8,749.3 
TOTAL LIABILITIES10,679.5 10,435.2 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock – No Par Value:
  
Authorized – 30,000,000 Shares
  
 Outstanding – 13,499,500 Shares
260.4 260.4 
Paid-in Capital1,939.5 1,834.5 
Retained Earnings3,415.1 3,185.5 
Accumulated Other Comprehensive Income (Loss)(5.1)(3.7)
TOTAL COMMON SHAREHOLDER’S EQUITY5,609.9 5,276.7 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$16,289.4 $15,711.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
71


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20242023
OPERATING ACTIVITIES  
Net Income$304.6 $247.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization444.5 424.8 
Deferred Income Taxes(23.0)5.2 
Allowance for Equity Funds Used During Construction(11.4)(8.7)
Mark-to-Market of Risk Management Contracts(33.6)21.7 
Deferred Fuel Over/Under-Recovery, Net124.1 108.2 
Change in Other Noncurrent Assets(13.1)24.4 
Change in Other Noncurrent Liabilities5.6 (29.9)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net3.6 80.2 
Fuel, Materials and Supplies62.2 (114.0)
Accounts Payable50.4 (129.5)
Accrued Taxes, Net12.8 (12.4)
Other Current Assets(24.7)(6.5)
Other Current Liabilities34.8 (0.6)
Net Cash Flows from Operating Activities936.8 610.2 
INVESTING ACTIVITIES  
Construction Expenditures(708.7)(813.4)
Change in Advances to Affiliates, Net 0.5 
Other Investing Activities14.4 (2.9)
Net Cash Flows Used for Investing Activities(694.3)(815.8)
FINANCING ACTIVITIES  
Capital Contribution from Parent109.5 6.5 
Return of Capital to Parent(4.5) 
Issuance of Long-term Debt – Nonaffiliated480.8 200.0 
Change in Advances from Affiliates, Net(338.7)20.3 
Retirement of Long-term Debt – Nonaffiliated(413.5)(26.5)
Principal Payments for Finance Lease Obligations(6.5)(6.2)
Dividends Paid on Common Stock(75.0) 
Other Financing Activities0.3 1.0 
Net Cash Flows from (Used for) Financing Activities(247.6)195.1 
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(5.1)(10.5)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period19.9 21.9 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$14.8 $11.4 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$159.6 $166.6 
Net Cash Paid for Income Taxes27.4 40.3 
Cash Paid (Received) for Transferable Tax Credits(0.2) 
Noncash Acquisitions Under Finance Leases0.9 4.1 
Construction Expenditures Included in Current Liabilities as of September 30,129.9 138.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
72


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 EndedNine Months Ended
 September 30,September 30,
 2024202320242023
 (in millions of KWhs)
Retail:    
Residential1,552 1,421 4,152 3,998 
Commercial1,450 1,360 4,015 3,756 
Industrial1,901 1,876 5,562 5,501 
Miscellaneous10 12 35 39 
Total Retail4,913 4,669 13,764 13,294 
Wholesale (a)1,305 1,246 4,042 4,210 
Total KWhs6,218 5,915 17,806 17,504 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

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.

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
 2024202320242023
 (in degree days)
Actual – Heating (a)— — 1,826 1,914 
Normal – Heating (b)2,428 2,430 
Actual – Cooling (c)608 516 965 722 
Normal – Cooling (b)583 588 852 857 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
73


Indiana Michigan Power Company and Subsidiaries
Reconciliation of 2023 to 2024 Net Income
(in millions)
Three Months Ended September 30,Nine Months Ended 
September 30,
2023 Net Income$93.0 $270.6 
  
Changes in Revenues: 
Retail Revenues31.9 21.1 
Off-system Sales25.0 25.8 
Transmission Revenues2.5 10.0 
Other Revenues(2.2)(0.2)
Total Change in Revenues57.2 56.7 
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation11.1 (4.5)
Purchased Electricity from AEP Affiliates(6.0)(29.8)
Other Operation and Maintenance(11.9)(40.5)
Asset Impairments and Other Related Charges— (13.4)
Depreciation and Amortization(15.9)(6.3)
Taxes Other Than Income Taxes1.3 (6.5)
Other Income(1.2)1.6 
Non-Service Cost Components of Net Periodic Benefit Cost(0.9)(3.4)
Interest Expense(2.7)3.1 
Total Change in Expenses and Other(26.2)(99.7)
  
Income Tax Expense55.1 131.7 
  
2024 Net Income$179.1 $359.3 

Third Quarter of 2024 Compared to Third Quarter of 2023

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

Retail Revenues increased $32 million primarily due to the following:
A $31 million increase in weather-normalized margins in all customer classes.
A $15 million increase in rider revenues.
A $9 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.
A $7 million increase due to the implementation of new base rates in Indiana and Michigan.
These increases were partially offset by:
A $12 million decrease due to regulatory provisions for refund.
A $12 million decrease in fuel revenues primarily driven by lower fuel rates in Indiana.
Off-system Sales increased $25 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

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

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $11 million primarily due to decreased recoverable fuel costs and a decrease due to a regulatory true-up associated with a final commission order, partially offset by an increase in merchant generation at Rockport Plant and an increase in recoverable purchased power costs.
Purchased Electricity from AEP Affiliates increased $6 million primarily due to an increase in purchased electricity from Rockport Plant.
74


Other Operation and Maintenance expenses increased $12 million primarily due to an increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
Depreciation and Amortization expenses increased $16 million primarily due to an increase in regulatory reserves related to Nuclear PTCs.
Income Tax Expense decreased $55 million primarily due to a $61 million decrease related to estimated Nuclear PTCs.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Retail Revenues increased $21 million primarily due to the following:
A $22 million increase in weather-related usage primarily due to a 34% increase in cooling degree days.
An $18 million increase in weather-normalized margins in the residential and commercial classes.
A $12 million increase due to the implementation of new base rates in Indiana and Michigan.
A $9 million increase in rider revenues.
These increases were partially offset by:
A $34 million decrease due to regulatory provisions for refund.
A $10 million decrease in fuel revenues primarily driven by lower fuel rates in Indiana.
Off-system Sales increased $26 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.
Transmission Revenues increased $10 million primarily due to continued investment in transmission assets.

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

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $5 million primarily due to an increase in merchant generation at Rockport Plant, partially offset by decreased recoverable fuel costs.
Purchased Electricity from AEP Affiliates increased $30 million primarily due to an increase in purchased electricity from Rockport Plant.
Other Operation and Maintenance expenses increased $41 million primarily due to the following:
A $23 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
A $15 million increase in employee-related expenses due to the voluntary severance program.
An $8 million increase in non-utility operation expenses due to an increase in RTD expenses and merchant operation expenses at Rockport Plant.
These increases were partially offset by:
A $4 million decrease in distribution expenses primarily due to a decrease in vegetation management costs.
A $4 million decrease in nuclear expenses at Cook Plant primarily due to lower refueling outage expenses.
A $3 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2024.
Asset Impairments and Other Related Charges increased $13 million due to the Federal EPA’s revised CCR rules.
Depreciation and Amortization expenses increased $6 million primarily due to the following:
A $13 million increase in regulatory reserves related to Nuclear PTCs.
A $9 million increase due to a higher depreciable base.
These increases were partially offset by:
An $18 million decrease primarily due to the deferral of Excess ADIT as a result of the PLR received regarding the treatment of stand-alone NOLCs and the timing of refunds to customers under rate rider mechanisms.
Taxes Other Than Income Taxes increased $7 million primarily due to an increase in property taxes resulting from additional capital expenditures.
Income Tax Expense decreased $132 million primarily due to the following:
A $67 million decrease due to a reduction in Excess ADIT as a result of the IRS PLR and I&M Michigan jurisdictional treatment of stand-alone NOLCs.
A $61 million decrease due to estimated Nuclear PTCs.

75



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2024202320242023
REVENUES    
Electric Generation, Transmission and Distribution$714.9 $656.1 $1,932.3 $1,879.3 
Sales to AEP Affiliates1.3 0.6 5.2 3.7 
Other Revenues – Affiliated15.2 15.4 50.7 45.8 
Other Revenues – Nonaffiliated2.1 4.2 7.0 9.7 
TOTAL REVENUES733.5 676.3 1,995.2 1,938.5 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation118.2 129.3 326.9 322.4 
Purchased Electricity from AEP Affiliates63.0 57.0 169.0 139.2 
Other Operation180.0 168.9 548.5 508.7 
Maintenance58.1 57.3 173.7 173.0 
Asset Impairments and Other Related Charges  13.4  
Depreciation and Amortization132.6 116.7 359.2 352.9 
Taxes Other Than Income Taxes21.0 22.3 68.9 62.4 
TOTAL EXPENSES572.9 551.5 1,659.6 1,558.6 
OPERATING INCOME 160.6 124.8 335.6 379.9 
Other Income (Expense):    
Other Income3.3 4.5 9.7 8.1 
Non-Service Cost Components of Net Periodic Benefit Cost6.8 7.7 20.0 23.4 
Interest Expense(35.7)(33.0)(98.9)(102.0)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)135.0 104.0 266.4 309.4 
Income Tax Expense (Benefit)(44.1)11.0 (92.9)38.8 
NET INCOME $179.1 $93.0 $359.3 $270.6 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
76


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended
 September 30,September 30,
2024202320242023
Net Income$179.1 $93.0 $359.3 $270.6 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES   
Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2024 and 2023, Respectively, and $0.1 and $(0.1) for the Nine Months Ended September 30, 2024 and 2023, Respectively
0.1 0.1 0.3 (0.5)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2024 and 2023, Respectively, and $0 and $(0.6) for the Nine Months Ended September 30, 2024 and 2023, Respectively
 (0.2)(0.1)(2.4)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)0.1 (0.1)0.2 (2.9)
TOTAL COMPREHENSIVE INCOME$179.2 $92.9 $359.5 $267.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
77


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2022
$56.6 $988.8 $1,963.2 $(0.3)$3,008.3 
Common Stock Dividends  (31.2) (31.2)
Net Income  102.8  102.8 
Other Comprehensive Loss   (2.6)(2.6)
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 202356.6 988.8 2,034.8 (2.9)3,077.3 
Capital Contribution from Parent0.1 0.1 
Common Stock Dividends(31.3)(31.3)
Net Income74.8 74.8 
Other Comprehensive Loss(0.2)(0.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202356.6 988.9 2,078.3 (3.1)3,120.7 
Capital Contribution from Parent1.6 1.6 
Common Stock Dividends(75.0)(75.0)
Net Income93.0 93.0 
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2023$56.6 $990.5 $2,096.3 $(3.2)$3,140.2 
     
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2023
$56.6 $997.6 $2,086.6 $(0.6)$3,140.2 
Common Stock Dividends(37.5)(37.5)
Net Income145.0 145.0 
Other Comprehensive Income0.1 0.1 
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 202456.6 997.6 2,194.1 (0.5)3,247.8 
Capital Contribution from Parent5.0 5.0 
Common Stock Dividends  (37.5) (37.5)
Net Income  35.2  35.2 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202456.6 1,002.6 2,191.8 (0.5)3,250.5 
Return of Capital to Parent(1.8)(1.8)
Common Stock Dividends(37.5)(37.5)
Net Income179.1 179.1 
Other Comprehensive Income0.1 0.1 
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2024$56.6 $1,000.8 $2,333.4 $(0.4)$3,390.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
78


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
September 30,December 31,
 20242023
CURRENT ASSETS  
Cash and Cash Equivalents$4.1 $2.1 
Accounts Receivable:  
Customers43.5 66.9 
Affiliated Companies72.6 65.0 
Accrued Unbilled Revenues29.1 0.2 
Miscellaneous4.7 8.2 
Total Accounts Receivable149.9 140.3 
Fuel71.9 88.1 
Materials and Supplies210.6 208.2 
Risk Management Assets21.7 27.8 
Accrued Tax Benefits48.2  
Regulatory Asset for Under-Recovered Fuel Costs12.0 14.8 
Prepayments and Other Current Assets55.2 46.7 
TOTAL CURRENT ASSETS573.6 528.0 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,675.8 5,646.8 
Transmission1,951.3 1,906.4 
Distribution3,467.2 3,254.0 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)919.4 898.5 
Construction Work in Progress360.2 301.7 
Total Property, Plant and Equipment12,373.9 12,007.4 
Accumulated Depreciation, Depletion and Amortization4,600.9 4,378.4 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,773.0 7,629.0 
OTHER NONCURRENT ASSETS  
Regulatory Assets572.6 406.3 
Spent Nuclear Fuel and Decommissioning Trusts4,425.8 3,860.2 
Operating Lease Assets50.2 53.8 
Deferred Charges and Other Noncurrent Assets272.7 330.7 
TOTAL OTHER NONCURRENT ASSETS5,321.3 4,651.0 
TOTAL ASSETS$13,667.9 $12,808.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
79


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2024 and December 31, 2023
(dollars in millions)
(Unaudited)
 September 30,December 31,
 20242023
CURRENT LIABILITIES  
Advances from Affiliates$77.0 $63.3 
Accounts Payable:  
General178.9 225.8 
Affiliated Companies88.0 107.3 
Long-term Debt Due Within One Year – Nonaffiliated
   (September 30, 2024 and December 31, 2023 Amounts Include $93.2 and $81.4,
   Respectively, Related to DCC Fuel)
284.1 83.7 
Customer Deposits53.5 72.2 
Accrued Taxes96.8 104.7 
Accrued Interest38.0 41.3 
Obligations Under Operating Leases13.1 16.8 
Regulatory Liability for Over-Recovered Fuel Costs6.7 23.2 
Other Current Liabilities114.2 91.9 
TOTAL CURRENT LIABILITIES950.3 830.2 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,233.4 3,415.7 
Deferred Income Taxes1,213.5 1,169.9 
Regulatory Liabilities and Deferred Investment Tax Credits2,544.4 2,052.3 
Asset Retirement Obligations2,243.2 2,104.3 
Obligations Under Operating Leases37.9 37.7 
Deferred Credits and Other Noncurrent Liabilities54.8 57.7 
TOTAL NONCURRENT LIABILITIES9,327.2 8,837.6 
TOTAL LIABILITIES10,277.5 9,667.8 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock – No Par Value:
  
Authorized – 2,500,000 Shares
  
Outstanding – 1,400,000 Shares
56.6 56.6 
Paid-in Capital1,000.8 997.6 
Retained Earnings2,333.4 2,086.6 
Accumulated Other Comprehensive Income (Loss)(0.4)(0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY3,390.4 3,140.2 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$13,667.9 $12,808.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
80


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20242023
OPERATING ACTIVITIES  
Net Income$359.3 $270.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization359.2 352.9 
Deferred Income Taxes(70.7)(16.4)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net(3.2)44.3 
Asset Impairments and Other Related Charges13.4  
Allowance for Equity Funds Used During Construction(10.1)(6.6)
Mark-to-Market of Risk Management Contracts16.3 (4.7)
Amortization of Nuclear Fuel74.3 75.7 
Deferred Fuel Over/Under-Recovery, Net(13.7)52.9 
Change in Other Noncurrent Assets24.4 3.1 
Change in Other Noncurrent Liabilities49.5 9.0 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(8.1)82.5 
Fuel, Materials and Supplies13.8 (42.7)
Accounts Payable(57.7)(34.8)
Accrued Taxes, Net(56.1)(25.3)
Other Current Assets(2.0)(3.4)
Other Current Liabilities(10.2)(22.7)
Net Cash Flows from Operating Activities678.4 734.4 
INVESTING ACTIVITIES  
Construction Expenditures(434.7)(418.4)
Change in Advances to Affiliates, Net 1.8 
Purchases of Investment Securities(2,389.0)(2,182.8)
Sales of Investment Securities2,336.0 2,139.3 
Acquisitions of Nuclear Fuel(98.4)(60.9)
Other Investing Activities5.7 4.9 
Net Cash Flows Used for Investing Activities(580.4)(516.1)
FINANCING ACTIVITIES  
Capital Contribution from Parent5.0 1.7 
Return of Capital to Parent(1.8) 
Issuance of Long-term Debt – Nonaffiliated80.4 494.8 
Change in Advances from Affiliates, Net13.7 (249.9)
Retirement of Long-term Debt – Nonaffiliated(76.1)(324.1)
Principal Payments for Finance Lease Obligations(5.2)(5.4)
Dividends Paid on Common Stock(112.5)(137.5)
Other Financing Activities0.5 0.6 
Net Cash Flows Used for Financing Activities(96.0)(219.8)
Net Increase (Decrease) in Cash and Cash Equivalents2.0 (1.5)
Cash and Cash Equivalents at Beginning of Period2.1 4.2 
Cash and Cash Equivalents at End of Period$4.1 $2.7 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$111.5 $100.1 
Net Cash Paid (Received) for Income Taxes(4.4)36.2 
Noncash Acquisitions Under Finance Leases1.1 3.6 
Construction Expenditures Included in Current Liabilities as of September 30,69.6 70.6 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,8.2 9.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
81


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 EndedNine Months Ended
 September 30,September 30,
2024202320242023
 (in millions of KWhs)
Retail:    
Residential4,090 3,761 10,905 10,323 
Commercial5,388 4,553 15,138 12,503 
Industrial3,544 3,536 10,585 10,456 
Miscellaneous24 24 77 78 
Total Retail (a)13,046 11,874 36,705 33,360 
Wholesale (b)504 485 1,347 1,366 
Total KWhs13,550 12,359 38,052 34,726 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

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.

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
2024202320242023
 (in degree days)
Actual – Heating (a)— — 1,573 1,521 
Normal – Heating (b)2,056 2,080 
Actual – Cooling (c)844 625 1,266 809 
Normal – Cooling (b)699 697 1,008 1,005 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
82


Ohio Power Company and Subsidiaries
Reconciliation of 2023 to 2024 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2023 Net Income
$80.5 $226.2 
 
Changes in Revenues: 
Retail Revenues3.8 6.0 
Off-system Sales(2.1)(11.7)
Transmission Revenues0.5 0.5 
Other Revenues12.5 26.3 
Total Change in Revenues14.7 21.1 
  
Changes in Expenses and Other: 
Purchased Electricity for Resale61.6 278.1 
Purchased Electricity from AEP Affiliates23.9 (36.6)
Other Operation and Maintenance(50.4)(121.1)
Asset Impairments and Other Related Charges— (52.9)
Depreciation and Amortization(4.8)(69.2)
Taxes Other Than Income Taxes(4.4)(43.0)
Other Income0.8 0.6 
Allowance for Equity Funds Used During Construction0.8 4.9 
Non-Service Cost Components of Net Periodic Benefit Cost(1.1)(3.3)
Interest Expense(4.8)(13.0)
Total Change in Expenses and Other21.6 (55.5)
  
Income Tax Expense(4.1)9.9 
  
2024 Net Income
$112.7 $201.7 

Third Quarter of 2024 Compared to Third Quarter of 2023

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

Retail Revenues increased $4 million primarily due to the following:
A $105 million increase in revenue from rate riders.
A $14 million increase in weather-related usage driven by a 35% increase in cooling degree days.
These increases were partially offset by:
A $104 million decrease due to lower customer participation in OPCo’s SSO, partially offset by higher prices.
A $12 million decrease in weather-normalized revenues in the industrial class.
Other Revenues increased $13 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.

Expenses and Other changed between years as follows:

Purchased Electricity for Resale expenses decreased $62 million primarily due to the following:
An $80 million decrease in recoverable auction purchases primarily due to lower volumes driven by lower customer participation in OPCo’s SSO.
This decrease was partially offset by:
A $19 million increase in recoverable OVEC costs.
83


Purchased Electricity from AEP Affiliates expenses decreased $24 million primarily due to decreased recoverable auction purchases in OPCo’s SSO.
Other Operation and Maintenance expenses increased $50 million primarily due to the following:
A $31 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
An $11 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.
An $8 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Retail Revenues increased $6 million primarily due to the following:
A $279 million increase in revenue from rate riders.
A $44 million increase in weather-related usage driven by a 56% increase in cooling degree days.
These increases were partially offset by:
A $306 million decrease due to lower customer participation in OPCo’s SSO, partially offset by higher prices.
A $15 million decrease in weather-normalized revenues in the industrial class, partially offset by residential and commercial classes.
Off-system Sales decreased $12 million primarily due to 2023 PJM settlements related to winter storm Elliott.
Other Revenues increased $26 million due to the following:
A $33 million increase due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.
This increase was partially offset by:
A $9 million decrease in recoverable sales of renewable energy credits.

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

Purchased Electricity for Resale expenses decreased $278 million primarily due to the following:
A $342 million decrease in recoverable auction purchases primarily due to lower volumes driven by lower customer participation in OPCo’s SSO, partially offset by higher prices.
A $16 million decrease in recoverable alternative energy rider expenses.
These decreases were partially offset by:
An $81 million increase in recoverable OVEC costs.
Purchased Electricity from AEP Affiliates expenses increased $37 million primarily due to increased recoverable purchases in OPCo’s SSO auction.
Other Operation and Maintenance expenses increased $121 million primarily due to the following:
A $73 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
A $19 million increase in distribution expenses primarily due to recoverable storm restoration costs and recoverable vegetation management expenses.
A $16 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.
A $15 million increase in employee-related expenses due to the voluntary severance program.
Asset Impairments and Other Related Charges increased $53 million primarily due to Federal EPA revised CCR rules.
Depreciation and Amortization expenses increased $69 million primarily due to a higher depreciable base and an increase in recoverable rider depreciable assets.
Taxes Other Than Income Taxes increased $43 million primarily due to the following:
A $35 million increase due to higher property taxes driven by additional investments in transmission and distribution assets and tax rate changes.
An $8 million increase in state excise taxes due to increased billed KWh in 2024 resulting in a higher tax burden.
Interest Expense increased $13 million primarily due to higher debt balances and interest rates.
Income Tax Expense decreased $10 million primarily due to a decrease in pretax book income.
84



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
 2024202320242023
REVENUES    
Electricity, Transmission and Distribution$995.8 $978.7 $2,899.0 $2,869.3 
Sales to AEP Affiliates5.6 7.8 17.0 23.6 
Other Revenues2.8 3.0 8.3 10.3 
TOTAL REVENUES1,004.2 989.5 2,924.3 2,903.2 
EXPENSES    
Purchased Electricity for Resale199.1 260.7 642.8 920.9 
Purchased Electricity from AEP Affiliates14.1 38.0 86.2 49.6 
Other Operation343.2 296.9 920.2 836.1 
Maintenance66.3 62.2 194.7 157.7 
Asset Impairments and Other Related Charges  52.9  
Depreciation and Amortization86.1 81.3 293.9 224.7 
Taxes Other Than Income Taxes136.9 132.5 425.0 382.0 
TOTAL EXPENSES845.7 871.6 2,615.7 2,571.0 
OPERATING INCOME158.5 117.9 308.6 332.2 
Other Income (Expense):    
Other Income0.9 0.1 1.0 0.4 
Allowance for Equity Funds Used During Construction6.4 5.6 16.2 11.3 
Non-Service Cost Components of Net Periodic Benefit Cost5.4 6.5 16.2 19.5 
Interest Expense(38.7)(33.9)(109.9)(96.9)
INCOME BEFORE INCOME TAX EXPENSE132.5 96.2 232.1 266.5 
Income Tax Expense19.8 15.7 30.4 40.3 
NET INCOME$112.7 $80.5 $201.7 $226.2 
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
85


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022
$321.2 $837.8 $1,929.1 $3,088.1 
Capital Contribution from Parent50.050.0 
Net Income78.0 78.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023
321.2 887.8 2,007.1 3,216.1 
Capital Contribution from Parent125.0 125.0 
Net Income  67.7 67.7 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2023
321.2 1,012.8 2,074.8 3,408.8 
Net Income80.5 80.5 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2023
$321.2 $1,012.8 $2,155.3 $3,489.3 
    
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023
$321.2 $1,012.8 $2,237.3 $3,571.3 
Net Income70.6 70.6 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024
321.2 1,012.8 2,307.9 3,641.9 
Net Income  18.4 18.4 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2024
321.2 1,012.8 2,326.3 3,660.3 
Capital Contribution from Parent0.8 0.8 
Net Income112.7 112.7 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2024
$321.2 $1,013.6 $2,439.0 $3,773.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
86


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
 September 30,December 31,
 20242023
CURRENT ASSETS  
Cash and Cash Equivalents$9.6 $6.4 
Advances to Affiliates97.4  
Accounts Receivable:  
Customers83.0 39.2 
Affiliated Companies122.6 129.2 
Miscellaneous8.7 2.3 
Total Accounts Receivable214.3 170.7 
Materials and Supplies150.1 183.9 
Prepayments and Other Current Assets26.2 16.8 
TOTAL CURRENT ASSETS497.6 377.8 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Transmission3,529.9 3,395.1 
Distribution7,143.3 6,839.4 
Other Property, Plant and Equipment1,192.6 1,125.0 
Construction Work in Progress768.7 654.0 
Total Property, Plant and Equipment12,634.5 12,013.5 
Accumulated Depreciation and Amortization2,855.5 2,713.6 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET9,779.0 9,299.9 
OTHER NONCURRENT ASSETS  
Regulatory Assets394.9 455.0 
Operating Lease Assets62.5 69.9 
Deferred Charges and Other Noncurrent Assets336.1 641.1 
TOTAL OTHER NONCURRENT ASSETS793.5 1,166.0 
TOTAL ASSETS$11,070.1 $10,843.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
87


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2024 and December 31, 2023
(Unaudited)
 September 30,December 31,
 20242023
(in millions)
CURRENT LIABILITIES  
Advances from Affiliates$ $110.5 
Accounts Payable:  
General312.0 320.7 
Affiliated Companies155.8 154.2 
Risk Management Liabilities6.3 6.8 
Customer Deposits68.1 62.0 
Accrued Taxes439.9 763.3 
Accrued Interest61.0 38.5 
Obligations Under Operating Leases12.6 13.5 
Other Current Liabilities145.8 144.8 
TOTAL CURRENT LIABILITIES1,201.5 1,614.3 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,715.0 3,366.8 
Long-term Risk Management Liabilities45.3 43.9 
Deferred Income Taxes1,179.5 1,152.7 
Regulatory Liabilities and Deferred Investment Tax Credits997.0 1,003.6 
Obligations Under Operating Leases50.3 56.7 
Deferred Credits and Other Noncurrent Liabilities107.7 34.4 
TOTAL NONCURRENT LIABILITIES6,094.8 5,658.1 
TOTAL LIABILITIES7,296.3 7,272.4 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock –No Par Value:
  
Authorized – 40,000,000 Shares
  
Outstanding – 27,952,473 Shares
321.2 321.2 
Paid-in Capital1,013.6 1,012.8 
Retained Earnings2,439.0 2,237.3 
TOTAL COMMON SHAREHOLDER’S EQUITY3,773.8 3,571.3 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$11,070.1 $10,843.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
88


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20242023
OPERATING ACTIVITIES  
Net Income$201.7 $226.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization293.9 224.7 
Deferred Income Taxes0.2 29.4 
Asset Impairments and Other Related Charges52.9  
Allowance for Equity Funds Used During Construction(16.2)(11.3)
Mark-to-Market of Risk Management Contracts0.9 11.6 
Property Taxes286.6 282.4 
Change in Other Noncurrent Assets19.2 (95.5)
Change in Other Noncurrent Liabilities47.2 (47.7)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(39.8)4.3 
Materials and Supplies33.8 5.3 
Accounts Payable(43.4)1.8 
Customer Deposits6.1 (37.3)
Accrued Taxes, Net(322.3)(367.3)
Other Current Assets(11.9)(2.3)
Other Current Liabilities17.2 0.4 
Net Cash Flows from Operating Activities526.1 224.7 
INVESTING ACTIVITIES  
Construction Expenditures(688.5)(769.0)
Change in Advances to Affiliates, Net(97.4) 
Other Investing Activities29.4 33.9 
Net Cash Flows Used for Investing Activities(756.5)(735.1)
FINANCING ACTIVITIES  
Capital Contribution from Parent0.8 175.0 
Issuance of Long-term Debt – Nonaffiliated346.3 395.0 
Change in Advances from Affiliates, Net(110.5)(59.6)
Retirement of Long-term Debt – Nonaffiliated (0.6)
Principal Payments for Finance Lease Obligations(4.0)(3.7)
Other Financing Activities1.0 1.5 
Net Cash Flows from Financing Activities233.6 507.6 
Net Increase (Decrease) in Cash and Cash Equivalents3.2 (2.8)
Cash and Cash Equivalents at Beginning of Period6.4 9.6 
Cash and Cash Equivalents at End of Period$9.6 $6.8 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$82.8 $76.5 
Net Cash Paid (Received) for Income Taxes(5.1)16.0 
Noncash Acquisitions Under Finance Leases1.1 3.3 
Construction Expenditures Included in Current Liabilities as of September 30,126.8 99.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
89


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 EndedNine Months Ended
 September 30,September 30,
2024202320242023
 (in millions of KWhs)
Retail:    
Residential2,170 2,197 5,084 4,943 
Commercial1,733 1,539 4,348 3,934 
Industrial1,524 1,557 4,436 4,503 
Miscellaneous371 373 981 965 
Total Retail5,798 5,666 14,849 14,345 
Wholesale (a)24 59 135 132 
Total KWhs5,822 5,725 14,984 14,477 
(a)Includes municipalities and cooperatives, unit power and other wholesale customers.

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.

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
2024202320242023
 (in degree days)
Actual – Heating (a)— — 917 899 
Normal – Heating (b)— — 1,088 1,100 
Actual – Cooling (c)1,433 1,554 2,263 2,202 
Normal – Cooling (b)1,429 1,425 2,111 2,102 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
90


Public Service Company of Oklahoma
Reconciliation of 2023 to 2024 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2023 Net Income
$139.4 $188.1 
Changes in Revenues:
Retail Revenues (a)(30.4)(88.2)
Transmission Revenues(0.2)(0.1)
Other Revenues1.8 14.4 
Total Change in Revenues(28.8)(73.9)
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation33.3 127.6 
Other Operation and Maintenance(11.6)(43.6)
Depreciation and Amortization(8.8)(14.3)
Taxes Other Than Income Taxes(1.6)(10.7)
Interest Income(0.1)(0.7)
Allowance for Equity Funds Used During Construction(1.1)(0.7)
Non-Service Cost Components of Net Periodic Benefit Cost(0.7)(2.2)
Interest Expense(1.0)7.3 
Total Change in Expenses and Other8.4 62.7 
  
Income Tax Benefit(5.3)45.1 
  
2024 Net Income
$113.7 $222.0 

(a)Includes firm wholesale sales to municipals and cooperatives.


Third Quarter of 2024 Compared to Third Quarter of 2023

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

Retail Revenues decreased $30 million primarily due to the following:
A $39 million decrease in fuel revenue primarily due to lower authorized fuel rates.
A $9 million decrease in weather-related usage primarily due to an 8% decrease in cooling degree days.
These decreases were partially offset by:
An $11 million increase in weather-normalized margins primarily in the residential class.

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

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $33 million primarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.
Other Operation and Maintenance expenses increased $12 million primarily due to the following:
A $7 million increase in transmission expenses primarily due to an increase in SPP expenses.
A $3 million increase in overhead line maintenance expenses.
Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base, implementation of new rates and the amortization of regulatory assets related to NCWF.
Income Tax Benefit decreased $5 million primarily due to the following:
A $13 million decrease due to a decrease in amortization of Excess ADIT.
This decrease was partially offset by:
A $4 million increase due to a decrease in pretax book income.
A $3 million increase due to a decrease in state income tax.
91



Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Retail Revenues decreased $88 million primarily due to the following:
A $137 million decrease in fuel revenue primarily due to lower authorized fuel rates.
This decrease was partially offset by:
A $32 million increase in base rate and rider revenues.
Other Revenues increased $14 million primarily due to associated business development revenues driven by costs associated with a third-party construction project.

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

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $128 million primarily due to the lower current year amortization of under-recovered fuel regulatory assets driven by lower authorized fuel rates.
Other Operation and Maintenance expenses increased $44 million primarily due to the following:
A $16 million increase in transmission expenses primarily due to an increase in SPP expenses.
A $13 million increase in associated business development expenses primarily due to partially reimbursable development costs associated with a third-party construction project.
A $10 million increase in employee-related expenses due to the voluntary severance program.
Depreciation and Amortization expenses increased $14 million primarily due to a higher depreciable base, implementation of new rates and the amortization of regulatory assets related to NCWF.
Taxes Other Than Income Taxes increased $11 million primarily due to an increase in property taxes.
Interest Expense decreased $7 million primarily due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.
Income Tax Benefit increased $45 million primarily due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.
92



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months Ended 
September 30,
Nine Months Ended 
September 30,
 2024202320242023
REVENUES    
Electric Generation, Transmission and Distribution$612.9 $642.6 $1,439.1 $1,529.8 
Sales to AEP Affiliates1.1 0.2 5.7 1.0 
Other Revenues1.4 1.4 17.2 5.1 
TOTAL REVENUES615.4 644.2 1,462.0 1,535.9 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation284.8 318.1 613.7 741.3 
Other Operation112.2 103.9 328.1 283.5 
Maintenance28.7 25.4 81.7 82.7 
Depreciation and Amortization70.6 61.8 202.1 187.8 
Taxes Other Than Income Taxes18.8 17.2 60.2 49.5 
TOTAL EXPENSES515.1 526.4 1,285.8 1,344.8 
OPERATING INCOME100.3 117.8 176.2 191.1 
Other Income (Expense):    
Interest Income0.2 0.3 0.7 1.4 
Allowance for Equity Funds Used During Construction1.3 2.4 4.6 5.3 
Non-Service Cost Components of Net Periodic Benefit Cost2.9 3.6 8.5 10.7 
Interest Expense(26.5)(25.5)(70.2)(77.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)78.2 98.6 119.8 131.0 
Income Tax Expense (Benefit)(35.5)(40.8)(102.2)(57.1)
NET INCOME$113.7 $139.4 $222.0 $188.1 
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
93


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
2024202320242023
Net Income$113.7 $139.4 $222.0 $188.1 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $(2.3) and $0 for the Three Months Ended September 30, 2024 and 2023, Respectively, and $(2.3) and $(0.4) for the Nine Months Ended September 30, 2024 and 2023, Respectively
(8.6) (8.6)(1.5)
    
TOTAL COMPREHENSIVE INCOME$105.1 $139.4 $213.4 $186.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
94


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2022$157.2 $1,042.6 $1,218.0 $1.3 $2,419.1 
Common Stock Dividends(17.5)(17.5)
Net Loss(2.3)(2.3)
Other Comprehensive Loss(1.5)(1.5)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2023157.2 1,042.6 1,198.2 (0.2)2,397.8 
Return of Capital to Parent(2.5)(2.5)
Net Income  51.0  51.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2023157.2 1,040.1 1,249.2 (0.2)2,446.3 
Capital Contribution from Parent 0.6   0.6 
Common Stock Dividends(17.5)(17.5)
Net Income139.4 139.4 
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2023$157.2 $1,040.7 $1,371.1 $(0.2)$2,568.8 
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2023$157.2 $1,039.3 $1,374.3 $(0.2)$2,570.6 
Common Stock Dividends(35.0)(35.0)
Net Income72.0 72.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2024157.2 1,039.3 1,411.3 (0.2)2,607.6 
Capital Contribution from Parent0.2 0.2 
Common Stock Dividends  (35.0) (35.0)
Net Income  36.3  36.3 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2024157.2 1,039.5 1,412.6 (0.2)2,609.1 
Common Stock Dividends(35.0)(35.0)
Net Income113.7 113.7 
Other Comprehensive Loss(8.6)(8.6)
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2024$157.2 $1,039.5 $1,491.3 $(8.8)$2,679.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

95


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2024 and December 31, 2023
(in millions)
(Unaudited)
 September 30,December 31,
 20242023
CURRENT ASSETS  
Cash and Cash Equivalents$4.8 $2.5 
Accounts Receivable:  
Customers59.5 107.6 
Affiliated Companies46.2 31.0 
Miscellaneous0.4 0.8 
Total Accounts Receivable106.1 139.4 
Fuel23.2 33.7 
Materials and Supplies105.2 106.9 
Risk Management Assets28.4 19.0 
Accrued Tax Benefits17.5 31.0 
Regulatory Asset for Under-Recovered Fuel Costs27.4 118.3 
Prepayments and Other Current Assets30.3 18.7 
TOTAL CURRENT ASSETS342.9 469.5 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation2,760.2 2,695.5 
Transmission1,272.2 1,228.3 
Distribution3,609.2 3,450.8 
Other Property, Plant and Equipment525.7 505.9 
Construction Work in Progress404.7 313.7 
Total Property, Plant and Equipment8,572.0 8,194.2 
Accumulated Depreciation and Amortization2,189.2 2,081.9 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET6,382.8 6,112.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets524.9 522.7 
Employee Benefits and Pension Assets71.9 68.4 
Operating Lease Assets107.6 112.8 
Deferred Charges and Other Noncurrent Assets61.5 49.2 
TOTAL OTHER NONCURRENT ASSETS765.9 753.1 
TOTAL ASSETS$7,491.6 $7,334.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
96


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2024 and December 31, 2023
(Unaudited)
 September 30,December 31,
 20242023
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$98.5 $54.4 
Accounts Payable:  
General181.1 159.3 
Affiliated Companies57.7 56.7 
Long-term Debt Due Within One Year – Nonaffiliated250.6 0.6 
Risk Management Liabilities22.3 28.9 
Customer Deposits63.9 81.4 
Accrued Taxes71.2 30.7 
Accrued Interest22.7 30.7 
Obligations Under Operating Leases10.8 10.1 
Other Current Liabilities61.2 106.2 
TOTAL CURRENT LIABILITIES840.0 559.0 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,134.8 2,384.0 
Deferred Income Taxes888.6 831.2 
Regulatory Liabilities and Deferred Investment Tax Credits699.1 765.6 
Asset Retirement Obligations120.0 83.9 
Obligations Under Operating Leases102.1 106.8 
Deferred Credits and Other Noncurrent Liabilities27.8 33.8 
TOTAL NONCURRENT LIABILITIES3,972.4 4,205.3 
TOTAL LIABILITIES4,812.4 4,764.3 
Rate Matters (Note 4)
Commitments 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
157.2 157.2 
Paid-in Capital1,039.5 1,039.3 
Retained Earnings1,491.3 1,374.3 
Accumulated Other Comprehensive Income (Loss)(8.8)(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY2,679.2 2,570.6 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$7,491.6 $7,334.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
97


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20242023
OPERATING ACTIVITIES  
Net Income$222.0 $188.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization202.1 187.8 
Deferred Income Taxes(12.7)(13.6)
Allowance for Equity Funds Used During Construction(4.6)(5.3)
Mark-to-Market of Risk Management Contracts(27.9)(0.2)
Property Taxes(14.8)(14.0)
Deferred Fuel Over/Under-Recovery, Net90.9 263.3 
Change in Other Regulatory Assets5.0 (66.1)
Change in Other Noncurrent Assets(24.4)(27.8)
Change in Other Noncurrent Liabilities0.8 11.0 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net33.3 11.9 
Fuel, Materials and Supplies12.2 (11.6)
Accounts Payable9.6 (19.5)
Accrued Taxes, Net54.0 (9.5)
Other Current Assets(15.3)(3.0)
Other Current Liabilities(67.0)(10.8)
Net Cash Flows from Operating Activities463.2 480.7 
INVESTING ACTIVITIES  
Construction Expenditures(402.9)(401.1)
Change in Advances to Affiliates, Net (9.2)
Acquisitions of Renewable Energy Facilities (145.7)
Other Investing Activities5.1 8.8 
Net Cash Flows Used for Investing Activities(397.8)(547.2)
FINANCING ACTIVITIES  
Capital Contribution from Parent0.2 0.6 
Return of Capital to Parent (2.5)
Issuance of Long-term Debt – Nonaffiliated 469.8 
Change in Advances from Affiliates, Net44.1 (364.2)
Retirement of Long-term Debt – Nonaffiliated(0.4)(0.4)
Principal Payments for Finance Lease Obligations(2.5)(2.5)
Dividends Paid on Common Stock(105.0)(35.0)
Other Financing Activities0.5 0.4 
Net Cash Flows from (Used for) Financing Activities(63.1)66.2 
Net Increase (Decrease) in Cash and Cash Equivalents2.3 (0.3)
Cash and Cash Equivalents at Beginning of Period2.5 4.0 
Cash and Cash Equivalents at End of Period$4.8 $3.7 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$86.4 $67.4 
Net Cash Paid (Received) for Income Taxes(27.2)(1.6)
Cash Paid (Received) for Transferable Tax Credits(76.9) 
Noncash Acquisitions Under Finance Leases1.2 1.9 
Construction Expenditures Included in Current Liabilities as of September 30,76.7 91.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

98


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 EndedNine Months Ended
 September 30,September 30,
 2024202320242023
 (in millions of KWhs)
Retail:    
Residential1,955 2,180 4,855 4,902 
Commercial1,617 1,689 4,287 4,269 
Industrial1,232 1,313 3,873 3,876 
Miscellaneous17 17 52 53 
Total Retail4,821 5,199 13,067 13,100 
Wholesale (a)1,567 1,668 4,281 4,226 
Total KWhs6,388 6,867 17,348 17,326 
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

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.

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
 September 30,September 30,
 2024202320242023
 (in degree days)
Actual – Heating (a)— — 560 413 
Normal – Heating (b)— 722 730 
Actual – Cooling (c)1,591 1,715 2,721 2,673 
Normal – Cooling (b)1,439 1,435 2,237 2,223 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.


99


Southwestern Electric Power Company
Reconciliation of 2023 to 2024
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2023 Earnings Attributable to Common Shareholder
$157.5 $279.1 
  
Changes in Revenues: 
Retail Revenues (a)(26.9)(175.5)
Off-system Sales0.5 2.4 
Transmission Revenues7.3 10.2 
Other Revenues3.1 5.2 
Total Change in Revenues(16.0)(157.7)
  
Changes in Expenses and Other: 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation11.3 32.5 
Other Operation and Maintenance4.9 (47.8)
Depreciation and Amortization(17.1)(30.8)
Taxes Other Than Income Taxes2.1 10.6 
Interest Income(1.0)(3.4)
Allowance for Equity Funds Used During Construction(1.4)2.4 
Non-Service Cost Components of Net Periodic Benefit Cost(0.8)(2.6)
Interest Expense10.2 32.1 
Total Change in Expenses and Other8.2 (7.0)
  
Income Tax Benefit(11.2)163.1 
Equity Earnings of Unconsolidated Subsidiary0.1 0.1 
Net Income Attributable to Noncontrolling Interest0.5 (0.5)
  
2024 Earnings Attributable to Common Shareholder
$139.1 $277.1 

(a)Includes firm wholesale sales to municipals and cooperatives.
Third Quarter of 2024 Compared to Third Quarter of 2023

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

Retail Revenues decreased $27 million primarily due to the following:
A $13 million decrease in fuel revenue.
A $12 million decrease in weather-normalized margins primarily in the residential and industrial classes.
A $10 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.
These decreases were partially offset by:
An $8 million increase primarily due to formula rate increases in Arkansas.
Transmission Revenues increased $7 million primarily due to an increase in 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 $11 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.
Depreciation and Amortization expenses increased $17 million primarily due to an increase in amortization of regulatory assets and a higher depreciable base.
100


Interest Expense decreased $10 million primarily due to the following:
An $8 million decrease due to the prior year amortization of carrying charges on storm-related regulatory assets.
A $3 million decrease due to the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.
Income Tax Benefit decreased $11 million primarily due to the following:
A $5 million decrease due to a decrease in PTCs.
A $4 million decrease due to a decrease in amortization of Excess ADIT.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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

Retail Revenues decreased $176 million primarily due to the recognition of a $160 million probable revenue refund associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
Transmission Revenues increased $10 million primarily due to a $15 million increase in continued investment in transmission assets and load, partially offset by a $4 million reversal of a prior period provision for refund in 2023.
Other Revenues increased $5 million primarily due to associated business development revenues driven by costs associated with a third-party construction project.

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

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $33 million primarily due to a current year decrease in amortization of under-recovered fuel regulatory assets.
Other Operation and Maintenance expenses increased $48 million primarily due to the following:
A $17 million increase in employee-related expenses primarily due to the voluntary severance program.
A $14 million increase due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
An $11 million increase in SPP transmission expenses.
A $5 million increase due to the prior year capitalization of previously expensed renewable generation pre-construction charges.
Depreciation and Amortization expenses increased $31 million primarily due to an increase in amortization of regulatory assets and a higher depreciable base, partially offset by the recognition of a regulatory asset related to NOLCs.
Taxes Other Than Income Taxes decreased $11 million primarily due to a decrease in property taxes.
Interest Expense decreased $32 million primarily due to the decrease in the recognition of debt carrying charges as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.
Income Tax Benefit increased $163 million primarily due to the following:
A $109 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail rate making.
A $34 million increase due to a decrease in pretax book income.
A $32 million increase due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC's March 2024 denial of SWEPCo's request to allow the merchant portion of the Turk Plant to serve Arkansas customers.
101



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
 September 30,September 30,
 2024202320242023
REVENUES    
Electric Generation, Transmission and Distribution$625.1 $640.0 $1,680.5 $1,665.2 
Sales to AEP Affiliates21.9 14.4 52.3 45.7 
Provision for Refund(8.9)(0.1)(189.0)(4.2)
Other Revenues0.7 0.5 7.0 1.8 
TOTAL REVENUES638.8 654.8 1,550.8 1,708.5 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation204.1 215.4 582.1 614.6 
Other Operation95.1 96.9 324.3 281.3 
Maintenance35.3 38.4 125.9 121.1 
Depreciation and Amortization117.7 100.6 297.6 266.8 
Taxes Other Than Income Taxes34.1 36.2 93.8 104.4 
TOTAL EXPENSES486.3 487.5 1,423.7 1,388.2 
OPERATING INCOME152.5 167.3 127.1 320.3 
Other Income (Expense):   
Interest Income3.1 4.1 11.4 14.8 
Allowance for Equity Funds Used During Construction2.9 4.3 9.7 7.3 
Non-Service Cost Components of Net Periodic Benefit Cost2.6 3.4 7.6 10.2 
Interest Expense(31.9)(42.1)(75.1)(107.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS129.2 137.0 80.7 245.4 
Income Tax Expense (Benefit)(10.5)(21.7)(198.8)(35.7)
Equity Earnings of Unconsolidated Subsidiary0.4 0.3 1.1 1.0 
NET INCOME140.1 159.0 280.6 282.1 
Net Income Attributable to Noncontrolling Interest1.0 1.5 3.5 3.0 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$139.1 $157.5 $277.1 $279.1 
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, 2024 and 2023
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2024202320242023
Net Income$140.1 $159.0 $280.6 $282.1 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2024 and 2023, Respectively, and $(0.1) and $0.1 for the Nine Months Ended September 30, 2024 and 2023, Respectively
(0.1) (0.2)0.3 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2024 and 2023, Respectively, and $(0.1) and $(0.3) for the Nine Months Ended September 30, 2024 and 2023, Respectively
(0.1)(0.4)(0.2)(1.0)
TOTAL OTHER COMPREHENSIVE LOSS(0.2)(0.4)(0.4)(0.7)
TOTAL COMPREHENSIVE INCOME139.9 158.6 280.2 281.4 
Total Comprehensive Income Attributable to Noncontrolling Interest1.0 1.5 3.5 3.0 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$138.9 $157.1 $276.7 $278.4 
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, 2024 and 2023
(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, 2022$0.1 $1,442.2 $2,236.0 $(4.2)$0.7 $3,674.8 
Capital Contribution from Parent50.050.0 
Common Stock Dividends – Nonaffiliated(1.5)(1.5)
Net Income40.6 1.2 41.8 
Other Comprehensive Income0.1 0.1 
TOTAL EQUITY – MARCH 31, 20230.1 1,492.2 2,276.6 (4.1)0.4 3,765.2 
Common Stock Dividends(50.0)(50.0)
Common Stock Dividends – Nonaffiliated    (0.6)(0.6)
Net Income  81.0  0.3 81.3 
Other Comprehensive Loss   (0.4) (0.4)
TOTAL EQUITY – JUNE 30, 20230.1 1,492.2 2,307.6 (4.5)0.1 3,795.5 
Common Stock Dividends(75.0)(75.0)
Common Stock Dividends – Nonaffiliated(0.3)(0.3)
Net Income157.5 1.5 159.0 
Other Comprehensive Loss(0.4)(0.4)
TOTAL EQUITY – SEPTEMBER 30, 2023$0.1 $1,492.2 $2,390.1 $(4.9)$1.3 $3,878.8 
TOTAL EQUITY – DECEMBER 31, 2023$0.1 $1,492.2 $2,281.3 $(3.4)$0.2 $3,770.4 
Common Stock Dividends(50.0)(50.0)
Common Stock Dividends – Nonaffiliated(1.4)(1.4)
Net Income208.1 1.5 209.6 
Other Comprehensive Loss(0.2)(0.2)
TOTAL EQUITY – MARCH 31, 20240.1 1,492.2 2,439.4 (3.6)0.3 3,928.4 
Common Stock Dividends  (100.0)  (100.0)
Common Stock Dividends – Nonaffiliated    (1.0)(1.0)
Net Income (Loss)  (70.1) 1.0 (69.1)
TOTAL EQUITY – JUNE 30, 20240.1 1,492.2 2,269.3 (3.6)0.3 3,758.3 
Return of Capital to Parent(1.1)(1.1)
Common Stock Dividends(100.0)(100.0)
Common Stock Dividends – Nonaffiliated(1.0)(1.0)
Net Income139.1 1.0 140.1 
Other Comprehensive Loss(0.2)(0.2)
TOTAL EQUITY – SEPTEMBER 30, 2024$0.1 $1,491.1 $2,308.4 $(3.8)$0.3 $3,796.1 
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, 2024 and December 31, 2023
(in millions)
(Unaudited)
 September 30,December 31,
 20242023
CURRENT ASSETS  
Cash and Cash Equivalents $4.4 $2.4 
Advances to Affiliates2.8 2.2 
Accounts Receivable:  
Customers27.5 39.0 
Affiliated Companies55.5 47.2 
Miscellaneous13.9 8.3 
Total Accounts Receivable96.9 94.5 
Fuel 84.1 113.8 
Materials and Supplies
(September 30, 2024 and December 31, 2023 Amounts Include $2.7 and $3.9, Respectively, Related to Sabine)
87.0 88.4 
Risk Management Assets24.1 11.6 
Accrued Tax Benefits21.4 28.4 
Regulatory Asset for Under-Recovered Fuel Costs106.6 170.8 
Prepayments and Other Current Assets32.2 29.2 
TOTAL CURRENT ASSETS459.5 541.3 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation4,845.1 4,790.7 
Transmission2,754.8 2,660.6 
Distribution2,986.1 2,824.1 
Other Property, Plant and Equipment
(September 30, 2024 and December 31, 2023 Amounts Include $166.8 and $182.7, Respectively, Related to Sabine)
930.6 814.4 
Construction Work in Progress636.4 555.8 
Total Property, Plant and Equipment12,153.0 11,645.6 
Accumulated Depreciation and Amortization
(September 30, 2024 and December 31, 2023 Amounts Include $166.8 and $182.7, Respectively, Related to Sabine)
3,244.8 3,087.2 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,908.2 8,558.4 
OTHER NONCURRENT ASSETS  
Regulatory Assets1,120.3 1,131.8 
Deferred Charges and Other Noncurrent Assets340.4 326.1 
TOTAL OTHER NONCURRENT ASSETS1,460.7 1,457.9 
TOTAL ASSETS$10,828.4 $10,557.6 
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, 2024 and December 31, 2023
(Unaudited)
 September 30,December 31,
 20242023
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$237.4 $88.7 
Accounts Payable:  
General226.2 198.9 
Affiliated Companies49.3 45.9 
Short-term Debt – Nonaffiliated4.6 4.3 
Customer Deposits75.3 72.5 
Accrued Taxes116.8 58.7 
Accrued Interest38.8 39.9 
Obligations Under Operating Leases8.8 9.0 
Provision for Refund62.5 0.7 
Other Current Liabilities127.5 168.3 
TOTAL CURRENT LIABILITIES947.2 686.9 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,648.7 3,646.9 
Deferred Income Taxes1,260.4 1,179.3 
Regulatory Liabilities and Deferred Investment Tax Credits577.5 756.1 
Asset Retirement Obligations257.0 258.6 
Employee Benefits and Pension Obligations43.1 43.1 
Obligations Under Operating Leases119.5 122.5 
Deferred Credits and Other Noncurrent Liabilities178.9 93.8 
TOTAL NONCURRENT LIABILITIES6,085.1 6,100.3 
TOTAL LIABILITIES7,032.3 6,787.2 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
EQUITY  
Common Stock – Par Value – $18 Per Share:
  
Authorized – 3,680 Shares
  
Outstanding – 3,680 Shares
0.1 0.1 
Paid-in Capital1,491.1 1,492.2 
Retained Earnings2,308.4 2,281.3 
Accumulated Other Comprehensive Income (Loss)(3.8)(3.4)
TOTAL COMMON SHAREHOLDER’S EQUITY3,795.8 3,770.2 
Noncontrolling Interest0.3 0.2 
TOTAL EQUITY3,796.1 3,770.4 
TOTAL LIABILITIES AND EQUITY$10,828.4 $10,557.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
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SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20242023
OPERATING ACTIVITIES  
Net Income$280.6 $282.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
Depreciation and Amortization297.6 266.8 
Deferred Income Taxes(117.1)44.9 
Allowance for Equity Funds Used During Construction(9.7)(7.3)
Mark-to-Market of Risk Management Contracts(23.3)1.4 
Property Taxes(23.7)(24.6)
Deferred Fuel Over/Under-Recovery, Net134.3 134.4 
Provision for Refund – Turk Plant100.0  
Change in Other Noncurrent Assets(41.3)(46.9)
Change in Other Noncurrent Liabilities(46.0)(26.7)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(2.4)29.7 
Fuel, Materials and Supplies26.2 (12.0)
Accounts Payable7.6 5.3 
Accrued Taxes, Net65.1 10.8 
Provision for Refund – Turk Plant60.0  
Other Current Assets(7.0)10.4 
Other Current Liabilities(51.5)(40.6)
Net Cash Flows from Operating Activities649.4 627.7 
INVESTING ACTIVITIES  
Construction Expenditures(539.6)(614.1)
Change in Advances to Affiliates, Net(0.6)(0.6)
Other Investing Activities10.9 1.8 
Net Cash Flows Used for Investing Activities(529.3)(612.9)
FINANCING ACTIVITIES  
Capital Contribution from Parent 50.0 
Return of Capital to Parent(1.1) 
Issuance of Long-term Debt – Nonaffiliated 346.8 
Change in Short-term Debt – Nonaffiliated0.3 3.9 
Change in Advances from Affiliates, Net148.7 (261.8)
Retirement of Long-term Debt – Nonaffiliated (94.1)
Principal Payments for Finance Lease Obligations(13.0)(17.6)
Dividends Paid on Common Stock(250.0)(125.0)
Dividends Paid on Common Stock – Nonaffiliated(3.4)(2.4)
Other Financing Activities0.4 0.6 
Net Cash Flows Used for Financing Activities(118.1)(99.6)
Net Increase (Decrease) in Cash and Cash Equivalents2.0 (84.8)
Cash and Cash Equivalents at Beginning of Period2.4 88.4 
Cash and Cash Equivalents at End of Period$4.4 $3.6 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$107.1 $89.8 
Net Cash Paid (Received) for Income Taxes(11.2)(23.3)
Cash Paid (Received) for Transferable Tax Credits(69.4) 
Noncash Acquisitions Under Finance Leases1.9 4.6 
Construction Expenditures Included in Current Liabilities as of September 30,84.9 69.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.
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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:
NoteRegistrantPage
Number
Significant Accounting MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
New Accounting StandardsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Comprehensive IncomeAEP
Rate MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Commitments, Guarantees and ContingenciesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Acquisitions and DispositionsAEP, PSO
Benefit PlansAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Business SegmentsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Derivatives and HedgingAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Fair Value MeasurementsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Income TaxesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Financing ActivitiesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Voluntary Severance ProgramAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Variable Interest EntitiesAEP
Property, Plant and EquipmentAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Revenue from Contracts with CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
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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, 2024 is not necessarily indicative of results that may be expected for the year ending December 31, 2024.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2023 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 26, 2024.

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 stock awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:
Three Months Ended September 30,
20242023
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$959.6  $953.7  
Weighted-Average Number of Basic AEP Common Shares Outstanding532.2 $1.80 520.5 $1.83 
Weighted-Average Dilutive Effect of Stock-Based Awards1.4  0.9  
Weighted-Average Number of Diluted AEP Common Shares Outstanding533.6 $1.80 521.4 $1.83 

Nine Months Ended September 30,
20242023
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$2,303.0  $1,871.9  
Weighted-Average Number of Basic AEP Common Shares Outstanding529.2 $4.35 516.5 $3.62 
Weighted-Average Dilutive Effect of Stock-Based Awards1.3 (0.01)1.3  
Weighted-Average Number of Diluted AEP Common Shares Outstanding530.5 $4.34 517.8 $3.62 

There were no antidilutive shares outstanding as of September 30, 2024 and 2023, respectively.


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Restricted Cash (Applies to AEP, AEP Texas and APCo)

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, 2024
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$245.8 $0.1 $6.5 
Restricted Cash53.4 45.1 8.3 
Total Cash, Cash Equivalents and Restricted Cash$299.2 $45.2 $14.8 

December 31, 2023
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$330.1 $0.1 $5.0 
Restricted Cash48.9 34.0 14.9 
Total Cash, Cash Equivalents and Restricted Cash$379.0 $34.1 $19.9 

Supplementary Cash Flow Information (Applies to AEP)

Nine Months Ended September 30,
Cash Flow Information20242023
(in millions)
Cash Paid (Received) for:
Interest, Net of Capitalized Amounts$1,247.3 $1,148.7 
Income Taxes87.9 26.7 
Sale of Transferable Tax Credits(163.7) 
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases24.5 38.5 
Construction Expenditures Included in Current Liabilities as of September 30,1,015.1 975.0 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,8.2 9.5 
Noncash Increase in Noncurrent Assets from the Sale of the Competitive Contracted Renewables Portfolio 74.7 
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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

On March 6, 2024, the SEC adopted final rules that require registrants to disclose certain climate-related information in registration statements and annual reports. The final rules require registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about a registrant’s board of directors oversight and management’s role in managing material climate-related risks. The final rules also require registrants to provide information related to any climate-related targets or goals that are material to a registrant’s business, results of operations or financial condition. A majority of the reporting requirements are applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for GHG emissions starting in 2029 for large accelerated filers. 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. On April 4, 2024, the SEC issued an order staying the final climate disclosure rules pending the completion of judicial review at the Court of Appeals. The Registrants are currently evaluating the impact of the final rules on their respective consolidated financial statements and related disclosures.

ASU 2023-07 “Improvements to Reportable Segment Disclosures” (ASU 2023-07)

In November 2023, the FASB issued ASU 2023-07, to address investors’ observations that there is limited information disclosed about segment expenses and to better understand expense categories and amounts included in segment profit or loss. The new standard requires annual and interim disclosure of (a) the categories and amounts of significant segment expenses (determined by management using both qualitative and quantitative factors) that are regularly provided to the CODM and included within each reported measure of segment profit or loss, (b) the amounts and a qualitative description of “other segment items”, defined as the difference between reported segment revenues less the significant segment expenses and each reported measure of segment profit or loss disclosed, (c) reportable segment profit or loss and assets that are currently only required annually, (d) the CODM’s title and position, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources and (e) a requirement that entities with a single reportable segment provide all disclosures required by ASU 2023-07 and all existing segment disclosures in Topic 280. Additionally, this new standard allows disclosure of one or more of additional profit or loss measures if the CODM uses more than one measure provided that at least one of the disclosed measures is determined in a manner “most consistent with the measurement principles under GAAP”. If multiple measures are presented, additional disclosure is required about how the CODM uses each measure to assess performance and decide how to allocate resources.

The amendments in the new standard are effective on a retrospective basis for all entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal periods beginning after December 15, 2024 with early adoption permitted. Management plans to adopt ASU 2023-07 effective for the 2024 10-K.

ASU 2023-09 “Improvements to Income Tax Disclosures” (ASU 2023-09)

In December 2023, the FASB issued ASU 2023-09, to address investors’ suggested enhancements to (a) better understand an entity’s exposure to potential changes in jurisdictional tax legislation and the ensuing risks and opportunities, (b) assess income tax information that affects cash flow forecasts and capital allocation decisions and (c) identify potential opportunities to increase future cash flows.

The new standard requires an annual rate reconciliation disclosure of the following categories regardless of materiality: state and local income tax, net of federal income tax effect, foreign tax effects, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items and changes in unrecognized tax benefits.

The new standard also requires an annual disclosure of the amount of income taxes paid (net of refunds received) disaggregated by federal, state and foreign taxes and by individual jurisdictions that are equal to or greater than 5 percent of total income taxes paid. Disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between
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domestic and foreign jurisdictions and income tax expense (benefit) from continuing operations disaggregated by federal, state and foreign jurisdictions is required.

The new standard removes the requirement to disclose the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized because of the exceptions to comprehensive recognition of deferred taxes related to subsidiaries and corporate joint ventures.

The amendments in the new standard may be applied on either a prospective or retrospective basis for public business entities for fiscal years beginning after December 15, 2024 with early adoption permitted. Management has not yet made a decision to early adopt the amendments to this standard or how to apply them.

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.
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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 HedgesPension 
Three Months Ended September 30, 2024CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2024$103.7 $9.3 $(153.0)$(40.0)
Change in Fair Value Recognized in AOCI, Net of Tax(28.8)(24.5) (53.3)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)
0.1   0.1 
Interest Expense (a)
 8.8  8.8 
Amortization of Prior Service Cost (Credit)  (1.4)(1.4)
Amortization of Actuarial (Gains) Losses  0.7 0.7 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.1 8.8 (0.7)8.2 
Income Tax (Expense) Benefit0.1 1.8 (0.1)1.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
 7.0 (0.6)6.4 
Net Current Period Other Comprehensive Loss(28.8)(17.5)(0.6)(46.9)
Balance in AOCI as of September 30, 2024$74.9 $(8.2)$(153.6)$(86.9)

 Cash Flow HedgesPension 
Three Months Ended September 30, 2023CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2023$93.5 $12.7 $(142.6)$(36.4)
Change in Fair Value Recognized in AOCI, Net of Tax19.3 (6.9) 12.4 
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)
(15.6)  (15.6)
Interest Expense (a)
 (1.3) (1.3)
Amortization of Prior Service Cost (Credit)
  (5.3)(5.3)
Amortization of Actuarial (Gains) Losses
  1.3 1.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(15.6)(1.3)(4.0)(20.9)
Income Tax (Expense) Benefit(3.4)(0.2)(0.8)(4.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(12.2)(1.1)(3.2)(16.5)
Net Current Period Other Comprehensive Income (Loss)
7.1 (8.0)(3.2)(4.1)
Balance in AOCI as of September 30, 2023$100.6 $4.7 $(145.8)$(40.5)
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 Cash Flow HedgesPension 
Nine Months Ended September 30, 2024CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2023$104.9 $(8.1)$(152.3)$(55.5)
Change in Fair Value Recognized in AOCI, Net of Tax(16.3)(5.2) (21.5)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)(17.4)  (17.4)
Interest Expense (a) 6.5  6.5 
Amortization of Prior Service Cost (Credit)  (4.0)(4.0)
Amortization of Actuarial (Gains) Losses  2.4 2.4 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(17.4)6.5 (1.6)(12.5)
Income Tax (Expense) Benefit(3.7)1.4 (0.3)(2.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(13.7)5.1 (1.3)(9.9)
Net Current Period Other Comprehensive Loss(30.0)(0.1)(1.3)(31.4)
Balance in AOCI as of September 30, 2024$74.9 $(8.2)$(153.6)$(86.9)

 Cash Flow HedgesPension 
Nine Months Ended September 30, 2023CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2022$223.5 $0.3 $(140.1)$83.7 
Change in Fair Value Recognized in AOCI, Net of Tax(170.1)5.3 (12.9)(177.7)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)59.7   59.7 
Interest Expense (a) (1.1) (1.1)
Amortization of Prior Service Cost (Credit)  (15.9)(15.9)
Amortization of Actuarial (Gains) Losses  3.9 3.9 
Reclassifications from AOCI, before Income Tax (Expense) Benefit59.7 (1.1)(12.0)46.6 
Income Tax (Expense) Benefit12.5 (0.2)(2.5)9.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit47.2 (0.9)(9.5)36.8 
Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, before Income Tax (Expense) Benefit  21.1 21.1 
Income Tax (Expense) Benefit  4.4 4.4 
Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, Net of Income Tax (Expense) Benefit  16.7 16.7 
Net Current Period Other Comprehensive Income (Loss)(122.9)4.4 (5.7)(124.2)
Balance in AOCI as of September 30, 2023$100.6 $4.7 $(145.8)$(40.5)

(a)Amounts reclassified to the referenced line item on the statements of income.

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4.  RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

As discussed in the 2023 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2023 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 2024 and updates the 2023 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 continuously 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 Units that have been Retired

SWEPCo

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. See the “2020 Texas Base Rate Case” section below for additional information. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the prudency of the retirement of the Dolet Hills Power Station and resulted in a disallowance of $14 million in the first quarter of 2024.

In March 2023, the Pirkey Plant was retired. 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. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. 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 ALJs’ July 2023 PFD. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo’s decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of September 30, 2024, the Texas jurisdictional share of the net book value of the Pirkey Plant was $69 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

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. As ordered by the OCC, as part of the 2022 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

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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.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2024, of generating facilities planned for early retirement:
PlantNet Book ValueAccelerated Depreciation Regulatory AssetCost of Removal
Regulatory Liability
Projected
Retirement Date
Current Authorized
Recovery Period
Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3$111.9 $181.2 $20.8 (b)2026(c)$15.7 
Welsh Plant, Units 1 and 3341.4 156.7 57.6 (d)2028(e)(f)41.6 

(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, units are being evaluated for conversion to natural gas after 2028.
(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.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station. The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of September 30, 2024, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $76 million, including materials and supplies, net of cost of removal collected in rates. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of September 30, 2024, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $35 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of up to $55 million, including denial of recovery of the $35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $55 million refund to customers and the denial of recovery of the $35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ’s recommendations. In April 2024, the LPSC approved a unanimous settlement agreement filed by SWEPCo, LPSC staff and certain intervenors that resolved the fuel recovery dispute and resulted in a fuel disallowance of $11 million. The remaining $24 million regulatory asset balance will be recovered over three years with interest.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $48 million of Oxbow mine related costs through 2035.

If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition.


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Pirkey Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of September 30, 2024, SWEPCo’s share of the net investment in the Pirkey Plant was $187 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” section above for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of September 30, 2024, SWEPCo had a net under-recovered fuel balance of $23 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses.

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. The LPSC established a procedural schedule stating staff and intervenor testimony is due in November 2024 and a hearing is scheduled for March 2025.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $33 million of Sabine related fuel costs through 2035.

If any of these costs are not recoverable or customer refunds are required, it could reduce future net income and cash flows and impact financial condition.

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
AEP
September 30,December 31,
20242023
 Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Welsh Plant, Units 1 and 3 Accelerated Depreciation$156.7 $125.6 
Pirkey Plant Accelerated Depreciation120.8 114.4 
Unrecovered Winter Storm Fuel Costs (a)75.9 97.2 
Storm-Related Costs41.3  
Other Regulatory Assets Pending Final Regulatory Approval16.2 49.8 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs 379.5 408.9 
Plant Retirement Costs – Asset Retirement Obligation Costs (b)340.4 25.9 
NOLC Costs (c)82.9  
2024-2025 Virginia Biennial Under-Earnings18.6  
Other Regulatory Assets Pending Final Regulatory Approval51.3 52.6 
Total Regulatory Assets Pending Final Regulatory Approval$1,283.6 $874.4 
(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2024 and December 31, 2023, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.
(c)In the second quarter of 2024, requests seeking to establish a recovery mechanism for these regulatory assets were filed in Indiana, Oklahoma and Texas. In Indiana and Oklahoma, certain intervenors have challenged the recovery, or have proposed ratemaking treatment that would offset the recovery, of the regulatory assets. In the third quarter of 2024, PUCT Staff and certain intervenors in Texas requested a hearing and direct testimony was filed by SWEPCo in October 2024.
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AEP Texas
September 30,December 31,
20242023
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Storm-Related Costs$41.3 $ 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs16.6 37.7 
Line Inspection Costs5.8 5.7 
Vegetation Management Program 5.2 
Texas Retail Electric Provider Bad Debt Expense 4.0 
Other Regulatory Assets Pending Final Regulatory Approval1.4 11.7 
Total Regulatory Assets Pending Final Regulatory Approval$65.1 $64.3 


APCo
September 30,December 31,
20242023
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$1.0 $0.6 
Regulatory Assets Currently Not Earning a Return  
Plant Retirement Costs – Asset Retirement Obligation Costs (a)266.9 25.9 
Storm-Related Costs – West Virginia126.5 91.5 
2024-2025 Virginia Biennial Under-Earnings18.6  
Other Regulatory Assets Pending Final Regulatory Approval14.7 7.5 
Total Regulatory Assets Pending Final Regulatory Approval$427.7 $125.5 
(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.


 I&M
September 30,December 31,
20242023
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$2.3 $0.2 
Regulatory Assets Currently Not Earning a Return  
Plant Retirement Costs – Asset Retirement Obligation Costs (a)72.9  
NOLC Costs – Indiana (b)24.6  
Storm-Related Costs – Indiana7.4 29.7 
Other Regulatory Assets Pending Final Regulatory Approval4.4 3.3 
Total Regulatory Assets Pending Final Regulatory Approval$111.6 $33.2 

(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.
(b)In the second quarter of 2024, a request seeking to establish a recovery mechanism for these regulatory assets were filed in Indiana. Certain intervenors have challenged the recovery, or have proposed ratemaking treatment that would offset the recovery, of the regulatory assets.
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 OPCo
September 30,December 31,
20242023
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$0.2 $ 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs 23.6 
Other Regulatory Assets Pending Final Regulatory Approval0.1  
Total Regulatory Assets Pending Final Regulatory Approval$0.3 $23.6 

 PSO
September 30,December 31,
20242023
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs $94.2 $88.5 
NOLC Costs (a)14.2  
Other Regulatory Assets Pending Final Regulatory Approval3.2 0.2 
Total Regulatory Assets Pending Final Regulatory Approval$111.6 $88.7 

(a)In the second quarter of 2024, a request seeking to establish a recovery mechanism for these regulatory assets were filed in Oklahoma. Certain intervenors have challenged the recovery, or have proposed ratemaking treatment that would offset the recovery, of the regulatory assets.
SWEPCo
September 30,December 31,
20242023
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Welsh Plant, Units 1 and 3 Accelerated Depreciation$156.7 $125.6 
Pirkey Plant Accelerated Depreciation120.8 114.4 
Unrecovered Winter Storm Fuel Costs (a)75.9 97.2 
Dolet Hills Power Station Accelerated Depreciation (b)11.8 12.0 
Other Regulatory Assets Pending Final Regulatory Approval1.0 26.0 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs - Louisiana, Texas49.0 56.0 
NOLC Costs (c)44.1  
Other Regulatory Assets Pending Final Regulatory Approval18.5 13.7 
Total Regulatory Assets Pending Final Regulatory Approval$477.8 $444.9 

(a)Includes $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2024 and December 31, 2023, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)Amounts include the FERC jurisdiction.
(c)In the second quarter of 2024, a request seeking to establish a recovery mechanism for the Texas jurisdictional share of these regulatory assets were filed in Texas. In the third quarter of 2024, PUCT Staff and certain intervenors in Texas requested a hearing and direct testimony was filed by SWEPCo in October 2024.

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
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AEP Texas Rate Matters (Applies to AEP and AEP Texas)

2024 AEP Texas Base Rate Case

In February 2024, AEP Texas filed a request with the PUCT for a $164 million annual base rate increase over its adjusted test year revenues which include interim transmission and distribution rate updates. AEP Texas’s request is based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence determination on all capital additions placed in service during the period January 1, 2019 through September 30, 2023. As of September 30, 2024, AEP Texas’ cumulative revenues from transmission and distribution interim rate increases are estimated to be approximately $1.3 billion and are subject to reconciliation in this base rate case. In July 2024, AEP Texas filed an unopposed settlement agreement with the PUCT. The settlement agreement included a proposed annual revenue increase of $70 million based upon a 9.76% ROE with a capital structure of 57.5% debt and 42.5% common equity. In addition, the settlement agreement approved the prudency of capital investments placed in service for the period January 1, 2019 through September 30, 2023 and the associated interim revenues collected on those capital investments. In October 2024, the PUCT issued a final order approving the settlement agreement without modification.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

ENEC (Expanded Net Energy Cost) Filings

In January 2024, the WVPSC issued an order resolving APCo’s and WPCo’s (the Companies) 2021-2023 ENEC cases. In the order, the WVPSC: (a) disallowed $232 million in ENEC under-recovered costs as of February 28, 2023 ($136 million related to APCo) and (b) approved the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023 ($174 million related to APCo) plus a 4% debt carrying charge rate over a ten-year recovery period starting September 1, 2024. In February 2024, the Companies filed briefs with the West Virginia Supreme Court to initiate an appeal of this order. In September 2024, oral arguments were held at the West Virginia Supreme Court. A final ruling is expected in the fourth quarter of 2024.

In April 2024, the Companies submitted their annual ENEC update filing with the WVPSC proposing a $58 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this ENEC rate change would: (a) become effective September 1, 2024, (b) include a $20 million annual increase in ENEC rates related to the period ending February 29, 2024 and the forecast period September 2024 through August 2025 and (c) include a $38 million annual increase in ENEC rates for the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023 over a ten-year period, plus a 4% debt carrying charge rate. In July 2024, intervenors and staff filed testimony with the WVPSC, which did not recommend any disallowances.

In August 2024, the WVPSC issued an order approving the requested $38 million annual increase effective September 1, 2024. The WVPSC will address the proposed additional $20 million annual increase in ENEC rates in a future order. If any costs included in the future filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

Virginia Fuel Adjustment Clause (FAC) Review

In 2023, APCo submitted its annual fuel cost filing with the Virginia SCC. Interim Virginia FAC rates were implemented in November 2023. In APCo's 2022 Virginia fuel update filing, the Virginia staff ordered the Virginia Staff to commence an audit of APCo’s fuel costs for the years ended December 31, 2019, 2020, 2021 and 2022. The Virginia staff analyzed APCo’s 2019 through 2022 fuel procurement activities and concluded the procurement practices were reasonable and prudent and recommended no disallowances. In May 2024, the Virginia SCC issued an order approving the audit of APCo’s 2019 and 2020 fuel costs but concluded that the review of APCo fuel costs for 2021 and 2022 remains open for further evaluation. As of September 30, 2024, APCo had a Virginia jurisdictional under-recovered fuel balance of $164 million. If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

2024 Virginia Base Rate Case

In March 2024, APCo filed a request with the Virginia SCC for a $95 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 51% debt and 49% common equity. The requested increase in base rates is primarily due to incremental rate base, proposed capital structure changes including an increase in ROE and proposed increases in distribution and generation operation and maintenance expenses. In September 2024, a hearing was held where APCo updated its requested increase in base rates to $64 million consistent with its rebuttal positions or, alternatively, an increase of $45 million if annual environmental compliance consumable expenses are moved from base rates to recovery through APCo’s environmental rate adjustment clause. An order will be issued in the fourth quarter of 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.
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2024 West Virginia Base Rate Case

In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $251 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 52% debt and 48% common equity. The requested net annual increase in base rates excludes the Companies’ proposed $94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $118 million in previously deferred major storm expense over a three-year period, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses.

The Companies’ November 2024 West Virginia base rate filing also included two sets of alternative frameworks to simplify rates and customer bills and provide predictable future rate increases. The Companies’ first framework includes: (a) securitization, (b) approval of a major storm expense recovery and tracking mechanism and (c) freezing of OATT revenues in the ENEC. This framework includes securitization in a concurrent proceeding of approximately $2.4 billion of West Virginia jurisdictional assets including: (a) the Companies’ remaining combined unrecovered ENEC balance related to costs incurred through February 28, 2023, (b) undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) deferred major storm operation and maintenance costs. Securitization of those items could reduce the Companies’ combined requested increase in annual base rates to $37 million.

The Companies also included an alternative ratemaking proposal that includes: (a) a separate surcharge that would allow the Companies up to a 3% annual increase in overall West Virginia rates for four consecutive years on April 1st of each year after the implementation of base rates in this case, (b) the elimination of all of the Companies’ existing West Virginia jurisdictional surcharges except for the ENEC, with the revenues of these eliminated riders rolled into base rates and (c) the creation of a new West Virginia jurisdictional environmental and new generation surcharge. This alternative proposal would allow the Companies to submit a base rate case filing in advance of and in lieu of the annual April 1st 3% increase and would require the Companies to submit a base rate case filing at the end of the proposed four-year period.

If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing

In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLC and AROs. If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition.

Hurricane Helene

In late September 2024, the remnants of Hurricane Helene significantly impacted APCo’s Virginia and West Virginia service territories leading to approximately 260,000 customer outages and damages to APCo’s power grid. Storm restoration efforts continued into early October and APCo completed restoration efforts for all customers who lost power by October 6th, 2024. As of September 30, 2024, APCo incurred approximately $19 million ($13 million related to the Virginia jurisdiction and $6 million related to the West Virginia jurisdiction) of incremental other operation and maintenance expenses and approximately $8 million of capital expenditures. APCo deferred $16 million of the incremental other operation and maintenance expenses as regulatory assets as the costs are deemed probable of future recovery. Based on the information currently available, APCo estimates total storm restoration costs to be approximately $140 million, of which 70% is expected to be deferred as regulatory assets and the remaining 30% of the costs are expected to be capital expenditures. If any costs related to Hurricane Helene are not recoverable, it could reduce future net income and cash flows and impact financial condition.


121


ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through September 30, 2024, AEP’s share of ETT’s cumulative revenues that are subject to a prudency review is approximately $1.8 billion. A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2025, during which the $1.8 billion of cumulative revenues above will be subject to review.

I&M Rate Matters (Applies to AEP and I&M)

2023 Michigan Power Supply Cost Recovery (PSCR) Reconciliation

In March 2024, I&M submitted its 2023 PSCR Reconciliation to the MPSC. In October 2024, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC Inter-Company Power Agreement and the Rockport UPA with AEGCo ranging from $3 million to $15 million. A hearing is scheduled for December 2024. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2023 Indiana Base Rate Case

In August 2023, I&M filed a request with the IURC for a $116 million annual increase in Indiana base rates based upon a 2024 forecasted test year, a proposed 10.5% ROE and a proposed capital structure of 48.8% debt and 51.2% common equity. I&M proposed that the annual increase in base rates be implemented in two steps, with the first increase effective in mid-2024, following an IURC order, and the second increase effective in January 2025. The proposed annual increase includes, but is not limited to, a $41 million increase related to depreciation expense, driven by increased depreciation rates and increased capital investments, and a $15 million increase related to storm expenses. I&M’s Indiana base case filing requested recovery of certain historical period regulatory asset balances and proposed deferral accounting for certain future investments and tax related issues, including CAMT expense and PTCs related to the Cook Plant.

In December 2023, I&M and intervenors reached a settlement agreement that was submitted to the IURC recommending a two-step increase in Indiana rates with a $28 million annual increase effective upon an IURC order and the remaining $34 million annual increase effective in January 2025 subject to I&M’s level of electric plant in service as of December 31, 2024 in comparison to I&M’s 2024 forecasted test year. The recommended revenue increase includes: (a) a 9.85% ROE, (b) a two-step update of I&M’s Indiana capital structure with a capital structure of 50% for both debt and common equity effective upon an IURC order and a January 2025 update based on I&M’s actual capital structure as of December 31, 2024 with common equity not to exceed 51.2%, (c) a $25 million increase related to depreciation expense and (d) an $11 million increase related to storm expenses. In addition, I&M also agreed to withdraw its proposal to defer CAMT and Cook Plant PTCs and to instead include the Indiana jurisdictional impact of Cook Plant PTCs in I&M’s Indiana earnings test evaluations. See “Indiana Earnings Test” below for additional information.

In May 2024, the IURC issued an order approving the settlement agreement with minor modifications.

2023 Michigan Base Rate Case

In September 2023, I&M filed a request with the MPSC for a $34 million annual increase in Michigan base rates based upon a 2024 forecasted test year, a proposed 10.5% ROE and a capital structure of 49.4% debt and 50.6% common equity. The proposed annual increase includes an $11 million annual increase in depreciation expense driven by increased capital investment. I&M’s Michigan base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax related issues, including CAMT expense and PTCs related to the Cook Plant.

In July 2024, the MPSC issued a final order approving an annual base rate increase of $17 million based on a 9.86% ROE and a capital structure of 52% debt and 48% common equity. The MPSC also ordered that Michigan jurisdictional Cook Plant PTCs will be reflected as a deferral in I&M’s PSCR reconciliation and rejected I&M’s request to defer Michigan jurisdictional CAMT.


122


Indiana Earnings Test

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In July 2024, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2024. In September 2024, an intervenor submitted testimony suggesting that I&M failed to prorate calculations of I&M’s operating income and I&M’s earnings test ceiling to reflect the impact of I&M’s updated Indiana base rates that became effective in May 2024. The IURC is expected to issue an order in November 2024. As of September 30, 2024, I&M’s financial statements adequately reflect the estimated impact of upcoming Indiana earnings test filings, including Indiana’s jurisdictional share of PTCs that have been recognized in 2024. If the IURC issues orders on I&M’s Indiana earnings test(s) that result in refunds to customers, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

In June 2023, the KPSC issued an order directing KPCo to show cause why it should not be subject to Kentucky statutory remedies, including fines and penalties, for failure to provide adequate service in its service territory. The KPSC’s show cause order did not make any determination regarding the adequacy of KPCo’s service. In July 2023, KPCo filed a response to the show cause order demonstrating that it has provided adequate service. In December 2023 and February 2024, KPCo and certain intervenors filed testimony with the KPSC. A hearing with the KPSC was previously scheduled to occur in June 2024. The hearing was postponed and has not yet been rescheduled. If any fines or penalties are levied against KPCo relating to the show cause order, it could reduce net income and cash flows and impact financial condition.

2023 Kentucky Base Rate and Securitization Case

In June 2023, KPCo filed a request with the KPSC for a $94 million net annual increase in base rates based upon a proposed 9.9% ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50% interest in Mitchell Plant, which will be addressed in the future. As of September 30, 2024, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $552 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In November 2023, KPCo filed an uncontested settlement agreement with the KPSC, that included an annual base rate increase of $75 million, based upon a 9.75% ROE. Settlement parties agreed that the KPSC should approve KPCo’s securitization request, and that the approximately $471 million regulatory assets requested for securitization are comprised of prudently incurred costs.

In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $60 million based upon a 9.75% ROE effective with billing cycles mid-January 2024. The order reduced KPCo’s base rate revenue requirement by $14 million to allow recovery of actual test year PJM transmission costs instead of KPCo’s requested annual level of costs based on PJM 2023 projected transmission revenue requirements. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court, challenging among other aspects of the order, the $14 million base rate revenue requirement reduction.

In January 2024, consistent with the November 2023 uncontested settlement agreement, the KPSC issued a financing order approving KPCo’s request to securitize certain regulatory assets balances as of the time securitization bonds are issued and concluding that costs requested for recovery through securitization were prudently incurred. The KPSC’s financing order includes certain additional requirements related to securitization bond structuring, marketing, placement and issuance that were not reflected in KPCo’s proposal. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in the first half of 2025, subject to market conditions. As of September 30, 2024, regulatory asset balances expected to be recovered through securitization total $485 million and include: (a) $297 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $49 million of deferred purchased power expenses, (d) $58 million of under-recovered purchased power rider costs and (e) $2 million of deferred issuance-related expenses, including KPSC advisor expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

123


Fuel Adjustment Clause (FAC) Review

In December 2023, KPCo received intervenor testimony in its FAC review for the two-year period ending October 31, 2022, recommending a disallowance ranging from $44 million to $60 million of its total $432 million purchased power cost recoveries as a result of proposed modifications to the ratemaking methodology that limits purchased power costs recoverable through the FAC. A hearing was held in February 2024 and the KPSC may issue its order in the fourth quarter of 2024 or early 2025. If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

Rockport Offset Recovery

In January 2024, KPCo filed an application with the KPSC seeking to recover an allowed cost (Rockport Offset) of $41 million in accordance with the terms of the settlement agreement in the 2017 Kentucky Base Rate Case permitting KPCo to use the level of non-fuel, non-environmental Rockport Plant UPA expense included in base rates to earn its authorized ROE in 2023 since the Rockport UPA ended in December 2022. An estimated Rockport Offset of $23 million was recovered through a rider, subject to true-up, during the 12-months ended December 2023. In February 2024, the KPSC issued an order allowing KPCo to collect the remaining $18 million through interim rates, subject to refund, over twelve months starting in March 2024. In April 2024, KPCo submitted to the KPSC a request for decision on the record. In August 2024, KPCo filed an application with the KPSC to extend the recovery of the remaining balance through September 2025. The KPSC may issue its order in the fourth quarter of 2024 or early 2025. Through the third quarter of 2024, the Rockport Offset true-up is reflected in revenues to the extent amounts have been billed to customers, as KPCo has not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”. If the Rockport Offset is not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In May 2023, as part of the OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2020 audit period were imprudent and should be disallowed.

In August 2024, the PUCO issued orders pertaining to the OVEC cost recovery audits that: (a) denied intervenors’ application for rehearing on the 2016-2017 audit period, (b) determined costs incurred by OPCo during the 2018-2019 audit period were prudent, (c) determined costs incurred by OPCo during the 2020 audit period were prudent and (d) recommended no disallowances for any mentioned audit period in question. In September 2024, intervenors filed for rehearing on the 2018-2019 and 2020 OVEC cost recovery audit periods claiming the PUCO’s August 2024 orders to adopt the findings of the audit reports were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In October 2024, the PUCO denied the intervenors’ applications for rehearing of the 2018-2019 and 2020 audit periods.

Ohio ESP Filings

In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. In June 2023, intervenors filed testimony opposing OPCo’s plan for various new riders and modifications to existing riders, including the DIR. In September 2023, OPCo and certain intervenors filed a settlement agreement with the PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May 2028, an ROE of 9.7% and continuation of a number of riders including the DIR subject to revenue caps. In April 2024, the PUCO issued an order approving the settlement agreement. In May 2024, intervenors filed an application for rehearing with the PUCO on the approved settlement agreement and the PUCO denied the intervenors’ application for rehearing in June 2024.


124


PSO Rate Matters (Applies to AEP and PSO)

2024 Oklahoma Base Rate Case

In January 2024, PSO filed a request with the OCC for a $218 million annual base rate increase based upon a 10.8% ROE with a capital structure of 48.9% debt and 51.1% common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP’s 2023 increased capacity planning reserve margin requirements. PSO’s request includes the 155 MW Rock Falls Wind Facility and reflects recovery of Northeastern Plant, Unit 3 through 2040.

In July 2024, OCC staff and various intervenors filed testimony. The OCC staff recommended a $115 million annual base rate increase based upon a 9.3% ROE while intervenors recommended an annual base rate increase ranging from $19 million to $113 million based on an ROE ranging from 9.0% to 9.6%. The OCC staff also recommended a $62 million disallowance of certain capital investments. In addition, a certain intervenor recommended the OCC reject PSO’s request to recover the Rock Falls Wind Facility through base rates, but allow PSO to retain PTCs and energy revenues up to the Rock Falls Wind Facility annual revenue requirement. In September 2024, the OCC staff withdrew its recommendation for a $62 million disallowance of certain capital investments.

In October 2024, PSO, the OCC and certain intervenors filed a joint stipulation and settlement agreement with the OCC that included a net annual revenue increase of $120 million based upon a 9.5% ROE with a capital structure of 48.9% debt and 51.1% common equity. The agreement also allows for Rock Falls Wind Facility to be included in base rates and the deferral of certain generation-related costs necessary to comply with SPP’s 2023 increased capacity reserve margin requirements. One intervenor opposed the joint stipulation and settlement agreement. In October 2024, a hearing was held at the OCC, and PSO implemented an interim annual base rate increase of $120 million, subject to refund pending a final order by the OCC. An order is expected in the fourth quarter of 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap and remanded the case to the PUCT for future proceedings. In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. In June 2023, the Texas Supreme Court denied SWEPCo’s request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

In December 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo’s request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the PUCT’s approval of the preliminary order, SWEPCo recorded a pretax, non-cash disallowance of $86 million in the fourth quarter of 2023.

The PUCT’s December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. On March 1, 2024, SWEPCo filed supplemental direct testimony with the PUCT in response to the December 2023 preliminary order. On March 8, 2024, intervenors and the PUCT staff filed a motion with the PUCT to strike portions of SWEPCo’s October 2023 direct testimony and March 2024 supplemental direct testimony. On March 19, 2024, the ALJ granted portions of the motion, which included removal of testimony supporting SWEPCo’s position that refunds were not appropriate. On March 28, 2024,
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SWEPCo filed an appeal of the ALJ decision with the PUCT. In April 2024, intervenors and PUCT staff submitted testimony recommending customer refunds through December 2023 ranging from $149 million to $197 million, including carrying charges, with refund periods ranging from 18 months to 48 months. In May 2024, the PUCT denied SWEPCo’s appeal of the ALJ’s March 2024 decision. In the second quarter of 2024, based on the PUCT’s decision, SWEPCo recorded a one-time, probable revenue refund provision of $160 million, including interest, associated with revenue collected from February 2013 through December 2023. In June 2024, SWEPCo and parties to the remand proceeding reached an agreement in principle that would resolve all issues in the case. In October 2024, SWEPCo filed the settlement agreement with the PUCT. Under the settlement agreement, SWEPCo will refund over a two-year period $148 million, including interest, associated with revenue collected from February 2013 through December 2023 and remove AFUDC in excess of the Texas jurisdictional capital cost cap from rate base. The settlement is expected to be considered by the PUCT in the fourth quarter of 2024.

2016 Texas Base Rate Case

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a 9.6% ROE, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Base Rate Case

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million, which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking judicial review of the several errors challenged in the PUCT’s final order.

2021 Louisiana Storm Cost Filing

In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC, which confirmed the prudency of $150 million of deferred incremental storm restoration
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expenses. The agreement also authorized an interim carrying charge at a rate of 3.125% through March 2024. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. In April 2024, SWEPCo and the LPSC staff filed a joint uncontested stipulation and settlement agreement with the LPSC requesting securitization of storm costs, including a storm reserve. In July 2024, the LPSC issued an order approving the joint uncontested stipulation and settlement agreement, including approval to securitize $343 million, which includes $180 million for storm costs and a $150 million storm reserve. Securitization bonds are expected to be issued in the fourth quarter of 2024, subject to market conditions.

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021 to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are shown in the table below:
JurisdictionSeptember 30, 2024December 31, 2023Approved Recovery PeriodApproved Carrying Charge
(in millions)
Arkansas$40.4 $54.2 6 years(a)
Louisiana75.9 97.2 (b)(b)
Texas79.3 101.9 5 years1.65%
Total$195.6 $253.3 

(a)SWEPCo is permitted to record carrying costs on the unrecovered balance of fuel costs at a weighted-cost of capital approved by the APSC. In August 2024, the APSC issued an order that found SWEPCo had prudently incurred these costs.
(b)In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge equal to the prime rate. The special order states the fuel and purchased power costs incurred will be subject to a future LPSC audit.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

PSO and SWEPCo Rate Matters (Applies to AEP, PSO and SWEPCo)

North Central Wind Energy Facilities

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee will be measured in MWhs across all facilities on a combined basis for each five year period for the first thirty full years of operation. The first NCF guarantee five year period began in April 2022. Certain wind turbines have experienced performance issues related to defects covered by the manufacturer’s warranty. These performance issues have prompted PSO and SWEPCo to file a lawsuit against the manufacturer in an attempt to find a resolution on the matter. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability to refund retail customers. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

FERC Rate Matters

Independence Energy Connection Project (Applies to AEP)

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania granted summary judgment in favor of Transource Energy, finding that the PAPUC decision violated federal law and the United States Constitution. In January 2024, the PAPUC filed an appeal of the district court’s grant of summary judgment with the United States Court of Appeals for the Third Circuit. Additional regulatory proceedings before the PAPUC are expected to resume in 2025.
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In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of September 30, 2024, AEP’s share of IEC capital expenditures was approximately $94 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in the UPA between AEGCo and I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.

In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. In August 2023, AEGCo reached a settlement agreement with the FERC trial staff that resolved all issues set for hearing. In September 2023, the settlement agreement was certified to the FERC as uncontested. In March 2024, the FERC issued an order approving the uncontested settlement agreement. The results of the order did not have a material impact on financial condition, results of operations or cash flows.

FERC 2021 PJM and SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, APCo, I&M, PSO and SWEPCo)

The Registrants transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the annual revenue requirements for years 2024, 2023, 2022 and 2021 by $52 million, $61 million, $69 million and $78 million, respectively.

In January 2024, the FERC issued two orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. Accordingly, in the third quarter of 2024, the AEP transmission owning subsidiaries within SPP provided a portion of the 2021 rate year refunds, with the remainder of the refunds expected to be provided in 2025. The AEP transmission owning subsidiaries within PJM are expected to provide their respective refunds for the 2021 rate year in 2025. In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests for rehearing. In March 2024, the FERC denied AEPSC’s requests for rehearing of the January 2024 orders by operation of law and stated it may address the requests for rehearing in future orders. In March 2024, AEPSC submitted refund compliance reports to the FERC, which preserve the non-finality of the FERC’s January 2024 orders pending further proceedings on rehearing and appeal. In April 2024, AEPSC made filings with the FERC which request that the FERC: (a) reopen the record so that the FERC may take the IRS PLRs received in April 2024 regarding the treatment of stand-alone NOLCs in ratemaking into evidence and consider them in substantive orders on rehearing and (b) stay its January 2024 orders and related compliance filings and refunds to provide time for consideration of the April 2024 IRS PLRs. In May 2024, AEPSC filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s January 2024 and March 2024 decisions. In July 2024, the FERC issued orders approving AEPSC’s request to reopen the record for the limited purpose of accepting into the record the IRS PLRs and establish additional briefing procedures. In August 2024, AEPSC filed briefs with the FERC requesting the commission modify or overturn their initial orders.

As a result of the January 2024 FERC orders, the Registrants’ balance sheets reflect a liability for the probable refund of all NOLC revenues included in transmission formula rates for years 2024, 2023, 2022 and 2021, with interest. The Registrants have not yet been directed to make cash refunds related to the 2024, 2023 or 2022 rate years. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets, with the exception of amounts expected to be refunded within one year which are reflected in Other Current Liabilities. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an increase to Regulatory Liabilities or a reduction to Regulatory Assets on the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms.
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Request to Update SWEPCo Generation Depreciation Rates (Applies to AEP and SWEPCo)

In October 2023, SWEPCo filed an application to revise its generation wholesale customer’s contracts to reflect an increase in the annual revenue requirement of approximately $5 million for updated depreciation rates and allow for the return on and of FERC customers jurisdictional share of regulatory assets associated with retired plants. In November 2023, certain intervenors filed a motion with the FERC protesting and recommending the rejection of SWEPCo’s filings. In December 2023, the FERC issued an order approving the proposed rates effective January 1, 2024, subject to further review and refund and established hearing and settlement proceedings. If SWEPCo is unable to recover the remaining regulatory assets associated with retired plants, it could reduce future net income and cash flows and impact financial condition.
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5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business.  In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted.  Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2023 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit (Applies to AEP and AEP Texas)

Standby letters of credit are entered into with third-parties.  These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

In March 2024, AEP increased its $4 billion revolving credit facility to $5 billion and extended the due date from March 2027 to March 2029. Also, in March 2024, AEP extended the due date of its $1 billion revolving credit facility from March 2025 to March 2027. AEP may issue up to $1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of September 30, 2024, no letters of credit were issued under either revolving credit facility.

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 six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2024 were as follows:
CompanyAmountMaturity
 (in millions) 
AEP$236.3 October 2024 to July 2025
AEP Texas1.8 July 2025

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of September 30, 2024, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf.  AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.


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Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of September 30, 2024, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
CompanyMaximum
Potential Loss
(in millions)
AEP$42.8 
AEP Texas9.9 
APCo5.5 
I&M4.0 
OPCo6.9 
PSO4.1 
SWEPCo4.9 

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

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”). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (“closure in place”) or the CCR material may be excavated and placed in a compliant landfill (“closure by removal”). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. AEP evaluated the applicability of the rule to current and former plant sites and recorded incremental ARO in the second quarter of 2024, as shown in the table below, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the CCR Rule.

RegistrantIncrease in AROIncrease in Generation Property (a)Increase in Regulatory Assets (b) Charged to Operating Expenses (c)
(in millions)
APCo$312.2 $75.6 $236.6 $ 
I&M85.7  72.3 13.4 
OPCo52.9   52.9 
PSO33.7 33.7   
SWEPCo23.8 23.8   
Non-Registrants166.1 43.8 46.1 76.2 
Total$674.4 $176.9 $355.0 $142.5 

(a)ARO is related to a legacy CCR surface impoundment or CCR management unit at an operating generation facility.
(b)ARO is related to a legacy CCR surface impoundment or CCR management unit at a retired generation facility and recognition of a regulatory asset in accordance with the accounting guidance for “Regulated Operations” is supported.
(c)ARO is related to a legacy CCR surface impoundment or CCR management unit and recognition of a regulatory asset in accordance with the accounting guidance for “Regulated Operations” is not yet supported.

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As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the ARO. These refinements may include, but are not limited to, changes in the expected method of closure, changes in estimated quantities of CCR at each site, the identification of new CCR management units, among other items. These future changes could have a material impact on the ARO and materially reduce future net income and cash flows and further impact financial condition.

AEP will seek cost recovery through regulated rates, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. Several parties, including AEP and one of its trade associations, have filed petitions for review of the rule with the U.S. Court of Appeals for the D.C. Circuit. One of the parties also filed a motion to stay the rule pending the outcome of the litigation. In November 2024, the court denied the stay motion. Management cannot predict the outcome of the litigation.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials.  The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  Management is currently evaluating applying for license extensions for both units. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cybersecurity incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants.  Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

Insurance coverage for certain claims made by third-parties is structured to reimburse the Registrants for the amounts they are legally obligated to pay in excess of the Registrants’ retentions. Such claims, when deemed probable of occurring and reasonably estimable, are reflected as liabilities on the financial statements of the Registrants. Also, when it is deemed probable that these claims, or any portion thereof, will be covered by insurance or otherwise reimbursable to the Registrant, an asset is recognized on the balance sheet. As of September 30, 2024, AEP Texas recorded an Accrued Litigation Settlement within current liabilities and a corresponding Insurance Receivable within current assets on the balance sheet related to an injured contractor claim.

In July 2024, the Registrants renewed insurance programs including coverage for wildfire liability. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cybersecurity incident, extreme weather or wildfire related liabilities or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered through rate-making process, could reduce future net income and cash flows and impact financial condition.


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Litigation Related to Ohio House Bill 6 (HB 6) (Applies to AEP and OPCo)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the U.S. District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In January 2021, an AEP shareholder filed a derivative action in the U.S. District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints (collectively, the “Derivative Actions”) together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss in April 2022. In June 2022, the Ohio state court entered an order continuing the stays of that case until the final resolution of the consolidated derivative actions pending in Ohio federal district court. In September 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. In January 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint and subsequently filed a brief in opposition to the New York plaintiffs’ motion to intervene in the consolidated action in Ohio. In March 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. In April 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention.

In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand letter from counsel representing the purported AEP shareholder who had filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court the (Litigation Demand). The Litigation Demand is directed to the AEP Board and contains factual allegations involving HB 6 that are generally consistent with those in the Derivative Actions. The Litigation Demand requested, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by certain current and former directors and officers, and that AEP commence a civil action asserting claims similar to the claims asserted in the Derivative Actions. The AEP Board considered the Litigation Demand and formed a committee of the Board (the Demand Review Committee) to investigate, review, monitor and analyze the Litigation Demand and make a recommendation to the AEP Board regarding a reasonable and appropriate response to the same.

In April 2024, AEP reached an agreement with the four shareholders to fully and finally resolve the Derivative Actions and the Litigation Demand, and all claims asserted or that could have been asserted by any AEP shareholder based on the facts alleged, in the manner and upon the terms and conditions set forth in the settlement documents (the Settlement). In July 2024, the U.S. District Court preliminarily approved the Settlement. The Settlement includes a payment of $450 thousand for attorneys’ fees and the implementation of certain governance changes outlined in the Settlement, many of which have already been put in place. The Settlement does not include any admission of liability. In October 2024, the District Court issued an Order and
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Judgment approving the Settlement and granted an Order of Dismissal with Prejudice. Under the Settlement, all Derivative Actions have been or will be dismissed, the Litigation Demand has been withdrawn, and those matters and claims have been resolved pursuant to the terms of the Settlement.

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals and inquiries regarding Empowering Ohio’s Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. AEP and the SEC are engaged in discussions about a possible resolution of the SEC’s investigation and potential claims under the securities laws. Based on these discussions, in the third quarter of 2024, AEP recorded a loss contingency of $19 million in Other Operation expenses on AEP’s statements of income and accrued a corresponding liability in Other Current Liabilities on AEP’s balance sheets. A resolution of the investigation or claims may subject AEP to civil penalties in an amount that could differ from the amount recorded; however, management does not believe any such resolution would be material.

Claims for Indemnification Made by Owners of the Gavin Power Station (Applies to AEP)

In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule (see “Environmental Issues - CCR Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information), including an assertion that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. 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. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit, which in June 2024, were dismissed for lack of jurisdiction. In January 2024, Gavin Power LLC also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Management cannot predict the outcome of that litigation. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Litigation Regarding Justice Thermal Coal Contract (Applies to AEP and APCo)

In December 2023, APCo filed a suit in the Franklin County Ohio Court of Common Pleas seeking a declaratory judgment confirming APCo’s right to terminate a long-term coal contract with Justice Thermal LLC (Justice Thermal) based on Justice Thermal’s failure to perform under the contract. APCo terminated that contract in January 2024, and in April 2024, APCo filed an amended complaint seeking a declaration that the termination was proper and also seeking damages for Justice Thermal’s breach of contract. Justice Thermal filed an answer and counterclaim in April 2024, contesting the validity of the contract termination and asserting counterclaims. The parties entered into a Settlement Agreement and Release pursuant to which the litigation was dismissed with prejudice in September 2024 and each party released the other from all claims relating to the contract or the litigation, and as a result this matter has been resolved.


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6. ACQUISITIONS AND DISPOSITIONS

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

Rock Falls Wind Facility (Vertically Integrated Utilities Segment) (Applies to AEP and PSO)

In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and construction for $146 million. In accordance with the guidance for “Business Combinations,” AEP management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The lease obligations related to Rock Falls were not material at the time of acquisition.

DISPOSITIONS

Disposition of AEP OnSite Partners (Generation & Marketing Segment) (Applies to AEP)

In April 2023, AEP initiated a sales process for its ownership in AEP OnSite Partners. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. In May 2024, AEP signed an agreement to sell AEP OnSite Partners to a nonaffiliated third-party. In September 2024, AEP completed the sale to a nonaffiliated third-party and received cash proceeds of approximately $318 million, net of taxes and transaction costs. The proceeds were used to pay down short-term debt.

Disposition of the Competitive Contracted Renewables Portfolio (Generation & Marketing Segment) (Applies to AEP)

In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio (the portfolio) within the Generation & Marketing segment. In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the portfolio and AEP signed an agreement with a nonaffiliated party. AEP recorded a pretax loss of $112 million ($88 million after-tax) in the first quarter of 2023 as a result of reaching Held for Sale status and determining the carrying value of the portfolio exceeded the estimated fair value.

In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs.

Disposition of NMRD (Generation & Marketing Segment) (Applies to AEP)

In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party and the sale was completed in February 2024. AEP received cash proceeds of approximately $107 million, net of taxes and transaction costs. The transaction did not have a material impact on net income or financial condition.
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7.  BENEFIT PLANS

The disclosures in this note apply to all Registrants except AEPTCo.

AEPSC sponsors a qualified pension plan and two unfunded non-qualified pension plans.  Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a non-qualified pension plan.  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost (Credit)

Pension Plans

Three Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$25.6 $2.3 $2.4 $3.3 $2.3 $1.5 $1.9 
Interest Cost51.9 4.4 6.2 5.9 4.8 2.5 3.1 
Expected Return on Plan Assets(80.2)(6.5)(10.7)(10.7)(8.2)(4.3)(4.4)
Amortization of Net Actuarial Loss1.0  0.1 0.1 0.1  0.1 
Net Periodic Benefit Cost (Credit) (a)$(1.7)$0.2 $(2.0)$(1.4)$(1.0)$(0.3)$0.7 

Three Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$23.6 $2.1 $2.3 $2.9 $2.1 $1.4 $2.0 
Interest Cost54.8 4.5 6.6 6.3 5.0 2.7 3.4 
Expected Return on Plan Assets(84.8)(7.0)(11.2)(11.0)(8.6)(4.6)(4.8)
Amortization of Net Actuarial Loss0.3       
Net Periodic Benefit Cost (Credit)$(6.1)$(0.4)$(2.3)$(1.8)$(1.5)$(0.5)$0.6 

Nine Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$76.8 $6.7 $7.3 $9.9 $7.0 $4.6 $5.9 
Interest Cost155.7 13.1 18.6 17.8 14.2 7.5 9.3 
Expected Return on Plan Assets(240.6)(19.5)(32.1)(32.1)(24.5)(13.0)(13.2)
Amortization of Net Actuarial Loss3.2 0.2 0.3 0.3 0.2 0.1 0.2 
Net Periodic Benefit Cost (Credit) (a)$(4.9)$0.5 $(5.9)$(4.1)$(3.1)$(0.8)$2.2 

Nine Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$70.8 $6.2 $6.8 $8.9 $6.3 $4.2 $5.8 
Interest Cost164.4 13.7 19.8 18.7 14.9 8.1 10.4 
Expected Return on Plan Assets(254.4)(21.0)(33.5)(33.1)(25.6)(13.8)(14.5)
Amortization of Net Actuarial Loss1.0       
Net Periodic Benefit Cost (Credit)$(18.2)$(1.1)$(6.9)$(5.5)$(4.4)$(1.5)$1.7 

(a)Excludes an immaterial settlement amount to a non-qualified pension plan in the second quarter of 2024 for AEP. Management continues to monitor settlements under the qualified pension plan as a result of the voluntary severance program announced in the second quarter of 2024. See Note 13 - Voluntary Severance Program for additional information.
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OPEB

Three Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$1.1 $ $0.2 $0.1 $ $0.1 $0.1 
Interest Cost10.3 0.9 1.7 1.2 1.1 0.6 0.7 
Expected Return on Plan Assets(27.8)(2.3)(4.1)(3.4)(3.0)(1.5)(1.9)
Amortization of Prior Service Credit(3.1)(0.3)(0.5)(0.4)(0.3)(0.2)(0.3)
Amortization of Net Actuarial Loss0.8 0.1 0.1 0.1 0.1  0.1 
Net Periodic Benefit Credit (a)$(18.7)$(1.6)$(2.6)$(2.4)$(2.1)$(1.0)$(1.3)

Three Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$1.1 $0.1 $0.1 $0.1 $0.1 $0.1 $ 
Interest Cost11.6 0.9 1.8 1.3 1.2 0.6 0.8 
Expected Return on Plan Assets(27.4)(2.2)(4.0)(3.3)(2.9)(1.5)(1.8)
Amortization of Prior Service Credit(15.8)(1.3)(2.3)(2.2)(1.6)(1.0)(1.3)
Amortization of Net Actuarial Loss3.7 0.3 0.6 0.5 0.4 0.2 0.3 
Net Periodic Benefit Credit$(26.8)$(2.2)$(3.8)$(3.6)$(2.8)$(1.6)$(2.0)

Nine Months Ended September 30, 2024AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$3.3 $0.2 $0.4 $0.4 $0.2 $0.2 $0.3 
Interest Cost31.4 2.5 5.0 3.6 3.2 1.7 2.0 
Expected Return on Plan Assets(83.5)(6.8)(12.2)(10.1)(8.9)(4.5)(5.6)
Amortization of Prior Service Credit(9.5)(0.8)(1.4)(1.3)(0.9)(0.6)(0.8)
Amortization of Net Actuarial Loss2.3 0.2 0.3 0.3 0.3 0.1 0.2 
Net Periodic Benefit Credit (a)$(56.0)$(4.7)$(7.9)$(7.1)$(6.1)$(3.1)$(3.9)

Nine Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$3.4 $0.3 $0.4 $0.5 $0.3 $0.2 $0.2 
Interest Cost34.7 2.7 5.5 4.0 3.5 1.8 2.2 
Expected Return on Plan Assets(82.2)(6.7)(12.0)(10.1)(8.8)(4.4)(5.4)
Amortization of Prior Service Credit(47.3)(4.0)(6.9)(6.5)(4.7)(3.0)(3.7)
Amortization of Net Actuarial Loss11.1 0.9 1.7 1.4 1.2 0.6 0.8 
Net Periodic Benefit Credit$(80.3)$(6.8)$(11.3)$(10.7)$(8.5)$(4.8)$(5.9)

(a)Excludes an immaterial amount related to special termination benefits resulting from the voluntary severance program announced in the second quarter of 2024. See Note 13 - Voluntary Severance Program for additional information.
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8.  BUSINESS SEGMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

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.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs.
Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs.

Generation & Marketing

Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.
Competitive generation in PJM.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.

AEP’s CODM makes operating decisions, allocates resources to and assesses performance based on these operating segments. AEP measures segment profit or loss based on net income (loss). Net income (loss) includes intercompany revenues and expenses that are eliminated on the Consolidated Financial Statements. In addition, direct interest expense and income taxes are included in net income (loss).







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The tables below represent AEP’s reportable segment income statement information for the three and nine months ended September 30, 2024 and 2023 and reportable segment balance sheet information as of September 30, 2024 and December 31, 2023.

Three Months Ended September 30, 2024
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers
$3,248.8 $1,568.5 $113.1 $483.7 $6.0 $ $5,420.1 
Other Operating Segments
54.2 6.9 399.4 15.4 32.1 (508.0)(b) 
Total Revenues$3,303.0 $1,575.4 $512.5 $499.1 $38.1 $(508.0)$5,420.1 
Net Income (Loss)
$572.5 $245.2 $215.8 $93.3 $(165.1)$ $961.7 
Three Months Ended September 30, 2023
 Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers
$3,158.1 $1,535.2 $94.0 $527.5 $26.9 $ $5,341.7 
Other Operating Segments
47.3 8.9 382.7 39.2 30.3 (508.4)(b) 
Total Revenues$3,205.4 $1,544.1 $476.7 $566.7 $57.2 $(508.4)$5,341.7 
Net Income (Loss)
$514.0 $206.0 $203.9 $132.8 $(98.4)$ $958.3 
Nine Months Ended September 30, 2024
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers
$8,722.0 $4,480.5 $332.3 $1,442.1 $48.1 $ $15,025.0 
Other Operating Segments
147.9 21.0 1,167.4 88.0 100.5 (1,524.8)(b) 
Total Revenues$8,869.9 $4,501.5 $1,499.7 $1,530.1 $148.6 $(1,524.8)$15,025.0 
Net Income (Loss)
$1,201.5 $542.3 $627.5 $226.1 $(287.5)$ $2,309.9 
Nine Months Ended September 30, 2023
 Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers
$8,603.4 $4,321.3 $272.4 $1,172.6 $35.4 $ $14,405.1 
Other Operating Segments
134.3 27.2 1,118.4 52.5 83.9 (1,416.3)(b) 
Total Revenues$8,737.7 $4,348.5 $1,390.8 $1,225.1 $119.3 $(1,416.3)$14,405.1 
Net Income (Loss)
$1,054.6 $508.4 $583.6 $(62.2)$(209.6)$ $1,874.8 

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September 30, 2024
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets$53,723.0 $26,102.6 $17,490.1 $1,725.2 $4,393.7 (c)$(3,315.5)(d)$100,119.1 
December 31, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets$51,802.1 $24,838.4 $16,575.6 $2,598.5 $5,194.0 (c)$(4,324.6)(d) $96,684.0 

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.
(b)Represents inter-segment revenues.
(c)Includes elimination of Parent’s investments in wholly-owned subsidiary companies.
(d)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.


Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo.  Other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
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AEPTCo’s Reportable Segments

AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

AEPTCo’s CODM makes operating decisions, allocates resources to and assesses performance based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2024 and 2023 and reportable segment balance sheet information as of September 30, 2024 and December 31, 2023.

Three Months Ended September 30, 2024
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$101.1 $ $ $101.1 
Sales to AEP Affiliates
395.9   395.9 
Other Revenues
0.2   0.2 
Total Revenues$497.2 $ $ $497.2 
Net Income$190.8 $0.5 (a)$ $191.3 
Three Months Ended September 30, 2023
State Transcos AEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$92.8 $ $ $92.8 
Sales to AEP Affiliates
369.9   369.9 
Total Revenues$462.7 $ $ $462.7 
Net Income$178.2 $1.0 (a)$ $179.2 
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Nine Months Ended September 30, 2024
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:
External Customers$295.1 $ $ $295.1 
Sales to AEP Affiliates1,157.1   1,157.1 
Other Revenues3.0   3.0 
Total Revenues$1,455.2 $ $ $1,455.2 
Net Income$547.7 $0.5 (a)$ $548.2 
Nine Months Ended September 30, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:
External Customers$269.2 $ $ $269.2 
Sales to AEP Affiliates1,080.0   1,080.0 
Total Revenues$1,349.2 $ $ $1,349.2 
Net Income$514.0 $3.6 (a)$ $517.6 
September 30, 2024
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets$15,972.9 $5,938.9 (b)$(6,017.5)(c)$15,894.3 
December 31, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets$15,120.6 $5,486.6 (b)$(5,534.7)(c)$15,072.5 

(a)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(b)Primarily relates to Notes Receivable from the State Transcos.
(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.
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9.  DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.

The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:
Notional Volume of Derivative Instruments
September 30, 2024December 31, 2023
Primary Risk
Exposure
AEPAEP TexasAPCoI&MOPCoPSOSWEPCoAEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:     
Power (MWhs)306.0  38.6 8.5 2.1 7.0 6.5 246.8  16.8 5.9 2.2 4.1 2.9 
Natural Gas (MMBtus)161.5  47.1   36.4 14.7 151.6  37.3   34.9 17.9 
Heating Oil and Gasoline (Gallons)7.2 1.7 0.9 1.6 1.1 0.7 0.8 6.5 1.8 1.0 0.6 1.2 0.7 0.9 
Interest Rate (USD)$59.3 $ $ $ $ $ $ $80.1 $ $ $ $ $ $ 
Interest Rate on Long-term Debt (USD)$1,750.0 $ $ $ $ $400.0 $ $1,300.0 $150.0 $ $ $ $ $ 
143


Fair Value Hedging Strategies (Applies to AEP)

Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

Cash Flow Hedging Strategies

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $44 million and $46 million as of September 30, 2024 and December 31, 2023, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of September 30, 2024 and December 31, 2023. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of September 30, 2024 and December 31, 2023.
144


Location and Fair Value of Derivative Assets and Liabilities Recognized In the Balance Sheet

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets. The derivative instruments are disclosed as gross. They are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

September 30, 2024
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity$444.4 $ $54.4 $22.7 $ $28.7 $24.6 
Hedging Contracts - Commodity41.2       
Hedging Contracts - Interest Rate       
Total Current Risk Management Assets485.6  54.4 22.7  28.7 24.6 
Long-term Risk Management Assets
Risk Management Contracts - Commodity448.3  0.8   0.6  
Hedging Contracts - Commodity63.3       
Hedging Contracts - Interest Rate       
Total Long-term Risk Management Assets511.6  0.8   0.6  
Total Assets$997.2 $ $55.2 $22.7 $ $29.3 $24.6 
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity$334.9 $0.5 $15.9 $1.5 $6.6 $11.9 $5.6 
Hedging Contracts - Commodity6.7       
Hedging Contracts - Interest Rate51.7     10.9  
Total Current Risk Management Liabilities393.3 0.5 15.9 1.5 6.6 22.8 5.6 
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity391.1 0.1 6.7 0.1 45.4 0.6  
Hedging Contracts - Commodity2.9       
Hedging Contracts - Interest Rate40.9       
Total Long-term Risk Management Liabilities434.9 0.1 6.7 0.1 45.4 0.6  
Total Liabilities$828.2 $0.6 $22.6 $1.6 $52.0 $23.4 $5.6 
Total MTM Derivative Contract Net Assets (Liabilities) Recognized$169.0 $(0.6)$32.6 $21.1 $(52.0)$5.9 $19.0 
145


December 31, 2023
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity$555.1 $ $24.6 $30.1 $ $19.7 $12.0 
Hedging Contracts - Commodity56.7       
Hedging Contracts - Interest Rate     —  
Total Current Risk Management Assets611.8  24.6 30.1  19.7 12.0 
Long-term Risk Management Assets
Risk Management Contracts - Commodity468.8  0.3 12.0   0.5 
Hedging Contracts - Commodity86.8       
Hedging Contracts - Interest Rate     —  
Total Long-term Risk Management Assets555.6  0.3 12.0   0.5 
Total Assets$1,167.4 $ $24.9 $42.1 $ $19.7 $12.5 
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity$588.0 $0.2 $18.5 $5.4 $6.9 $29.7 $14.9 
Hedging Contracts - Commodity8.2       
Hedging Contracts - Interest Rate50.5 2.7    —  
Total Current Risk Management Liabilities646.7 2.9 18.5 5.4 6.9 29.7 14.9 
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity377.6  6.9 0.2 43.9 1.0 1.7 
Hedging Contracts - Commodity2.2       
Hedging Contracts - Interest Rate56.9     —  
Total Long-term Risk Management Liabilities436.7  6.9 0.2 43.9 1.0 1.7 
Total Liabilities$1,083.4 $2.9 $25.4 $5.6 $50.8 $30.7 $16.6 
Total MTM Derivative Contract Net Assets (Liabilities) Recognized$84.0 $(2.9)$(0.5)$36.5 $(50.8)$(11.0)$(4.1)



146


Offsetting Assets and Liabilities

The following tables show the net amounts of assets and liabilities presented on the balance sheets. The gross amounts offset include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with accounting guidance for “Derivatives and Hedging.” All derivative contracts subject to a master netting arrangement or similar agreement are offset on the balance sheets.

September 30, 2024
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Gross Amounts Recognized$485.6 $ $54.4 $22.7 $ $28.7 $24.6 
Gross Amounts Offset(248.9) (7.3)(1.0) (0.3)(0.5)
Net Amounts Presented236.7  47.1 21.7  28.4 24.1 
Long-term Risk Management Assets
Gross Amounts Recognized511.6  0.8   0.6  
Gross Amounts Offset(253.3) (0.8)  (0.5) 
Net Amounts Presented258.3     0.1  
Total Assets$495.0 $ $47.1 $21.7 $ $28.5 $24.1 
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized$393.3 $0.5 $15.9 $1.5 $6.6 $22.8 $5.6 
Gross Amounts Offset(241.3)(0.5)(8.3)(1.2)(0.3)(0.5)(0.8)
Net Amounts Presented152.0  7.6 0.3 6.3 22.3 4.8 
Long-term Risk Management Liabilities
Gross Amounts Recognized434.9 0.1 6.7 0.1 45.4 0.6  
Gross Amounts Offset(233.3)(0.1)(0.8) (0.1)(0.5) 
Net Amounts Presented201.6  5.9 0.1 45.3 0.1  
Total Liabilities$353.6 $ $13.5 $0.4 $51.6 $22.4 $4.8 
Total MTM Derivative Contract Net Assets (Liabilities)$141.4 $ $33.6 $21.3 $(51.6)$6.1 $19.3 

December 31, 2023
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
Assets:(in millions)
Current Risk Management Assets
Gross Amounts Recognized$611.8 $ $24.6 $30.1 $ $19.7 $12.0 
Gross Amounts Offset(394.3) (2.2)(2.3) (0.7)(0.4)
Net Amounts Presented217.5  22.4 27.8  19.0 11.6 
Long-term Risk Management Assets
Gross Amounts Recognized555.6  0.3 12.0   0.5 
Gross Amounts Offset(234.4) (0.3)(0.2)  (0.5)
Net Amounts Presented321.2   11.8    
Total Assets$538.7 $ $22.4 $39.6 $ $19.0 $11.6 
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized$646.7 $2.9 $18.5 $5.4 $6.9 $29.7 $14.9 
Gross Amounts Offset(417.1)(0.2)(2.6)(3.4)(0.1)(0.8)(0.5)
Net Amounts Presented229.6 2.7 15.9 2.0 6.8 28.9 14.4 
Long-term Risk Management Liabilities
Gross Amounts Recognized436.7  6.9 0.2 43.9 1.0 1.7 
Gross Amounts Offset(194.9) (0.3)(0.2)  (0.5)
Net Amounts Presented241.8  6.6  43.9 1.0 1.2 
Total Liabilities$471.4 $2.7 $22.5 $2.0 $50.7 $29.9 $15.6 
Total MTM Derivative Contract Net Assets (Liabilities)$67.3 $(2.7)$(0.1)$37.6 $(50.7)$(10.9)$(4.0)

147


The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on Risk Management Contracts

Three Months Ended September 30, 2024
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(1.1)$ $ $ $ $ $ 
Generation & Marketing Revenues(67.1)      
Electric Generation, Transmission and Distribution Revenues  0.1 (1.2)   
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation0.7  0.5     
Other Operation(0.3)(0.1) (0.1)   
Maintenance(0.5)(0.1)(0.1)(0.1)(0.1) (0.1)
Regulatory Assets (a)3.1 (0.6)(3.9) (9.2)11.6 6.5 
Regulatory Liabilities (a)60.8  9.8 2.9  23.8 21.8 
Total Gain (Loss) on Risk Management Contracts$(4.4)$(0.8)$6.4 $1.5 $(9.3)$35.4 $28.2 

Three Months Ended September 30, 2023
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(9.5)$ $ $ $ $ $ 
Generation & Marketing Revenues(1.4)      
Electric Generation, Transmission and Distribution Revenues  0.1 (9.6)   
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation0.2  0.2     
Maintenance(0.4)(0.1)(0.1) (0.1)(0.1)(0.1)
Regulatory Assets (a)1.2 0.5 1.2 1.7 0.5 (3.5)(1.1)
Regulatory Liabilities (a)43.0 0.4 11.9 1.6  12.9 12.7 
Total Gain (Loss) on Risk Management Contracts$33.1 $0.8 $13.3 $(6.3)$0.4 $9.3 $11.5 
148


Nine Months Ended September 30, 2024
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(22.5)$ $ $ $ $ $ 
Generation & Marketing Revenues(164.8)      
Electric Generation, Transmission and Distribution Revenues  0.2 (22.7)   
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation2.4  2.1 0.1    
Maintenance0.1       
Regulatory Assets (a)48.3 (0.3)11.2 3.0 (3.7)19.3 11.6 
Regulatory Liabilities (a)206.0  35.5 12.2  75.9 71.4 
Total Gain (Loss) on Risk Management Contracts$69.5 $(0.3)$49.0 $(7.4)$(3.7)$95.2 $83.0 
Nine Months Ended September 30, 2023
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$2.2 $ $ $ $ $ $ 
Generation & Marketing Revenues(290.6)      
Electric Generation, Transmission and Distribution Revenues  0.1 2.1    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation2.2  2.1 0.1    
Other Operation(0.1)      
Maintenance(0.6)(0.2)(0.1) (0.1)(0.1)(0.1)
Regulatory Assets (a)(36.0)  (0.4)(24.6)(7.0)(3.5)
Regulatory Liabilities (a)143.5 0.4 3.1 6.4  73.3 58.2 
Total Gain (Loss) on Risk Management Contracts$(179.4)$0.2 $5.2 $8.2 $(24.7)$66.2 $54.6 

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
149


Accounting for Fair Value Hedging Strategies (Applies to AEP)

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.

AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
Carrying Amount of the Hedged LiabilitiesCumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
September 30, 2024December 31, 2023September 30, 2024December 31, 2023
(in millions)
Long-term Debt (a) (b)$(890.1)$(878.2)$57.5 $68.4 

(a)Amounts included within Noncurrent Liabilities line item Long-term Debt on the Balance Sheet.
(b)Amounts include $(24) million and $(30) million as of September 30, 2024 and December 31, 2023, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:

Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)$14.8 $(13.4)$16.7 $(10.7)
Fair Value Portion of Long-term Debt (a)(14.8)13.4 (16.7)10.7 

(a)Gain (Loss) is included in Interest Expense on the statements of income.

Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo)

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2024 and 2023, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended September 30, 2024, AEP and PSO applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three months ended September 30, 2023, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. During the nine months ended September 30, 2024, AEP, AEP Texas and PSO applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the nine months ended September 30, 2023, AEP, AEP Texas, I&M, PSO and SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.
150


Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

Impact of Cash Flow Hedges on the Registrants’ Balance Sheets
September 30, 2024December 31, 2023
Portion Expected toPortion Expected to
AOCIbe Reclassed toAOCIbe Reclassed to
Gain (Loss)Net Income DuringGain (Loss)Net Income During
Net of Taxthe Next Twelve MonthsNet of Taxthe Next Twelve Months
CommodityInterest RateCommodityInterest RateCommodityInterest RateCommodityInterest Rate
(in millions)
AEP$74.9 $(8.2)$27.3 $2.9 $104.9 $(8.1)$38.3 $3.2 
AEP Texas 6.5  0.7  0.5  0.2 
APCo 5.3  0.8  5.9  0.8 
I&M (5.2) (0.4) (5.5) (0.4)
PSO (8.8) (0.6) (0.2)  
SWEPCo 1.1  0.3  1.3  0.3 

As of September 30, 2024 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is approximately 10 years.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Credit-Risk-Related Contingent Features

Credit Downgrade Triggers (Applies to AEP)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts.  The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral.  The total exposure of AEP’s derivative contracts with collateral triggering events in a net liability position was immaterial as of September 30, 2024 and December 31, 2023. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of September 30, 2024 and December 31, 2023.

151


Cross-Acceleration Triggers (Applies to AEP & PSO)

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $102 million and $107 million and no cash collateral posted as of September 30, 2024 and December 31, 2023, respectively. PSO had derivative contracts with cross-acceleration provisions in a net liability position of $11 million and $0 and no cash collateral posted as of September 30, 2024 and December 31, 2023, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The other Registrant Subsidiaries’ derivative contracts with cross-acceleration provisions outstanding as of September 30, 2024 and December 31, 2023 were immaterial.

Cross-Default Triggers (Applies to AEP, APCo, PSO and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative contracts with cross-default provisions in a net liability position of $174 million and $242 million and no cash collateral posted as of September 30, 2024 and December 31, 2023, respectively, after considering contractual netting arrangements. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $14 million, $11 million and $5 million, respectively, and no cash collateral posted as of September 30, 2024. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $22 million, $29 million and $15 million, respectively, and no cash collateral posted as of December 31, 2023. If a cross-default provision would have been triggered, settlement at fair value would have been required. The other Registrant Subsidiaries had no derivative contracts with cross-default provisions outstanding as of September 30, 2024 and December 31, 2023.
152


10.  FAIR VALUE MEASUREMENTS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.


153


Fair Value Measurements of Long-term Debt (Applies to all Registrants)

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt are summarized in the following table:
September 30, 2024December 31, 2023
CompanyBook ValueFair ValueBook ValueFair Value
(in millions)
AEP$41,974.4 $40,104.2 $40,143.2 $37,325.7 
AEP Texas6,479.4 6,112.1 5,889.8 5,400.7 
AEPTCo5,862.3 5,288.5 5,414.4 4,796.9 
APCo5,659.2 5,582.5 5,588.3 5,390.1 
I&M3,517.5 3,363.4 3,499.4 3,291.6 
OPCo3,715.0 3,389.6 3,366.8 2,992.1 
PSO2,385.4 2,210.9 2,384.6 2,154.3 
SWEPCo3,648.7 3,329.1 3,646.9 3,209.7 

Fair Value Measurements of Other Temporary Investments and Restricted Cash (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.

The following is a summary of Other Temporary Investments and Restricted Cash:
September 30, 2024
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$53.4 $ $ $53.4 
Other Cash Deposits17.0   17.0 
Fixed Income Securities – Mutual Funds (b)168.0  (3.4)164.6 
Equity Securities – Mutual Funds14.8 32.2  47.0 
Total Other Temporary Investments and Restricted Cash$253.2 $32.2 $(3.4)$282.0 
December 31, 2023
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$48.9 $ $ $48.9 
Other Cash Deposits13.9   13.9 
Fixed Income Securities – Mutual Funds (b)165.9  (6.2)159.7 
Equity Securities – Mutual Funds14.8 25.9  40.7 
Total Other Temporary Investments and Restricted Cash$243.5 $25.9 $(6.2)$263.2 

(a)Primarily represents amounts held for the repayment of debt.
(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
154


The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
 Three Months Ended September 30,Nine Months Ended September 30,
 2024202320242023
(in millions)
Proceeds from Investment Sales$4.5 $0.8 $7.5 $0.8 
Purchases of Investments6.0 14.6 9.0 16.9 
Gross Realized Gains on Investment Sales0.4 0.3 0.7 0.3 
Gross Realized Losses on Investment Sales0.3  0.5  

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

Acceptable investments (rated investment grade or above when purchased).
Maximum percentage invested in a specific type of investment.
Prohibition of investment in obligations of AEP, I&M or their affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.

The following is a summary of nuclear trust fund investments:
 September 30, 2024December 31, 2023
GrossGrossOther-Than-GrossGrossOther-Than-
FairUnrealizedUnrealizedTemporaryFairUnrealizedUnrealizedTemporary
ValueGainsLossesImpairmentsValueGainsLossesImpairments
(in millions)
Cash and Cash Equivalents$26.2 $ $ $ $16.8 $ $ $ 
Fixed Income Securities:
United States Government1,370.5 42.0 (0.1)(22.5)1,273.0 28.6 (3.9)(33.2)
Corporate Debt215.6 7.3 (1.8)3.0 132.1 4.8 (5.2)(8.6)
State and Local Government1.7    1.7    
Subtotal Fixed Income Securities1,587.8 49.3 (1.9)(19.5)1,406.8 33.4 (9.1)(41.8)
Equity Securities - Domestic2,811.8 2,271.0 (0.3) 2,436.6 1,869.5 (0.9) 
Spent Nuclear Fuel and Decommissioning Trusts$4,425.8 $2,320.3 $(2.2)$(19.5)$3,860.2 $1,902.9 $(10.0)$(41.8)

155


The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended September 30,Nine Months Ended September 30,
 2024202320242023
 (in millions)
Proceeds from Investment Sales$1,181.9 $933.0 $2,336.0 $2,139.3 
Purchases of Investments1,201.9 949.5 2,389.0 2,182.8 
Gross Realized Gains on Investment Sales108.4 36.8 118.7 91.6 
Gross Realized Losses on Investment Sales0.7 7.7 6.1 20.0 

The base cost of fixed income securities was $1.5 billion and $1.4 billion as of September 30, 2024 and December 31, 2023, respectively.  The base cost of equity securities was $541 million and $568 million as of September 30, 2024 and December 31, 2023, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2024 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year$401.2 
After 1 year through 5 years600.8 
After 5 years through 10 years249.7 
After 10 years336.1 
Total$1,587.8 

156


Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$53.4 $ $ $ $53.4 
Other Cash Deposits (a)   17.0 17.0 
Fixed Income Securities – Mutual Funds164.6    164.6 
Equity Securities – Mutual Funds (b)47.0    47.0 
Total Other Temporary Investments and Restricted Cash265.0   17.0 282.0 
Risk Management Assets
Risk Management Commodity Contracts (c) (d)3.9 571.5 307.2 (484.1)398.5 
Cash Flow Hedges:
Commodity Hedges (c) 83.9 20.1 (7.5)96.5 
Interest Rate Hedges     
Total Risk Management Assets3.9 655.4 327.3 (491.6)495.0 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)15.6   10.6 26.2 
Fixed Income Securities:
United States Government 1,370.5   1,370.5 
Corporate Debt 215.6   215.6 
State and Local Government 1.7   1.7 
Subtotal Fixed Income Securities 1,587.8   1,587.8 
Equity Securities – Domestic (b)2,811.8    2,811.8 
Total Spent Nuclear Fuel and Decommissioning Trusts2,827.4 1,587.8  10.6 4,425.8 
Total Assets$3,096.3 $2,243.2 $327.3 $(464.0)$5,202.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)$7.5 $574.8 $133.6 $(456.5)$259.4 
Cash Flow Hedges:
Commodity Hedges (c) 8.5 0.6 (7.5)1.6 
Interest Rate Hedges 10.9   10.9 
Fair Value Hedges 81.7   81.7 
Total Risk Management Liabilities$7.5 $675.9 $134.2 $(464.0)$353.6 
157



Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$48.9 $ $ $ $48.9 
Other Cash Deposits (a)   13.9 13.9 
Fixed Income Securities – Mutual Funds159.7    159.7 
Equity Securities – Mutual Funds (b)40.7    40.7 
Total Other Temporary Investments and Restricted Cash249.3   13.9 263.2 
Risk Management Assets
Risk Management Commodity Contracts (c) (f)9.7 736.9 274.3 (617.0)403.9 
Cash Flow Hedges:
Commodity Hedges (c) 123.5 19.8 (8.5)134.8 
Total Risk Management Assets9.7 860.4 294.1 (625.5)538.7 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)7.8   9.0 16.8 
Fixed Income Securities:
United States Government 1,273.0   1,273.0 
Corporate Debt 132.1   132.1 
State and Local Government 1.7   1.7 
Subtotal Fixed Income Securities 1,406.8   1,406.8 
Equity Securities – Domestic (b)2,436.6    2,436.6 
Total Spent Nuclear Fuel and Decommissioning Trusts2,444.4 1,406.8  9.0 3,860.2 
Total Assets$2,703.4 $2,267.2 $294.1 $(602.6)$4,662.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)$24.7 $783.8 $154.1 $(600.3)$362.3 
Cash Flow Hedges:
Commodity Hedges (c) 9.6 0.6 (8.5)1.7 
Interest Rate Hedges 9.0   9.0 
Fair Value Hedges 98.4   98.4 
Total Risk Management Liabilities$24.7 $900.8 $154.7 $(608.8)$471.4 

158


AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$45.1 $ $ $ $45.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $(0.6)$ $0.6 $ 

December 31, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$34.0 $ $ $ $34.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $0.2 $ $(0.2)$ 
Cash Flow Hedges:
Interest Rate Hedges 2.7   2.7 
Total Risk Management Liabilities$ $2.9 $ $(0.2)$2.7 

159


APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$8.3 $ $ $ $8.3 
Risk Management Assets
Risk Management Commodity Contracts (c) 7.3 47.5 (7.7)47.1 
Total Assets$8.3 $7.3 $47.5 $(7.7)$55.4 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $21.9 $0.3 $(8.7)$13.5 



December 31, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$14.9 $ $ $ $14.9 
Risk Management Assets
Risk Management Commodity Contracts (c) 1.1 23.5 (2.2)22.4 
Total Assets$14.9 $1.1 $23.5 $(2.2)$37.3 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $24.0 $1.1 $(2.6)$22.5 

160


I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$ $12.7 $10.0 $(1.0)$21.7 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)15.6   10.6 26.2 
Fixed Income Securities:
United States Government 1,370.5   1,370.5 
Corporate Debt 215.6   215.6 
State and Local Government 1.7   1.7 
Subtotal Fixed Income Securities 1,587.8   1,587.8 
Equity Securities - Domestic (b)2,811.8    2,811.8 
Total Spent Nuclear Fuel and Decommissioning Trusts2,827.4 1,587.8  10.6 4,425.8 
Total Assets$2,827.4 $1,600.5 $10.0 $9.6 $4,447.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $0.9 $0.7 $(1.2)$0.4 

December 31, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$ $37.4 $4.5 $(2.3)$39.6 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)7.8   9.0 16.8 
Fixed Income Securities:
United States Government 1,273.0   1,273.0 
Corporate Debt 132.1   132.1 
State and Local Government 1.7   1.7 
Subtotal Fixed Income Securities 1,406.8   1,406.8 
Equity Securities - Domestic (b)2,436.6    2,436.6 
Total Spent Nuclear Fuel and Decommissioning Trusts2,444.4 1,406.8  9.0 3,860.2 
Total Assets$2,444.4 $1,444.2 $4.5 $6.7 $3,899.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $3.7 $1.7 $(3.4)$2.0 
161


OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Liabilities:(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $0.4 $51.6 $(0.4)$51.6 

December 31, 2023
Level 1Level 2Level 3OtherTotal
Liabilities:(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $0.2 $50.6 $(0.1)$50.7 

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$ $0.6 $28.6 $(0.7)$28.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $12.2 $0.2 $10.0 $22.4 
Cash Flow Hedges:
Commodity Hedges (c)   (10.9)(10.9)
Interest Rate Hedges 10.9   10.9 
Total Risk Management Liabilities$ $23.1 $0.2 $(0.9)$22.4 

December 31, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$ $ $19.7 $(0.7)$19.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $29.6 $1.1 $(0.8)$29.9 
162


SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2024
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$ $0.3 $24.3 $(0.5)$24.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $5.0 $0.6 $(0.8)$4.8 

December 31, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)$ $0.5 $12.0 $(0.9)$11.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$ $15.7 $0.9 $(1.0)$15.6 

(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’
(d)The September 30, 2024 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(1) million in 2024 and $(2) million in periods 2025-2027; Level 2 matures $(23) million in 2024, $15 million in periods 2025-2027 and $5 million in periods 2028-2029; Level 3 matures $45 million in 2024, $129 million in periods 2025-2027, $17 million in periods 2028-2029 and $(18) million in periods 2030-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2023 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(11) million in 2024 and $(4) million in 2025-2027; Level 2 matures $(99) million in 2024, $(44) million in periods 2025-2027, $7 million in periods 2028-2029 and $2 million in periods 2030-2033; Level 3 matures $74 million in 2024, $43 million in periods 2025-2027, $18 million in periods 2028-2029 and $(16) million in periods 2030-2033.  Risk management commodity contracts are substantially comprised of power contracts.

163


The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30, 2024AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2024$288.2 $67.8 $14.5 $(43.2)$49.4 $38.1 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
60.4 13.4 2.9 (0.1)23.2 21.2 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(6.9)     
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
(0.1)     
Settlements(133.1)(26.9)(7.9)1.0 (46.3)(37.7)
Transfers into Level 3 (d) (e)(0.3)     
Transfers out of Level 3 (e)(0.6)     
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
(14.5)(7.1)(0.2)(9.3)2.1 2.1 
Balance as of September 30, 2024$193.1 $47.2 $9.3 $(51.6)$28.4 $23.7 

Three Months Ended September 30, 2023AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2023$126.1 $39.4 $6.8 $(54.0)$43.1 $26.0 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
39.7 10.0 2.3  14.2 14.0 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
72.7      
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
4.9      
Settlements(87.1)(16.5)(3.7)1.1 (30.5)(24.8)
Transfers out of Level 3 (e)6.6 0.1 (0.1)   
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
19.9 12.1 1.3 1.3 0.4 1.3 
Balance as of September 30, 2023$182.8 $45.1 $6.6 $(51.6)$27.2 $16.5 
Nine Months Ended September 30, 2024AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2023$139.4 $22.4 $2.8 $(50.6)$18.6 $11.1 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
90.6 24.1 7.3 (0.9)26.2 23.6 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
2.3      
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)1.5      
Settlements(164.7)(46.5)(10.0)6.0 (44.8)(36.0)
Transfers into Level 3 (d) (e)6.8      
Transfers out of Level 3 (e)2.2     0.5 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
115.0 47.2 9.2 (6.1)28.4 24.5 
Balance as of September 30, 2024$193.1 $47.2 $9.3 $(51.6)$28.4 $23.7 
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Nine Months Ended September 30, 2023AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2022$160.4 $69.1 $4.6 $(40.0)$23.7 $14.2 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
(41.3)(47.0)(1.7)(2.4)3.5 5.9 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
67.7      
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
(10.5)     
Settlements(85.9)(22.1)(2.9)3.5 (27.2)(20.0)
Transfers into Level 3 (d) (e)(6.1)     
Transfers out of Level 3 (e)3.8      
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
94.7 45.1 6.6 (12.7)27.2 16.4 
Balance as of September 30, 2023$182.8 $45.1 $6.6 $(51.6)$27.2 $16.5 
(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.
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The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

Significant Unobservable Inputs
September 30, 2024
SignificantInput/Range
Type ofFair ValueValuationUnobservableWeighted
CompanyInputAssetsLiabilitiesTechniqueInputLowHighAverage (a)
(in millions)
AEPEnergy Contracts$199.9 $130.4 Discounted Cash FlowForward Market Price (b)$0.46 $121.80 $45.50 
AEPFTRs127.4 3.8 Discounted Cash FlowForward Market Price (b)(41.91)24.96 0.20 
APCoFTRs47.5 0.3 Discounted Cash FlowForward Market Price (b)(0.06)9.63 1.30 
I&MFTRs10.0 0.7 Discounted Cash FlowForward Market Price (b)(5.00)9.63 1.21 
OPCoEnergy Contracts 51.6 Discounted Cash FlowForward Market Price (b)19.94 68.22 41.34 
PSOFTRs28.6 0.2 Discounted Cash FlowForward Market Price (b)(41.91)5.93 (3.82)
SWEPCoFTRs24.3 0.6 Discounted Cash FlowForward Market Price (b)(41.91)5.93 (3.82)

December 31, 2023
SignificantInput/Range
Type ofFair ValueValuationUnobservableWeighted
CompanyInputAssetsLiabilitiesTechniqueInputLowHighAverage (a)
(in millions)
AEPEnergy Contracts$225.5 $144.9 Discounted Cash FlowForward Market Price (b)$5.21 $153.77 $45.05 
AEPNatural Gas Contracts 0.5 Discounted Cash FlowForward Market Price (c)3.11 3.11 3.11 
AEPFTRs68.6 9.3 Discounted Cash FlowForward Market Price (b)(25.45)17.07  
APCoFTRs23.5 1.1 Discounted Cash FlowForward Market Price (b)(1.04)6.45 1.36 
I&MFTRs4.5 1.7 Discounted Cash FlowForward Market Price (b)(1.48)8.40 0.85 
OPCoEnergy Contracts 50.6 Discounted Cash FlowForward Market Price (b)22.92 67.53 42.85 
PSOFTRs19.7 1.1 Discounted Cash FlowForward Market Price (b)(25.45)4.80 (4.33)
SWEPCoNatural Gas Contracts 0.5 Discounted Cash FlowForward Market Price (c)3.11 3.11 3.11 
SWEPCoFTRs12.0 0.4 Discounted Cash FlowForward Market Price (b)(25.45)4.80 (4.33)
(a)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.
(b)Represents market prices in dollars per MWh.
(c)Represents market prices in dollars per MMBtu.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of September 30, 2024 and December 31, 2023:
Significant Unobservable InputPositionChange in InputImpact on Fair Value Measurement
Forward Market PriceBuyIncrease (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)
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11.  INCOME TAXES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2024 and 2023, adjusted for tax expense associated with certain discrete items. In the first quarter of 2024, I&M, PSO, and SWEPCo recorded tax benefits of $61 million, $49 million and $114 million, respectively, related to the reduction of a regulatory liability associated with the PLRs received from the IRS. In the third quarter of 2024, I&M recorded a $61 million tax benefit related to Nuclear PTCs. The actual Nuclear PTC realized by AEP and I&M in 2024 could vary significantly based on annual generation, and/or the U.S. Treasury guidance, particularly computational guidance on gross receipts. These items are the primary drivers of the interim ETR resulting in AEP’s year to date tax rate of (4.4)% as shown below.

The ETR for each of the Registrants are included in the following tables:

Three Months Ended September 30, 2024
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net0.6 %0.3 %2.5 %1.4 %0.7 %1.1 % %(2.6)%
Tax Reform Excess ADIT Reversal
(2.8)%(1.0)%0.2 %(2.3)%(7.9)%(7.3)%(5.0)%(3.2)%
Production and Investment Tax Credits
(9.9)% % %(0.1)%(45.6)% %(61.9)%(23.4)%
Reversal of Origination Flow-Through0.1 %0.1 %0.3 %(1.1)%0.3 %0.7 %0.3 %0.6 %
AFUDC Equity(1.5)%(2.3)%(1.9)%(1.5)%(1.2)%(1.2)%(1.3)%(0.5)%
Discrete Tax Adjustments
(3.7)% % % % % % % %
Other
 %0.2 %(0.2)%(0.4)% %0.6 %1.5 % %
Effective Income Tax Rate3.8 %18.3 %21.9 %17.0 %(32.7)%14.9 %(45.4)%(8.1)%

Three Months Ended September 30, 2023
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net1.4 %0.5 %2.8 %2.2 %2.1 %0.8 %3.0 %(4.3)%
Tax Reform Excess ADIT Reversal(5.7)%(1.3)%(0.2)%(5.3)%(8.5)%(6.8)%(17.0)%(6.2)%
Production and Investment Tax Credits
(5.1)%0.1 % %(0.1)%(0.7)% %(46.9)%(25.5)%
Reversal of Origination Flow-Through0.1 %0.2 %0.3 %1.8 %0.7 %0.8 %0.3 %(0.2)%
AFUDC Equity(1.4)%(1.4)%(2.4)%(1.5)%(0.5)%(0.8)%(1.6)%(0.8)%
Discrete Tax Adjustments(4.1)% % % % % % % %
Other
0.1 %(0.5)%(1.0)%0.7 %(3.5)%1.3 %(0.2)%0.2 %
Effective Income Tax Rate6.3 %18.6 %20.5 %18.8 %10.6 %16.3 %(41.4)%(15.8)%

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Nine Months Ended September 30, 2024
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net1.2 %0.4 %2.5 %2.1 %1.5 %0.9 % %(2.6)%
Tax Reform Excess ADIT Reversal
(3.1)%(1.1)%0.2 %(7.1)%(5.7)%(8.7)%(4.3)%(4.2)%
Remeasurement of Excess ADIT(11.9)%1.5 % % %(27.5)% %(40.5)%(181.8)%
Production and Investment Tax Credits
(8.3)%(0.1)% %(0.1)%(23.4)% %(61.7)%(79.1)%
Reversal of Origination Flow-Through0.2 %0.1 %0.3 %(0.8)%0.3 %0.8 %0.3 %2.1 %
AFUDC Equity(1.6)%(1.7)%(2.0)%(1.1)%(1.1)%(1.3)%(1.3)%(2.3)%
Discrete Tax Adjustments
(2.1)% % % % % %1.2 %1.1 %
Other
0.2 % %(0.1)%(0.1)% %0.4 % %(0.5)%
Effective Income Tax Rate(4.4)%20.1 %21.9 %13.9 %(34.9)%13.1 %(85.3)%(246.3)%

Nine Months Ended September 30, 2023
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State and Local Income Taxes, Net1.7 %0.5 %2.7 %2.4 %2.3 %0.9 %2.8 %(2.9)%
Tax Reform Excess ADIT Reversal
(6.0)%(1.3)%0.1 %(4.8)%(7.6)%(7.3)%(17.1)%(5.3)%
Production and Investment Tax Credits
(7.4)% % %(0.1)%(0.6)% %(48.9)%(26.7)%
Reversal of Origination Flow-Through(0.2)%0.2 %0.3 %0.1 %(1.7)%0.8 %0.3 %(0.3)%
AFUDC Equity(1.4)%(1.2)%(2.0)%(1.2)%(0.4)%(0.8)%(1.5)%(0.5)%
Discrete Tax Adjustments(2.8)% % %1.5 %0.7 % % % %
Other
0.3 %(0.2)%(0.5)%0.4 %(1.2)%0.5 %(0.2)%0.2 %
Effective Income Tax Rate5.2 %19.0 %21.6 %19.3 %12.5 %15.1 %(43.6)%(14.5)%

Federal and State Income Tax Audit Status

The statute of limitations (“SOL”) for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In July 2024, the Congressional Joint Committee on Taxation (“JCT”) completed its review of the results of the 2017-2020 IRS Audit and agreed to them. AEP received the associated tax refund and interest payment in September 2024.

This IRS audit and associated refund claim resulted from a net operating loss carryback to 2015 that originated in the 2017 return. AEP agreed to extend the SOL on the 2017-2020 tax returns to May 31, 2025, to allow the JCT adequate time to complete its review. However, AEP has IRS confirmation that tax years 2017-2020 are now effectively closed as they only remain open for changes to other non-consolidated entities that AEP holds an interest in.

AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. Generally, the SOL have expired for tax years prior to 2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

Federal Legislation

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022, or IRA. Most notably this budget reconciliation legislation created a 15% minimum tax on adjusted financial statement income (CAMT), extended and increased the value of PTCs and ITCs, added a nuclear and clean hydrogen PTC, an energy storage ITC and allowed the sale or transfer of tax credits to third-parties for cash. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.
168


In September 2024, Treasury and the IRS issued proposed regulations on the application of CAMT. AEP and subsidiaries are subject to the CAMT and are expected to incur a liability in 2024. However, any CAMT cash taxes incurred are expected to be partially offset by regulatory recovery, the utilization of tax credits and additionally the cash inflow generated by the sale of tax credits. The sale of tax credits are presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP presents the loss on sale of tax credits through income tax expense.

In April 2024, the IRS issued final regulations related to the transfer of tax credits. In 2023, AEP, on behalf of PSO, SWEPCo and AEP Energy Supply LLC, entered into transferability agreements with nonaffiliated parties to sell 2023 generated PTCs resulting in cash proceeds of approximately $174 million with $102 million received in 2023, $62 million received in the first quarter of 2024 and the remaining $10 million was received in the second quarter of 2024. In the third quarter of 2024, AEP, on behalf of PSO, SWEPCo and APCo, entered into transferability agreements with nonaffiliated parties to sell 2024 generated PTCs which will result in approximately $137 million of cash proceeds, of which approximately $91 million was received in the third quarter of 2024 and the remaining $46 million is expected to be received in the fourth quarter of 2024 and the first quarter of 2025. AEP expects to continue to explore the ability to efficiently monetize its tax credits through third-party transferability agreements.

I&M’s Cook Plant qualifies for the transferable Nuclear PTC, which is available for tax years beginning in 2024 through 2032. The Nuclear PTC is calculated based on electricity generated and sold to third-parties and is subject to a “reduction amount” as the facility’s gross receipts increase above a certain threshold. In the third quarter of 2024, AEP and I&M have included $64 million of estimated Nuclear PTCs within their annualized ETR. Absent specific IRS guidance, AEP and I&M’s estimated 2024 Nuclear PTC was calculated using estimated 2024 gross receipts and forecasted annual generation for the Cook Plant. If, and when, IRS guidance is eventually issued, the value of the estimated Nuclear PTC will be updated to reflect such guidance, if necessary.
169


12.  FINANCING ACTIVITIES

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Common Stock (Applies to AEP)

At-the-Market (ATM) Program

In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1.7 billion of its common stock through an ATM program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. For the nine months ended September 30, 2024, AEP issued 4,437,136 shares of common stock and received net cash proceeds of $397 million under the ATM program. As of September 30, 2024, approximately $1.3 billion of equity is available for issuance under the ATM program.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:
Type of DebtSeptember 30, 2024December 31, 2023
 (in millions)
Senior Unsecured Notes$35,771.2 $33,779.4 
Pollution Control Bonds1,770.4 1,771.6 
Notes Payable644.3 193.3 
Securitization Bonds285.7 368.9 
Spent Nuclear Fuel Obligation (a)312.7 300.4 
Junior Subordinated Notes2,578.0 2,388.1 
Other Long-term Debt612.1 1,341.5 
Total Long-term Debt Outstanding41,974.4 40,143.2 
Long-term Debt Due Within One Year2,826.7 2,490.5 
Long-term Debt$39,147.7 $37,652.7 

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $366 million and $348 million as of September 30, 2024 and December 31, 2023, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.


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Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2024 are shown in the following tables:
PrincipalInterest
CompanyType of DebtAmount (a)RateDue Date
Issuances: (in millions)(%)
AEPJunior Subordinated Notes$600.0 6.952054
AEPJunior Subordinated Notes400.0 7.052054
AEPTCoSenior Unsecured Notes450.0 5.152034
AEP TexasSenior Unsecured Notes500.0 5.452029
AEP TexasSenior Unsecured Notes350.0 5.702034
APCoPollution Control Bonds86.0 3.382028
APCoSenior Unsecured Notes400.0 5.652034
I&MNotes Payable80.4 6.412028
OPCoSenior Unsecured Notes350.0 5.652034
Non-Registrant:
AEGCoOther Long-term Debt70.0 Variable2025
Transource EnergyOther Long-term Debt50.0 Variable2025
WPCoNotes Payable450.0 6.892034
Total Issuances$3,786.4 

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

171


PrincipalInterest
CompanyType of DebtAmount PaidRateDue Date
Retirements and Principal Payments:
(in millions)(%)
AEPJunior Subordinated Debt$805.0 2.032024
AEP TexasOther Long-term Debt200.0 Variable2025
AEP TexasSecuritization Bonds32.6 2.852024
AEP TexasSecuritization Bonds23.9 2.062025
APCoOther Long-term Debt300.0 Variable2024
APCoOther Long-term Debt0.1 13.722026
APCoPollution Control Bonds86.0 2.552024
APCoSecuritization Bonds27.4 3.772028
I&MNotes Payable1.7 Variable2024
I&MNotes Payable7.4 0.932025
I&MNotes Payable2.9 Variable2025
I&MNotes Payable15.2 3.442026
I&MNotes Payable15.1 5.932027
I&MNotes Payable20.6 6.012028
I&MNotes Payable11.4 6.412028
I&MOther Long-term Debt1.8 6.002025
PSOOther Long-term Debt0.4 3.002027
Non-Registrant:
AEGCoNotes Payable5.0 2.432028
AEGCoOther Long-term Debt80.0 Variable2024
KPCoSenior Unsecured Notes65.0 3.132024
Transource EnergySenior Unsecured Notes1.4 2.752050
Transource EnergySenior Unsecured Notes1.2 2.752050
WPCoNotes Payable265.0 Variable2024
Total Retirements and Principal Payments
$1,969.1 

Long-term Debt Subsequent Events

In October 2024, I&M retired $9 million of Notes Payable related to DCC Fuel.

In October 2024, Transource Energy issued $2 million of variable rate Other Long-term Debt due in 2025.

Debt Covenants (Applies to AEP and AEPTCo)

Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.3% of consolidated tangible net assets as of September 30, 2024. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.

Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. 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.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M.
172


Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.
The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP must 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 the credit agreements.

Corporate Borrowing Program (Applies to all Registrant Subsidiaries)

AEP subsidiaries use a corporate borrowing program to meet their short-term borrowing needs. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2024 and December 31, 2023 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the nine months ended September 30, 2024 are described in the following table:
MaximumAverageNet Loans to
BorrowingsMaximumBorrowingsAverage(Borrowings from)Authorized
from theLoans to thefrom theLoans to thethe Utility MoneyShort-term
UtilityUtilityUtilityUtilityPool as ofBorrowing
CompanyMoney PoolMoney PoolMoney PoolMoney PoolSeptember 30, 2024Limit
 (in millions)
AEP Texas$374.6 $274.3 $237.0 $203.1 $54.7 $600.0 
AEPTCo313.3 332.0 75.7 159.2 152.6 820.0 (a)
APCo399.5 132.3 110.2 32.6 18.0 750.0 
I&M126.9 8.4 53.3 3.9 (77.0)500.0 
OPCo310.0 159.9 180.5 75.9 97.4 600.0 
PSO302.2  184.0  (98.5)750.0 
SWEPCo362.2  243.2  (237.4)750.0 

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2024 and December 31, 2023 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2024 is described in the following table:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
CompanyMoney PoolMoney PoolSeptember 30, 2024
(in millions)
AEP Texas$7.1 $7.0 $7.1 
SWEPCo2.8 2.6 2.8 

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AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of borrowings from AEP as of September 30, 2024 and December 31, 2023 are included in Advances from Affiliates on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 2024 are described in the following table:
BorrowingsAuthorized
MaximumMaximumAverageAveragefrom AEPLoans toShort-term
BorrowingsLoansBorrowingsLoansas of AEP as ofBorrowing
Companyfrom AEP to AEP from AEP to AEP September 30,September 30,Limit (a)
(in millions)
AEPTCo Parent$49.4 $148.5 $15.3 $69.8 $11.8 $ $ 
AEP SWTCo$1.9 $ $1.8 $ $1.8 $ $50.0 

(a)    Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:
 Nine Months Ended September 30,
20242023
Maximum Interest Rate5.79 %5.81 %
Minimum Interest Rate5.14 %4.66 %

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table:
Average Interest Rate for FundsAverage Interest Rate for Funds
Borrowed from the Utility Money PoolLoaned to the Utility Money Pool
for Nine Months Ended September 30,for Nine Months Ended September 30,
Company2024202320242023
AEP Texas5.69 %5.44 %5.48 %5.70 %
AEPTCo5.68 %5.29 %5.58 %5.52 %
APCo5.72 %5.47 %5.51 %5.47 %
I&M5.64 %5.13 %5.44 %5.54 %
OPCo5.70 %5.37 %5.49 %5.60 %
PSO5.59 %5.48 % %5.24 %
SWEPCo5.58 %5.25 % %5.72 %

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
Nine Months Ended September 30, 2024Nine Months Ended September 30, 2023
  Maximum Minimum AverageMaximum Minimum Average
  Interest Rate Interest Rate Interest RateInterest Rate Interest Rate Interest Rate
  for Funds for Funds for Fundsfor Funds for Funds for Funds
 Loaned to Loaned to Loaned toLoaned to Loaned to Loaned to
 the Nonutility the Nonutility the Nonutilitythe Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money PoolMoney Pool Money Pool Money Pool
AEP Texas 5.79 %5.25 %5.64 %5.81 %4.66 %5.47 %
SWEPCo 5.79 %5.25 %5.64 %5.81 %4.66 %5.49 %

174


AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

 MaximumMinimumMaximumMinimumAverageAverage
 Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate
Nine Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
Ended BorrowedBorrowedLoanedLoanedBorrowedLoaned
September 30, from AEP from AEPto AEP to AEP from AEP to AEP
2024 5.79 %5.25 %5.79 %5.25 %5.66 %5.63 %
2023 5.81 %4.53 %5.81 %4.53 %5.43 %5.46 %

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:
 September 30, 2024December 31, 2023
OutstandingInterestOutstandingInterest
CompanyType of DebtAmountRate (a)AmountRate (a)
 (dollars in millions)
AEPSecuritized Debt for Receivables (b)$900.0 5.32 %$888.0 5.65 %
AEPCommercial Paper755.0 5.26 %1,937.9 5.69 %
SWEPCoNotes Payable4.6 7.20 %4.3 7.71 %
Total Short-term Debt$1,659.6  $2,830.2  

(a)Weighted-average rate as of September 30, 2024 and December 31, 2023, respectively.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

For’ a discussion of credit facilities, see “Letters of Credit” section of Note 5.

Securitized Accounts Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2026. As of September 30, 2024, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Accounts receivable information for AEP Credit was as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2024202320242023
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable
5.50 %5.55 %5.54 %5.23 %
Net Uncollectible Accounts Receivable Written-Off$8.4 $8.8 $22.3 $22.9 

September 30, 2024December 31, 2023
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
$1,285.4 $1,207.4 
Short-term – Securitized Debt of Receivables900.0 888.0 
Delinquent Securitized Accounts Receivable 66.4 52.2 
Bad Debt Reserves Related to Securitization44.9 42.0 
Unbilled Receivables Related to Securitization327.4 409.8 

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
175


Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:

CompanySeptember 30, 2024December 31, 2023
 (in millions)
APCo$178.5 $184.6 
I&M183.6 156.4 
OPCo517.2 541.7 
PSO192.2 134.6 
SWEPCo189.2 168.3 

The fees paid to AEP Credit for customer accounts receivable sold were:

 Three Months Ended September 30,Nine Months Ended September 30,
Company2024202320242023
 (in millions)
APCo$4.0 $4.1 $12.1 $13.3 
I&M4.1 4.4 12.0 12.2 
OPCo7.5 7.4 22.3 22.3 
PSO4.1 4.6 10.9 11.3 
SWEPCo4.4 5.2 13.5 13.9 

The proceeds on the sale of receivables to AEP Credit were:

 Three Months Ended September 30,Nine Months Ended September 30,
Company2024202320242023
(in millions)
APCo$504.6 $451.6 $1,487.9 $1,372.7 
I&M576.7 553.3 1,608.5 1,575.9 
OPCo860.0 850.3 2,477.2 2,518.6 
PSO611.5 633.8 1,398.1 1,510.3 
SWEPCo531.4 558.4 1,428.7 1,456.5 

176


13.  VOLUNTARY SEVERANCE PROGRAM

In April 2024, management announced a voluntary severance program designed to achieve a reduction in the size of AEP’s workforce. Approximately 7,400 of AEP’s 16,800 employees were eligible to participate in the program. Approximately 1,000 employees chose to take the voluntary severance package and substantially all terminated employment in July 2024. The severance program provides two weeks of base pay for every year of service with a minimum of four weeks and a maximum of 52 weeks of base pay. Certain positions impacted by the voluntary severance program have been and will continue to be refilled to maintain safe, effective and efficient operations. Net savings from the program will help offset increasing operating expenses and high interest costs in order to keep electricity costs affordable for customers.

AEP recorded a charge to expense in the second quarter of 2024 related to this voluntary severance program.

AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Severance Expense Incurred$122.0 $19.8 $10.7 $26.5 $14.8 $14.8 $10.1 $16.9 
Settled/Adjustments111.0 19.5 10.7 24.7 14.3 14.4 9.8 15.9 
Remaining Balance as of September 30, 2024
$11.0 $0.3 $ $1.8 $0.5 $0.4 $0.3 $1.0 

These expenses were primarily included in Other Operation and Maintenance on the statements of income and Other Current Liabilities on the balance sheets. The voluntary severance program has not triggered any material curtailment or settlement accounting considerations under the accounting guidance for “Compensation - Retirement Benefits”.

AEP continues to monitor settlements under the qualified pension plan and will assess if the threshold of $306 million is reached in the fourth quarter of 2024. In the event the settlement threshold is reached during 2024, settlement accounting would result in a plan remeasurement and approximately $75 million to $100 million of the net actuarial loss to be recognized in AEP’s Statement of Income. If the settlement threshold is reached, AEP expects to seek recovery for the portion of the loss related to regulated operations.
177


14. VARIABLE INTEREST ENTITIES

The disclosures in this note apply to AEP unless indicated otherwise.

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting.

Consolidated Variable Interest Entities

The Annual Report on Form 10-K for the year ended December 31, 2023 includes a detailed discussion of the Registrants’ consolidated VIEs.

The balances below represent the assets and liabilities of consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.

September 30, 2024
Consolidated VIEs
SWEPCo
Sabine
I&M
DCC Fuel
AEP Texas Transition FundingAEP Texas Restoration FundingAPCo Appalachian Consumer Rate Relief FundingAEP CreditProtected
Cell
of EIS
Transource Energy
(in millions)
ASSETS
Current Assets$6.6 $93.6 $44.5 $15.9 $5.6 $1,287.0 $232.1 $35.0 
Net Property, Plant and Equipment 160.5      581.0 
Other Noncurrent Assets120.1 76.0 19.6 (a)127.8 (b)117.0 (c)11.0  4.1 
Total Assets$126.7 $330.1 $64.1 $143.7 $122.6 $1,298.0 $232.1 $620.1 
LIABILITIES AND EQUITY
Current Liabilities$23.9 $93.4 $43.2 $29.9 $29.4 $1,230.9 $58.8 $26.4 
Noncurrent Liabilities102.5 236.7 16.3 112.5 91.3 1.0 106.5 289.4 
Equity0.3  4.6 1.3 1.9 66.1 66.8 304.3 
Total Liabilities and Equity$126.7 $330.1 $64.1 $143.7 $122.6 $1,298.0 $232.1 $620.1 

(a)Includes an intercompany item eliminated in consolidation of $2 million.
(b)Includes an intercompany item eliminated in consolidation of $5 million.
(c)Includes an intercompany item eliminated in consolidation of $1 million.


178


December 31, 2023
Consolidated VIEs
SWEPCo
Sabine
I&M
DCC Fuel
AEP Texas Transition FundingAEP Texas Restoration FundingAPCo
Appalachian
Consumer
Rate Relief Funding
AEP CreditProtected
Cell
of EIS
Transource Energy
(in millions)
ASSETS
Current Assets$4.2 $81.9 $25.5 $27.5 $13.3 $1,208.8 $205.3 $36.9 
Net Property, Plant and Equipment 153.8      533.4 
Other Noncurrent Assets150.7 81.7 71.4 (a)145.6 (b)138.2 (c)9.6  5.1 
Total Assets$154.9 $317.4 $96.9 $173.1 $151.5 $1,218.4 $205.3 $575.4 
LIABILITIES AND EQUITY
Current Liabilities$19.9 $81.7 $75.5 $36.8 $29.9 $1,155.0 $49.2 $45.3 
Noncurrent Liabilities134.8 235.7 17.0 135.1 119.7 0.9 91.7 241.5 
Equity0.2  4.4 1.2 1.9 62.5 64.4 288.6 
Total Liabilities and Equity$154.9 $317.4 $96.9 $173.1 $151.5 $1,218.4 $205.3 $575.4 

(a)Includes an intercompany item eliminated in consolidation of $8 million.
(b)Includes an intercompany item eliminated in consolidation of $6 million.
(c)Includes an intercompany item eliminated in consolidation of $2 million.


Significant Variable Interests in Non-Consolidated VIEs and Significant Equity Method Investments

The Annual Report on Form 10-K for the year ended December 31, 2023 includes a detailed discussion of significant variable interests in non-consolidated VIEs and other significant equity method investments.

179


15. PROPERTY, PLANT AND EQUIPMENT

The disclosures in this note apply to all Registrants except AEPTCo.

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The table below summarizes significant changes to the Registrants ARO recorded in 2024 and should be read in conjunction with the Property, Plant and Equipment note within the 2023 Annual Report.

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 as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and incurred ARO liabilities of $602 million and revised cash flow estimates by an additional $72 million based on initial cost estimates. See the “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

The following is a reconciliation of the aggregate carrying amounts of ARO by registrant:
Company
ARO as of December 31, 2023
Accretion
Expense
Liabilities
Incurred
Liabilities
Settled
Revisions in
Cash Flow
Estimates (a)
ARO as of September 30, 2024
(in millions)
AEP(b)(c)(d)(e)(f)(g) $3,031.2 $97.2 $606.0 $(80.3)$122.9 $3,777.0 
AEP Texas (b)(e)4.5 0.2  (0.8) 3.9 
APCo (b)(e)464.0 17.6 247.1 (14.2)97.2 811.7 
I&M (b)(c)(e)2,106.0 59.1 85.7 (1.9) 2,248.9 
OPCo (b)(e)2.1 0.6 52.9 (0.1) 55.5 
PSO (b)(e)(g)84.2 4.1 33.7 (1.1) 120.9 
SWEPCo (b)(d)(e)(g) 281.6 10.8 23.8 (54.2)19.9 281.9 

(a)Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.
(b)Includes ARO related to ash disposal facilities.
(c)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $2.1 billion and $2.1 billion as of September 30, 2024 and December 31, 2023, respectively.
(d)Includes ARO related to Sabine and DHLC.
(e)Includes ARO related to asbestos removal.
(f)Includes ARO related to solar farms.
(g)Includes ARO related to wind farms.


180


16. REVENUE FROM CONTRACTS WITH CUSTOMERS

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment and Registrant Subsidiary revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Three Months Ended September 30, 2024
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,362.9 $773.7 $ $ $ $ $2,136.6 
Commercial Revenues776.1 396.5     1,172.6 
Industrial Revenues (a)692.6 123.7    (0.3)816.0 
Other Retail Revenues63.8 13.9     77.7 
Total Retail Revenues2,895.4 1,307.8    (0.3)4,202.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues 202.5   25.4  0.1 228.0 
Transmission Revenues (b)129.6 195.1 505.5   (439.4)390.8 
Renewable Generation Revenues (a)   8.7  (1.5)7.2 
Retail, Trading and Marketing Revenues (c)   529.3 (0.2)(13.8)515.3 
Total Wholesale and Competitive Retail Revenues
332.1 195.1 505.5 563.4 (0.2)(454.6)1,141.3 
Other Revenues from Contracts with Customers (d)76.2 58.9 5.8 0.8 37.6 (53.4)125.9 
Total Revenues from Contracts with Customers
3,303.7 1,561.8 511.3 564.2 37.4 (508.3)5,470.1 
Other Revenues:
Alternative Revenue Programs (a) (e)0.3 10.3 1.2   1.0 12.8 
Other Revenues (a) (f)(1.0)3.3  (65.1)0.7 (0.7)(62.8)
Total Other Revenues(0.7)13.6 1.2 (65.1)0.7 0.3 (50.0)
Total Revenues$3,303.0 $1,575.4 $512.5 $499.1 $38.1 $(508.0)$5,420.1 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $402 million. The affiliated revenue for Vertically Integrated Utilities was $51 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $14 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $34 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(f)Generation & Marketing includes economic hedge activity.
181


Three Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,326.7 $772.5 $ $ $ $ $2,099.2 
Commercial Revenues753.3 387.7     1,141.0 
Industrial Revenues699.9 138.9    (0.3)838.5 
Other Retail Revenues66.6 13.0     79.6 
Total Retail Revenues2,846.5 1,312.1    (0.3)4,158.3 
Wholesale and Competitive Retail Revenues:
Generation Revenues 174.3   31.8  (0.3)205.8 
Transmission Revenues (a)120.6 176.0 466.1   (425.1)337.6 
Renewable Generation Revenues (b)   19.8  (2.5)17.3 
Retail, Trading and Marketing Revenues (c)   510.8 0.8 (36.7)474.9 
Total Wholesale and Competitive Retail Revenues
294.9 176.0 466.1 562.4 0.8 (464.6)1,035.6 
Other Revenues from Contracts with Customers (d)61.3 58.2 4.8 0.9 55.6 (48.5)132.3 
Total Revenues from Contracts with Customers
3,202.7 1,546.3 470.9 563.3 56.4 (513.4)5,326.2 
Other Revenues:
Alternative Revenue Programs (b) (e)0.5 (5.0)5.8   5.7 7.0 
Other Revenues (b) (f)2.2 2.8  3.4 0.8 (0.7)8.5 
Total Other Revenues2.7 (2.2)5.8 3.4 0.8 5.0 15.5 
Total Revenues$3,205.4 $1,544.1 $476.7 $566.7 $57.2 $(508.4)$5,341.7 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $366 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $37 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $32 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(f)Generation & Marketing includes economic hedge activity.

182


Three Months Ended September 30, 2024
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$230.2 $ $442.6 $249.4 $543.4 $301.1 $260.1 
Commercial Revenues120.3  196.4 169.9 276.2 165.1 172.5 
Industrial Revenues (a)33.7  201.2 155.4 89.9 98.5 102.5 
Other Retail Revenues9.7  28.1 1.2 4.2 30.8 2.3 
Total Retail Revenues393.9  868.3 575.9 913.7 595.5 537.4 
Wholesale Revenues:
Generation Revenues (b)  78.7 113.5  2.1 42.7 
Transmission Revenues (c)170.6 491.9 45.6 10.4 24.5 12.0 50.0 
Total Wholesale Revenues170.6 491.9 124.3 123.9 24.5 14.1 92.7 
Other Revenues from Contracts with Customers (d)8.2 6.0 36.2 35.3 50.8 6.0 8.8 
Total Revenues from Contracts with Customers
572.7 497.9 1,028.8 735.1 989.0 615.6 638.9 
Other Revenues:
Alternative Revenue Programs (a) (e)(1.5)(0.7) (0.4)11.9 (0.2)(0.1)
Other Revenues (a)  0.1 (1.2)3.3   
Total Other Revenues(1.5)(0.7)0.1 (1.6)15.2 (0.2)(0.1)
Total Revenues$571.2 $497.2 $1,028.9 $733.5 $1,004.2 $615.4 $638.8 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $41 million primarily related to the PPA with KGPCo.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $399 million, APCo was $22 million and SWEPCo was $22 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

183


Three Months Ended September 30, 2023
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$236.2 $ $397.1 $230.7 $536.3 $310.5 $286.5 
Commercial Revenues112.4  181.3 159.2 275.3 171.9 174.9 
Industrial Revenues35.4  197.1 159.1 103.6 114.1 105.5 
Other Retail Revenues9.2  26.8 1.3 3.8 33.8 2.4 
Total Retail Revenues393.2  802.3 550.3 919.0 630.3 569.3 
Wholesale Revenues:
Generation Revenues (a)  79.4 90.2  (4.9)36.8 
Transmission Revenues (b)154.6 454.7 45.5 10.4 21.4 10.8 42.4 
Total Wholesale Revenues154.6 454.7 124.9 100.6 21.4 5.9 79.2 
Other Revenues from Contracts with Customers (c)8.8 5.0 35.2 26.2 49.2 5.4 6.0 
Total Revenues from Contracts with Customers
556.6 459.7 962.4 677.1 989.6 641.6 654.5 
Other Revenues:
Alternative Revenue Programs (d) (e)(2.0)3.0 (0.7)(2.9)(3.1)2.6 0.3 
Other Revenues (e)  0.1 2.1 3.0   
Total Other Revenues(2.0)3.0 (0.6)(0.8)(0.1)2.6 0.3 
Total Revenues$554.6 $462.7 $961.8 $676.3 $989.5 $644.2 $654.8 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $36 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $363 million, APCo was $22 million and SWEPCo was $17 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(e)Amounts include affiliated and nonaffiliated revenues.

184


Nine Months Ended September 30, 2024
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,524.2 $2,127.7 $ $ $ $ $5,651.9 
Commercial Revenues2,071.0 1,184.6     3,255.6 
Industrial Revenues (a)1,992.5 382.8    (0.6)2,374.7 
Other Retail Revenues174.9 41.5     216.4 
Total Retail Revenues7,762.6 3,736.6    (0.6)11,498.6 
Wholesale and Competitive Retail Revenues:
Generation Revenues587.4   76.5  0.1 664.0 
Transmission Revenues (b)371.5 583.2 1,490.8   (1,255.0)1,190.5 
Renewable Generation Revenues (a)   23.2  (4.3)18.9 
Retail, Trading and Marketing Revenues (c)   1,586.2 0.6 (83.7)1,503.1 
Total Wholesale and Competitive Retail Revenues958.9 583.2 1,490.8 1,685.9 0.6 (1,342.9)3,376.5 
Other Revenues from Contracts with Customers (d)183.3 148.8 20.1 3.1 153.2 (170.9)337.6 
Total Revenues from Contracts with Customers
8,904.8 4,468.6 1,510.9 1,689.0 153.8 (1,514.4)15,212.7 
Other Revenues:
Alternative Revenue Programs (a) (e)(12.5)17.7 (11.2)  (15.3)(21.3)
Other Revenues (a) (f)(22.4)15.2  (158.9)(5.2)4.9 (166.4)
Total Other Revenues(34.9)32.9 (11.2)(158.9)(5.2)(10.4)(187.7)
Total Revenues$8,869.9 $4,501.5 $1,499.7 $1,530.1 $148.6 $(1,524.8)$15,025.0 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.2 billion. The affiliated revenue for Vertically Integrated Utilities was $133 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $84 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $112 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(f)Generation & Marketing includes economic hedge activity.
185


Nine Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,459.1 $2,003.4 $ $ $ $ $5,462.5 
Commercial Revenues2,029.4 1,121.9     3,151.3 
Industrial Revenues (a)2,069.1 503.9    (0.6)2,572.4 
Other Retail Revenues182.3 37.4     219.7 
Total Retail Revenues7,739.9 3,666.6    (0.6)11,405.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues498.5   83.8  (0.2)582.1 
Transmission Revenues (b)348.8 524.3 1,372.0   (1,229.7)1,015.4 
Renewable Generation Revenues (a)   74.2  (5.7)68.5 
Retail, Trading and Marketing Revenues (c)
   1,332.2 1.7 (46.7)1,287.2 
Total Wholesale and Competitive Retail Revenues
847.3 524.3 1,372.0 1,490.2 1.7 (1,282.3)2,953.2 
Other Revenues from Contracts with Customers (d)155.8 157.1 12.7 7.7 113.6 (132.1)314.8 
Total Revenues from Contracts with Customers
8,743.0 4,348.0 1,384.7 1,497.9 115.3 (1,415.0)14,673.9 
Other Revenues:
Alternative Revenue Programs (a) (e)(7.5)(19.5)6.1   2.3 (18.6)
Other Revenues (a) (f)2.2 20.0  (272.8)4.0 (3.6)(250.2)
Total Other Revenues(5.3)0.5 6.1 (272.8)4.0 (1.3)(268.8)
Total Revenues$8,737.7 $4,348.5 $1,390.8 $1,225.1 $119.3 $(1,416.3)$14,405.1 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.1 billion. The affiliated revenue for Vertically Integrated Utilities was $125 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $47 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $87 million. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
(f)Generation & Marketing includes economic hedge activity.
186


Nine Months Ended September 30, 2024
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$562.4 $ $1,333.7 $664.7 $1,565.2 $647.1 $563.2 
Commercial Revenues346.2  571.8 465.5 838.4 398.2 413.2 
Industrial Revenues (a)103.3  603.5 456.4 279.4 269.9 269.8 
Other Retail Revenues28.7  84.3 3.8 12.9 78.2 6.6 
Total Retail Revenues1,040.6  2,593.3 1,590.4 2,695.9 1,393.4 1,252.8 
Wholesale Revenues:
Generation Revenues (b)  235.9 305.6  7.0 139.9 
Transmission Revenues (c)511.3 1,450.5 138.3 30.5 71.9 33.0 136.3 
Total Wholesale Revenues511.3 1,450.5 374.2 336.1 71.9 40.0 276.2 
Other Revenues from Contracts with
Customers (d)
27.4 20.3 71.0 92.3 121.5 30.4 26.0 
Total Revenues from Contracts with Customers1,579.3 1,470.8 3,038.5 2,018.8 2,889.3 1,463.8 1,555.0 
Other Revenues:
Alternative Revenue Program (a) (e)(2.1)(15.6)(6.6)(0.9)19.8 (1.8)(4.2)
Other Revenues (a)  0.2 (22.7)15.2   
Total Other Revenues(2.1)(15.6)(6.4)(23.6)35.0 (1.8)(4.2)
Total Revenues$1,577.2 $1,455.2 $3,032.1 $1,995.2 $2,924.3 $1,462.0 $1,550.8 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $118 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.2 billion, APCo was $65 million and SWEPCo was $50 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $59 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
187


Nine Months Ended September 30, 2023
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$511.8 $ $1,192.4 $655.5 $1,491.6 $667.9 $647.5 
Commercial Revenues310.3  516.2 439.5 811.6 412.7 472.2 
Industrial Revenues (a)109.9  575.4 467.6 394.0 320.2 320.3 
Other Retail Revenues26.2  78.2 3.8 11.2 86.3 7.6 
Total Retail Revenues958.2  2,362.2 1,566.4 2,708.4 1,487.1 1,447.6 
Wholesale Revenues:
Generation Revenues (b)  223.8 257.7  0.3 120.3 
Transmission Revenues (c)464.0 1,338.1 130.8 28.1 60.3 32.0 123.6 
Total Wholesale Revenues464.0 1,338.1 354.6 285.8 60.3 32.3 243.9 
Other Revenues from Contracts with
Customers (d)
29.2 12.8 60.0 92.6 127.9 14.9 20.9 
Total Revenues from Contracts with Customers1,451.4 1,350.9 2,776.8 1,944.8 2,896.6 1,534.3 1,712.4 
Other Revenues:
Alternative Revenue Program (a) (e)(6.1)(1.7)(0.9)(8.4)(13.5)1.6 (3.9)
Other Revenues (a)  0.1 2.1 20.1   
Total Other Revenues(6.1)(1.7)(0.8)(6.3)6.6 1.6 (3.9)
Total Revenues$1,445.3 $1,349.2 $2,776.0 $1,938.5 $2,903.2 $1,535.9 $1,708.5 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $121 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.1 billion, APCo was $64 million and SWEPCo was $43 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $52 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

Fixed Performance Obligations (Applies to AEP, APCo and I&M)

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2024. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
Company20242025-20262027-2028After 2028Total
(in millions)
AEP$23.1 $169.0 $85.4 $24.9 $302.4 
APCo4.0 32.1 26.5 11.6 74.2 
I&M1.1 8.8 8.8 4.5 23.2 


188


Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of September 30, 2024 and December 31, 2023.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of September 30, 2024 and December 31, 2023.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of September 30, 2024 and December 31, 2023. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:

AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
September 30, 2024$ $131.1 $74.0 $46.8 $66.9 $12.5 $25.7 
December 31, 2023 123.2 71.7 44.0 70.1 12.4 27.4 


189


CONTROLS AND PROCEDURES

During the third quarter of 2024, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of September 30, 2024, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 2024 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
190


PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2023 includes a detailed discussion of risk factors. As of September 30, 2024, the risk factors appearing in AEP’s 2023 Annual Report are supplemented and updated as follows:

The occurrence of one or more wildfires could cause tremendous loss, impact the market value and credit ratings of our securities and have a material adverse effect on our financial condition. (Applies to all Registrants)

更頻繁和更嚴重的乾旱條件,降水量和降水量的極端波動,植被的變化,反常的溫暖溫度,非常低的溼度,更強的風和其他因素增加了野火季節的持續時間和事件的潛在影響。AEP的基礎設施正在老化,並對安全和系統可靠性構成風險,野火緩解舉措可能無法成功或有效地預防或減少與野火相關的事件。儘管AEP採取了緩解野火的舉措,但野火可能會被點燃、蔓延並造成破壞,這將使AEP承擔重大責任。與野火相關的其他潛在風險包括無法確保足夠的保險覆蓋範圍、未投保的損失或超過當前保險覆蓋範圍的損失、保險成本增加、監管復甦風險、訴訟風險以及信用評級下調的可能性和進入資本市場的後續額外成本。

項目2. 股權證券的未登記銷售和收益的使用

沒有。

項目3. 優先證券

沒有。

項目4. 礦山安全披露

不適用。

項目5. 其他信息

截至2024年9月30日的三個月內,公司沒有任何董事或高級管理人員(定義見1934年證券交易法第16 a-1(f)條) 通過, 終止 或修改規則10 b5 -1交易安排或非規則10 b5 -1交易安排(此類術語的定義見1933年證券法第S-k條第408項)。

191


項目6. 展品

下表中標有(X)的證據是代表註冊人提交的。
展品描述AEPAEP
Texas
AEPTCoAPCOI & MOpcoPSOSWEPCO
10(a)AEPSC和William J. Fehrman之間的飛機分時協議
31(a)
根據2002年薩班斯-奧克斯利法案第302條對首席執行官進行認證
31(b)
根據2002年薩班斯-奧克斯利法案第302條對首席財務官進行認證
32(a)
根據美國法典第18篇第63章第1350條的首席執行官認證
32(b)
根據美國法典第18篇第63章第1350條對首席財務官進行認證
101.INS
XBRL實例文檔
該實例文檔不會出現在交互式數據文件中,因爲其MBE標籤嵌入在內聯MBE文檔中。
101.SCH
BEP分類擴展架構
XXXXXXXX
101.CAL
BEP分類擴展計算Linkbase
XXXXXXXX
101.DEF
DatabRL分類擴展定義Linkbase
XXXXXXXX
101.LAB
BEP分類擴展標籤Linkbase
XXXXXXXX
101.PRE
BEP分類擴展演示鏈接庫
XXXXXXXX
104
封面互動數據文件
指定爲Inline BEP幷包含在附件101中。
192


簽名


根據1934年證券交易法的要求,每位登記人均已正式促使以下正式授權的簽署人代表其簽署本報告。 每家以下籤署公司的簽名應被視爲僅與涉及該公司及其任何子公司的事項有關。


美國電力公司



作者: /s/凱特·斯特吉斯
凱特·斯特吉斯
主計長兼首席會計官
(首席會計官和授權簽署人)



AEP德克薩斯公司
AEP傳輸公司
阿巴拉契亞電力公司
印第安納密歇根電力公司
俄亥俄電力公司
俄克拉荷馬州公共服務公司
西南電力公司



作者: /s/凱特·斯特吉斯
凱特·斯特吉斯
主計長兼首席會計官
(首席會計官和授權簽署人)



日期:2024年11月6日
193