2022年11月，联邦环保局发布了一项最终决定，拒绝了Gavin Power LLC的请求，即允许Gavin Power Station的CCR地面蓄水在2021年4月11日之后继续接收CCR和非CCR废流，直到2023年5月4日(Gavin拒绝)。作为Gavin否认的一部分，联邦环保局做出了几项与CCR规则相关的断言(有关更多信息，请参阅下面的“CCR规则”部分)，包括一项断言，关闭300英亩无衬砌的飞灰库(FAR)在多个方面不符合CCR规则。Gavin发电站以前由AEP拥有和运营，并于2017年出售给Gavin Power LLC和Lightstone Generation LLC。根据PSA，AEP继续负责按照俄亥俄州环保局批准的关闭计划完成FAR的关闭，该计划于2021年7月完成。PSA包含赔偿条款，根据这些条款，Gavin发电站的所有者已通知AEP，他们认为他们有权就这些索赔可能导致的任何损害获得赔偿，包括因联邦环保局判定不遵守与Gavin否认一致的CCR规则的各个方面而导致的任何未来执法或诉讼。Gavin发电站的所有者还要求赔偿土地所有者据称因对FAR进行改造而造成的财产损失。管理部门不认为Gavin发电站的所有者根据PSA向AEP提出任何有效的赔偿或其他索赔要求。此外，Gavin Power LLC、几家AEP子公司和其他各方已向美国哥伦比亚特区巡回上诉法院提交了对Gavin否认的复审请愿书，该法院于2024年6月因缺乏管辖权而被驳回。2024年1月，Gavin Power LLC还向俄亥俄州南区美国地区法院提出申诉，指控各种违反《行政程序法》的行为，并声称联邦环保局由于先前的不作为，已经放弃并被禁止提出在Gavin否认案中提出的某些反对意见。管理层无法预测这场诉讼的结果。管理层无法确定合理可能发生的潜在损失范围。
有关正义电煤合同的诉讼
2023年12月，APCo向富兰克林县俄亥俄州普通上诉法院提起诉讼，寻求宣告性判决，确认APCo有权终止与Justice Hot LLC（Justice Hot）的长期煤炭合同，理由是Justice Hot未能履行合同。 APCo于2024年1月终止了该合同，2024年4月，APCo提交了一份修改后的投诉，要求声明终止是适当的，并要求对Justice Hot违反合同的损害赔偿。 热法官于2024年4月提出答复和反诉，对合同终止的有效性提出质疑并提出反诉。 双方签订了和解协议并解除诉讼，根据该协议，诉讼于2024年9月被驳回，但存在偏见，双方免除了对方与合同或诉讼相关的所有索赔，因此此事已得到解决。
For the Nine Months Ended September 30, 2024 and 2023
(in millions)
(Unaudited)
Nine Months Ended September 30,
2024
2023
OPERATING ACTIVITIES
Net Income
$
2,309.9
$
1,874.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization
2,461.7
2,309.4
Deferred Income Taxes
89.5
171.5
Loss on the Sale of the Competitive Contracted Renewables Portfolio
—
112.0
Asset Impairments and Other Related Charges
142.5
—
Allowance for Equity Funds Used During Construction
(153.0)
(123.4)
Mark-to-Market of Risk Management Contracts
(97.6)
(82.8)
Property Taxes
508.3
486.1
Deferred Fuel Over/Under-Recovery, Net
304.6
542.8
Change in Other Noncurrent Assets
(244.0)
(396.8)
Change in Other Noncurrent Liabilities
193.8
(21.5)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net
(131.8)
114.0
Fuel, Materials and Supplies
188.5
(344.4)
Accounts Payable
14.2
(163.0)
Accrued Taxes, Net
(532.3)
(566.7)
Other Current Assets
(139.2)
(91.5)
Other Current Liabilities
161.8
(144.8)
Net Cash Flows from Operating Activities
5,076.9
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 Securities
2,343.5
2,140.1
Acquisitions of Nuclear Fuel
(98.4)
(60.9)
Acquisitions of Renewable Energy Facilities
—
(154.0)
Proceeds from Sales of Assets
365.0
1,335.6
Proceeds from Sale of Equity Method Investment
114.0
—
Other Investing Activities
73.0
62.5
Net Cash Flows Used for Investing Activities
(4,769.5)
(4,643.5)
FINANCING ACTIVITIES
Issuance of Common Stock
513.0
959.3
Issuance of Long-term Debt
3,748.5
4,017.8
Issuance of Short-term Debt with Original Maturities greater than 90 Days
376.6
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 Period
379.0
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in millions of KWhs)
Retail:
Residential
4,116
4,681
10,174
10,295
Commercial
4,283
4,021
11,733
10,208
Industrial
3,181
3,065
9,778
9,344
Miscellaneous
189
196
496
487
Total Retail
11,769
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(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 Revenues
5.2
84.9
Transmission Revenues
16.1
47.3
Other Revenues
(4.7)
(0.3)
Total Change in Revenues
16.6
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 Taxes
3.8
11.5
Interest Income
2.6
4.2
Allowance for Equity Funds Used During Construction
2.7
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 Expenseincreased $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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
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 Construction
10.5
7.8
34.6
19.4
Non-Service Cost Components of Net Periodic Benefit Cost
3.7
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
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 Parent
100.0
100.0
Net Income
47.6
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 Parent
175.3
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 Parent
250.5
250.5
Net Income
125.5
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 Income
79.7
79.7
Other Comprehensive Income
3.9
3.9
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2024
2,079.6
2,804.8
(4.7)
4,879.7
Capital Contribution from Parent
1.6
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 Income
132.5
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 Affiliates
61.8
7.1
Accounts Receivable:
Customers
213.0
176.5
Affiliated Companies
20.4
23.8
Accrued Unbilled Revenues
116.7
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 Receivable
55.0
—
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 Leases
16.1
28.7
Accrued Litigation Settlement
55.0
—
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 Leases
45.9
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, Net
56.0
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 Activities
44.2
42.2
Net Cash Flows Used for Investing Activities
(1,052.9)
(1,175.0)
FINANCING ACTIVITIES
Capital Contribution from Parent
1.6
525.8
Return of Capital to Parent
(0.7)
(4.3)
Issuance of Long-term Debt – Nonaffiliated
841.9
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 Activities
1.4
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,
2024
2023
(in millions)
Plant In Service
$
14,720.4
$
13,638.0
Construction Work in Progress
2,188.6
1,902.1
Accumulated Depreciation and Amortization
1,509.4
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 Revenues
34.5
106.0
Total Change in Transmission Revenues
34.5
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 Income
1.5
3.6
Allowance for Equity Funds Used During Construction
1.6
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
REVENUES
Transmission Revenues
$
103.3
$
93.8
$
299.0
$
274.0
Sales to AEP Affiliates
404.4
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 Revenues
0.2
—
3.0
—
TOTAL REVENUES
497.2
462.7
1,455.2
1,349.2
EXPENSES
Other Operation
31.7
31.6
101.6
87.0
Maintenance
5.7
5.1
16.0
14.3
Depreciation and Amortization
108.2
99.6
320.8
291.2
Taxes Other Than Income Taxes
79.7
73.8
228.6
216.6
TOTAL EXPENSES
225.3
210.1
667.0
609.1
OPERATING INCOME
271.9
252.6
788.2
740.1
Other Income (Expense):
Interest Income – Affiliated
3.1
1.6
9.3
5.7
Allowance for Equity Funds Used During Construction
24.3
22.7
64.7
62.2
Interest Expense
(54.3)
(51.6)
(160.5)
(147.5)
INCOME BEFORE INCOME TAX EXPENSE
245.0
225.3
701.7
660.5
Income Tax Expense
53.7
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 Member
25.0
25.0
Dividends Paid to Member
(55.0)
(55.0)
Net Income
162.7
162.7
TOTAL MEMBER'S EQUITY – MARCH 31, 2023
3,047.3
2,958.4
6,005.7
Return of Capital to Member
(8.6)
(8.6)
Dividends Paid to Member
(30.0)
(30.0)
Net Income
175.7
175.7
TOTAL MEMBER'S EQUITY – JUNE 30, 2023
3,038.7
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 Member
25.0
25.0
Dividends Paid to Member
(40.0)
(40.0)
Net Income
181.2
181.2
TOTAL MEMBER'S EQUITY – MARCH 31, 2024
3,068.4
3,431.1
6,499.5
Capital Contribution from Member
9.6
9.6
Dividends Paid to Member
(31.0)
(31.0)
Net Income
175.7
175.7
TOTAL MEMBER'S EQUITY – JUNE 30, 2024
3,078.0
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 – Nonaffiliated
185.0
95.0
Accrued Taxes
418.9
568.6
Accrued Interest
68.4
39.6
Obligations Under Operating Leases
1.2
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 Leases
1.1
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 Capital
3,073.5
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,
2024
2023
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 – Nonaffiliated
445.7
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in millions of KWhs)
Retail:
Residential
2,568
2,481
7,918
7,527
Commercial
1,553
1,537
4,482
4,286
Industrial
2,141
2,229
6,446
6,473
Miscellaneous
203
205
617
595
Total Retail
6,465
6,452
19,463
18,881
Wholesale (a)
550
691
1,768
1,694
Total KWhs
7,015
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in degree days)
Actual – Heating (a)
—
—
1,029
928
Normal – Heating (b)
2
2
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 Revenues
65.5
244.0
Off-system Sales
(0.8)
(1.1)
Transmission Revenues
0.7
1.8
Other Revenues
1.7
11.4
Total Change in Revenues
67.1
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 Income
1.0
1.6
Allowance for Equity Funds Used During Construction
0.6
2.7
Non-Service Cost Components of Net Periodic Benefit Cost
(1.2)
(4.0)
Interest Expense
1.3
(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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
REVENUES
Electric Generation, Transmission and Distribution
$
960.6
$
896.0
$
2,836.6
$
2,573.0
Sales to AEP Affiliates
65.2
62.5
183.1
193.2
Other Revenues
3.1
3.3
12.4
9.8
TOTAL REVENUES
1,028.9
961.8
3,032.1
2,776.0
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
358.4
343.2
1,060.0
960.8
Other Operation
204.2
187.9
628.8
569.6
Maintenance
86.4
74.3
244.7
222.5
Depreciation and Amortization
149.0
143.7
444.5
424.8
Taxes Other Than Income Taxes
44.3
43.5
132.5
126.5
TOTAL EXPENSES
842.3
792.6
2,510.5
2,304.2
OPERATING INCOME
186.6
169.2
521.6
471.8
Other Income (Expense):
Interest Income
1.8
0.8
3.8
2.2
Allowance for Equity Funds Used During Construction
4.2
3.6
11.4
8.7
Non-Service Cost Components of Net Periodic Benefit Cost
6.9
8.1
20.4
24.4
Interest Expense
(67.2)
(68.5)
(203.4)
(200.7)
INCOME BEFORE INCOME TAX EXPENSE
132.3
113.2
353.8
306.4
Income Tax Expense
22.5
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,
2024
2023
2024
2023
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 Income
112.5
112.5
Other Comprehensive Loss
(1.0)
(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023
260.4
1,828.7
3,003.6
(5.8)
5,086.9
Capital Contribution from Parent
4.3
4.3
Net Income
42.9
42.9
Other Comprehensive Loss
(1.0)
(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2023
260.4
1,833.0
3,046.5
(6.8)
5,133.1
Capital Contribution from Parent
2.2
2.2
Net Income
91.9
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 Parent
100.0
100.0
Net Income
136.5
136.5
Other Comprehensive Loss
(0.5)
(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024
260.4
1,934.5
3,322.0
(4.2)
5,512.7
Capital Contribution from Parent
9.5
9.5
Net Income
58.3
58.3
Other Comprehensive Loss
(0.5)
(0.5)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024
260.4
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 Income
109.8
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,
2024
2023
CURRENT ASSETS
Cash and Cash Equivalents
$
6.5
$
5.0
Restricted Cash for Securitized Funding
8.3
14.9
Advances to Affiliates
18.9
18.9
Accounts Receivable:
Customers
183.0
170.3
Affiliated Companies
102.7
98.8
Accrued Unbilled Revenues
53.3
70.8
Miscellaneous
0.2
0.6
Allowance for Uncollectible Accounts
(2.0)
(2.0)
Total Accounts Receivable
337.2
338.5
Fuel
270.3
315.0
Materials and Supplies
130.9
148.4
Risk Management Assets
47.1
22.4
Regulatory Asset for Under-Recovered Fuel Costs
153.7
155.4
Prepayments and Other Current Assets
64.8
40.5
TOTAL CURRENT ASSETS
1,037.7
1,059.0
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation
7,245.9
7,041.3
Transmission
4,912.9
4,711.8
Distribution
5,412.0
5,176.6
Other Property, Plant and Equipment
1,046.4
981.3
Construction Work in Progress
752.5
709.2
Total Property, Plant and Equipment
19,369.7
18,620.2
Accumulated Depreciation and Amortization
5,964.9
5,688.7
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
13,404.8
12,931.5
OTHER NONCURRENT ASSETS
Regulatory Assets
1,312.4
1,155.1
Securitized Assets
113.0
133.4
Employee Benefits and Pension Assets
184.8
171.7
Operating Lease Assets
70.2
73.7
Deferred Charges and Other Noncurrent Assets
166.5
187.5
TOTAL OTHER NONCURRENT ASSETS
1,846.9
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,
2024
2023
(in millions)
CURRENT LIABILITIES
Advances from Affiliates
$
0.9
$
339.6
Accounts Payable:
General
363.3
280.4
Affiliated Companies
124.8
121.3
Long-term Debt Due Within One Year – Nonaffiliated
748.6
538.8
Risk Management Liabilities
7.6
15.9
Customer Deposits
85.5
80.0
Accrued Taxes
129.5
117.6
Accrued Interest
95.6
58.9
Obligations Under Operating Leases
13.9
14.6
Other Current Liabilities
165.3
118.8
TOTAL CURRENT LIABILITIES
1,735.0
1,685.9
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
4,910.6
5,049.5
Deferred Income Taxes
2,020.8
2,011.9
Regulatory Liabilities and Deferred Investment Tax Credits
1,100.4
1,081.9
Asset Retirement Obligations
774.3
442.5
Employee Benefits and Pension Obligations
31.6
32.8
Obligations Under Operating Leases
56.9
59.8
Deferred Credits and Other Noncurrent Liabilities
49.9
70.9
TOTAL NONCURRENT LIABILITIES
8,944.5
8,749.3
TOTAL LIABILITIES
10,679.5
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 Capital
1,939.5
1,834.5
Retained Earnings
3,415.1
3,185.5
Accumulated Other Comprehensive Income (Loss)
(5.1)
(3.7)
TOTAL COMMON SHAREHOLDER’S EQUITY
5,609.9
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,
2024
2023
OPERATING ACTIVITIES
Net Income
$
304.6
$
247.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization
444.5
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, Net
124.1
108.2
Change in Other Noncurrent Assets
(13.1)
24.4
Change in Other Noncurrent Liabilities
5.6
(29.9)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net
3.6
80.2
Fuel, Materials and Supplies
62.2
(114.0)
Accounts Payable
50.4
(129.5)
Accrued Taxes, Net
12.8
(12.4)
Other Current Assets
(24.7)
(6.5)
Other Current Liabilities
34.8
(0.6)
Net Cash Flows from Operating Activities
936.8
610.2
INVESTING ACTIVITIES
Construction Expenditures
(708.7)
(813.4)
Change in Advances to Affiliates, Net
—
0.5
Other Investing Activities
14.4
(2.9)
Net Cash Flows Used for Investing Activities
(694.3)
(815.8)
FINANCING ACTIVITIES
Capital Contribution from Parent
109.5
6.5
Return of Capital to Parent
(4.5)
—
Issuance of Long-term Debt – Nonaffiliated
480.8
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 Activities
0.3
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 Period
19.9
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 Taxes
27.4
40.3
Cash Paid (Received) for Transferable Tax Credits
(0.2)
—
Noncash Acquisitions Under Finance Leases
0.9
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in millions of KWhs)
Retail:
Residential
1,552
1,421
4,152
3,998
Commercial
1,450
1,360
4,015
3,756
Industrial
1,901
1,876
5,562
5,501
Miscellaneous
10
12
35
39
Total Retail
4,913
4,669
13,764
13,294
Wholesale (a)
1,305
1,246
4,042
4,210
Total KWhs
6,218
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in degree days)
Actual – Heating (a)
—
—
1,826
1,914
Normal – Heating (b)
6
7
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 Revenues
31.9
21.1
Off-system Sales
25.0
25.8
Transmission Revenues
2.5
10.0
Other Revenues
(2.2)
(0.2)
Total Change in Revenues
57.2
56.7
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
11.1
(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 Taxes
1.3
(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 Expense
55.1
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 expensesincreased $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 expensesincreased $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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
REVENUES
Electric Generation, Transmission and Distribution
$
714.9
$
656.1
$
1,932.3
$
1,879.3
Sales to AEP Affiliates
1.3
0.6
5.2
3.7
Other Revenues – Affiliated
15.2
15.4
50.7
45.8
Other Revenues – Nonaffiliated
2.1
4.2
7.0
9.7
TOTAL REVENUES
733.5
676.3
1,995.2
1,938.5
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
118.2
129.3
326.9
322.4
Purchased Electricity from AEP Affiliates
63.0
57.0
169.0
139.2
Other Operation
180.0
168.9
548.5
508.7
Maintenance
58.1
57.3
173.7
173.0
Asset Impairments and Other Related Charges
—
—
13.4
—
Depreciation and Amortization
132.6
116.7
359.2
352.9
Taxes Other Than Income Taxes
21.0
22.3
68.9
62.4
TOTAL EXPENSES
572.9
551.5
1,659.6
1,558.6
OPERATING INCOME
160.6
124.8
335.6
379.9
Other Income (Expense):
Other Income
3.3
4.5
9.7
8.1
Non-Service Cost Components of Net Periodic Benefit Cost
6.8
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,
2024
2023
2024
2023
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, 2023
56.6
988.8
2,034.8
(2.9)
3,077.3
Capital Contribution from Parent
0.1
0.1
Common Stock Dividends
(31.3)
(31.3)
Net Income
74.8
74.8
Other Comprehensive Loss
(0.2)
(0.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2023
56.6
988.9
2,078.3
(3.1)
3,120.7
Capital Contribution from Parent
1.6
1.6
Common Stock Dividends
(75.0)
(75.0)
Net Income
93.0
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 Income
145.0
145.0
Other Comprehensive Income
0.1
0.1
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2024
56.6
997.6
2,194.1
(0.5)
3,247.8
Capital Contribution from Parent
5.0
5.0
Common Stock Dividends
(37.5)
(37.5)
Net Income
35.2
35.2
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2024
56.6
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 Income
179.1
179.1
Other Comprehensive Income
0.1
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,
2024
2023
CURRENT ASSETS
Cash and Cash Equivalents
$
4.1
$
2.1
Accounts Receivable:
Customers
43.5
66.9
Affiliated Companies
72.6
65.0
Accrued Unbilled Revenues
29.1
0.2
Miscellaneous
4.7
8.2
Total Accounts Receivable
149.9
140.3
Fuel
71.9
88.1
Materials and Supplies
210.6
208.2
Risk Management Assets
21.7
27.8
Accrued Tax Benefits
48.2
—
Regulatory Asset for Under-Recovered Fuel Costs
12.0
14.8
Prepayments and Other Current Assets
55.2
46.7
TOTAL CURRENT ASSETS
573.6
528.0
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation
5,675.8
5,646.8
Transmission
1,951.3
1,906.4
Distribution
3,467.2
3,254.0
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)
919.4
898.5
Construction Work in Progress
360.2
301.7
Total Property, Plant and Equipment
12,373.9
12,007.4
Accumulated Depreciation, Depletion and Amortization
4,600.9
4,378.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
7,773.0
7,629.0
OTHER NONCURRENT ASSETS
Regulatory Assets
572.6
406.3
Spent Nuclear Fuel and Decommissioning Trusts
4,425.8
3,860.2
Operating Lease Assets
50.2
53.8
Deferred Charges and Other Noncurrent Assets
272.7
330.7
TOTAL OTHER NONCURRENT ASSETS
5,321.3
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,
2024
2023
CURRENT LIABILITIES
Advances from Affiliates
$
77.0
$
63.3
Accounts Payable:
General
178.9
225.8
Affiliated Companies
88.0
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 Deposits
53.5
72.2
Accrued Taxes
96.8
104.7
Accrued Interest
38.0
41.3
Obligations Under Operating Leases
13.1
16.8
Regulatory Liability for Over-Recovered Fuel Costs
6.7
23.2
Other Current Liabilities
114.2
91.9
TOTAL CURRENT LIABILITIES
950.3
830.2
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
3,233.4
3,415.7
Deferred Income Taxes
1,213.5
1,169.9
Regulatory Liabilities and Deferred Investment Tax Credits
2,544.4
2,052.3
Asset Retirement Obligations
2,243.2
2,104.3
Obligations Under Operating Leases
37.9
37.7
Deferred Credits and Other Noncurrent Liabilities
54.8
57.7
TOTAL NONCURRENT LIABILITIES
9,327.2
8,837.6
TOTAL LIABILITIES
10,277.5
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 Capital
1,000.8
997.6
Retained Earnings
2,333.4
2,086.6
Accumulated Other Comprehensive Income (Loss)
(0.4)
(0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY
3,390.4
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,
2024
2023
OPERATING ACTIVITIES
Net Income
$
359.3
$
270.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization
359.2
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 Charges
13.4
—
Allowance for Equity Funds Used During Construction
(10.1)
(6.6)
Mark-to-Market of Risk Management Contracts
16.3
(4.7)
Amortization of Nuclear Fuel
74.3
75.7
Deferred Fuel Over/Under-Recovery, Net
(13.7)
52.9
Change in Other Noncurrent Assets
24.4
3.1
Change in Other Noncurrent Liabilities
49.5
9.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net
(8.1)
82.5
Fuel, Materials and Supplies
13.8
(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 Activities
678.4
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 Securities
2,336.0
2,139.3
Acquisitions of Nuclear Fuel
(98.4)
(60.9)
Other Investing Activities
5.7
4.9
Net Cash Flows Used for Investing Activities
(580.4)
(516.1)
FINANCING ACTIVITIES
Capital Contribution from Parent
5.0
1.7
Return of Capital to Parent
(1.8)
—
Issuance of Long-term Debt – Nonaffiliated
80.4
494.8
Change in Advances from Affiliates, Net
13.7
(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 Activities
0.5
0.6
Net Cash Flows Used for Financing Activities
(96.0)
(219.8)
Net Increase (Decrease) in Cash and Cash Equivalents
2.0
(1.5)
Cash and Cash Equivalents at Beginning of Period
2.1
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 Leases
1.1
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in millions of KWhs)
Retail:
Residential
4,090
3,761
10,905
10,323
Commercial
5,388
4,553
15,138
12,503
Industrial
3,544
3,536
10,585
10,456
Miscellaneous
24
24
77
78
Total Retail (a)
13,046
11,874
36,705
33,360
Wholesale (b)
504
485
1,347
1,366
Total KWhs
13,550
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in degree days)
Actual – Heating (a)
—
—
1,573
1,521
Normal – Heating (b)
4
4
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 Revenues
3.8
6.0
Off-system Sales
(2.1)
(11.7)
Transmission Revenues
0.5
0.5
Other Revenues
12.5
26.3
Total Change in Revenues
14.7
21.1
Changes in Expenses and Other:
Purchased Electricity for Resale
61.6
278.1
Purchased Electricity from AEP Affiliates
23.9
(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 Income
0.8
0.6
Allowance for Equity Funds Used During Construction
0.8
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 Other
21.6
(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 Salesdecreased $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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
REVENUES
Electricity, Transmission and Distribution
$
995.8
$
978.7
$
2,899.0
$
2,869.3
Sales to AEP Affiliates
5.6
7.8
17.0
23.6
Other Revenues
2.8
3.0
8.3
10.3
TOTAL REVENUES
1,004.2
989.5
2,924.3
2,903.2
EXPENSES
Purchased Electricity for Resale
199.1
260.7
642.8
920.9
Purchased Electricity from AEP Affiliates
14.1
38.0
86.2
49.6
Other Operation
343.2
296.9
920.2
836.1
Maintenance
66.3
62.2
194.7
157.7
Asset Impairments and Other Related Charges
—
—
52.9
—
Depreciation and Amortization
86.1
81.3
293.9
224.7
Taxes Other Than Income Taxes
136.9
132.5
425.0
382.0
TOTAL EXPENSES
845.7
871.6
2,615.7
2,571.0
OPERATING INCOME
158.5
117.9
308.6
332.2
Other Income (Expense):
Other Income
0.9
0.1
1.0
0.4
Allowance for Equity Funds Used During Construction
6.4
5.6
16.2
11.3
Non-Service Cost Components of Net Periodic Benefit Cost
5.4
6.5
16.2
19.5
Interest Expense
(38.7)
(33.9)
(109.9)
(96.9)
INCOME BEFORE INCOME TAX EXPENSE
132.5
96.2
232.1
266.5
Income Tax Expense
19.8
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 Parent
50.0
50.0
Net Income
78.0
78.0
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023
321.2
887.8
2,007.1
3,216.1
Capital Contribution from Parent
125.0
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 Income
80.5
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 Income
70.6
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 Parent
0.8
0.8
Net Income
112.7
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,
2024
2023
CURRENT ASSETS
Cash and Cash Equivalents
$
9.6
$
6.4
Advances to Affiliates
97.4
—
Accounts Receivable:
Customers
83.0
39.2
Affiliated Companies
122.6
129.2
Miscellaneous
8.7
2.3
Total Accounts Receivable
214.3
170.7
Materials and Supplies
150.1
183.9
Prepayments and Other Current Assets
26.2
16.8
TOTAL CURRENT ASSETS
497.6
377.8
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission
3,529.9
3,395.1
Distribution
7,143.3
6,839.4
Other Property, Plant and Equipment
1,192.6
1,125.0
Construction Work in Progress
768.7
654.0
Total Property, Plant and Equipment
12,634.5
12,013.5
Accumulated Depreciation and Amortization
2,855.5
2,713.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
9,779.0
9,299.9
OTHER NONCURRENT ASSETS
Regulatory Assets
394.9
455.0
Operating Lease Assets
62.5
69.9
Deferred Charges and Other Noncurrent Assets
336.1
641.1
TOTAL OTHER NONCURRENT ASSETS
793.5
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,
2024
2023
(in millions)
CURRENT LIABILITIES
Advances from Affiliates
$
—
$
110.5
Accounts Payable:
General
312.0
320.7
Affiliated Companies
155.8
154.2
Risk Management Liabilities
6.3
6.8
Customer Deposits
68.1
62.0
Accrued Taxes
439.9
763.3
Accrued Interest
61.0
38.5
Obligations Under Operating Leases
12.6
13.5
Other Current Liabilities
145.8
144.8
TOTAL CURRENT LIABILITIES
1,201.5
1,614.3
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
3,715.0
3,366.8
Long-term Risk Management Liabilities
45.3
43.9
Deferred Income Taxes
1,179.5
1,152.7
Regulatory Liabilities and Deferred Investment Tax Credits
997.0
1,003.6
Obligations Under Operating Leases
50.3
56.7
Deferred Credits and Other Noncurrent Liabilities
107.7
34.4
TOTAL NONCURRENT LIABILITIES
6,094.8
5,658.1
TOTAL LIABILITIES
7,296.3
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 Capital
1,013.6
1,012.8
Retained Earnings
2,439.0
2,237.3
TOTAL COMMON SHAREHOLDER’S EQUITY
3,773.8
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,
2024
2023
OPERATING ACTIVITIES
Net Income
$
201.7
$
226.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization
293.9
224.7
Deferred Income Taxes
0.2
29.4
Asset Impairments and Other Related Charges
52.9
—
Allowance for Equity Funds Used During Construction
(16.2)
(11.3)
Mark-to-Market of Risk Management Contracts
0.9
11.6
Property Taxes
286.6
282.4
Change in Other Noncurrent Assets
19.2
(95.5)
Change in Other Noncurrent Liabilities
47.2
(47.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net
(39.8)
4.3
Materials and Supplies
33.8
5.3
Accounts Payable
(43.4)
1.8
Customer Deposits
6.1
(37.3)
Accrued Taxes, Net
(322.3)
(367.3)
Other Current Assets
(11.9)
(2.3)
Other Current Liabilities
17.2
0.4
Net Cash Flows from Operating Activities
526.1
224.7
INVESTING ACTIVITIES
Construction Expenditures
(688.5)
(769.0)
Change in Advances to Affiliates, Net
(97.4)
—
Other Investing Activities
29.4
33.9
Net Cash Flows Used for Investing Activities
(756.5)
(735.1)
FINANCING ACTIVITIES
Capital Contribution from Parent
0.8
175.0
Issuance of Long-term Debt – Nonaffiliated
346.3
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 Activities
1.0
1.5
Net Cash Flows from Financing Activities
233.6
507.6
Net Increase (Decrease) in Cash and Cash Equivalents
3.2
(2.8)
Cash and Cash Equivalents at Beginning of Period
6.4
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 Leases
1.1
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in millions of KWhs)
Retail:
Residential
2,170
2,197
5,084
4,943
Commercial
1,733
1,539
4,348
3,934
Industrial
1,524
1,557
4,436
4,503
Miscellaneous
371
373
981
965
Total Retail
5,798
5,666
14,849
14,345
Wholesale (a)
24
59
135
132
Total KWhs
5,822
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(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 Revenues
1.8
14.4
Total Change in Revenues
(28.8)
(73.9)
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
33.3
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 Other
8.4
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,
2024
2023
2024
2023
REVENUES
Electric Generation, Transmission and Distribution
$
612.9
$
642.6
$
1,439.1
$
1,529.8
Sales to AEP Affiliates
1.1
0.2
5.7
1.0
Other Revenues
1.4
1.4
17.2
5.1
TOTAL REVENUES
615.4
644.2
1,462.0
1,535.9
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
284.8
318.1
613.7
741.3
Other Operation
112.2
103.9
328.1
283.5
Maintenance
28.7
25.4
81.7
82.7
Depreciation and Amortization
70.6
61.8
202.1
187.8
Taxes Other Than Income Taxes
18.8
17.2
60.2
49.5
TOTAL EXPENSES
515.1
526.4
1,285.8
1,344.8
OPERATING INCOME
100.3
117.8
176.2
191.1
Other Income (Expense):
Interest Income
0.2
0.3
0.7
1.4
Allowance for Equity Funds Used During Construction
1.3
2.4
4.6
5.3
Non-Service Cost Components of Net Periodic Benefit Cost
2.9
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
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, 2023
157.2
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, 2023
157.2
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 Income
139.4
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 Income
72.0
72.0
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2024
157.2
1,039.3
1,411.3
(0.2)
2,607.6
Capital Contribution from Parent
0.2
0.2
Common Stock Dividends
(35.0)
(35.0)
Net Income
36.3
36.3
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2024
157.2
1,039.5
1,412.6
(0.2)
2,609.1
Common Stock Dividends
(35.0)
(35.0)
Net Income
113.7
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,
2024
2023
CURRENT ASSETS
Cash and Cash Equivalents
$
4.8
$
2.5
Accounts Receivable:
Customers
59.5
107.6
Affiliated Companies
46.2
31.0
Miscellaneous
0.4
0.8
Total Accounts Receivable
106.1
139.4
Fuel
23.2
33.7
Materials and Supplies
105.2
106.9
Risk Management Assets
28.4
19.0
Accrued Tax Benefits
17.5
31.0
Regulatory Asset for Under-Recovered Fuel Costs
27.4
118.3
Prepayments and Other Current Assets
30.3
18.7
TOTAL CURRENT ASSETS
342.9
469.5
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation
2,760.2
2,695.5
Transmission
1,272.2
1,228.3
Distribution
3,609.2
3,450.8
Other Property, Plant and Equipment
525.7
505.9
Construction Work in Progress
404.7
313.7
Total Property, Plant and Equipment
8,572.0
8,194.2
Accumulated Depreciation and Amortization
2,189.2
2,081.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
6,382.8
6,112.3
OTHER NONCURRENT ASSETS
Regulatory Assets
524.9
522.7
Employee Benefits and Pension Assets
71.9
68.4
Operating Lease Assets
107.6
112.8
Deferred Charges and Other Noncurrent Assets
61.5
49.2
TOTAL OTHER NONCURRENT ASSETS
765.9
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,
2024
2023
(in millions)
CURRENT LIABILITIES
Advances from Affiliates
$
98.5
$
54.4
Accounts Payable:
General
181.1
159.3
Affiliated Companies
57.7
56.7
Long-term Debt Due Within One Year – Nonaffiliated
250.6
0.6
Risk Management Liabilities
22.3
28.9
Customer Deposits
63.9
81.4
Accrued Taxes
71.2
30.7
Accrued Interest
22.7
30.7
Obligations Under Operating Leases
10.8
10.1
Other Current Liabilities
61.2
106.2
TOTAL CURRENT LIABILITIES
840.0
559.0
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
2,134.8
2,384.0
Deferred Income Taxes
888.6
831.2
Regulatory Liabilities and Deferred Investment Tax Credits
699.1
765.6
Asset Retirement Obligations
120.0
83.9
Obligations Under Operating Leases
102.1
106.8
Deferred Credits and Other Noncurrent Liabilities
27.8
33.8
TOTAL NONCURRENT LIABILITIES
3,972.4
4,205.3
TOTAL LIABILITIES
4,812.4
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 Capital
1,039.5
1,039.3
Retained Earnings
1,491.3
1,374.3
Accumulated Other Comprehensive Income (Loss)
(8.8)
(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY
2,679.2
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,
2024
2023
OPERATING ACTIVITIES
Net Income
$
222.0
$
188.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization
202.1
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, Net
90.9
263.3
Change in Other Regulatory Assets
5.0
(66.1)
Change in Other Noncurrent Assets
(24.4)
(27.8)
Change in Other Noncurrent Liabilities
0.8
11.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net
33.3
11.9
Fuel, Materials and Supplies
12.2
(11.6)
Accounts Payable
9.6
(19.5)
Accrued Taxes, Net
54.0
(9.5)
Other Current Assets
(15.3)
(3.0)
Other Current Liabilities
(67.0)
(10.8)
Net Cash Flows from Operating Activities
463.2
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 Activities
5.1
8.8
Net Cash Flows Used for Investing Activities
(397.8)
(547.2)
FINANCING ACTIVITIES
Capital Contribution from Parent
0.2
0.6
Return of Capital to Parent
—
(2.5)
Issuance of Long-term Debt – Nonaffiliated
—
469.8
Change in Advances from Affiliates, Net
44.1
(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 Activities
0.5
0.4
Net Cash Flows from (Used for) Financing Activities
(63.1)
66.2
Net Increase (Decrease) in Cash and Cash Equivalents
2.3
(0.3)
Cash and Cash Equivalents at Beginning of Period
2.5
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 Leases
1.2
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in millions of KWhs)
Retail:
Residential
1,955
2,180
4,855
4,902
Commercial
1,617
1,689
4,287
4,269
Industrial
1,232
1,313
3,873
3,876
Miscellaneous
17
17
52
53
Total Retail
4,821
5,199
13,067
13,100
Wholesale (a)
1,567
1,668
4,281
4,226
Total KWhs
6,388
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
(in degree days)
Actual – Heating (a)
—
—
560
413
Normal – Heating (b)
1
—
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 Sales
0.5
2.4
Transmission Revenues
7.3
10.2
Other Revenues
3.1
5.2
Total Change in Revenues
(16.0)
(157.7)
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
11.3
32.5
Other Operation and Maintenance
4.9
(47.8)
Depreciation and Amortization
(17.1)
(30.8)
Taxes Other Than Income Taxes
2.1
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 Expense
10.2
32.1
Total Change in Expenses and Other
8.2
(7.0)
Income Tax Benefit
(11.2)
163.1
Equity Earnings of Unconsolidated Subsidiary
0.1
0.1
Net Income Attributable to Noncontrolling Interest
0.5
(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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
REVENUES
Electric Generation, Transmission and Distribution
$
625.1
$
640.0
$
1,680.5
$
1,665.2
Sales to AEP Affiliates
21.9
14.4
52.3
45.7
Provision for Refund
(8.9)
(0.1)
(189.0)
(4.2)
Other Revenues
0.7
0.5
7.0
1.8
TOTAL REVENUES
638.8
654.8
1,550.8
1,708.5
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation
204.1
215.4
582.1
614.6
Other Operation
95.1
96.9
324.3
281.3
Maintenance
35.3
38.4
125.9
121.1
Depreciation and Amortization
117.7
100.6
297.6
266.8
Taxes Other Than Income Taxes
34.1
36.2
93.8
104.4
TOTAL EXPENSES
486.3
487.5
1,423.7
1,388.2
OPERATING INCOME
152.5
167.3
127.1
320.3
Other Income (Expense):
Interest Income
3.1
4.1
11.4
14.8
Allowance for Equity Funds Used During Construction
2.9
4.3
9.7
7.3
Non-Service Cost Components of Net Periodic Benefit Cost
2.6
3.4
7.6
10.2
Interest Expense
(31.9)
(42.1)
(75.1)
(107.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS
129.2
137.0
80.7
245.4
Income Tax Expense (Benefit)
(10.5)
(21.7)
(198.8)
(35.7)
Equity Earnings of Unconsolidated Subsidiary
0.4
0.3
1.1
1.0
NET INCOME
140.1
159.0
280.6
282.1
Net Income Attributable to Noncontrolling Interest
1.0
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 Ended
Nine Months Ended
September 30,
September 30,
2024
2023
2024
2023
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 INCOME
139.9
158.6
280.2
281.4
Total Comprehensive Income Attributable to Noncontrolling Interest
1.0
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 Parent
50.0
50.0
Common Stock Dividends – Nonaffiliated
(1.5)
(1.5)
Net Income
40.6
1.2
41.8
Other Comprehensive Income
0.1
0.1
TOTAL EQUITY – MARCH 31, 2023
0.1
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, 2023
0.1
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 Income
157.5
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 Income
208.1
1.5
209.6
Other Comprehensive Loss
(0.2)
(0.2)
TOTAL EQUITY – MARCH 31, 2024
0.1
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, 2024
0.1
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 Income
139.1
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,
2024
2023
CURRENT ASSETS
Cash and Cash Equivalents
$
4.4
$
2.4
Advances to Affiliates
2.8
2.2
Accounts Receivable:
Customers
27.5
39.0
Affiliated Companies
55.5
47.2
Miscellaneous
13.9
8.3
Total Accounts Receivable
96.9
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 Assets
24.1
11.6
Accrued Tax Benefits
21.4
28.4
Regulatory Asset for Under-Recovered Fuel Costs
106.6
170.8
Prepayments and Other Current Assets
32.2
29.2
TOTAL CURRENT ASSETS
459.5
541.3
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation
4,845.1
4,790.7
Transmission
2,754.8
2,660.6
Distribution
2,986.1
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 Progress
636.4
555.8
Total Property, Plant and Equipment
12,153.0
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 – NET
8,908.2
8,558.4
OTHER NONCURRENT ASSETS
Regulatory Assets
1,120.3
1,131.8
Deferred Charges and Other Noncurrent Assets
340.4
326.1
TOTAL OTHER NONCURRENT ASSETS
1,460.7
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,
2024
2023
(in millions)
CURRENT LIABILITIES
Advances from Affiliates
$
237.4
$
88.7
Accounts Payable:
General
226.2
198.9
Affiliated Companies
49.3
45.9
Short-term Debt – Nonaffiliated
4.6
4.3
Customer Deposits
75.3
72.5
Accrued Taxes
116.8
58.7
Accrued Interest
38.8
39.9
Obligations Under Operating Leases
8.8
9.0
Provision for Refund
62.5
0.7
Other Current Liabilities
127.5
168.3
TOTAL CURRENT LIABILITIES
947.2
686.9
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated
3,648.7
3,646.9
Deferred Income Taxes
1,260.4
1,179.3
Regulatory Liabilities and Deferred Investment Tax Credits
577.5
756.1
Asset Retirement Obligations
257.0
258.6
Employee Benefits and Pension Obligations
43.1
43.1
Obligations Under Operating Leases
119.5
122.5
Deferred Credits and Other Noncurrent Liabilities
178.9
93.8
TOTAL NONCURRENT LIABILITIES
6,085.1
6,100.3
TOTAL LIABILITIES
7,032.3
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 Capital
1,491.1
1,492.2
Retained Earnings
2,308.4
2,281.3
Accumulated Other Comprehensive Income (Loss)
(3.8)
(3.4)
TOTAL COMMON SHAREHOLDER’S EQUITY
3,795.8
3,770.2
Noncontrolling Interest
0.3
0.2
TOTAL EQUITY
3,796.1
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.
106
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,
2024
2023
OPERATING ACTIVITIES
Net Income
$
280.6
$
282.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization
297.6
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, Net
134.3
134.4
Provision for Refund – Turk Plant
100.0
—
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 Supplies
26.2
(12.0)
Accounts Payable
7.6
5.3
Accrued Taxes, Net
65.1
10.8
Provision for Refund – Turk Plant
60.0
—
Other Current Assets
(7.0)
10.4
Other Current Liabilities
(51.5)
(40.6)
Net Cash Flows from Operating Activities
649.4
627.7
INVESTING ACTIVITIES
Construction Expenditures
(539.6)
(614.1)
Change in Advances to Affiliates, Net
(0.6)
(0.6)
Other Investing Activities
10.9
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 – Nonaffiliated
0.3
3.9
Change in Advances from Affiliates, Net
148.7
(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 Activities
0.4
0.6
Net Cash Flows Used for Financing Activities
(118.1)
(99.6)
Net Increase (Decrease) in Cash and Cash Equivalents
2.0
(84.8)
Cash and Cash Equivalents at Beginning of Period
2.4
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 Leases
1.9
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.
107
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS
The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:
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,
2024
2023
(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 Outstanding
532.2
$
1.80
520.5
$
1.83
Weighted-Average Dilutive Effect of Stock-Based Awards
1.4
—
0.9
—
Weighted-Average Number of Diluted AEP Common Shares Outstanding
533.6
$
1.80
521.4
$
1.83
Nine Months Ended September 30,
2024
2023
(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 Outstanding
529.2
$
4.35
516.5
$
3.62
Weighted-Average Dilutive Effect of Stock-Based Awards
1.3
(0.01)
1.3
—
Weighted-Average Number of Diluted AEP Common Shares Outstanding
530.5
$
4.34
517.8
$
3.62
There were no antidilutive shares outstanding as of September 30, 2024 and 2023, respectively.
109
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
AEP
AEP Texas
APCo
(in millions)
Cash and Cash Equivalents
$
245.8
$
0.1
$
6.5
Restricted Cash
53.4
45.1
8.3
Total Cash, Cash Equivalents and Restricted Cash
$
299.2
$
45.2
$
14.8
December 31, 2023
AEP
AEP Texas
APCo
(in millions)
Cash and Cash Equivalents
$
330.1
$
0.1
$
5.0
Restricted Cash
48.9
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 Information
2024
2023
(in millions)
Cash Paid (Received) for:
Interest, Net of Capitalized Amounts
$
1,247.3
$
1,148.7
Income Taxes
87.9
26.7
Sale of Transferable Tax Credits
(163.7)
—
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases
24.5
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
110
2. NEW ACCOUNTING STANDARDS
The disclosures in this note apply to all Registrants unless indicated otherwise.
Management reviews the FASB’s standard-setting process and the SEC’s rulemaking activity to determine the relevance, if any, to the Registrants’ business. The following standards/rules will impact the Registrants’ financial statements.
SEC Climate Disclosure Rule
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
111
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.
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.
112
3. COMPREHENSIVE INCOME
The disclosures in this note apply to AEP only. The impact of AOCI is not material to the financial statements of the Registrant Subsidiaries.
Presentation of Comprehensive Income
The following tables provide AEP’s components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.
Cash Flow Hedges
Pension
Three Months Ended September 30, 2024
Commodity
Interest Rate
and OPEB
Total
(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) Benefit
0.1
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 Hedges
Pension
Three Months Ended September 30, 2023
Commodity
Interest Rate
and OPEB
Total
(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 Tax
19.3
(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)
113
Cash Flow Hedges
Pension
Nine Months Ended September 30, 2024
Commodity
Interest Rate
and OPEB
Total
(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 Hedges
Pension
Nine Months Ended September 30, 2023
Commodity
Interest Rate
and OPEB
Total
(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) Benefit
59.7
(1.1)
(12.0)
46.6
Income Tax (Expense) Benefit
12.5
(0.2)
(2.5)
9.8
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
47.2
(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:
Plant
Net Book Value
Accelerated Depreciation Regulatory Asset
Cost of Removal Regulatory Liability
Projected Retirement Date
Current Authorized Recovery Period
Annual Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3
$
111.9
$
181.2
$
20.8
(b)
2026
(c)
$
15.7
Welsh Plant, Units 1 and 3
341.4
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.
116
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,
2024
2023
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 Depreciation
120.8
114.4
Unrecovered Winter Storm Fuel Costs (a)
75.9
97.2
Storm-Related Costs
41.3
—
Other Regulatory Assets Pending Final Regulatory Approval
Other Regulatory Assets Pending Final Regulatory Approval
51.3
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.
(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.
117
AEP Texas
September 30,
December 31,
2024
2023
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 Costs
16.6
37.7
Line Inspection Costs
5.8
5.7
Vegetation Management Program
—
5.2
Texas Retail Electric Provider Bad Debt Expense
—
4.0
Other Regulatory Assets Pending Final Regulatory Approval
1.4
11.7
Total Regulatory Assets Pending Final Regulatory Approval
$
65.1
$
64.3
APCo
September 30,
December 31,
2024
2023
Noncurrent Regulatory Assets
(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval
Other Regulatory Assets Pending Final Regulatory Approval
4.4
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.
118
OPCo
September 30,
December 31,
2024
2023
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 Approval
0.1
—
Total Regulatory Assets Pending Final Regulatory Approval
$
0.3
$
23.6
PSO
September 30,
December 31,
2024
2023
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 Approval
3.2
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,
2024
2023
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 Depreciation
120.8
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 Approval
1.0
26.0
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - Louisiana, Texas
49.0
56.0
NOLC Costs (c)
44.1
—
Other Regulatory Assets Pending Final Regulatory Approval
18.5
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.
119
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.
120
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.
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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.
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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.
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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 2018and (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:
Jurisdiction
September 30, 2024
December 31, 2023
Approved Recovery Period
Approved Carrying Charge
(in millions)
Arkansas
$
40.4
$
54.2
6 years
(a)
Louisiana
75.9
97.2
(b)
(b)
Texas
79.3
101.9
5 years
1.65%
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:
Company
Amount
Maturity
(in millions)
AEP
$
236.3
October 2024 to July 2025
AEP Texas
1.8
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:
Company
Maximum Potential Loss
(in millions)
AEP
$
42.8
AEP Texas
9.9
APCo
5.5
I&M
4.0
OPCo
6.9
PSO
4.1
SWEPCo
4.9
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.
Registrant
Increase in ARO
Increase in Generation Property (a)
Increase in Regulatory Assets (b)
Charged to Operating Expenses (c)
(in millions)
APCo
$
312.2
$
75.6
$
236.6
$
—
I&M
85.7
—
72.3
13.4
OPCo
52.9
—
—
52.9
PSO
33.7
33.7
—
—
SWEPCo
23.8
23.8
—
—
Non-Registrants
166.1
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, 2024
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
25.6
$
2.3
$
2.4
$
3.3
$
2.3
$
1.5
$
1.9
Interest Cost
51.9
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 Loss
1.0
—
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, 2023
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
23.6
$
2.1
$
2.3
$
2.9
$
2.1
$
1.4
$
2.0
Interest Cost
54.8
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 Loss
0.3
—
—
—
—
—
—
Net Periodic Benefit Cost (Credit)
$
(6.1)
$
(0.4)
$
(2.3)
$
(1.8)
$
(1.5)
$
(0.5)
$
0.6
Nine Months Ended September 30, 2024
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
76.8
$
6.7
$
7.3
$
9.9
$
7.0
$
4.6
$
5.9
Interest Cost
155.7
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 Loss
3.2
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, 2023
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
70.8
$
6.2
$
6.8
$
8.9
$
6.3
$
4.2
$
5.8
Interest Cost
164.4
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 Loss
1.0
—
—
—
—
—
—
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, 2024
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
1.1
$
—
$
0.2
$
0.1
$
—
$
0.1
$
0.1
Interest Cost
10.3
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 Loss
0.8
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, 2023
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
1.1
$
0.1
$
0.1
$
0.1
$
0.1
$
0.1
$
—
Interest Cost
11.6
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 Loss
3.7
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, 2024
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
3.3
$
0.2
$
0.4
$
0.4
$
0.2
$
0.2
$
0.3
Interest Cost
31.4
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 Loss
2.3
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, 2023
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Service Cost
$
3.4
$
0.3
$
0.4
$
0.5
$
0.3
$
0.2
$
0.2
Interest Cost
34.7
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 Loss
11.1
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.
137
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).
138
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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other (a)
Reconciling Adjustments
Consolidated
(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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other (a)
Reconciling Adjustments
Consolidated
(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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other (a)
Reconciling Adjustments
Consolidated
(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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other (a)
Reconciling Adjustments
Consolidated
(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
139
September 30, 2024
Vertically Integrated Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & 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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & 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.
140
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 Transcos
AEPTCo Parent
Reconciling Adjustments
AEPTCo 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 Parent
Reconciling Adjustments
AEPTCo 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
141
Nine Months Ended September 30, 2024
State Transcos
AEPTCo Parent
Reconciling Adjustments
AEPTCo Consolidated
(in millions)
Revenues from:
External Customers
$
295.1
$
—
$
—
$
295.1
Sales to AEP Affiliates
1,157.1
—
—
1,157.1
Other Revenues
3.0
—
—
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 Transcos
AEPTCo Parent
Reconciling Adjustments
AEPTCo Consolidated
(in millions)
Revenues from:
External Customers
$
269.2
$
—
$
—
$
269.2
Sales to AEP Affiliates
1,080.0
—
—
1,080.0
Total Revenues
$
1,349.2
$
—
$
—
$
1,349.2
Net Income
$
514.0
$
3.6
(a)
$
—
$
517.6
September 30, 2024
State Transcos
AEPTCo Parent
Reconciling Adjustments
AEPTCo Consolidated
(in millions)
Total Assets
$
15,972.9
$
5,938.9
(b)
$
(6,017.5)
(c)
$
15,894.3
December 31, 2023
State Transcos
AEPTCo Parent
Reconciling Adjustments
AEPTCo 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.
142
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, 2024
December 31, 2023
Primary Risk Exposure
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(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
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
Assets:
(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity
$
444.4
$
—
$
54.4
$
22.7
$
—
$
28.7
$
24.6
Hedging Contracts - Commodity
41.2
—
—
—
—
—
—
Hedging Contracts - Interest Rate
—
—
—
—
—
—
—
Total Current Risk Management Assets
485.6
—
54.4
22.7
—
28.7
24.6
Long-term Risk Management Assets
Risk Management Contracts - Commodity
448.3
—
0.8
—
—
0.6
—
Hedging Contracts - Commodity
63.3
—
—
—
—
—
—
Hedging Contracts - Interest Rate
—
—
—
—
—
—
—
Total Long-term Risk Management Assets
511.6
—
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 - Commodity
6.7
—
—
—
—
—
—
Hedging Contracts - Interest Rate
51.7
—
—
—
—
10.9
—
Total Current Risk Management Liabilities
393.3
0.5
15.9
1.5
6.6
22.8
5.6
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity
391.1
0.1
6.7
0.1
45.4
0.6
—
Hedging Contracts - Commodity
2.9
—
—
—
—
—
—
Hedging Contracts - Interest Rate
40.9
—
—
—
—
—
—
Total Long-term Risk Management Liabilities
434.9
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
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
Assets:
(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity
$
555.1
$
—
$
24.6
$
30.1
$
—
$
19.7
$
12.0
Hedging Contracts - Commodity
56.7
—
—
—
—
—
—
Hedging Contracts - Interest Rate
—
—
—
—
—
—
—
Total Current Risk Management Assets
611.8
—
24.6
30.1
—
19.7
12.0
Long-term Risk Management Assets
Risk Management Contracts - Commodity
468.8
—
0.3
12.0
—
—
0.5
Hedging Contracts - Commodity
86.8
—
—
—
—
—
—
Hedging Contracts - Interest Rate
—
—
—
—
—
—
—
Total Long-term Risk Management Assets
555.6
—
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 - Commodity
8.2
—
—
—
—
—
—
Hedging Contracts - Interest Rate
50.5
2.7
—
—
—
—
—
Total Current Risk Management Liabilities
646.7
2.9
18.5
5.4
6.9
29.7
14.9
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity
377.6
—
6.9
0.2
43.9
1.0
1.7
Hedging Contracts - Commodity
2.2
—
—
—
—
—
—
Hedging Contracts - Interest Rate
56.9
—
—
—
—
—
—
Total Long-term Risk Management Liabilities
436.7
—
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
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
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 Presented
236.7
—
47.1
21.7
—
28.4
24.1
Long-term Risk Management Assets
Gross Amounts Recognized
511.6
—
0.8
—
—
0.6
—
Gross Amounts Offset
(253.3)
—
(0.8)
—
—
(0.5)
—
Net Amounts Presented
258.3
—
—
—
—
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 Presented
152.0
—
7.6
0.3
6.3
22.3
4.8
Long-term Risk Management Liabilities
Gross Amounts Recognized
434.9
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 Presented
201.6
—
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
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
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 Presented
217.5
—
22.4
27.8
—
19.0
11.6
Long-term Risk Management Assets
Gross Amounts Recognized
555.6
—
0.3
12.0
—
—
0.5
Gross Amounts Offset
(234.4)
—
(0.3)
(0.2)
—
—
(0.5)
Net Amounts Presented
321.2
—
—
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 Presented
229.6
2.7
15.9
2.0
6.8
28.9
14.4
Long-term Risk Management Liabilities
Gross Amounts Recognized
436.7
—
6.9
0.2
43.9
1.0
1.7
Gross Amounts Offset
(194.9)
—
(0.3)
(0.2)
—
—
(0.5)
Net Amounts Presented
241.8
—
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)
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(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 Generation
0.7
—
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)
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(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 Generation
0.2
—
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)
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(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 Generation
2.4
—
2.1
0.1
—
—
—
Maintenance
0.1
—
—
—
—
—
—
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)
AEP
AEP Texas
APCo
I&M
OPCo
PSO
SWEPCo
(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 Generation
2.2
—
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 Liabilities
Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
September 30, 2024
December 31, 2023
September 30, 2024
December 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,
2024
2023
2024
2023
(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, 2024
December 31, 2023
Portion Expected to
Portion Expected to
AOCI
be Reclassed to
AOCI
be Reclassed to
Gain (Loss)
Net Income During
Gain (Loss)
Net Income During
Net of Tax
the Next Twelve Months
Net of Tax
the Next Twelve Months
Commodity
Interest Rate
Commodity
Interest Rate
Commodity
Interest Rate
Commodity
Interest 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, 2024
December 31, 2023
Company
Book Value
Fair Value
Book Value
Fair Value
(in millions)
AEP
$
41,974.4
$
40,104.2
$
40,143.2
$
37,325.7
AEP Texas
6,479.4
6,112.1
5,889.8
5,400.7
AEPTCo
5,862.3
5,288.5
5,414.4
4,796.9
APCo
5,659.2
5,582.5
5,588.3
5,390.1
I&M
3,517.5
3,363.4
3,499.4
3,291.6
OPCo
3,715.0
3,389.6
3,366.8
2,992.1
PSO
2,385.4
2,210.9
2,384.6
2,154.3
SWEPCo
3,648.7
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
Gross
Gross
Unrealized
Unrealized
Fair
Other Temporary Investments and Restricted Cash
Cost
Gains
Losses
Value
(in millions)
Restricted Cash (a)
$
53.4
$
—
$
—
$
53.4
Other Cash Deposits
17.0
—
—
17.0
Fixed Income Securities – Mutual Funds (b)
168.0
—
(3.4)
164.6
Equity Securities – Mutual Funds
14.8
32.2
—
47.0
Total Other Temporary Investments and Restricted Cash
$
253.2
$
32.2
$
(3.4)
$
282.0
December 31, 2023
Gross
Gross
Unrealized
Unrealized
Fair
Other Temporary Investments and Restricted Cash
Cost
Gains
Losses
Value
(in millions)
Restricted Cash (a)
$
48.9
$
—
$
—
$
48.9
Other Cash Deposits
13.9
—
—
13.9
Fixed Income Securities – Mutual Funds (b)
165.9
—
(6.2)
159.7
Equity Securities – Mutual Funds
14.8
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,
2024
2023
2024
2023
(in millions)
Proceeds from Investment Sales
$
4.5
$
0.8
$
7.5
$
0.8
Purchases of Investments
6.0
14.6
9.0
16.9
Gross Realized Gains on Investment Sales
0.4
0.3
0.7
0.3
Gross Realized Losses on Investment Sales
0.3
—
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, 2024
December 31, 2023
Gross
Gross
Other-Than-
Gross
Gross
Other-Than-
Fair
Unrealized
Unrealized
Temporary
Fair
Unrealized
Unrealized
Temporary
Value
Gains
Losses
Impairments
Value
Gains
Losses
Impairments
(in millions)
Cash and Cash Equivalents
$
26.2
$
—
$
—
$
—
$
16.8
$
—
$
—
$
—
Fixed Income Securities:
United States Government
1,370.5
42.0
(0.1)
(22.5)
1,273.0
28.6
(3.9)
(33.2)
Corporate Debt
215.6
7.3
(1.8)
3.0
132.1
4.8
(5.2)
(8.6)
State and Local Government
1.7
—
—
—
1.7
—
—
—
Subtotal Fixed Income Securities
1,587.8
49.3
(1.9)
(19.5)
1,406.8
33.4
(9.1)
(41.8)
Equity Securities - Domestic
2,811.8
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,
2024
2023
2024
2023
(in millions)
Proceeds from Investment Sales
$
1,181.9
$
933.0
$
2,336.0
$
2,139.3
Purchases of Investments
1,201.9
949.5
2,389.0
2,182.8
Gross Realized Gains on Investment Sales
108.4
36.8
118.7
91.6
Gross Realized Losses on Investment Sales
0.7
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 years
600.8
After 5 years through 10 years
249.7
After 10 years
336.1
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 1
Level 2
Level 3
Other
Total
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 Funds
164.6
—
—
—
164.6
Equity Securities – Mutual Funds (b)
47.0
—
—
—
47.0
Total Other Temporary Investments and Restricted Cash
265.0
—
—
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 Assets
3.9
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 Trusts
2,827.4
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 1
Level 2
Level 3
Other
Total
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 Funds
159.7
—
—
—
159.7
Equity Securities – Mutual Funds (b)
40.7
—
—
—
40.7
Total Other Temporary Investments and Restricted Cash
249.3
—
—
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 Assets
9.7
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 Trusts
2,444.4
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 Trusts
2,827.4
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 1
Level 2
Level 3
Other
Total
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 Trusts
2,444.4
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 1
Level 2
Level 3
Other
Total
Liabilities:
(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)
$
—
$
0.4
$
51.6
$
(0.4)
$
51.6
December 31, 2023
Level 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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 1
Level 2
Level 3
Other
Total
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, 2024
AEP
APCo
I&M
OPCo
PSO
SWEPCo
(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, 2023
AEP
APCo
I&M
OPCo
PSO
SWEPCo
(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, 2024
AEP
APCo
I&M
OPCo
PSO
SWEPCo
(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
164
Nine Months Ended September 30, 2023
AEP
APCo
I&M
OPCo
PSO
SWEPCo
(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.
165
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:
Significant Unobservable Inputs
September 30, 2024
Significant
Input/Range
Type of
Fair Value
Valuation
Unobservable
Weighted
Company
Input
Assets
Liabilities
Technique
Input
Low
High
Average (a)
(in millions)
AEP
Energy Contracts
$
199.9
$
130.4
Discounted Cash Flow
Forward Market Price (b)
$
0.46
$
121.80
$
45.50
AEP
FTRs
127.4
3.8
Discounted Cash Flow
Forward Market Price (b)
(41.91)
24.96
0.20
APCo
FTRs
47.5
0.3
Discounted Cash Flow
Forward Market Price (b)
(0.06)
9.63
1.30
I&M
FTRs
10.0
0.7
Discounted Cash Flow
Forward Market Price (b)
(5.00)
9.63
1.21
OPCo
Energy Contracts
—
51.6
Discounted Cash Flow
Forward Market Price (b)
19.94
68.22
41.34
PSO
FTRs
28.6
0.2
Discounted Cash Flow
Forward Market Price (b)
(41.91)
5.93
(3.82)
SWEPCo
FTRs
24.3
0.6
Discounted Cash Flow
Forward Market Price (b)
(41.91)
5.93
(3.82)
December 31, 2023
Significant
Input/Range
Type of
Fair Value
Valuation
Unobservable
Weighted
Company
Input
Assets
Liabilities
Technique
Input
Low
High
Average (a)
(in millions)
AEP
Energy Contracts
$
225.5
$
144.9
Discounted Cash Flow
Forward Market Price (b)
$
5.21
$
153.77
$
45.05
AEP
Natural Gas Contracts
—
0.5
Discounted Cash Flow
Forward Market Price (c)
3.11
3.11
3.11
AEP
FTRs
68.6
9.3
Discounted Cash Flow
Forward Market Price (b)
(25.45)
17.07
—
APCo
FTRs
23.5
1.1
Discounted Cash Flow
Forward Market Price (b)
(1.04)
6.45
1.36
I&M
FTRs
4.5
1.7
Discounted Cash Flow
Forward Market Price (b)
(1.48)
8.40
0.85
OPCo
Energy Contracts
—
50.6
Discounted Cash Flow
Forward Market Price (b)
22.92
67.53
42.85
PSO
FTRs
19.7
1.1
Discounted Cash Flow
Forward Market Price (b)
(25.45)
4.80
(4.33)
SWEPCo
Natural Gas Contracts
—
0.5
Discounted Cash Flow
Forward Market Price (c)
3.11
3.11
3.11
SWEPCo
FTRs
12.0
0.4
Discounted Cash Flow
Forward 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 Input
Position
Change in Input
Impact on Fair Value Measurement
Forward Market Price
Buy
Increase (Decrease)
Higher (Lower)
Forward Market Price
Sell
Increase (Decrease)
Lower (Higher)
166
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
AEP
AEP Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
U.S. Federal Statutory Rate
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
Increase (decrease) due to:
State and Local Income Taxes, Net
0.6
%
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-Through
0.1
%
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 Rate
3.8
%
18.3
%
21.9
%
17.0
%
(32.7)
%
14.9
%
(45.4)
%
(8.1)
%
Three Months Ended September 30, 2023
AEP
AEP Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
U.S. Federal Statutory Rate
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
Increase (decrease) due to:
State and Local Income Taxes, Net
1.4
%
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-Through
0.1
%
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 Rate
6.3
%
18.6
%
20.5
%
18.8
%
10.6
%
16.3
%
(41.4)
%
(15.8)
%
167
Nine Months Ended September 30, 2024
AEP
AEP Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
U.S. Federal Statutory Rate
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
Increase (decrease) due to:
State and Local Income Taxes, Net
1.2
%
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-Through
0.2
%
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
AEP
AEP Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
U.S. Federal Statutory Rate
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
21.0
%
Increase (decrease) due to:
State and Local Income Taxes, Net
1.7
%
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 Rate
5.2
%
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 Debt
September 30, 2024
December 31, 2023
(in millions)
Senior Unsecured Notes
$
35,771.2
$
33,779.4
Pollution Control Bonds
1,770.4
1,771.6
Notes Payable
644.3
193.3
Securitization Bonds
285.7
368.9
Spent Nuclear Fuel Obligation (a)
312.7
300.4
Junior Subordinated Notes
2,578.0
2,388.1
Other Long-term Debt
612.1
1,341.5
Total Long-term Debt Outstanding
41,974.4
40,143.2
Long-term Debt Due Within One Year
2,826.7
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.
170
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:
Principal
Interest
Company
Type of Debt
Amount (a)
Rate
Due Date
Issuances:
(in millions)
(%)
AEP
Junior Subordinated Notes
$
600.0
6.95
2054
AEP
Junior Subordinated Notes
400.0
7.05
2054
AEPTCo
Senior Unsecured Notes
450.0
5.15
2034
AEP Texas
Senior Unsecured Notes
500.0
5.45
2029
AEP Texas
Senior Unsecured Notes
350.0
5.70
2034
APCo
Pollution Control Bonds
86.0
3.38
2028
APCo
Senior Unsecured Notes
400.0
5.65
2034
I&M
Notes Payable
80.4
6.41
2028
OPCo
Senior Unsecured Notes
350.0
5.65
2034
Non-Registrant:
AEGCo
Other Long-term Debt
70.0
Variable
2025
Transource Energy
Other Long-term Debt
50.0
Variable
2025
WPCo
Notes Payable
450.0
6.89
2034
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
Principal
Interest
Company
Type of Debt
Amount Paid
Rate
Due Date
Retirements and Principal Payments:
(in millions)
(%)
AEP
Junior Subordinated Debt
$
805.0
2.03
2024
AEP Texas
Other Long-term Debt
200.0
Variable
2025
AEP Texas
Securitization Bonds
32.6
2.85
2024
AEP Texas
Securitization Bonds
23.9
2.06
2025
APCo
Other Long-term Debt
300.0
Variable
2024
APCo
Other Long-term Debt
0.1
13.72
2026
APCo
Pollution Control Bonds
86.0
2.55
2024
APCo
Securitization Bonds
27.4
3.77
2028
I&M
Notes Payable
1.7
Variable
2024
I&M
Notes Payable
7.4
0.93
2025
I&M
Notes Payable
2.9
Variable
2025
I&M
Notes Payable
15.2
3.44
2026
I&M
Notes Payable
15.1
5.93
2027
I&M
Notes Payable
20.6
6.01
2028
I&M
Notes Payable
11.4
6.41
2028
I&M
Other Long-term Debt
1.8
6.00
2025
PSO
Other Long-term Debt
0.4
3.00
2027
Non-Registrant:
AEGCo
Notes Payable
5.0
2.43
2028
AEGCo
Other Long-term Debt
80.0
Variable
2024
KPCo
Senior Unsecured Notes
65.0
3.13
2024
Transource Energy
Senior Unsecured Notes
1.4
2.75
2050
Transource Energy
Senior Unsecured Notes
1.2
2.75
2050
WPCo
Notes Payable
265.0
Variable
2024
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:
Maximum
Average
Net Loans to
Borrowings
Maximum
Borrowings
Average
(Borrowings from)
Authorized
from the
Loans to the
from the
Loans to the
the Utility Money
Short-term
Utility
Utility
Utility
Utility
Pool as of
Borrowing
Company
Money Pool
Money Pool
Money Pool
Money Pool
September 30, 2024
Limit
(in millions)
AEP Texas
$
374.6
$
274.3
$
237.0
$
203.1
$
54.7
$
600.0
AEPTCo
313.3
332.0
75.7
159.2
152.6
820.0
(a)
APCo
399.5
132.3
110.2
32.6
18.0
750.0
I&M
126.9
8.4
53.3
3.9
(77.0)
500.0
OPCo
310.0
159.9
180.5
75.9
97.4
600.0
PSO
302.2
—
184.0
—
(98.5)
750.0
SWEPCo
362.2
—
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
Company
Money Pool
Money Pool
September 30, 2024
(in millions)
AEP Texas
$
7.1
$
7.0
$
7.1
SWEPCo
2.8
2.6
2.8
173
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:
Borrowings
Authorized
Maximum
Maximum
Average
Average
from AEP
Loans to
Short-term
Borrowings
Loans
Borrowings
Loans
as of
AEP as of
Borrowing
Company
from 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,
2024
2023
Maximum Interest Rate
5.79
%
5.81
%
Minimum Interest Rate
5.14
%
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 Funds
Average Interest Rate for Funds
Borrowed from the Utility Money Pool
Loaned to the Utility Money Pool
for Nine Months Ended September 30,
for Nine Months Ended September 30,
Company
2024
2023
2024
2023
AEP Texas
5.69
%
5.44
%
5.48
%
5.70
%
AEPTCo
5.68
%
5.29
%
5.58
%
5.52
%
APCo
5.72
%
5.47
%
5.51
%
5.47
%
I&M
5.64
%
5.13
%
5.44
%
5.54
%
OPCo
5.70
%
5.37
%
5.49
%
5.60
%
PSO
5.59
%
5.48
%
—
%
5.24
%
SWEPCo
5.58
%
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, 2024
Nine Months Ended September 30, 2023
Maximum
Minimum
Average
Maximum
Minimum
Average
Interest Rate
Interest Rate
Interest Rate
Interest Rate
Interest Rate
Interest Rate
for Funds
for Funds
for Funds
for Funds
for Funds
for Funds
Loaned to
Loaned to
Loaned to
Loaned to
Loaned to
Loaned to
the Nonutility
the Nonutility
the Nonutility
the Nonutility
the Nonutility
the Nonutility
Company
Money Pool
Money Pool
Money Pool
Money 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:
Maximum
Minimum
Maximum
Minimum
Average
Average
Interest Rate
Interest Rate
Interest Rate
Interest Rate
Interest Rate
Interest Rate
Nine Months
for Funds
for Funds
for Funds
for Funds
for Funds
for Funds
Ended
Borrowed
Borrowed
Loaned
Loaned
Borrowed
Loaned
September 30,
from AEP
from AEP
to 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, 2024
December 31, 2023
Outstanding
Interest
Outstanding
Interest
Company
Type of Debt
Amount
Rate (a)
Amount
Rate (a)
(dollars in millions)
AEP
Securitized Debt for Receivables (b)
$
900.0
5.32
%
$
888.0
5.65
%
AEP
Commercial Paper
755.0
5.26
%
1,937.9
5.69
%
SWEPCo
Notes Payable
4.6
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,
2024
2023
2024
2023
(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, 2024
December 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 Receivables
900.0
888.0
Delinquent Securitized Accounts Receivable
66.4
52.2
Bad Debt Reserves Related to Securitization
44.9
42.0
Unbilled Receivables Related to Securitization
327.4
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:
Company
September 30, 2024
December 31, 2023
(in millions)
APCo
$
178.5
$
184.6
I&M
183.6
156.4
OPCo
517.2
541.7
PSO
192.2
134.6
SWEPCo
189.2
168.3
The fees paid to AEP Credit for customer accounts receivable sold were:
Three Months Ended September 30,
Nine Months Ended September 30,
Company
2024
2023
2024
2023
(in millions)
APCo
$
4.0
$
4.1
$
12.1
$
13.3
I&M
4.1
4.4
12.0
12.2
OPCo
7.5
7.4
22.3
22.3
PSO
4.1
4.6
10.9
11.3
SWEPCo
4.4
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,
Company
2024
2023
2024
2023
(in millions)
APCo
$
504.6
$
451.6
$
1,487.9
$
1,372.7
I&M
576.7
553.3
1,608.5
1,575.9
OPCo
860.0
850.3
2,477.2
2,518.6
PSO
611.5
633.8
1,398.1
1,510.3
SWEPCo
531.4
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.
AEP
AEP Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Severance Expense Incurred
$
122.0
$
19.8
$
10.7
$
26.5
$
14.8
$
14.8
$
10.1
$
16.9
Settled/Adjustments
111.0
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 Funding
AEP Texas Restoration Funding
APCo Appalachian Consumer Rate Relief Funding
AEP Credit
Protected 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 Assets
120.1
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 Liabilities
102.5
236.7
16.3
112.5
91.3
1.0
106.5
289.4
Equity
0.3
—
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 Funding
AEP Texas Restoration Funding
APCo Appalachian Consumer Rate Relief Funding
AEP Credit
Protected 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 Assets
150.7
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 Liabilities
134.8
235.7
17.0
135.1
119.7
0.9
91.7
241.5
Equity
0.2
—
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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other
Reconciling Adjustments
AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues
$
1,362.9
$
773.7
$
—
$
—
$
—
$
—
$
2,136.6
Commercial Revenues
776.1
396.5
—
—
—
—
1,172.6
Industrial Revenues (a)
692.6
123.7
—
—
—
(0.3)
816.0
Other Retail Revenues
63.8
13.9
—
—
—
—
77.7
Total Retail Revenues
2,895.4
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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other
Reconciling Adjustments
AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues
$
1,326.7
$
772.5
$
—
$
—
$
—
$
—
$
2,099.2
Commercial Revenues
753.3
387.7
—
—
—
—
1,141.0
Industrial Revenues
699.9
138.9
—
—
—
(0.3)
838.5
Other Retail Revenues
66.6
13.0
—
—
—
—
79.6
Total Retail Revenues
2,846.5
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 Revenues
2.7
(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 Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Retail Revenues:
Residential Revenues
$
230.2
$
—
$
442.6
$
249.4
$
543.4
$
301.1
$
260.1
Commercial Revenues
120.3
—
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 Revenues
9.7
—
28.1
1.2
4.2
30.8
2.3
Total Retail Revenues
393.9
—
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 Revenues
170.6
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 Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Retail Revenues:
Residential Revenues
$
236.2
$
—
$
397.1
$
230.7
$
536.3
$
310.5
$
286.5
Commercial Revenues
112.4
—
181.3
159.2
275.3
171.9
174.9
Industrial Revenues
35.4
—
197.1
159.1
103.6
114.1
105.5
Other Retail Revenues
9.2
—
26.8
1.3
3.8
33.8
2.4
Total Retail Revenues
393.2
—
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 Revenues
154.6
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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other
Reconciling Adjustments
AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues
$
3,524.2
$
2,127.7
$
—
$
—
$
—
$
—
$
5,651.9
Commercial Revenues
2,071.0
1,184.6
—
—
—
—
3,255.6
Industrial Revenues (a)
1,992.5
382.8
—
—
—
(0.6)
2,374.7
Other Retail Revenues
174.9
41.5
—
—
—
—
216.4
Total Retail Revenues
7,762.6
3,736.6
—
—
—
(0.6)
11,498.6
Wholesale and Competitive Retail Revenues:
Generation Revenues
587.4
—
—
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 Revenues
958.9
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 Utilities
Transmission and Distribution Utilities
AEP Transmission Holdco
Generation & Marketing
Corporate and Other
Reconciling Adjustments
AEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues
$
3,459.1
$
2,003.4
$
—
$
—
$
—
$
—
$
5,462.5
Commercial Revenues
2,029.4
1,121.9
—
—
—
—
3,151.3
Industrial Revenues (a)
2,069.1
503.9
—
—
—
(0.6)
2,572.4
Other Retail Revenues
182.3
37.4
—
—
—
—
219.7
Total Retail Revenues
7,739.9
3,666.6
—
—
—
(0.6)
11,405.9
Wholesale and Competitive Retail Revenues:
Generation Revenues
498.5
—
—
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 Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Retail Revenues:
Residential Revenues
$
562.4
$
—
$
1,333.7
$
664.7
$
1,565.2
$
647.1
$
563.2
Commercial Revenues
346.2
—
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 Revenues
28.7
—
84.3
3.8
12.9
78.2
6.6
Total Retail Revenues
1,040.6
—
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 Revenues
511.3
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 Customers
1,579.3
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 Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
(in millions)
Retail Revenues:
Residential Revenues
$
511.8
$
—
$
1,192.4
$
655.5
$
1,491.6
$
667.9
$
647.5
Commercial Revenues
310.3
—
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 Revenues
26.2
—
78.2
3.8
11.2
86.3
7.6
Total Retail Revenues
958.2
—
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 Revenues
464.0
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 Customers
1,451.4
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.
Company
2024
2025-2026
2027-2028
After 2028
Total
(in millions)
AEP
$
23.1
$
169.0
$
85.4
$
24.9
$
302.4
APCo
4.0
32.1
26.5
11.6
74.2
I&M
1.1
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 Texas
AEPTCo
APCo
I&M
OPCo
PSO
SWEPCo
(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 5incorporated 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)
