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(All Registrants)
LG&E and KU have entered into various operating leases primarily for office space, vehicles and railcars. The leases generally have fixed payments with expiration dates ranging from 2025 to 2042, some of which have options to extend the leases from one year to ten years and some have options to terminate at LG&E's and KU's discretion.
PPL has also entered into various operating leases primarily for office and warehouse space. These leases generally have fixed payments with expiration dates ranging from 2025 through 2051. RIE has various operating leases, primarily related to buildings, land, and finance leases related to fleet vehicles used to support the electric and gas operations, with lease terms ranging between 1 and 28 years. In measuring lease liabilities, the Company excludes variable lease payments, other than those that depend on an index or rate, or are in substance fixed payments, and includes lease payments made at or before the commencement date. The variable lease payments were not material for the year ended December 31, 2024.
PPL Electric also has operating leases which do not have a significant impact to its operations.
(PPL, LG&E and KU)
Lessee Transactions
The following table provides the components of lease cost for the Registrants' leases for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Lease cost: |  |  |  |  |
Finance lease cost: |  |  |  |  |
Amortization of right-of-use assets | $ | — |  |  | 1 |  |  | $ | — |
Interest on lease liabilities | — |  |  | — |  |  | — |
Operating lease cost | — |  |  | 26 |  |  | 20 |
Short-term lease cost | — |  |  | 6 |  |  | 6 |
Total lease cost | $ | — |  |  | $ | 33 |  |  | $ | 26 |
LG&E |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 5 |  |  | $ | 6 |
Short-term lease cost |  |  | 1 |  |  | 1 |
Total lease cost | $ | — |  |  | $ | 6 |  |  | $ | 7 |
KU |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 10 |  |  | $ | 9 |
Short-term lease cost |  |  | 1 |  |  | 2 |
Total lease cost | $ | — |  |  | $ | 11 |  |  | $ | 11 |

The following table provides other key information related to the Registrants' leases at December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from finance leases | $ | — |  |  | — |  |  | $ | — |
Operating cash flows from operating leases | — |  |  | 25 |  |  | 26 |
Financing cash flows from finance leases | — |  |  | 1 |  |  | — |
Right-of-use asset obtained in exchange for new finance lease liabilities | — |  |  | 7 |  |  | — |
Right-of-use asset obtained in exchange for new operating lease liabilities | — |  |  | 47 |  |  | 15 |
LG&E |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 6 |  |  | $ | 8 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 6 |  |  | 4 |
KU |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 9 |  |  | $ | 12 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 10 |  |  | 5 |

The following table provides the total future minimum rental payments for leases, as well as a reconciliation of these undiscounted cash flows to the lease liabilities recognized on the Balance Sheets as of December 31, 2025.

| PPL |  | LG&E |  | KU
| Operating leases |  | Finance leases |  | Operating leases |  | Operating leases
2024 | $ | — |  | $ | — |  |  |  |
2025 | — |  | — |  |  |  |
2026 | — |  | — |  |  |  |
2027 | — |  | — |  |  |  |
2028 | — |  | — |  |  |  |
Thereafter | — |  | — |  |  |  |
Total | $ | — |  | $ | — |  | $ | — |  | $ | —
Weighted-average discount rate |  |  |  |  |  |  |
Weighted-average remaining lease term (in years) |  |  |  |  |  |  |
Current lease liabilities (a) | $ | — |  | $ | — |  |  |  |
Non-current lease liabilities (a) | — |  | — |  |  |  |
Right-of-use assets (b) | — |  | — |  |  |  |

(a) Current lease liabilities are included in "Other Current Liabilities" on the Balance Sheets. Non-current lease liabilities are included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets. The difference between the total future minimum lease payments and the recorded lease liabilities is due to the impact of discounting.
(b) Operating lease right-of-use assets are included in "Other noncurrent assets" and finance lease right-of-use assets are included in "Property, Plant and Equipment" on the Balance Sheets.
Lessor Transactions
Third parties leased land from LG&E and KU at certain generation plants to produce refined coal used to generate electricity. The leases were operating leases and expired in 2021. Payments were allocated among lease and non-lease components as stated in the agreements. Lease payments were fixed or determined based on the amount of refined coal used in electricity generation at the facility. Payments received were primarily recorded as a regulatory liability and amortized in accordance with regulatory approvals. There are certain leases in which RIE is the lessor. Revenue under such leases was immaterial for the year ended December 31, 2025.
The following table shows the lease income recognized for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL | $ | — |  |  | 4 |  |  | 6 |
LG&E | — |  |  | — |  |  | 2 |
KU | — |  |  | — |  |  | — |

one year one year ten years ten years
The following table provides the components of lease cost for the Registrants' leases for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Lease cost: |  |  |  |  |
Finance lease cost: |  |  |  |  |
Amortization of right-of-use assets | $ | — |  |  | 1 |  |  | $ | — |
Interest on lease liabilities | — |  |  | — |  |  | — |
Operating lease cost | — |  |  | 26 |  |  | 20 |
Short-term lease cost | — |  |  | 6 |  |  | 6 |
Total lease cost | $ | — |  |  | $ | 33 |  |  | $ | 26 |
LG&E |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 5 |  |  | $ | 6 |
Short-term lease cost |  |  | 1 |  |  | 1 |
Total lease cost | $ | — |  |  | $ | 6 |  |  | $ | 7 |
KU |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 10 |  |  | $ | 9 |
Short-term lease cost |  |  | 1 |  |  | 2 |
Total lease cost | $ | — |  |  | $ | 11 |  |  | $ | 11 |

The following table provides other key information related to the Registrants' leases at December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from finance leases | $ | — |  |  | — |  |  | $ | — |
Operating cash flows from operating leases | — |  |  | 25 |  |  | 26 |
Financing cash flows from finance leases | — |  |  | 1 |  |  | — |
Right-of-use asset obtained in exchange for new finance lease liabilities | — |  |  | 7 |  |  | — |
Right-of-use asset obtained in exchange for new operating lease liabilities | — |  |  | 47 |  |  | 15 |
LG&E |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 6 |  |  | $ | 8 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 6 |  |  | 4 |
KU |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 9 |  |  | $ | 12 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 10 |  |  | 5 |

The following table provides the components of lease cost for the Registrants' leases for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Lease cost: |  |  |  |  |
Finance lease cost: |  |  |  |  |
Amortization of right-of-use assets | $ | — |  |  | 1 |  |  | $ | — |
Interest on lease liabilities | — |  |  | — |  |  | — |
Operating lease cost | — |  |  | 26 |  |  | 20 |
Short-term lease cost | — |  |  | 6 |  |  | 6 |
Total lease cost | $ | — |  |  | $ | 33 |  |  | $ | 26 |
LG&E |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 5 |  |  | $ | 6 |
Short-term lease cost |  |  | 1 |  |  | 1 |
Total lease cost | $ | — |  |  | $ | 6 |  |  | $ | 7 |
KU |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 10 |  |  | $ | 9 |
Short-term lease cost |  |  | 1 |  |  | 2 |
Total lease cost | $ | — |  |  | $ | 11 |  |  | $ | 11 |

The following table provides other key information related to the Registrants' leases at December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from finance leases | $ | — |  |  | — |  |  | $ | — |
Operating cash flows from operating leases | — |  |  | 25 |  |  | 26 |
Financing cash flows from finance leases | — |  |  | 1 |  |  | — |
Right-of-use asset obtained in exchange for new finance lease liabilities | — |  |  | 7 |  |  | — |
Right-of-use asset obtained in exchange for new operating lease liabilities | — |  |  | 47 |  |  | 15 |
LG&E |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 6 |  |  | $ | 8 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 6 |  |  | 4 |
KU |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 9 |  |  | $ | 12 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 10 |  |  | 5 |

The following table provides the components of lease cost for the Registrants' leases for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Lease cost: |  |  |  |  |
Finance lease cost: |  |  |  |  |
Amortization of right-of-use assets | $ | — |  |  | 1 |  |  | $ | — |
Interest on lease liabilities | — |  |  | — |  |  | — |
Operating lease cost | — |  |  | 26 |  |  | 20 |
Short-term lease cost | — |  |  | 6 |  |  | 6 |
Total lease cost | $ | — |  |  | $ | 33 |  |  | $ | 26 |
LG&E |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 5 |  |  | $ | 6 |
Short-term lease cost |  |  | 1 |  |  | 1 |
Total lease cost | $ | — |  |  | $ | 6 |  |  | $ | 7 |
KU |  |  |  |  |
Lease cost: |  |  |  |  |
Operating lease cost |  |  | $ | 10 |  |  | $ | 9 |
Short-term lease cost |  |  | 1 |  |  | 2 |
Total lease cost | $ | — |  |  | $ | 11 |  |  | $ | 11 |

The following table provides other key information related to the Registrants' leases at December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from finance leases | $ | — |  |  | — |  |  | $ | — |
Operating cash flows from operating leases | — |  |  | 25 |  |  | 26 |
Financing cash flows from finance leases | — |  |  | 1 |  |  | — |
Right-of-use asset obtained in exchange for new finance lease liabilities | — |  |  | 7 |  |  | — |
Right-of-use asset obtained in exchange for new operating lease liabilities | — |  |  | 47 |  |  | 15 |
LG&E |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 6 |  |  | $ | 8 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 6 |  |  | 4 |
KU |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities: |  |  |  |  |
Operating cash flows from operating leases |  |  | $ | 9 |  |  | $ | 12 |
Right-of-use asset obtained in exchange for new operating lease liabilities |  |  | 10 |  |  | 5 |

—1—————26 20—6 6—33 26 5 6 1 1—6 7 10 9 1 2—11 11————25 26—1——7——47 15 6 8 6 4 9 12 10 5
The following table provides the total future minimum rental payments for leases, as well as a reconciliation of these undiscounted cash flows to the lease liabilities recognized on the Balance Sheets as of December 31, 2025.

| PPL |  | LG&E |  | KU
| Operating leases |  | Finance leases |  | Operating leases |  | Operating leases
2024 | $ | — |  | $ | — |  |  |  |
2025 | — |  | — |  |  |  |
2026 | — |  | — |  |  |  |
2027 | — |  | — |  |  |  |
2028 | — |  | — |  |  |  |
Thereafter | — |  | — |  |  |  |
Total | $ | — |  | $ | — |  | $ | — |  | $ | —
Weighted-average discount rate |  |  |  |  |  |  |
Weighted-average remaining lease term (in years) |  |  |  |  |  |  |
Current lease liabilities (a) | $ | — |  | $ | — |  |  |  |
Non-current lease liabilities (a) | — |  | — |  |  |  |
Right-of-use assets (b) | — |  | — |  |  |  |

(a) Current lease liabilities are included in "Other Current Liabilities" on the Balance Sheets. Non-current lease liabilities are included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets. The difference between the total future minimum lease payments and the recorded lease liabilities is due to the impact of discounting.
(b) Operating lease right-of-use assets are included in "Other noncurrent assets" and finance lease right-of-use assets are included in "Property, Plant and Equipment" on the Balance Sheets.
The following table provides the total future minimum rental payments for leases, as well as a reconciliation of these undiscounted cash flows to the lease liabilities recognized on the Balance Sheets as of December 31, 2025.

| PPL |  | LG&E |  | KU
| Operating leases |  | Finance leases |  | Operating leases |  | Operating leases
2024 | $ | — |  | $ | — |  |  |  |
2025 | — |  | — |  |  |  |
2026 | — |  | — |  |  |  |
2027 | — |  | — |  |  |  |
2028 | — |  | — |  |  |  |
Thereafter | — |  | — |  |  |  |
Total | $ | — |  | $ | — |  | $ | — |  | $ | —
Weighted-average discount rate |  |  |  |  |  |  |
Weighted-average remaining lease term (in years) |  |  |  |  |  |  |
Current lease liabilities (a) | $ | — |  | $ | — |  |  |  |
Non-current lease liabilities (a) | — |  | — |  |  |  |
Right-of-use assets (b) | — |  | — |  |  |  |

(a) Current lease liabilities are included in "Other Current Liabilities" on the Balance Sheets. Non-current lease liabilities are included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets. The difference between the total future minimum lease payments and the recorded lease liabilities is due to the impact of discounting.
(b) Operating lease right-of-use assets are included in "Other noncurrent assets" and finance lease right-of-use assets are included in "Property, Plant and Equipment" on the Balance Sheets.
The following table provides the total future minimum rental payments for leases, as well as a reconciliation of these undiscounted cash flows to the lease liabilities recognized on the Balance Sheets as of December 31, 2025.

| PPL |  | LG&E |  | KU
| Operating leases |  | Finance leases |  | Operating leases |  | Operating leases
2024 | $ | — |  | $ | — |  |  |  |
2025 | — |  | — |  |  |  |
2026 | — |  | — |  |  |  |
2027 | — |  | — |  |  |  |
2028 | — |  | — |  |  |  |
Thereafter | — |  | — |  |  |  |
Total | $ | — |  | $ | — |  | $ | — |  | $ | —
Weighted-average discount rate |  |  |  |  |  |  |
Weighted-average remaining lease term (in years) |  |  |  |  |  |  |
Current lease liabilities (a) | $ | — |  | $ | — |  |  |  |
Non-current lease liabilities (a) | — |  | — |  |  |  |
Right-of-use assets (b) | — |  | — |  |  |  |

(a) Current lease liabilities are included in "Other Current Liabilities" on the Balance Sheets. Non-current lease liabilities are included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets. The difference between the total future minimum lease payments and the recorded lease liabilities is due to the impact of discounting.
(b) Operating lease right-of-use assets are included in "Other noncurrent assets" and finance lease right-of-use assets are included in "Property, Plant and Equipment" on the Balance Sheets.
——————————————————————http://fasb.org/us-gaap/2025#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2025#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2025#OtherAssetsNoncurrent http://fasb.org/us-gaap/2025#OtherAssetsNoncurrent http://fasb.org/us-gaap/2025#OtherAssetsNoncurrent http://fasb.org/us-gaap/2025#PublicUtilitiesPropertyPlantAndEquipmentPlantInService for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL | $ | — |  |  | 4 |  |  | 6 |
LG&E | — |  |  | — |  |  | 2 |
KU | — |  |  | — |  |  | — |

for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL | $ | — |  |  | 4 |  |  | 6 |
LG&E | — |  |  | — |  |  | 2 |
KU | — |  |  | — |  |  | — |

for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL | $ | — |  |  | 4 |  |  | 6 |
LG&E | — |  |  | — |  |  | 2 |
KU | — |  |  | — |  |  | — |

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Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K
☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2025
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period from _________ to ___________

Commission File Number | Registrant; State of Incorporation; Address and Telephone Number | IRS Employer Identification No.
1-11459 | PPL Corporation (Exact name of Registrant as specified in its charter) Pennsylvania 645 Hamilton Street Allentown, PA 18101 (610) 774-5151 | 23-2758192
1-905 | PPL Electric Utilities Corporation (Exact name of Registrant as specified in its charter) Pennsylvania 827 Hausman Road Allentown, PA 18104-9392 (610) 774-5151 | 23-0959590
1-2893 | Louisville Gas and Electric Company (Exact name of Registrant as specified in its charter) Kentucky 820 West Broadway Louisville, KY 40202 (502) 627-2000 | 61-0264150
1-3464 | Kentucky Utilities Company (Exact name of Registrant as specified in its charter) Kentucky and Virginia One Quality Street Lexington, KY 40507-1462 (502) 627-2000 | 61-0247570

Table of Contents
Securities registered pursuant to Section 12(b) of the Act:

Title of each class | Trading Symbol(s): | Name of each exchange on which registered
Common Stock of PPL Corporation | PPL | New York Stock Exchange
Junior Subordinated Notes of PPL Capital Funding, Inc. |  |
2007 Series A due 2067 | PPL/67 | New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Common Stock of PPL Electric Utilities Corporation

Indicate by check mark if the registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

PPL Corporation | Yes | ☒ | No | ☐ |
PPL Electric Utilities Corporation | Yes | ☒ | No | ☐ |
Louisville Gas and Electric Company | Yes | ☒ | No | ☐ |
Kentucky Utilities Company | Yes | ☒ | No | ☐ |

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

PPL Corporation | Yes | ☐ | No | ☒ |
PPL Electric Utilities Corporation | Yes | ☐ | No | ☒ |
Louisville Gas and Electric Company | Yes | ☐ | No | ☒ |
Kentucky Utilities Company | Yes | ☐ | No | ☒ |

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

PPL Corporation | Yes | ☒ | No | ☐ |
PPL Electric Utilities Corporation | Yes | ☒ | No | ☐ |
Louisville Gas and Electric Company | Yes | ☒ | No | ☐ |
Kentucky Utilities Company | Yes | ☒ | No | ☐ |

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).

PPL Corporation | Yes | ☒ | No | ☐ |
PPL Electric Utilities Corporation | Yes | ☒ | No | ☐ |
Louisville Gas and Electric Company | Yes | ☒ | No | ☐ |
Kentucky Utilities Company | Yes | ☒ | No | ☐ |

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies or emerging growth companies. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

| Large accelerated filer | Accelerated filer | Non-accelerated filer | Smaller reporting company | Emerging growth company
PPL Corporation | ☒ | ☐ | ☐ | ☐ | ☐
PPL Electric Utilities Corporation | ☐ | ☐ | ☒ | ☐ | ☐
Louisville Gas and Electric Company | ☐ | ☐ | ☒ | ☐ | ☐
Kentucky Utilities Company | ☐ | ☐ | ☒ | ☐ | ☐

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If emerging growth companies, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

PPL Corporation | ☐ |  |  |  |
PPL Electric Utilities Corporation | ☐ |  |  |  |
Louisville Gas and Electric Company | ☐ |  |  |  |
Kentucky Utilities Company | ☐ |  |  |  |

Indicate by check mark whether each registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

PPL Corporation | ☒ |  |  |  |
PPL Electric Utilities Corporation | ☐ |  |  |  |
Louisville Gas and Electric Company | ☐ |  |  |  |
Kentucky Utilities Company | ☐ |  |  |  |

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements
of the registrants included in the filing reflect the correction of an error to previously issued financial statements.

PPL Corporation | ☐ |  |  |  |
PPL Electric Utilities Corporation | ☐ |  |  |  |
Louisville Gas and Electric Company | ☐ |  |  |  |
Kentucky Utilities Company | ☐ |  |  |  |

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-
based compensation received by any of the registrants' executive officers during the relevant recovery period pursuant
to §240.10D-1(b).

PPL Corporation | ☐ |  |  |  |
PPL Electric Utilities Corporation | ☐ |  |  |  |
Louisville Gas and Electric Company | ☐ |  |  |  |
Kentucky Utilities Company | ☐ |  |  |  |

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

PPL Corporation | Yes | ☐ | No | ☒ |
PPL Electric Utilities Corporation | Yes | ☐ | No | ☒ |
Louisville Gas and Electric Company | Yes | ☐ | No | ☒ |
Kentucky Utilities Company | Yes | ☐ | No | ☒ |

As of June 30, 2025, PPL Corporation had 739,306,310 shares of its $0.01 par value Common Stock outstanding. The aggregate market value of these common shares (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $25,055,090,846. As of January 30, 2026, PPL Corporation had 751,306,792 shares of its $0.01 par value Common Stock outstanding.
As of January 30, 2026, PPL Corporation held all 66,368,056 outstanding common shares, no par value, of PPL Electric Utilities Corporation.
As of January 30, 2026, LG&E and KU Energy LLC held all 21,294,223 outstanding common shares, no par value, of Louisville Gas and Electric Company.
As of January 30, 2026, LG&E and KU Energy LLC held all 37,817,878 outstanding common shares, no par value, of Kentucky Utilities Company.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and are therefore filing this form with the reduced disclosure format.

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Documents incorporated by reference:
PPL Corporation has incorporated herein by reference certain sections of PPL Corporation's 2026 Notice of Annual Meeting and Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 2025 and which will provide the information required by Part III of this Report.

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PPL CORPORATION
PPL ELECTRIC UTILITIES CORPORATION
LOUISVILLE GAS AND ELECTRIC COMPANY
KENTUCKY UTILITIES COMPANY
FORM 10-K ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 2025
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This combined Form 10-K is separately filed by the following Registrants in their individual capacity: PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company. Information contained herein relating to any individual Registrant is filed by such Registrant solely on its own behalf and no Registrant makes any representation as to information relating to any other Registrant, except that information under "Forward-Looking Information" relating to subsidiaries of PPL Corporation is also attributed to PPL Corporation.
Unless otherwise specified, references in this Report, individually, to PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company are references to such entities directly or to one or more of their subsidiaries, as the case may be, the financial results of which subsidiaries are consolidated into such Registrants' financial statements in accordance with GAAP. This presentation has been applied where identification of particular subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis.

Item |  |  | Page
|  | PART I |
|  | Glossary of Terms and Abbreviations | i
|  | Forward-Looking Information | 1
1. |  | Business | 3
1A. |  | Risk Factors | 18
1B. |  | Unresolved Staff Comments | 26
1C. |  | Cybersecurity | 26
2. |  | Properties | 28
3. |  | Legal Proceedings | 29
4. |  | Mine Safety Disclosures | 29
|  | PART II |
5. |  | Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 30
6. |  | Reserved | 30
7. |  | Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | 31
|  | Overview | 31
|  | Business Strategy | 31
|  | Financial and Operational Developments | 32
|  | Results of Operations | 37
|  | PPL Corporation and Subsidiaries - Statement of Income Analysis and Segment Earnings | 38
|  | PPL Electric Utilities Corporation and Subsidiaries - Statement of Income Analysis | 46
|  | Louisville Gas and Electric Company - Statement of Income Analysis | 48
|  | Kentucky Utilities Company - Statement of Income Analysis | 49

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Item |  |  | Page
|  | Financial Condition | 49
|  | Liquidity and Capital Resources | 50
|  | Risk Management | 58
|  | Related Party Transactions | 60
|  | Acquisitions, Developments and Divestitures | 60
|  | Environmental Matters | 60
|  | Sustainability | 61
|  | Cybersecurity | 61
|  | Competition | 61
|  | New Accounting Guidance | 61
|  | Application of Critical Accounting Policies | 61
|  | Other Information | 65
7A. |  | Quantitative and Qualitative Disclosures About Market Risk | 65
|  | Reports of Independent Registered Public Accounting Firms (PCAOB ID No. 34) | 66
8. |  | Financial Statements and Supplementary Data |
|  | FINANCIAL STATEMENTS |
|  | PPL Corporation and Subsidiaries |
|  | Consolidated Statements of Income for the years ended December 31, 202 5, 202 4 and 20 23 | 75
|  | Consolidated Statements of Comprehensive Income for the years ended December 31, 202 5, 202 4 and 202 3 | 76
|  | Consolidated Statements of Cash Flows for the years ended December 31, 202 5, 202 4 and 202 3 | 77
|  | Consolidated Balance Sheets at December 31, 202 5 and 20 2 4 | 78
|  | Consolidated Statements of Equity for the years ended December 31, 202 5, 202 4 and 20 23 | 80
|  | PPL Electric Utilities Corporation and Subsidiaries |
|  | Consolidated Statements of Income for the years ended December 31, 202 5, 202 4 and 20 23 | 82
|  | Consolidated Statements of Cash Flows for the years ended December 31, 202 5, 202 4 and 20 23 | 83
|  | Consolidated Balance Sheets at December 31, 202 5 and 20 24 | 84
|  | Consolidated Statements of Equity for the years ended December 31, 2 025, 202 4 and 20 23 | 86
|  | Louisville Gas and Electric Company |
|  | Statements of Income for the years ended December 31, 202 5, 202 4 and 20 23 | 88
|  | Statements of Cash Flows for the years ended December 31, 202 5, 202 4 and 20 23 | 89
|  | Balance Sheets at December 31, 202 5 and 202 4 | 90
|  | Statements of Equity for the years ended December 31, 202 5, 202 4 and 20 23 | 92
|  | Kentucky Utilities Company |
|  | Statements of Income for the years ended December 31, 202 5, 202 4 and 20 23 | 94
|  | Statements of Cash Flows for the years ended December 31, 202 5, 202 4 and 2 023 | 95
|  | Balance Sheets at December 31, 202 5 and 20 24 | 96
|  | Statements of Equity for the years ended December 31, 202 5, 202 4 and 20 23 | 98

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Item |  |  | Page
|  | COMBINED NOTES TO FINANCIAL STATEMENTS |
|  | Index to Combined Notes to Consolidated Financial Statements | 99
|  | 1. Summary of Significant Accounting Policies | 99
|  | 2. Segment and Related Information | 109
|  | 3. Revenue from Contracts with Customers | 113
|  | 4. Preferred Securities | 117
|  | 5. Earnings Per Share | 117
|  | 6. Income and Other Taxes | 118
|  | 7. Utility Rate Regulation | 126
|  | 8. Financing Activities | 139
|  | 9. Acquisitions, Development and Divestitures | 144
|  | 10. Retirement and Postemployment Benefits | 145
|  | 11. Jointly Owned Facilities | 155
|  | 12. Commitments and Contingencies | 156
|  | 13. Related Party Transactions | 164
|  | 14. Other Income (Expense) - net | 165
|  | 15. Fair Value Measurements | 166
|  | 16. Derivative Instruments and Hedging Activities | 169
|  | 17. Goodwill and Other Intangible Assets | 175
|  | 18. Asset Retirement Obligations | 177
|  | 19. Accumulated Other Comprehensive Income (Loss) | 178
|  | 20. New Accounting Guidance Pending Adoption | 179
9. |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 180
9A. |  | Controls and Procedures | 180
9B. |  | Other Information | 183
9C. |  | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 183
|  | PART III |
10. |  | Directors, Executive Officers and Corporate Governance | 184
11. |  | Executive Compensation | 187
12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 187
13. |  | Certain Relationships and Related Transactions, and Director Independence | 189
14. |  | Principal Accounting Fees and Services | 189
|  | PART IV |
15. |  | Exhibits, Financial Statement Schedules | 191
|  | Shareowner and Investor Information | 192
|  | Exhibit Index | 194
|  | Signatures | 208
|  | Certifications of Principal Executive Officer and Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|  | Certificates of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|  | PPL Corporation and Subsidiaries Long-term Debt Schedule |

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GLOSSARY OF TERMS AND ABBREVIATIONS
PPL Corporation and its subsidiaries
CEP Reserves - CEP Reserves, Inc., a cash management subsidiary of PPL that maintains cash reserves for the balance sheet management of PPL and certain subsidiaries.
KU - Kentucky Utilities Company, a public utility subsidiary of LKE engaged in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky.
LG&E - Louisville Gas and Electric Company, a public utility subsidiary of LKE engaged in the regulated generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas in Kentucky.
LKE - LG&E and KU Energy LLC, a subsidiary of PPL and the parent of LG&E, KU and other subsidiaries.
LKS - LG&E and KU Services Company, a subsidiary of LKE that provides administrative, management and support services primarily to LG&E and KU, as well as to LKE and its other subsidiaries.
Narragansett Electric - The Narragansett Electric Company, an entity that serves electric and natural gas customers in Rhode Island. Narragansett Electric is sometimes referred to as Rhode Island Energy or RIE.
PPL - PPL Corporation, the ultimate parent holding company of PPL Electric, PPL Energy Funding, PPL Capital Funding, LKE, RIE and other subsidiaries.
PPL Capital Funding - PPL Capital Funding, Inc., a financing subsidiary of PPL that provides financing for the operations of PPL and certain subsidiaries. Debt issued by PPL Capital Funding is fully and unconditionally guaranteed as to payment by PPL.
PPL Electric - PPL Electric Utilities Corporation, a public utility subsidiary of PPL engaged in the regulated transmission and distribution of electricity in its Pennsylvania service area and that provides electricity supply to its retail customers in this area as a PLR.
PPL Energy Holdings - PPL Energy Holdings, LLC, a subsidiary of PPL and the parent holding company of PPL Energy Funding, LKE, PPL Electric, PPL Rhode Island Holdings, PPL Services and other subsidiaries.
PPL Rhode Island Holdings - PPL Rhode Island Holdings, LLC, a subsidiary of PPL Energy Holdings formed for the purpose of acquiring Narragansett Electric to which certain interests of PPL Energy Holdings in the Narragansett Stock Purchase Agreement were assigned.
PPL Services - PPL Services Corporation, a subsidiary of PPL that provides administrative, management and support services to PPL and its subsidiaries.
PPL WPD Limited - Prior to the sale of the U.K. utility business on June 14, 2021, PPL WPD Limited was an indirect parent to WPD. PPL WPD Limited was not included in the sale of the U.K. utility business on June 14, 2021. PPL WPD Limited was dissolved June 17, 2025.
RIE - Rhode Island Energy, the name under which Narragansett Electric provides gas and electric services to customers in Rhode Island.
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Other terms and abbreviations
£ - British pound sterling.
401(h) account(s) - a sub account established within a qualified pension trust to provide for the payment of retiree medical costs.
2024 Form 10-K - Annual Report filed with the SEC on Form 10-K for the year ended December 31, 2024.
Act 11 - Act 11 of 2012 that became effective on April 16, 2012. The Pennsylvania legislation authorized the PAPUC to approve two specific ratemaking mechanisms: the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, a DSIC.
Act 129 - Act 129 of 2008 that became effective in October 2008. The law amended the Pennsylvania Public Utility Code and created an energy efficiency and conservation program and smart metering technology requirements, adopted new PLR electricity supply procurement rules, provided remedies for market misconduct and changed the Alternative Energy Portfolio Standard (AEPS).
AFUDC - allowance for funds used during construction. The cost of equity and debt funds used to finance construction projects of regulated businesses, which is capitalized as part of construction costs.
AOCI - accumulated other comprehensive income or loss.
ARO - asset retirement obligation.
ATM Program - at-the-market stock offering program.
Bcf - billion cubic feet. A unit of measure commonly used in quoting volumes of natural gas.
CCR(s) - coal combustion residual(s). CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes.
CLC - Corporate Leadership Council - executive management committee that is comprised of the President and Chief Executive Officer, Chief Technology and Innovation Officer, Chief Financial Officer, Chief Human Resources Officer, Chief Legal Officer, Chief Operating Officer-Utilities, Executive Vice President of Engineering, Construction and Generation.
Clean Air Act - federal legislation enacted to address certain environmental issues related to air emissions, including acid rain, ozone and toxic air emissions.
Clean Water Act - federal legislation enacted to address certain environmental issues relating to water quality including effluent discharges, cooling water intake, and dredge and fill activities.
CPCN - Certificate of Public Convenience and Necessity. Authority granted by the KPSC pursuant to Kentucky Revised Statute 278.020 to provide utility service to or for the public or the construction of certain plant, equipment, property or facilities for furnishing of utility service to the public. A CPCN is required for any capital addition, subject to KPSC jurisdiction, in excess of $100 million.
Customer Choice Act - the Pennsylvania Electricity Generation Customer Choice and Competition Act, legislation enacted to restructure the state's electric utility industry to create retail access to a competitive market for generation of electricity.
DDCP - Directors Deferred Compensation Plan.
DER - Distributed Energy Resources.
DRIP - PPL Amended and Restated Dividend Reinvestment and Direct Stock Purchase Plan.
DSIC - Distribution System Improvement Charge. Authorized under Act 11, which is an alternative ratemaking mechanism providing more-timely cost recovery of qualifying distribution system capital expenditures.
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DSM - Demand Side Management. Pursuant to Kentucky Revised Statute 278.285, the KPSC may determine the reasonableness of DSM programs proposed by any utility under its jurisdiction. DSM programs consist of energy efficiency programs intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information regarding their energy usage and support energy efficiency.
Earnings from Ongoing Operations - a non-GAAP financial measure of earnings adjusted for the impact of special items and used in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A).
EBPB - Employee Benefit Plan Board. The administrator of PPL's U.S. qualified retirement plans, which is charged with the fiduciary responsibility to oversee and manage those plans and the investments associated with those plans.
ECR - Environmental Cost Recovery. Pursuant to Kentucky Revised Statute 278.183, Kentucky electric utilities are entitled to the current recovery of costs of complying with the Clean Air Act, as amended, and those federal, state or local environmental requirements that apply to coal combustion wastes and byproducts from the production of energy from coal.
ELG(s) - Effluent Limitation Guidelines, regulations promulgated by the EPA.
Environmental Response Fund - Established in RIPUC Docket No. 2930. Created to satisfy remedial and clean-up obligations of RIE arising from the past ownership and/or operation of manufactured gas plants and sites associated with the operation and disposal activities of such gas plants.
EPA - Environmental Protection Agency, a U.S. government agency.
EPS - earnings per share.
FERC - Federal Energy Regulatory Commission, the U.S. federal agency that regulates, among other things, interstate transmission and wholesale sales of electricity, hydroelectric power projects and related matters.
FY - fiscal year.
GAAP - Generally Accepted Accounting Principles in the U.S.
GHG(s) - greenhouse gas(es).
GWh - gigawatt-hour, one million kilowatt hours.
ICPKE - The PPL Incentive Compensation Plan for Key Employees. The ICPKE provides for incentive compensation to certain employees below the level of senior executive.
If-Converted Method - A method applied to calculate diluted EPS for a company with outstanding convertible debt. This method generally adds back the interest charges, net of tax, of the debt to net income and the convertible debt is assumed to have been converted to equity at the beginning of the period, and the resulting common shares are treated as outstanding shares for diluted EPS calculations.
IRA - Inflation Reduction Act, a U.S. federal law, which aims to curb inflation by possibly reducing the federal government budget deficit, lowering prescription drug prices, and investing in domestic energy production while promoting clean energy.
IRS - Internal Revenue Service, a U.S. government agency.
ISO - Independent System Operator.
ISR - Infrastructure, safety and reliability.
KPSC - Kentucky Public Service Commission, the state agency that has jurisdiction over the regulation of rates and service of utilities in Kentucky.
KU 2010 Mortgage Indenture - KU's indenture, dated as of October 1, 2010, to the Bank of New York Mellon, as supplemented.
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kVA - kilovolt ampere.
kWh - kilowatt hour, basic unit of electrical energy.
LCIDA - Lehigh County Industrial Development Authority.
LG&E 2010 Mortgage Indenture - LG&E's indenture, dated as of October 1, 2010, to the Bank of New York Mellon, as supplemented.
LRS - Last Resort Service, the role of RIE in providing default electricity supply within its delivery area to all customers who have not elected to receive their electric supply from a non-regulated power producer or any customer who, for any reason, has stopped receiving generation service from a non-regulated power producer.
McF - one thousand cubic feet, a unit of measure for natural gas.
MMBtu - one million British Thermal Units.
Moody's - Moody's Ratings, a division of Moody's Corporation, a credit rating agency.
MW - megawatt, one thousand kilowatts.
MWac - megawatt, alternating current. The measure of the power output from a solar installation.
NAAQS - National Ambient Air Quality Standards periodically adopted pursuant to the Clean Air Act.
National Grid USA - National Grid USA is a wholly-owned subsidiary of National Grid plc, a British multinational electricity and gas utility company headquartered in London, England.
NERC - North American Electric Reliability Corporation.
NGCC - Natural gas combined cycle.
NPNS - the normal purchases and normal sales exception as permitted by derivative accounting rules. Derivatives that qualify for this exception may receive accrual accounting treatment.
OCI - other comprehensive income or loss.
OVEC - Ohio Valley Electric Corporation, located in Piketon, Ohio, an entity in which LG&E owns a 5.63% interest and KU owns a 2.50% interest, which are recorded at cost. OVEC owns and operates two coal-fired power plants, the Kyger Creek plant in Ohio and the Clifty Creek plant in Indiana, with combined capacities of 2,120 MW.
PAPUC - Pennsylvania Public Utility Commission, the state agency that regulates certain ratemaking, services, accounting and operations of Pennsylvania utilities.
Performance unit - stock-based compensation award that represents a variable number of shares of PPL common stock that a recipient may receive based on PPL's attainment of (i) relative total shareowner return (TSR) as compared to companies in the PHLX Utility Sector Index; (ii) corporate return on equity (ROE); (iii) corporate earnings growth (EG); and (iv) corporate environmental, social and governance (ESG) metrics.
PHMSA - Pipeline and Hazardous Materials Safety Administration.
PJM - PJM Interconnection, L.L.C., operator of the electricity transmission network and electricity energy market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
PLR - Provider of Last Resort, the role of PPL Electric in providing default electricity supply within its delivery area to retail customers who have not chosen to select an alternative electricity supplier under the Customer Choice Act.
PP&E - property, plant and equipment.
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PPA(s) - power purchase agreement(s).
PPL EU Services - PPL EU Services Corporation, a former subsidiary of PPL that, prior to being merged into PPL Services on December 31, 2021, provided administrative, management and support services primarily to PPL Electric.
PPL WPD Investments Limited - PPL WPD Investments Limited, which was, prior to the sale of the U.K. utility business on June 14, 2021, a subsidiary of PPL WPD Limited and parent to WPD plc. PPL WPD Investments Limited was included in the sale of the U.K. utility business on June 14, 2021.
RAR - Retired Asset Recovery rider, established by KPSC orders in 2021 to provide for recovery of and return on the remaining investment in certain electric generating units upon their retirement over a ten-year period following retirement.
Registrant(s) - refers to the Registrants named on the cover of this Report (each a "Registrant" and collectively, the "Registrants").
RIPUC - Rhode Island Public Utilities Commission, a three-member quasi-judicial tribunal with jurisdiction, powers, and duties to implement and enforce the standards of conduct under R.I. Gen. Laws § 39-1-27.6 and to hold investigations and hearings involving the rates, tariffs, tolls, and charges, and the sufficiency and reasonableness of facilities and accommodations of public utilities.
Rhode Island Division of Public Utilities and Carriers - the Rhode Island Division of Public Utilities and Carriers, which is headed by an Administrator who is not a Commissioner of the RIPUC, exercises the jurisdiction, supervision, power, and duties not specifically assigned to the RIPUC.
RTO - Regional Transmission Operator, an electric power transmission system operator that coordinates, controls and monitors a multi-state electric grid.
ROE - Return on equity.
Safari - Safari Energy, LLC, which was, prior to the sale of Safari Holdings on November 1, 2022, a subsidiary of Safari Holdings that provided solar energy solutions for commercial customers in the U.S.
Safari Holdings - Safari Holdings, LLC, which was, prior to its sale on November 1, 2022, a subsidiary of PPL and parent holding company of Safari.
Sarbanes-Oxley - Sarbanes-Oxley Act of 2002, which sets requirements for management's assessment of internal controls for financial reporting. It also requires an independent auditor to make its own assessment.
Scrubber - an air pollution control device that can remove particulates and/or gases (primarily sulfur dioxide) from exhaust gases.
SEC - the U.S. Securities and Exchange Commission, a U.S. government agency primarily responsible to protect investors and maintain the integrity of the securities markets.
SIP - PPL Corporation's Amended and Restated 2012 Stock Incentive Plan.
Smart metering technology - technology that can measure, among other things, time of electricity consumption to permit offering rate incentives for usage during lower cost or demand intervals. The use of this technology also has the potential to strengthen network reliability.
SOFR - Secured Overnight Financing Rate, a broad measure of the cost of borrowing cash overnight collateralized by Treasury securities.
S&P - S&P Global Ratings, a credit rating agency.
Superfund - federal environmental statute that addresses remediation of contaminated sites; states also have similar statutes.
TCJA - Tax Cuts and Jobs Act. Comprehensive U.S. federal tax legislation enacted on December 22, 2017.
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Total shareowner return - the change in market value of a share of the company's common stock plus the value of all dividends paid on a share of the common stock during the applicable performance period, divided by the price of the common stock as of the beginning of the performance period. The price used for purposes of this calculation is the average share price for the 20 trading days at the beginning and end of the applicable period.
Treasury Stock Method - a method applied to calculate diluted EPS that assumes any proceeds that could be obtained upon exercise of options and warrants (and their equivalents) would be used to purchase common stock at the average market price during the relevant period.
U.K. utility business - PPL WPD Investments Limited and its subsidiaries, including, notably, WPD plc and the four distribution network operators, which substantially represented PPL's U.K. Regulated segment. The U.K. utility business was sold on June 14, 2021.
VEBA - Voluntary Employee Beneficiary Association, a tax-exempt trust under the Internal Revenue Code Section 501 (c)(9) used by employers to fund and pay eligible medical, life and similar benefits.
VSCC - Virginia State Corporation Commission, the state agency that has jurisdiction over the regulation of Virginia corporations, including utilities.
WPD - Prior to the sale of the U.K. utility business on June 14, 2021, refers to PPL WPD Investments Limited and its subsidiaries. WPD was included in the sale of the U.K. utility business on June 14, 2021.
WPD plc - Western Power Distribution plc, prior to the sale of the U.K utility business, a U.K. indirect subsidiary of PPL WPD Limited. Its principal indirectly owned subsidiaries are WPD (East Midlands), WPD (South Wales), WPD (South West) and WPD (West Midlands). WPD plc was included in the sale of the U.K. utility business on June 14, 2021.
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Forward-looking Information
Statements contained in this Annual Report concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are other than statements of historical fact are "forward-looking statements" within the meaning of the federal securities laws. Although the Registrants believe that the expectations and assumptions reflected in these statements are reasonable, there can be no assurance that these expectations will prove to be correct. Forward-looking statements are subject to many risks and uncertainties, and actual results may differ materially from the results discussed in forward-looking statements. In addition to the specific factors discussed in "Item 1A. Risk Factors" and in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report, the following are among the important factors that could cause actual results to differ materially and adversely from the forward-looking statements:
•weather and other conditions affecting generation, transmission and distribution operations, operating costs and customer energy use;
•strategic acquisitions, dispositions, joint-ventures or similar transactions and our ability to consummate these business transactions, integrate the acquired entities or realize expected benefits from them;
•the outcome of rate cases or other cost recovery, revenue or regulatory proceedings;
•catastrophic events such as epidemic or pandemic health events, wildfires, earthquakes, explosions, floods, droughts, tornadoes, hurricanes and other extreme weather-related events (including events potentially caused or exacerbated by climate change) and their impact on economic conditions, financial markets and supply chains;
•capital market conditions, including the availability of capital, credit or insurance, changes in interest rates and certain economic indices, and decisions regarding capital structure;
•volatility in or the impact of other changes in financial markets, commodity prices and economic conditions, including inflation;
•the direct or indirect effects on PPL or its subsidiaries or business systems of cyber-based intrusion or the threat of cyberattacks;
•development, adoption and use of artificial intelligence by us, our customers and our third-party vendors;
•the effect of existing trade policies (including tariffs and other trade measures), the establishment of additional trade policies or subsequent changes to trade policies once announced or implemented, on the cost or availability of imported goods;
•significant changes in the demand for electricity, including uncertainties related to projected rapid growth in electricity demand driven primarily by data centers and other large load customers and the related requirement for substantial new generation and transmission investment, which may create capital access, revenue recovery and customer affordability risks;
•expansion of alternative and distributed sources of electricity generation and storage;
•the effectiveness of our risk management programs, including commodity and interest rate hedging;
•prolonged or recurring US federal government shutdowns;
•defaults by counterparties or suppliers for energy, capacity, coal, natural gas or key commodities, goods or services;
•a material decline in the market value of PPL's equity;
•significant decreases in the fair value of debt and equity securities and their impact on the value of assets in defined benefit plans, and the related cash funding requirements if the fair value of those assets decline;
•interest rates and their effect on pension and retiree medical liabilities, ARO liabilities, interest payable on certain debt securities, and the general economy;
•the potential impact of any unrecorded commitments and liabilities of the Registrants and their subsidiaries;
•new accounting requirements or new interpretations or applications of existing requirements;
•adverse changes in the corporate credit ratings or securities analyst rankings of the Registrants and their securities;
•any requirement to record impairment charges pursuant to GAAP with respect to any of our significant investments;
•laws or regulations to reduce emissions of GHGs or the physical effects of climate change;
•the availability of electricity and natural gas, and any consequences of a perceived or actual inability to serve demand reliably;
•continuing ability to access fuel supply for LG&E and KU, as well as the ability to recover fuel costs and environmental expenditures in a timely manner at LG&E and KU and natural gas supply costs at LG&E and RIE;
•war, armed conflicts, terrorist attacks, or similar disruptive events, including the ongoing conflicts in Ukraine and the Middle East;
•changes in political, regulatory or economic conditions in states or regions where the Registrants or their subsidiaries conduct business;
•the ability to obtain necessary governmental permits and approvals;
•changes in state or federal tax laws or regulations;
•changes in state, federal or foreign legislation or regulatory developments;
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•the impact of any state, federal or foreign investigations applicable to the Registrants, their subsidiaries or the energy industry;
•our ability to attract and retain qualified employees;
•the effect of changing expectations and demands of our customers, regulators, investors and stakeholders, including differing views on environmental, social and governance concerns;
•the effect of any business or industry restructuring;
•the ability to control costs and avoid cost and schedule overruns during the development, construction and operation of significant projects, including generation and battery storage facilities and IT infrastructure;
•development of new projects, markets and technologies, including the potential impact of advancing technologies on the electricity demand required by data centers and other large load customers;
•collective labor bargaining negotiations and labor costs;
•risks related to wildfires, including costs of potential regulatory penalties and other liabilities, and the cost and availability of insurance and damages in excess of insurance liability coverage; and
•the outcome of litigation involving the Registrants and their subsidiaries.
Any forward-looking statements should be considered in light of these important factors and in conjunction with other documents of the Registrants on file with the SEC.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for the Registrants to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Any forward-looking statement speaks only as of the date on which such statement is made, and the Registrants undertake no obligation to update the information contained in the statement to reflect subsequent developments or information.
Investors should note that PPL announces material financial information in SEC filings, press releases and public conference calls. In accordance with SEC guidelines, PPL also uses the Investors section of its website, www.pplweb.com, to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on PPL's website is not part of this document.
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PART I
ITEM 1. BUSINESS
General
(All Registrants)
PPL, headquartered in Allentown, Pennsylvania, is a utility holding company, incorporated in 1994. PPL, through its regulated utility subsidiaries, delivers electricity to customers in Pennsylvania, Kentucky, Virginia, and Rhode Island; delivers natural gas to customers in Kentucky and Rhode Island; and generates electricity from power plants in Kentucky.
PPL's principal subsidiaries at December 31, 2025 are shown below (* denotes a Registrant).

|  |  |  |  |  |  | PPL Corporation* |  |  |  |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  | PPL Capital Funding Provides financing for the operations of PPL and certain subsidiaries |
| PPL Electric* Engages in the regulated transmission and distribution of electricity in Pennsylvania |  |  | LKE A holding company that owns regulated utility operations through its subsidiaries, LG&E and KU |  |  | RIE Engages in the regulated transmission, distribution and sale of electricity and regulated distribution and sale of natural gas in Rhode Island |
|  |  |  | LG&E* Engages in the regulated generation, transmission, distribution and sale of electricity and regulated distribution and sale of natural gas in Kentucky |  |  | KU* Engages in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky |  |  |  |
| Pennsylvania Regulated Segment |  | Kentucky Regulated Segment |  | Rhode Island Regulated Segment |

In addition to PPL, the other Registrants included in this filing are as follows.
PPL Electric, headquartered in Allentown, Pennsylvania, is a wholly-owned subsidiary of PPL and a regulated public utility that is an electricity transmission and distribution service provider in eastern and central Pennsylvania. PPL Electric is subject to regulation as a public utility by the PAPUC, and certain of its transmission activities are subject to the jurisdiction of the FERC under the Federal Power Act. PPL Electric delivers electricity in its Pennsylvania service area and provides electricity supply to retail customers in that area as a PLR under the Customer Choice Act. PPL Electric was organized in 1920 as Pennsylvania Power & Light Company.
LG&E, headquartered in Louisville, Kentucky, is a wholly-owned subsidiary of LKE and a regulated utility engaged in the generation, transmission, distribution and sale of electricity and distribution and sale of natural gas in Kentucky. LG&E is subject to regulation as a public utility by the KPSC, and certain of its transmission activities are subject to the jurisdiction of the FERC under the Federal Power Act. LG&E was incorporated in 1913.
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KU, headquartered in Lexington, Kentucky, is a wholly-owned subsidiary of LKE and a regulated utility engaged in the generation, transmission, distribution and sale of electricity in Kentucky and Virginia. KU is subject to regulation as a public utility by the KPSC and the VSCC, and certain of its transmission and wholesale power activities are subject to the jurisdiction of the FERC under the Federal Power Act. KU serves its Kentucky customers under the KU name and its Virginia customers under the Old Dominion Power name. KU was incorporated in Kentucky in 1912 and in Virginia in 1991.
Segment Information
(PPL)
PPL is organized into three reportable segments as depicted in the chart above: Kentucky Regulated, which primarily represents the results of LG&E and KU, Pennsylvania Regulated, which primarily represents the results of PPL Electric, and Rhode Island Regulated, which primarily represents the results of RIE. "Corporate and Other" primarily includes corporate level financing costs, certain unallocated corporate costs, and certain non-recoverable costs incurred in conjunction with the acquisition of RIE.
A comparison of PPL's Regulated segments is shown below.

| Kentucky |  | Pennsylvania |  | Rhode Island
| Regulated |  | Regulated |  | Regulated
For the year ended December 31, 2025: |  |  |  |  |
Operating Revenues (in billions) | $ | 3.8 |  |  | $ | 3.1 |  |  | $ | 2.2 |
Net Income (in millions) | $ | 674 |  |  | $ | 639 |  |  | $ | 85 |
Electricity delivered (GWh) | 31,368 |  |  | 37,186 |  |  | 7,165 |
Natural gas delivered (Bcf) | 47 |  |  | — |  |  | 40 |
At December 31, 2025: |  |  |  |  |
Regulatory Asset Base (in billions) (a) | $ | 13.6 |  |  | $ | 11.1 |  |  | $ | 4.3 |
Service area (in square miles) | 8,000 |  |  | 10,000 |  |  | 1,200 |
Customers (in millions) | 1.4 |  |  | 1.5 |  |  | 0.8 |

(a)Represents capitalization for Kentucky Regulated and rate base for Pennsylvania Regulated and Rhode Island Regulated. The amount for Pennsylvania Regulated reflects estimated 2025 year-end rate base for Pennsylvania electric distribution. The amount for Rhode Island Regulated excludes acquisition-related adjustments for non-earning assets.
See Note 2 to the Financial Statements for additional financial information by segment. See Note 3 to the Financial Statements for additional revenue information.
(PPL Electric, LG&E and KU)
PPL Electric has two operating segments, distribution and transmission, which are aggregated into a single reportable segment. Each of LG&E and KU operates as a single operating and reportable segment.
Kentucky Regulated Segment (PPL)
The Kentucky Regulated segment consists primarily of the regulated electricity generation, transmission and distribution operations conducted by LG&E and KU, as well as LG&E's regulated distribution and sale of natural gas.
(PPL, LG&E and KU)
LG&E and KU are engaged in the regulated generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, also Virginia. LG&E also engages in the distribution and sale of natural gas in Kentucky. LG&E provides electric service to approximately 443,000 customers and provides natural gas service to approximately 336,000 customers in Louisville and 16 surrounding counties, covering approximately 700 square miles. KU provides electric service to approximately 553,000 customers in 77 counties in central, southeastern and western Kentucky and approximately 28,000 customers in five counties in southwestern Virginia, covering approximately 4,800 non-contiguous square miles. KU also sells wholesale electricity to two municipalities in Kentucky under load following contracts.
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Franchises and Licenses
LG&E and KU provide electricity delivery service, and LG&E provides natural gas distribution service, in their respective service territories pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by state legislatures, cities or municipalities or other entities.
Competition
There are currently no other electric public utilities operating within the electric service areas of LG&E and KU. From time to time, bills are introduced into the Kentucky General Assembly which seek to authorize, promote or mandate increased distributed generation, customer choice or other developments. Neither the Kentucky General Assembly nor the KPSC has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of legislative or regulatory actions, if any, regarding industry restructuring and their impact on LG&E and KU, which may be significant, cannot currently be predicted. Virginia, formerly a deregulated jurisdiction, has enacted legislation that implemented a hybrid model of cost-based regulation. KU's operations in Virginia have been and remain regulated.
Alternative energy sources such as electricity, oil, propane and other fuels indirectly impact LG&E's natural gas revenues. Marketers may also compete to sell natural gas to certain large end-users. LG&E's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity. Therefore, customer natural gas purchases from alternative suppliers do not generally impact LG&E's profitability. Some large industrial and commercial customers, however, may physically bypass LG&E's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.
Power Supply
At December 31, 2025, LG&E owned generating capacity of 2,466 MW and KU owned generating capacity of 4,798 MW. See "Item 2. Properties - Kentucky Regulated Segment" for a complete list of generating facilities.
The system capacity of LG&E's and KU's owned generation is based upon several factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changes in circumstances.
During 2025, LG&E's and KU's power plants generated the following amounts of electricity:

| GWh
Fuel Source | LG&E |  | KU
Coal | 10,331 |  |  | 14,738 |
Gas | 1,613 |  |  | 4,899 |
Hydro | 220 |  |  | 105 |
Solar | 8 |  |  | 12 |
Total (a) | 12,172 |  |  | 19,754 |

(a)This generation represents an increase for LG&E of 3% and an increase for KU of 5% from 2024 output.
The majority of LG&E's and KU's generated electricity was used to supply their retail customer bases.
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their customers. When LG&E has excess generation capacity after serving its own customers and its generation cost is lower than that of KU, KU purchases electricity from LG&E and vice versa.
Due to environmental requirements, energy efficiency measures, and the relative cost of replacement resources, as of December 31, 2025, LG&E and KU have retired approximately 1,500 MW of coal-fired generation plants since 2010.
LG&E and KU received approval from the KPSC to develop a 4 MW Solar Share facility to service a Solar Share program. The Solar Share program is a voluntary program that allows customers to subscribe capacity in the Solar Share facility. Construction commences, in 500-kilowatt phases, when subscription is complete. Through December 31, 2025, construction of five 500-kilowatt phases was completed. LG&E and KU continue to market the program and are accepting subscriptions for the sixth 500-kilowatt phase.
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On November 6, 2023, the KPSC issued an order approving LG&E's and KU's December 15, 2022 CPCN requests (i) to construct a 645 MW net summer rating NGCC combustion turbine at LG&E's Mill Creek Generating Station in Jefferson County, Kentucky, (ii) to construct a 120 MWac solar photovoltaic electric generating facility in Mercer County, Kentucky, (iii) to acquire a 120 MWac solar facility to be built by a third-party solar developer in Marion County, Kentucky and (iv) to construct a 125 MW, 4-hour battery energy storage system facility at KU's E.W. Brown Generating Station. The order also authorized LG&E's and KU's entry into four potential solar PPAs, subject to certain conditions, but deferred for future proceedings specific decisions on cost recovery treatment or mechanisms. Agreements related to two of the four potential solar PPAs have been terminated. One PPA agreement was terminated by the developer due to land control issues. The second agreement terminated contractually due to a PPA price increase that was not acceptable to LG&E and KU. Further, the order approved the new, adjusted or expanded energy efficiency programs contained in the requested 2024-2030 DSM plan.
The KPSC order included approval of the requested retirements of two existing coal-fired generation units, LG&E's Mill Creek Unit 1 (300 MW) in 2024, which occurred on December 31, 2024, and Mill Creek Unit 2 (297 MW) in 2027, subject to certain conditions, and three small gas-fired units. LG&E subsequently requested for Mill Creek Unit 2 to remain operational past the 2027 date. The order denied approval of the retirement of KU's E.W. Brown 3 Unit (412 MW) and Ghent Unit 2 (486 MW) in 2028 at this time, citing the need for additional clarity regarding environmental compliance regulations.
The new NGCC facility will be jointly owned by LG&E (31%) and KU (69%) and the solar units will be jointly owned by LG&E (37%) and KU (63%), the battery storage unit will be owned by LG&E, and the proposed PPA transactions and DSM programs will be entered into or conducted jointly by LG&E and KU, consistent with LG&E and KU's shared dispatch, cost allocation, tariff or other frameworks.
In February 2024, LG&E and KU entered into agreements to begin construction of Mill Creek Unit 5. Total project costs are estimated at approximately $1.0 billion, including AFUDC. Commercial operation of the facility is anticipated to begin in mid-2027.
See "2025 CPCN" and "Rate Case Proceedings" in Note 7 to the Financial Statements for additional information on the 2025 application filed with the KPSC regarding certain future plans for new generation and generation-related construction matters.
Fuel Supply
Coal and natural gas are expected to be the predominant fuels used by LG&E and KU for generation for the foreseeable future. Natural gas used for generation is purchased using contractual arrangements separate from LG&E's natural gas distribution operations. Natural gas and oil are also used for intermediate and peaking capacity and flame stabilization in coal-fired boilers.
Fuel inventory is maintained at levels estimated to be necessary to avoid operational disruptions at coal-fired generating units. Reliability of coal deliveries can be affected from time to time by several factors including fluctuations in demand, coal mine production issues, high or low river level events, lock outages and other supplier or transporter operating or financial difficulties.
LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2030 and augment their coal supply agreements with spot market purchases, as needed.
For their existing units, LG&E and KU expect, for the foreseeable future, to purchase most of their coal from western Kentucky, southern Indiana, southern Illinois, northern West Virginia and western Pennsylvania. LG&E and KU continue to purchase certain quantities of ultra-low sulfur content coal from Wyoming for blending at Trimble County Unit 2. Coal is delivered to the generating plants primarily by barge and rail.
To enhance the reliability of natural gas supply, LG&E and KU have secured firm long-term pipeline transport capacity services with contracts of various durations through 2056 on the interstate pipeline serving Cane Run Unit 7, six simple cycle combustion turbines at the Trimble County site, and the future Mill Creek Unit 5. This pipeline also serves the two simple cycle units at the Paddy's Run site. For the seven simple cycle combustion turbines at the E.W. Brown facility, no firm long-term pipeline transport capacity has been purchased due to the facility's connection to two interstate pipelines and some of the units having dual fuel capability.
LG&E and KU have firm contracts for a portion of the natural gas fuel for Cane Run Unit 7 through 2027. The bulk of the natural gas fuel is expected to be purchased on the spot market.
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(PPL and LG&E)
Natural Gas Distribution Supply
Four underground natural gas storage fields in service, with a current working natural gas capacity of approximately 11 Bcf, are used to provide natural gas service to LG&E's firm sales customers. Natural gas is stored during the summer season for withdrawal during the following winter heating season. Without this storage capacity, LG&E would need to purchase additional natural gas and pipeline transportation services during winter months when customer demand increases, and the cost of natural gas supply and pipeline transportation services are expected to be higher. At December 31, 2025, LG&E had 9.7 Bcf of natural gas stored underground with a carrying value of $33 million.
LG&E has a portfolio of supply arrangements of varying terms that provide competitively priced natural gas designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. In tandem with pipeline transportation services, these natural gas supplies provide the reliability and flexibility necessary to serve LG&E's natural gas customers.
LG&E purchases natural gas supply transportation services from two pipelines. LG&E has a set of contracts with one pipeline that are subject to termination by LG&E between 2028 and 2031. Total winter season capacity under these contracts is 184,900 MMBtu/day and summer season capacity is 60,000 MMBtu/day. LG&E has two additional contracts with this same pipeline. One contract is for pipeline capacity through 2031 for 60,000 MMBtu/day during both the winter and summer seasons. The other contract is for pipeline capacity through 2028 for 30,000 MMBtu/day during the winter season. LG&E has two contracts with a second pipeline with a total capacity of 40,000 MMBtu/day during both the winter and summer seasons that expire in 2030.
LG&E expects to purchase natural gas supplies for its gas distribution operations from onshore producing regions in South Texas, East Texas, North Louisiana and Arkansas, as well as gas originating in the Marcellus and Utica production areas.
(PPL, LG&E and KU)
Transmission
LG&E and KU contract with the Tennessee Valley Authority to act as their transmission reliability coordinator and contract with TranServ International, Inc. to act as their independent transmission organization.
Rates
LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the VSCC and the FERC. LG&E and KU operate under a FERC-approved open access transmission tariff.
Prior to January 1, 2026, LG&E's and KU's Kentucky base rates were calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. Effective January 1, 2026, pursuant to the KPSC rate case, Kentucky base rates are calculated based on a return on rate base (net utility plant plus certain regulatory assets and working capital less accumulated deferred income taxes and certain regulatory liabilities) and include recovery of applicable operations and maintenance expenses.
KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus certain regulatory assets and working capital less accumulated deferred income taxes, certain regulatory liabilities and miscellaneous deductions) and include recovery of applicable operations and maintenance expenses.
KU's rates to two municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions) and include recovery of applicable operations and maintenance expenses.
See "Financial and Operational Developments" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 7 to the Financial Statements for additional information on current rate proceedings, regulatory matters and rate mechanisms.
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Pennsylvania Regulated Segment (PPL)
The Pennsylvania Regulated segment consists of PPL Electric, a regulated public utility engaged in the distribution and transmission of electricity.
(PPL and PPL Electric)
PPL Electric delivers electricity to approximately 1.5 million customers in a 10,000-square mile territory in 29 counties within eastern and central Pennsylvania. PPL Electric also provides electricity to retail customers in this territory as a PLR under the Customer Choice Act.
Franchises and Licenses
PPL Electric provides electricity delivery service in its service territory pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by the Pennsylvania state legislature, cities or municipalities or other entities.
Competition
Pursuant to authorizations from the Commonwealth of Pennsylvania and the PAPUC, PPL Electric operates a regulated distribution monopoly in its service area. Accordingly, PPL Electric does not face competition in its electricity distribution business. Pursuant to the Customer Choice Act, generation of electricity is a competitive business in Pennsylvania, and PPL Electric does not own or operate any generation facilities.
The PPL Electric transmission business, operating under a FERC-approved PJM Open Access Transmission Tariff, is subject to competition pursuant to FERC Order 1000 from entities that are not incumbent PJM transmission owners with respect to the construction and ownership of transmission facilities within PJM.
Rates and Regulation
Transmission
PPL Electric's transmission facilities are within PJM, which operates the electricity transmission network and electric energy market in the Mid-Atlantic and Midwest regions of the U.S.
PJM serves as a FERC-approved Regional Transmission Operator (RTO) to promote greater participation and competition in the region it serves. In addition to operating the electricity transmission network, PJM also administers regional markets for energy, capacity and ancillary services. A primary objective of any RTO is to separate the operation of, and access to, the transmission grid from market participants that buy or sell electricity in the same markets. Electric utilities continue to own the transmission assets and to receive their share of transmission revenues, but the RTO directs the control and operation of the transmission facilities. Certain types of transmission investments are subject to competitive processes outlined in the PJM tariff.
PPL Electric's transmission revenues are billed in accordance with a FERC-approved Open Access Transmission Tariff that utilizes a formula-based rate recovery mechanism. Under this formula, rates are put into effect on January 1st of each year based upon actual expenditures from the most recently filed FERC Form 1, forecasted capital additions, and other data based on PPL Electric's books and records. Rates are compared during the year to the estimated annual expenses and capital additions that will be filed in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts. Under the mechanism, any difference between the revenue requirement in effect and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability, and the regulatory asset or regulatory liability is to be recovered from or returned to customers starting one year after the conclusion of the rate year.
As a PLR, PPL Electric also purchases transmission services from PJM. See "PLR" below.
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Distribution
PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). All regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base. Therefore, no return is earned on the related assets unless specifically provided for by the PAPUC. Currently, PPL Electric's Smart Meter rider and the DSIC are the only riders authorized to earn a return. Certain operating expenses are also included in PPL Electric's distribution base rates including wages and benefits, other operation and maintenance expenses, depreciation and taxes.
Pennsylvania's Alternative Energy Portfolio Standard (AEPS) requires electric distribution companies and electricity generation suppliers to obtain from alternative energy resources a portion of the electricity sold to retail customers in Pennsylvania. Under the default service procurement plans approved by the PAPUC, PPL Electric purchases all of the alternative energy generation supply it needs to comply with the AEPS.
Act 129 created an energy efficiency and conservation program, a demand side management program, smart metering technology requirements, new PLR generation supply procurement rules, remedies for market misconduct and changes to the existing AEPS.
Act 11 authorizes the PAPUC to approve two specific ratemaking mechanisms: the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it is in a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging assets. PPL Electric utilized the fully projected future test year mechanism in its 2015 base rate proceeding. PPL has had the ability to utilize the DSIC recovery mechanism since July 2013.
See "Financial and Operational Developments" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 7 to the Financial Statements for additional information on current rate proceedings, regulatory matters and rate mechanisms.
PLR
The Customer Choice Act requires electric distribution companies, including PPL Electric, or an alternative supplier approved by the PAPUC, to act as a PLR of electricity supply for customers who do not choose to shop for supply with a competitive supplier and provides that electricity supply costs will be recovered by the PLR pursuant to PAPUC regulations. In 2025, the following average percentages of PPL Electric's customer load were provided by competitive suppliers: 40% of residential, 81% of small commercial and industrial and 98% of large commercial and industrial customers.
PPL Electric's electricity generation costs are established based upon the results of a competitive solicitation process. In November 2024, the PAPUC approved PPL Electric's default service plan for the period of June 1, 2025 through May 31, 2029, which included a total of eight solicitations for electricity supply held semiannually in February and July. Through December 31, 2025, two auctions of the plan were completed. The plan also included solicitations for alternative energy credits held annually in July with the first solicitation in 2025 and the final solicitation in 2029. Through December 31, 2025, one alternative energy credit solicitation has been completed.
Pursuant to the plans, PPL Electric contracts for all electricity supply for residential, commercial and industrial customers who elect to take default service from PPL Electric. These solicitations contain a mix of products including 10-year block energy contracts for residential customers, 12- and 24-month fixed-price load-following contracts for residential and small commercial and industrial customers, 12-month real-time pricing contracts for large commercial and industrial customers, and alternative energy credit contracts for residential, commercial and industrial customers. These contracts fulfill PPL Electric's obligation to provide customer electricity supply as a PLR.
Numerous alternative suppliers have offered to provide generation supply in PPL Electric's service area. As the cost of generation supply is a pass-through cost for PPL Electric, its financial results are not impacted if its customers purchase electricity supply from these alternative suppliers.
Rhode Island Regulated Segment (PPL)
The Rhode Island Regulated segment consists primarily of the regulated electricity transmission and distribution operations and regulated distribution and sale of natural gas conducted by RIE.
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RIE is engaged in the regulated transmission, distribution and sale of electricity and regulated distribution and sale of natural gas in Rhode Island. RIE provides electric service to approximately 515,000 customers and natural gas service to approximately 280,000 customers. RIE's service area covers substantially all of Rhode Island.
Franchises and Licenses
RIE provides electricity delivery service and natural gas distribution service in its service territory pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by the Rhode Island state legislature, cities or municipalities or other entities.
Competition
There are currently no other electric or gas public utilities operating within the service area of RIE.
Alternative energy sources such as electricity, oil, propane and other fuels indirectly impact RIE's natural gas revenues. Marketers may also compete to sell natural gas to certain large end-users. RIE's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity. Therefore, customer natural gas purchases from alternative suppliers do not generally impact RIE's profitability. Some large industrial and commercial customers, however, may physically bypass RIE's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.
Rates and Regulation
In general, RIE operates subject to the jurisdiction of the FERC, the RIPUC and the Rhode Island Division of Public Utilities and Carriers.
Distribution
RIE owns and maintains electric and natural gas distribution networks in Rhode Island. Distribution revenues are primarily from the sale of electricity, natural gas, and related services to retail customers. Distribution sales are regulated by the RIPUC, which is responsible for approving the rates and other terms of services as part of the rate making process. Natural gas and electric distribution revenues are derived from the regulated sale and distribution of electricity and natural gas to residential, commercial, and industrial customers within RIE's service territory under the tariff rates. The tariff rates approved by the RIPUC are designed to recover the costs incurred by RIE for products and services provided, along with a return on investment.
RIE's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). All regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base. Therefore, no return is earned on the related assets unless specifically provided for by the RIPUC. Currently, RIE's ISR and Renewable Energy Growth Program adjustment mechanisms are the only mechanisms authorized to earn a return. Certain operating expenses are also included in RIE's distribution base rates including wages and benefits, other operation and maintenance expenses, depreciation, and taxes.
Transmission
RIE owns an electric transmission system in Rhode Island. RIE's transmission services are regulated by the FERC and coordinated with ISO – New England.
Deferral Mechanisms
RIE records revenues in accordance with accounting principles for rate-regulated operations for arrangements between RIE and the applicable regulator. These include various deferral mechanisms such as capital trackers, energy efficiency programs, and other programs that qualify as Alternative Revenue Programs (ARPs). ARPs enable RIE to adjust rates in the future, in response to past activities or completed events. RIE's electric and gas distribution rates both have a revenue decoupling mechanism, which allows for annual adjustments to the RIE's delivery rates, as a result of the reconciliation between allowed revenue and billed revenue. RIE also has other ARPs related to the achievement of certain objectives, demand side management initiatives, and certain other rate making mechanisms. RIE recognizes ARPs with a corresponding offset to a regulatory asset or liability account when the regulatory specified events or conditions have been met, when the amounts are determinable, and are probable of recovery (or payment) through future rate adjustments.
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LRS
RIE is required by the RIPUC and by statute to provide LRS to all customers who have not elected to receive their electric supply from a non-regulated power producer or any customer who, for any reason, has stopped receiving generation service from a non-regulated power producer.
The charge for LRS is the sum of the applicable LRS charges in addition to all appropriate Retail Delivery charges as stated in the applicable tariff. The monthly charge for LRS also includes the costs incurred by RIE to comply with the Renewable Energy Standard, established in Rhode Island General Laws Section 39-26-1 and the costs to comply with the RIPUC's Rules Governing Energy Source Disclosure. The charge for LRS includes the administrative costs associated with the procurement of LRS, including an adjustment for uncollectible accounts as approved by the RIPUC.
Numerous alternative suppliers have offered to provide generation supply in RIE's service area. As the cost of generation supply is a pass-through cost for RIE, its financial results are not impacted if its customers purchase electricity supply from these alternative suppliers.
See "Financial and Operational Developments" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 7 to the Financial Statements for additional information on current rate proceedings, regulatory matters and rate mechanisms.
Natural Gas Distribution Supply
To meet the projected annual gas supply requirements of approximately 35 Bcf, RIE has a portfolio of gas supply arrangements of varying contractual terms and durations to provide service to its customers. These natural gas supply arrangements include contracts with natural gas producers and marketers that reflect market price signals. RIE also has firm pipeline and underground storage capacity contracts to support the delivery of natural gas supplies to its customers. To manage the winter peak requirements for RIE customers, RIE contracts for liquified natural gas (LNG) service and owns and operates certain LNG storage facilities.
The RIE gas supply portfolio includes contracts for firm transportation service with eleven interstate pipeline companies and natural gas storage operators. These contracts have various termination dates with certain contracts being subject to evergreen renewal provisions providing RIE with flexibility in managing its upstream resource portfolio.
RIE has purchased and expects to continue to purchase natural gas supplies for its gas distribution operations from onshore producing regions accessed by its pipeline capacity portfolio in South Texas, East Texas, and Louisiana, as well as gas originating in the Marcellus and Utica production areas. RIE expects to purchase certain natural gas supplies that originate in Canada and from regional LNG import terminals.
Corporate and Other (PPL)
PPL Services provides PPL subsidiaries with administrative, management and support services. The costs of these services are charged directly to the respective recipients for the services provided or indirectly charged to applicable recipients based on an average of the recipients' relative invested capital, operation and maintenance expenses and number of employees or a ratio of overall direct and indirect costs.
PPL Capital Funding provides financing for the operations of PPL and certain subsidiaries. PPL's growth in rate-regulated businesses provides the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that enables PPL to cost effectively support targeted credit profiles across all of PPL's rated companies. As a result, PPL utilizes PPL Capital Funding as a source of capital in financings, in addition to continued direct financing by certain operating subsidiaries. Unlike those of PPL Services, PPL Capital Funding's costs are not generally charged to PPL subsidiaries. Costs are charged directly to PPL.
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ENVIRONMENTAL MATTERS
(All Registrants)
The Registrants are subject to certain existing and developing federal, regional, state and local laws and regulations with respect to air and water quality, land use and other environmental matters, and may be subject to different and more stringent laws and regulations enacted in the future. The EPA and other federal agencies with jurisdiction over environmental matters have issued numerous environmental regulations relating to air, water and waste that directly affect the electric power industry. Due to these environmental issues, it may be necessary for the Registrants to modify or cease certain operations or operation of certain facilities to comply with statutes, regulations and other requirements of regulatory bodies or courts. In addition, legal challenges to environmental permits or rules add uncertainty to estimating future costs of complying with such permits and rules. The Registrants are monitoring executive orders and other ongoing actions by the new Presidential administration, but are unable to predict changes in regulations, regulatory guidance, legal interpretations, policy positions, and implementation actions that may result.
See "Legal Matters" in Note 12 to the Financial Statements for a discussion of environmental commitments and contingencies. See Note 18 to the Financial Statements for information related to the impacts of CCRs on AROs.
LG&E and KU are entitled to recover, through the ECR mechanism, certain costs of complying with the Clean Air Act, as amended, and other federal, state and local environmental requirements applicable to coal combustion wastes and by-products from coal-fired generating facilities upon KPSC review. Costs not covered by the ECR mechanism for LG&E and KU and all such costs for PPL Electric and RIE are subject to rate recovery at the discretion of the companies' respective state regulatory authorities, or the FERC, if applicable. Because PPL Electric and RIE do not own any generating plants, they have less exposure to related environmental compliance costs. The Registrants can provide no assurances as to the ultimate outcome of future proceedings before regulatory authorities.
(PPL, LG&E and KU)
EPA Deregulatory Initiative
On March 12, 2025, the EPA announced a plan to reconsider 31 environmental rules including the Section 111 performance standards and emissions limits for greenhouse gases, the endangerment finding for greenhouse gases, the Good Neighbor Plan, the Mercury and Air Toxics Standards, revisions to the fine particulate matter standard, the ELGs, and the CCRs Rule. Supplementing previous Executive Orders directing various regulatory changes, on April 9, 2025, President Trump issued an Executive Order and Presidential Memorandum directing review of existing rules, repeal of unlawful rules, and initiation of a zero-based budgeting process by which certain rules would automatically expire unless extended. While the current Presidential administration may seek to implement some regulatory changes outside of the rulemaking process, changes to existing rules are generally expected to require formal rulemaking proceedings. Any final EPA actions repealing or revising current rules will likely result in legal challenges. PPL, LG&E, and KU are unable to predict future regulatory changes, if any, that may result from the EPA's deregulatory plan or the outcome of any associated legal challenges. PPL, LG&E, and KU are closely monitoring the ongoing EPA initiative and any related litigation for the impact to our business including planned capital expenditures to comply with the EPA rules.
Air
NAAQS
Applicable regulations require each state to identify areas within its boundaries that fail to meet the NAAQS, (known as nonattainment areas), and develop a state implementation plan to achieve and maintain compliance. States that are found to contribute significantly to another state's nonattainment with ozone standards are required to establish "good neighbor" state implementation plans. In addition, for attainment of ozone and fine particulates standards, certain states, including Kentucky, are subject to a regional EPA program known as the Cross-State Air Pollution Rule (CSAPR).
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The Clean Air Act has a significant impact on the operation of fossil fuel generation plants. The Clean Air Act requires the EPA periodically to establish and review NAAQS for six pollutants including ozone (contributed to by nitrogen oxide emissions) and particulate matter, which are particularly relevant for fossil fuel generation plants. On February 2, 2024, the D.C. Circuit Court granted the EPA's motion for voluntary remand, without vacatur, of the ozone rule, which was under legal challenge. The EPA will complete a new review to incorporate new studies and updated analyses to determine the adequacy of the existing ozone standard. On March 6, 2024, the EPA finalized revisions to the particulate matter standard that lowers the primary standard for fine particulates. Several states and trade groups challenged the EPA's finalized revisions to the particulate matter standard in the D.C. Circuit Court. In March 2025, the EPA announced that it would reconsider the revised fine particulate standard. On November 25, 2025, the EPA filed a motion in the D.C. Circuit Court to vacate the fine particulate standard. The D.C. Circuit Court has not responded to the motion and environmental groups have filed responses against the motion. Nonattainment designations for counties in which LG&E and KU generation is located, including Jefferson County, Kentucky, could potentially require additional particulate matter and nitrogen oxide reductions from sources including LG&E's Mill Creek Station, and more stringent requirements for new generation. PPL, LG&E, and KU are unable to predict future implementation actions or the outcome of future evaluations by the EPA and the states with respect to the NAAQS standards.
In March 2021, the EPA released final revisions to the Cross-State Air Pollution Rule (CSAPR), aimed at ensuring compliance with the 2008 ozone NAAQS and providing for reductions in ozone season nitrogen oxide emissions for 2021 and subsequent years. In March 2023, the EPA released a final Federal Implementation Plan under the Good Neighbor provisions of the Clean Air Act providing for significant additional nitrogen oxide emission reductions for compliance with the revised 2015 ozone NAAQS. The reductions in Kentucky state-wide nitrogen oxide budgets were scheduled to commence in 2023, with the largest reductions planned for 2026. The rules provide for reduced availability of nitrogen oxide allowances that have historically permitted operational flexibility for fossil units and could potentially result in constraints that may require implementation of additional emission controls or accelerate implementation of lower emission generation technologies. In June 2024, the U.S. Supreme Court issued a stay of the Good Neighbor Plan while the D.C. Circuit Court considers legal challenges to the rule. On December 10, 2024, EPA published in the Federal Register a supplement to the record. On December 6, 2024, the U.S. Court of Appeals for the Sixth Circuit vacated and remanded the EPA's disapproval of Kentucky's state implementation plan for the ozone NAAQS. In March 2025, the EPA announced that it would reconsider the Good Neighbor Plan. On January 27, 2026, the EPA released proposed Phase I Good Neighbor Plan revisions providing for approval of certain state implementation plans including that of Kentucky and withdrawing several prior disapprovals and error corrections. PPL, LG&E, and KU are monitoring ongoing legal and regulatory developments.
PPL, LG&E, and KU are unable to predict the ultimate outcome of pending litigation or future emission reductions that may be required by future federal rules or state implementation actions. Compliance with the NAAQS, CSAPR, Good Neighbor Plan, and related requirements may require installation of additional pollution controls or other compliance actions, inclusive of retirements, the costs of which PPL, LG&E and KU believe would be subject to rate recovery.
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Modification of Mercury and Air Toxics Standards
In 2012, the EPA issued the Mercury and Air Toxics Standards (MATS) rule requiring reductions in mercury and other hazardous air pollutants from fossil fuel-fired power plants. LG&E and KU installed significant controls to achieve compliance with MATS and other rules. On May 7, 2024, the EPA issued a final rule increasing the stringency of MATS and further reducing emissions of certain hazardous air pollutants to reflect perceived developments in control technologies. Legal challenges to the rule have been filed in the D.C. Circuit Court. PPL, LG&E, and KU have reviewed the final rule and do not expect significant operational changes or additional controls to be required. On June 17, 2025, the EPA proposed in the Federal Register to repeal the 2024 MATS revisions except for the Particulate Matter Continuous Emission Monitoring System testing criteria.
Greenhouse Gas Standards
On May 9, 2024, the EPA issued a final rule under Section 111 of the Clean Air Act, which establishes performance standards and emissions limits aimed at reducing GHG emissions from certain new, existing, and modified fossil fuel-fired electric generating units (EGUs). In the final rule, the EPA announced it would set performance standards for existing natural gas-fired turbines in a future rule. The standards require phased implementation of carbon mitigation technologies including state-of-the-art efficiency requirements, carbon capture and sequestration, and natural gas co-firing. New natural gas EGUs would be immediately subject to the stricter efficiency standard. Legal challenges to the rule have been filed in the D.C. Circuit Court. PPL, LG&E, and KU are unable to predict the impact of new GHG reduction requirements until completion of a comprehensive review and resolution of related legal and regulatory proceedings. While the impact of new GHG reduction requirements on operations and financial results of operations could potentially be substantial, the cost of complying with such requirements is expected to be subject to rate recovery. On June 17, 2025, the EPA proposed in the Federal Register two options for repeal of the 2024 standard. In the first proposal, the EPA would determine that EGU emissions of greenhouse gases do not pose an endangerment to the health and welfare of the public and repeal the 2024 and 2015 standards for EGUs. Under an alternate proposal, the EPA would repeal the 2024 standards for existing coal, natural-gas and oil-fired steam generating units along with most standards for new combustion turbines. On February 12, 2026, the EPA issued a final reconsideration determination repealing the 2009 endangerment finding for GHG emissions from motor vehicles, which provided support for the regulation of GHG emissions. While the action has no immediate impact on regulation of GHG emissions from electric generating units, the EPA is expected to take additional regulatory actions with respect to that industrial sector. PPL, LG&E, and KU are unable to determine the exact impact on operations until resolution of pending regulatory actions and litigation.
Climate Change (All Registrants)
In recent years the federal government has undertaken various efforts aimed at addressing climate change, which could have far-reaching impacts on PPL's business operations, products, and services. In 2022, the U.S. Supreme Court ruled that provisions of the EPA's Clean Power Plan, premised on generation shifting from coal-fired plants to lower emitting natural gas-fired plants and renewables, exceeded the authority granted to the EPA under the Clean Air Act. While the EPA contends that the new GHG emissions rule discussed above is consistent with the provisions of the Clean Air Act, it is uncertain how a ruling from the D.C. Circuit Court or, if appealed, the U.S. Supreme Court may affect the new GHG emissions rule and any future EPA rulemaking on GHG emissions. The current Presidential administration has issued various executive orders regarding climate change initiatives and is expected to continue to consider changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions, but the Registrants are unable to predict the changes that may ultimately be adopted. These developments are generally preliminary or ongoing in nature and the Registrants cannot predict the final outcome or ultimate impact on operations.
PPL has adopted a goal of net-zero carbon emissions by 2050, which PPL expects will include continuing to retire uneconomic generation, deploying newer generation technology and investing in research and innovation that will help to achieve this goal, while maintaining reliable and affordable energy in our service territories. The net-zero goal relates to direct and indirect carbon emissions consistent with Greenhouse Gas Protocol guidance and referenced by the EPA Center for Corporate Climate Leadership. Achievement of our emissions goal may be affected by factors that are outside of our control including potential load growth, especially from large load customers, energy policy and regulations at the state and federal level, technological developments, and the cost of new generation technology.
PPL is aware of the various risks associated with climate change, including increased frequency and severity of severe weather. To address these risks, PPL continues to work to advance grid modernization and improve the company's equipment to help mitigate the impacts of extreme weather events and improve reliability.
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Water/Waste (PPL, LG&E and KU)
Clean Water Act
Regulations under the federal Clean Water Act dictate permitting and mitigation requirements for facilities and construction projects that impact "Waters of the United States". Many other requirements relate to power plant operations, including the treatment of pollutants in effluents prior to discharge, the temperature of effluent discharges and the location, design and construction of cooling water intake structures at generating facilities, and standards intended to protect aquatic organisms that become trapped at or pulled through cooling water intake structures at generating facilities. These requirements could impose significant costs for LG&E and KU, which are expected to be subject to rate recovery. A proposed rule definition revision was issued in November 2025. A final rule is expected by the end of 2026.
Clean Water Act Jurisdiction
Environmental groups and others have claimed that discharges to groundwater from leaking CCR impoundments at power plants are subject to Clean Water Act permitting. On April 12, 2019, the EPA released regulatory clarification finding that Clean Water Act jurisdiction does not cover such discharges to groundwater. On January 23, 2020, the EPA announced a final rule modifying the jurisdictional scope of the Clean Water Act. The announced rule revises the definition of the "Waters of the United States," including a revision to exclude groundwater from the definition. In April 2020, the U.S. Supreme Court issued a ruling that Clean Water Act jurisdiction may apply to certain discharges to groundwater that result in the functional equivalent of a direct discharge to navigable waters. In a December 2025 proposed revision to the definition of "Waters of the United States", the EPA clarified groundwater exclusions and a final rule is expected by the end of 2026. PPL, LG&E, and KU are unaware of any unpermitted releases from their facilities that are subject to Clean Water Act jurisdiction, but future regulatory developments and judicial rulings could potentially subject certain releases from CCR impoundments and landfills to additional permitting and remediation requirements, which could impose substantial costs. Any associated costs are expected to be subject to rate recovery. PPL, LG&E and KU are unable to predict the outcome or financial impact of future regulatory proceedings and litigation.
Waters of the U.S.
PPL, LG&E, and KU are subject to permitting and mitigation requirements for certain construction activities that impact "Waters of the United States." On April 21, 2020, the EPA and U.S. Army Corps of Engineers published a final rule revising the definition of "Waters of the United States" to exclude jurisdiction over certain surface waters. On August 30, 2021, a U.S. District Court in Arizona vacated and remanded the rule. On December 7, 2021, the EPA and U.S. Army Corps of Engineers proposed to repeal the rule and restore the definition of "Waters of the United States" that was in place prior to 2015. On January 18, 2023, the EPA and U.S. Army Corps of Engineers published a final revision to the rule broadening the definition of Waters of the United States and reverting to the pre-2015 regulatory framework. Although the broader definition incorporates additional water bodies, any resulting permitting, construction, and operational expenses are expected to be immaterial and subject to rate recovery.
On May 25, 2023, the U.S. Supreme Court issued an opinion in Sackett v. EPA holding that the government's jurisdiction to regulate wetlands under the Clean Water Act extends to wetlands with a continuous surface connection to bodies that are "Waters of the United States." On September 8, 2023, the EPA issued a conforming rule that incorporated the holding of Sackett into federal definitions of waters of the United States; some states and industry groups have challenged the conforming rule as well. By limiting water bodies that fall within the jurisdiction of the Clean Water Act, the U.S. Supreme Court's decision could reduce the number of projects or the scope of project activities subject to federal permitting for wetlands. A proposed rule regarding revision of the definition was issued in December 2025. A final rule is expected by the end of 2026. PPL, LG&E and KU are unable to predict the outcome of current or future litigation or regulatory proceedings, but do not expect a material impact on operations.
Superfund and Other Remediation (All Registrants)
From time to time, PPL's subsidiaries undertake testing, monitoring or remedial action in response to spills or other releases at various on-site and off-site locations, negotiate with the EPA and state and local agencies regarding actions necessary to comply with applicable requirements, negotiate with property owners and other third parties alleging impacts from PPL's operations and undertake similar actions necessary to resolve environmental matters that arise in the course of normal operations. Based on analyses to date, resolution of these environmental matters is not expected to have a significant adverse impact on the operations of PPL, PPL Electric, LG&E, KU and RIE.
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Future cleanup or remediation work at sites not yet identified may result in significant additional costs for the Registrants. Insurance policies maintained by LKE may be available to cover certain costs or other obligations related to these matters for LG&E or KU, but the amount of insurance coverage or reimbursement cannot be estimated or assured.
See "Legal Matters" in Note 12 to the Financial Statements for additional information.
(All Registrants)
SEASONALITY
The demand for and market prices of electricity and natural gas are affected by weather. As a result, the Registrants' operating results in the future may fluctuate substantially on a seasonal basis, especially when unpredictable weather conditions make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities owned.
FINANCIAL CONDITION
See "Financial Condition" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for this information.
CAPITAL EXPENDITURE REQUIREMENTS
See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information concerning projected capital expenditure requirements for 2026 through 2028. See "Item 1. Business - Environmental Matters" for additional information concerning the potential impact on capital expenditures from environmental matters.
HUMAN CAPITAL
PPL, together with its subsidiaries, is committed to fostering an exceptional workplace for employees. PPL pledges to enable the success of its current and future workforce by ensuring a safe and healthy work environment, cultivating a supportive, empowering and collaborative culture, encouraging employee engagement and fostering professional development. Matters related to these priorities and corporate culture are overseen by PPL's senior management, which provides updates to the PPL Board of Directors (the Board). Pursuant to its charter, the People and Compensation Committee of the Board also periodically reviews and assesses the company's strategy for human capital management. PPL's investment in the success of its workforce is embodied in the following areas with dedicated leadership and Board oversight:
•Safety and Compliance - PPL is committed to maintaining an ethical and safe workplace culture for employees and contractors. Additional steps to ensure the Board has oversight in these areas include:
•Safety - PPL implements programs focused on health and safety, including emergency preparedness, vehicle safety and accident prevention. Employees receive safety training and are encouraged to share, implement, and follow best practices. PPL requires contractor work practices to meet or exceed PPL safety requirements and all applicable safety standards. Senior management receives monthly safety data updates to determine whether additional safety measures should be implemented. The Board reviews the company's safety programs and results several times a year. The Board is also immediately engaged in the event of a fatality.
•Compliance - The Corporate Compliance Committee, including senior executives, meets quarterly to discuss metrics and other matters related to the compliance and ethics culture. Among the items discussed are statistics regarding Ethics Helpline reports and employee concerns. This information is also reviewed with the Audit Committee of the Board quarterly and with the Board annually.
•Corporate culture - Foster a supportive, empowering and collaborative workplace culture in which employees with various backgrounds can thrive. Senior management reviews workforce metrics, culture related objectives and associated programs semi-annually. The Board also receives periodic updates from senior management on PPL's strategy and initiatives that drive corporate culture.
•Employee engagement - Create a workplace that fosters an engaged, high-quality workforce. PPL's operating companies regularly conduct assessments related to employee engagement, safety and culture. Senior management reviews employee engagement efforts with the Board at least annually.
•Professional development - Invest in the current and future workforce through training and development, succession planning and creation of a pipeline for internal advancement. Senior management reviews succession planning with the People and Compensation Committee of the Board on an annual basis.
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•Comprehensive benefits - In addition to challenging careers and competitive salaries, PPL offers competitive benefits programs to attract and retain talent and support employees' well-being. PPL offers competitive vacation time, expanded leave for new parents, retirement programs, and internal and external development opportunities, including tuition reimbursement offerings for undergraduate and certain graduate degrees. Senior management conducts annual benchmarking of employee compensation and benefits.
PPL will continue to engage with employees and to assess these priorities as we work to best position individuals and the company for future success. PPL had a turnover rate of 10.83% for the year ended December 31, 2025. Looking forward, PPL will maintain a strong focus on workforce planning to address future talent needs.
At December 31, 2025, the Registrants had the following full-time employees and employees represented by labor unions:

| Total Full-Time Employees |  | Number of Union Employees |  | Percentage of Total Workforce
PPL | 6,546 |  |  | 2,368 |  |  | 36 | %
PPL Electric | 1,378 |  |  | 902 |  |  | 65 | %
LG&E | 908 |  |  | 578 |  |  | 64 | %
KU | 720 |  |  | 107 |  |  | 15 | %

(PPL)
In May 2025, PPL and the Rhode Island United Steelworkers (USW) Local 12431 reached a five-year tentative agreement that was ratified and effective from June 2, 2025, through June 2, 2030. The agreement currently covers approximately 300 employees.
(PPL and LG&E)
LG&E's current collective bargaining agreement with IBEW Local 2100, which covers approximately 600 employees, is scheduled to expire October 1, 2026. It is expected that the parties will be engaging in negotiations for a new contract prior to that date.
AVAILABLE INFORMATION
PPL's Internet website is www.pplweb.com. Under the Investors heading of that website, PPL provides access to SEC filings of the Registrants (including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed or furnished pursuant to Section 13(d) or 15(d)) free of charge, as soon as reasonably practicable after filing with the SEC. The information contained on, or available through, PPL's Internet website is not, and shall not be deemed to be, incorporated by reference into this report. Additionally, the Registrants' filings are available at the SEC's website (www.sec.gov).
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ITEM 1A. RISK FACTORS
The Registrants face various risks associated with their businesses. Our businesses, financial condition, cash flows or results of operations could be materially adversely affected by any of these risks. In addition, this report also contains forward-looking and other statements about our businesses that are subject to numerous risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 12 to the Financial Statements for additional information concerning the risks described below and for other risks, uncertainties and factors that could affect our businesses and financial results.
As used in this Item 1A., the terms "we," "our" and "us" generally refer to PPL and its consolidated subsidiaries taken as a whole, or PPL Electric and its consolidated subsidiaries taken as a whole within the Pennsylvania Regulated segment discussion, LG&E, KU and their consolidated subsidiaries taken as a whole within the Kentucky Regulated segment discussion, and RIE within the Rhode Island Regulated segment discussion.
Order of Subsection Presentation
A.Risks Related to Registrant Holding Company
B.Risks Related to Regulated Utility Operations
C.Risks Specific to Kentucky Regulated Segment
D.Risks Specific to Pennsylvania Regulated Segment
E.Risks Specific to Rhode Island Regulated Segment
F.Risks Related to All Segments
(PPL)
A. Risk Related to Registrant Holding Company
PPL is a holding company and its cash flows and ability to meet its obligations with respect to indebtedness and under guarantees, and its ability to pay dividends, largely depends on the financial performance of its respective subsidiaries and, as a result, is effectively subordinated to all existing and future liabilities of those subsidiaries.
PPL is a holding company and conducts its operations primarily through subsidiaries. Substantially all of the consolidated assets of PPL are held by its subsidiaries. Accordingly, PPL's cash flows and ability to meet debt and guaranty obligations, as well as PPL's ability to pay dividends, are largely dependent upon the earnings of those subsidiaries and the distribution or other payment of such earnings in the form of dividends, distributions, loans, advances or repayment of loans and advances. The subsidiaries are separate legal entities and have no obligation to pay dividends or distributions to their parents or to make funds available for such a payment. The ability of PPL's subsidiaries to pay dividends or distributions in the future will depend on the subsidiaries' future earnings and cash flows and the needs of their businesses, and may be restricted by their obligations to holders of their outstanding debt and other creditors, as well as any contractual or legal restrictions in effect at such time, including the requirements of state corporate law applicable to payment of dividends and distributions, and regulatory requirements, including restrictions on the ability of PPL Electric, LG&E, KU, and RIE to pay dividends under Section 305(a) of the Federal Power Act.
Because PPL is a holding company, its debt and guaranty obligations are structurally subordinated to all existing and future liabilities of its subsidiaries. Although certain agreements to which certain subsidiaries are parties limit their ability to incur additional indebtedness, PPL and its subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities. Therefore, PPL's rights and the rights of its creditors, including rights of debt holders, to participate in the assets of any of its subsidiaries, in the event that such a subsidiary is liquidated or reorganized, will be subject to the prior claims of such subsidiary's creditors.
(All Registrants)
B. Risks Related to Regulated Utility Operations
Our regulated utility businesses face many of the same risks, in addition to those risks that are unique to each of the Kentucky Regulated, Pennsylvania Regulated and Rhode Island Regulated segments. Set forth below are risk factors common to the regulated segments, followed by sections identifying separately the risks specific to each of these segments.
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The business and capital investment plans of PPL depend, in part, on the continued growth and viability of data centers and large load customers in its service territories.
PPL is anticipating increases in load demand, creating a business need for new power generating resources and transmission facilities. Much of this demand is driven by interconnecting with and providing power to data centers and large load customers to serve an increasingly digital economy and to support artificial intelligence. The business and capital investment plans of PPL are focused on meeting these current and projected needs. If these increased demands for electricity do not occur as projected or are not sustained as projected, for any reason, it could affect PPL's financial condition.
Our profitability is highly dependent on our ability to recover the costs of providing energy and utility services to our customers and earn an adequate return on our capital investments. Regulators may not approve the rates we request and existing rates may be challenged.
The rates we charge our utility customers must be approved by one or more federal or state regulatory commissions, including the FERC, KPSC, VSCC, PAPUC and RIPUC. Although rate regulation is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that regulatory authorities will consider all of our costs to have been prudently incurred or that the regulatory process by which rates are determined will always result in rates that achieve full or timely recovery of our costs or an adequate return on our capital investments. Federal or state agencies, intervenors and other permitted parties may challenge our current or future rate requests, structures or mechanisms, and ultimately reduce, alter or limit the rates we receive. The requests for rate increases and the frequency of rate cases could face resistance from customers and other stakeholders, especially in a rising cost environment. Although our rates are generally regulated based on an analysis of our costs incurred in a base year or on future projected costs, the rates we are allowed to charge may or may not match our costs at any given time. Our regulated utility businesses are subject to substantial capital expenditure requirements over the next several years, which may require rate increase requests to the regulators in the future. If our costs are not adequately recovered through rates, it could have an adverse effect on our business, results of operations, cash flows and financial condition.
Our utility businesses are subject to significant and complex governmental regulation.
In addition to regulating the rates we charge, various federal and state regulatory authorities regulate many aspects of our utility operations, including:
•the terms and conditions of our service and operations;
•financial and capital structure matters, and issuance of securities;
•siting, construction and operation of facilities;
•mandatory reliability and safety standards under the Energy Policy Act of 2005 and other standards of conduct;
•accounting, depreciation and cost allocation methodologies;
•tax matters;
•affiliate transactions;
•acquisition, retirement and disposal of utility assets; and
•various other matters, including energy efficiency.
Such regulations or changes thereto may subject us to higher operating costs or increased capital expenditures and failure to comply could result in sanctions or possible penalties which may not be recoverable from customers.
Our regulated businesses undertake significant capital projects and these activities are subject to unforeseen costs, delays or failures, as well as risk of inadequate recovery of resulting costs.
The regulated utility businesses are capital intensive and require significant investments in energy generation (in the case of LG&E and KU) and transmission, distribution and other infrastructure projects, including providing service to new data centers and large load customers, constructing projects for environmental compliance and maintaining system reliability. The completion of these projects without delays or cost overruns is subject to risks in many areas, including:
•approval, licensing and permitting;
•land acquisition and the availability of suitable land;
•skilled labor or equipment shortages;
•construction problems or delays, including disputes with third-party intervenors;
•increases in commodity prices or labor rates;
•potential supply chain disruptions or delays; and
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•contractor performance.
PPL is anticipating increases in load demand, creating the need for new power generating resources and transmission facilities. A substantial portion of this demand is driven by the current and projected power needs of data centers to serve an increasingly digital economy and to support artificial intelligence. Extending service to these facilities necessitates significant capital expenditures, which in turn requires sufficient access to sources of capital. These additional capital needs, the increased concentration of business within a single industry based on emerging technologies, and uncertainties regarding the actual capacity required to satisfy the projected new demands of these new industries creates risks for PPL. Ensuring that incremental revenues from these projected new demands cover incremental costs and risks is critical to PPL and its relationship to its existing customers. While contracts with new large load customers typically include provisions for early termination payments, minimum bills, and financial security, these contracts may not fully protect PPL against all risks. Changes in industry practice or advances in the related technologies could reduce the demand for electricity to power data centers or other large load facilities. Additionally, these industries may experience a business downturn, which could cause the loss of current or potential customers or may weaken the financial condition and creditworthiness of existing customers. If anticipated demand growth does not materialize, PPL could experience unrecovered capital investments. Conversely, if demand grows more rapidly than projected, PPL may face challenges in securing adequate generation and transmission capacity and maintaining service reliability.
Failure to complete our capital projects on schedule or on budget, or at all, could adversely affect our financial performance, operations and future growth if such expenditures are not granted rate recovery by our regulators.
We are or may be subject to costs of remediation of environmental contamination at facilities that are currently owned by us or that are owned or operated by our former subsidiaries.
We may be subject to liability for the costs of environmental remediation of property now or formerly owned by us with respect to substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We also have current or previous ownership interests in sites associated with the production of manufactured gas for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former manufactured gas plant operations are one source of such costs. Citizen groups or others may bring litigation regarding environmental issues including claims of various types, such as property damage, personal injury and citizen challenges to compliance decisions on the enforcement of environmental requirements, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although they could be material.
C. Risks Specific to Kentucky Regulated Segment
(PPL, LG&E and KU)
We are subject to financial, operational, regulatory and other risks related to requirements, developments and uncertainties in environmental regulation, including those affecting coal-fired generation facilities.
Extensive federal, state and local environmental laws and regulations are applicable to LG&E's and KU's generation supply, including its air emissions, water discharges (ELGs) and the management of hazardous and solid wastes (CCRs), among other business-related activities, and the costs of compliance or alleged non-compliance cannot be predicted and could be material. In addition, our costs may increase significantly if the requirements or scope of environmental laws, regulations or similar rules are expanded or changed as the environmental standards governing LG&E's and KU's businesses, particularly as applicable to coal-fired generation and related activities, continue to be subject to uncertainties due to rulemaking and other regulatory developments, legislative activities and litigation, administrative and permit challenges. In recent years, the federal government has undertaken various efforts aimed at addressing climate change, some of which remain subject to legal challenge, that may affect these costs. The Registrants are unable to predict changes in regulations, regulatory guidance, legal interpretations, policy positions, and implementation actions that may be initiated by the current Presidential administration. Depending on the extent, frequency and timing of such changes, LG&E and KU may face higher risks of unsuccessful implementation of environmental-related business plans, noncompliance with applicable environmental rules, delayed or incomplete rate recovery or increased costs of implementation. Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or forfeitures, operational changes, permit limitations or other restrictions. At some of our older generating facilities it may be uneconomic for us to install necessary pollution control equipment, which could cause us to retire those units. Our ability to retire plants we believe are uneconomic is expected to be subject to receipt of regulatory approvals. Market prices for energy and capacity also affect this cost-effectiveness analysis.
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Many of these environmental law considerations are also applicable to the operations of our key suppliers or customers, such as coal producers, power producers and industrial power users, and may impact the costs of their products and demand for our services.
(PPL and LG&E)
We are subject to regulatory and other risks regarding natural gas supply infrastructure.
The PHMSA enforces regulations that govern the design, construction, operation and maintenance of pipeline facilities. Failure to comply with these regulations could result in the assessment of fines or penalties against LG&E. These regulations require, among other things, that pipeline operators take certain measures with respect to pipeline integrity. Depending on the results of integrity tests and other integrity program activities, we could incur significant and unexpected costs to perform remedial activities on our natural gas infrastructure to ensure our continued safe and reliable operation. Recent pipeline incidents in the U.S. have also led to the introduction of proposed rules and possible federal legislative actions which could impose restrictions on LG&E's operations or require more stringent testing to ensure pipeline integrity. Implementation of these regulations could increase our costs to comply with pipeline integrity and safety regulations.
D. Risks Specific to Pennsylvania Regulated Segment
(PPL and PPL Electric)
We face competition for transmission projects, which could adversely affect our rate base growth.
FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electricity transmission planning activities. The PPL Electric transmission business, operating under a FERC-approved PJM Open Access Transmission Tariff, is subject to competition pursuant to FERC Order 1000 from entities that are not incumbent PJM transmission owners with respect to the construction and ownership of transmission facilities within PJM. Increased competition can result in lower rate base growth.
We could be subject to higher costs and/or penalties related to Pennsylvania Conservation and Energy Efficiency Programs.
PPL Electric is subject to Act 129, which contains requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposes PLR electricity supply procurement rules, provides remedies for market misconduct, and made changes to the existing Alternative Energy Portfolio Standard. The law also requires electric utilities to meet specified goals for reduction in customer electricity usage and peak demand. Utilities not meeting these Act 129 requirements are subject to significant penalties that cannot be recovered in rates. Numerous factors outside of our control could prevent compliance with these requirements and result in penalties to us.
E. Risks Specific to the Rhode Island Regulated Segment
(PPL)
We are subject to regulatory and other risks regarding natural gas supply infrastructure in Rhode Island.
The PHMSA enforces regulations that govern the design, construction, operation and maintenance of pipeline facilities. Failure to comply with these regulations could result in the assessment of fines or penalties against RIE. These regulations require, among other things, that pipeline operators take certain measures with respect to pipeline integrity. Depending on the results of integrity tests and other integrity program activities, we could incur significant and unexpected costs to perform remedial activities on our natural gas infrastructure to ensure our continued safe and reliable operation.
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F. Risks Related to All Segments
(All Registrants)
Our business operations are continually subject to cyber-based security and data integrity risks from vulnerabilities related to our IT systems, operational technology infrastructure and supply chain relationships.
Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems and network infrastructure. The operation of our transmission and distribution systems, including gas distribution systems, as well as our generation plants, are all reliant on cyber-based, complex and integrated technologies. Systemic issues could arise as a result of upgrades to particular software or human error. In addition, these complex systems are subject to the risk that they could be the target of disruptive actions by terrorists, nation state actors or criminals or otherwise be compromised. Attacks may come through ransomware, software updates or patches, use of opensource software, firmware that hackers can manipulate to include malicious codes for exploitation at a later date, or the compromising of hardware by bad actors, creating serious risks to our security, the security of our customers' information, and potentially to our ability to provide power. Attacks could also target our personnel or contractors through attempts to gain access or credentials that could be used to breach our systems. As a result, operations could be interrupted, property could be damaged and sensitive customer information lost or stolen, causing us to incur significant losses of revenues, other substantial liabilities and damages, costs to replace or repair damaged equipment and damage to our reputation. Threats to our systems and operations continue to emerge as new ways to compromise components of our systems or networks are developed. Additionally, cybersecurity risks also threaten our supply chains, including aspects that are not under our control, such as the incorporation of opensource software in systems or software that we use, that despite our efforts do not meet our current security standards.
In addition, under the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including PPL Electric, LG&E, KU and RIE, are subject to mandatory reliability standards promulgated by NERC and enforced by the FERC. As an operator of natural gas distribution systems, LG&E is also subject to mandatory reliability standards of the U.S. Department of Transportation and is also subject to certain security directives related to cybersecurity issued by the Department of Homeland Security (DHS) Transportation Security Administration (TSA) in 2021. The TSA has determined that LG&E is critical, while RIE has not been notified of this distinction and is therefore not currently subject to the security directives. Failure to comply with these standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of the standards.
Artificial Intelligence (AI) is an evolving area of technology that has the potential to affect multiple aspects of our business operations, grid management, critical infrastructure management, customer interactions, cybersecurity posture, and decision support processes.
Because AI technologies remain in the early stages of development and industry standards are still emerging, their use, whether by PPL, its subsidiaries or third-party vendors, presents inherent risks. Although we seek contractual protections and conduct due diligence with third-party vendors that incorporate AI technologies into their products or services, we may not have full visibility into, awareness of, or control over, the underlying data, supply chain dependencies, model training practices, performance, security safeguards, or compliance posture of such AI enabled tools. AI algorithms that we or our third-party vendors use may be flawed or may be based on datasets that are biased or insufficient, which may introduce risks involving data quality, data integrity, cybersecurity, adversarial manipulation, intellectual property, regulatory compliance, biased outcomes, or improper handling of sensitive information.
These limitations, failures, or inaccurate results generated as a result of our employees', contractors' or vendors' use or misuse of AI technologies could lead to operational interruptions or otherwise adversely affect our business, reputation, or financial results. In addition, the development, testing, and deployment of AI capabilities may require significant computational resources, specialized personnel, and additional investment, resulting in increased costs. We may not be able to recover these costs through our regulatory proceedings. Rapid advances in AI capabilities, as well as the emerging regulatory landscape in the United States and internationally, may also require modifications to our systems, adoption of enhanced governance processes or implementation of new safeguards. Future laws, regulations, Executive Orders, or industry standards relating to AI (which may be conflicting), including those addressing transparency, data usage, cybersecurity, accountability, or risk management, could materially affect how we design, procure, or use AI technologies and could increase compliance costs. In addition, the pace of AI innovation and regulation is unpredictable, and we cannot foresee all potential impacts of AI technologies or future laws and regulations or compliance requirements, and their associated costs and consequences. Any of the risks described above could adversely affect our business operations, reputation, or financial results.
Natural disasters or operational accidents may adversely affect the Registrants' operating results.
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Natural disasters or operational accidents (such as wildfires, earthquakes, hurricanes or natural gas transmission pipeline explosions) could have direct or indirect impacts on the Registrants or key contractors or suppliers. Further, the generation of electricity and the transportation and storage of natural gas involve inherent operating risks that may result in accidents involving serious injury or loss of life, environmental damage or property damage. Such events could affect the Registrants through civil or criminal legal proceedings or changes to policies, laws and regulations the compliance costs of which may have a significant impact on the Registrants' results of operations, financial position and cash flows. Existing insurance policies may not cover all of the potential exposures in connection with such incidents. Any losses not covered by insurance, or any increases in the cost of applicable insurance as a result of such incidents, could have a material adverse effect on the results of operations, financial position and cash flows of the Registrants.
We are subject to risks associated with federal and state tax laws and regulations.
Changes in tax law as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations and cash flows. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, gross receipts, franchise, sales and use, employment-related and other taxes. We also estimate our ability to utilize deferred tax assets and tax credits. Dependent upon the revenue needs of the jurisdictions in which our businesses operate, various tax and fee increases may be proposed or considered. We cannot predict changes in tax law or regulation or the effect of any such changes on our businesses. Any such changes could increase tax expense and could have a significant negative impact on our results of operations and cash flows. We continue to evaluate the application of relevant laws, including the TCJA, the IRA and the One Big Beautiful Bill Act.
Increases in electricity prices and/or a weak economy can lead to changes in legislative and regulatory policy, including the promotion of energy efficiency, conservation and distributed generation or self-generation, which may adversely affect our business.
Energy consumption is significantly impacted by overall levels of economic activity and costs of energy supplies. Economic downturns or periods of high energy supply costs can lead to changes in or the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency, alternative and renewable energy sources, and distributed or self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity demand, which could adversely affect our business.
We could be negatively affected by rising interest rates, downgrades to our credit ratings, adverse credit market conditions or other negative developments in our ability to access capital markets.
Our businesses are capital-intensive and, in the ordinary course of business, we are reliant upon adequate long-term and short-term financing to fund our significant capital expenditures, debt service and operating needs. As a result, we are sensitive to developments in interest rates, credit rating considerations, insurance, security or collateral requirements, market liquidity and credit availability and refinancing opportunities necessary or advisable to respond to credit market changes. Changes in these conditions could result in increased costs and decreased availability of credit. In addition, certain sources of debt and equity capital have expressed reservations about investing in companies that rely on fossil fuels. If sources of our capital are reduced, capital costs could increase materially.
A downgrade in our credit ratings could negatively affect our ability to access capital and increase the cost of maintaining our credit facilities and any new debt.
Credit ratings assigned by Moody's and S&P to our businesses and their financial obligations have a significant impact on the cost of capital incurred by our businesses. A ratings downgrade could increase our short-term borrowing costs and negatively affect our ability to fund liquidity needs and access new long-term debt at acceptable interest rates. See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Ratings Triggers" for additional information on the financial impact of a downgrade in our credit ratings.
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Our operating revenues could fluctuate on a seasonal basis, especially as a result of extreme weather conditions, including storms, or from changes in average temperatures for extended periods, which may be caused or exacerbated by climate change.
Our businesses are subject to seasonal demand cycles. For example, in some markets demand for, and market prices of, electricity peak during hot summer months, while in other markets such peaks occur in cold winter months. As a result, our overall operating results may fluctuate substantially on a seasonal basis if weather conditions diverge adversely from seasonal norms. Extreme weather and other significant disruptive events could significantly affect our profitability or operations by causing outages, damaging infrastructure and requiring significant repair costs. Storm outages and damage often directly decrease revenues and increase expenses, due to reduced usage and restoration costs. The effects of climate change may cause, contribute to or magnify fluctuations in our operating results.
Our businesses are subject to physical, market and economic risks relating to potential effects of climate change.
Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects. Climate change may also contribute to heightened risk or severity of wildfires, which could disrupt our operations and cause us to incur significant costs, though the annual FEMA National Risk Index for wildfires in the jurisdictions in which we provide service is very low to relatively moderate. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Greenhouse gas regulation such as the EPA's May 2024 rule governing emissions from certain fossil fuel-fired electric generating units could increase the cost of electricity, and such increases could have a depressive effect on regional economies. Reduced economic and consumer activity in our service areas -- both generally and specific to certain industries and consumers accustomed to previously lower cost power -- could reduce demand for the power we generate, market and deliver. Also, demand for our energy-related services could be similarly lowered by consumers' preferences or market factors favoring energy efficiency, low-carbon power sources or reduced electricity usage. The Registrants' responses to such climate-related risks include compliance with evolving governmental policy, which may affect our financial condition, results of operations or cash flows.
We cannot predict the outcome of legal proceedings or investigations related to our businesses in which we are periodically involved. An unfavorable outcome or determination in any of these matters could have a material adverse effect on our financial condition, results of operations or cash flows.
We are involved in legal proceedings, claims and litigation and periodically are subject to state and federal investigations arising out of our business operations, the most significant of which are summarized in Item 1. Business and "Regulatory Matters" in Note 7 to the Financial Statements and in "Legal Matters" and "Regulatory Issues" in Note 12 to the Financial Statements. We cannot predict the ultimate outcome of these matters, nor can we reasonably estimate the costs or liabilities that could potentially result from a negative outcome in each case.
Significant increases in our operation and maintenance expenses, including health care and pension costs, could adversely affect our future earnings and liquidity.
We continually focus on limiting and reducing our operation and maintenance expenses. However, we expect to continue to face increased cost pressures in our operations. Increased costs of materials and labor may result from general inflation, increased regulatory requirements (especially in respect of environmental regulations), the need for higher-cost expertise in the workforce or other factors. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. These benefits give rise to significant expenses. Due to general inflation with respect to such costs, the aging demographics of our workforce and other factors, we have experienced significant health care cost inflation in recent years, and we expect our health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take to require employees and retirees to bear a higher portion of the costs of their health care benefits. In addition, we expect to continue to incur significant costs with respect to the defined benefit pension plans for our employees and retirees. The measurement of our expected future health care and pension obligations, costs and liabilities is highly dependent on a variety of assumptions, most of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, inflation rates, benefit improvements, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs and cash contribution requirements to fund these benefits could increase significantly.
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We may incur liabilities in connection with divestitures.
In connection with various divestitures, and certain other transactions, we have indemnified or guaranteed parties against certain liabilities. These indemnities and guarantees relate, among other things, to liabilities which may arise with respect to the period during which we or our subsidiaries operated a divested business, and to certain ongoing contractual relationships and entitlements with respect to which we or our subsidiaries made commitments in connection with a divestiture. See "Guarantees and Other Assurances" in Note 12 to the Financial Statements.
We are subject to liability risks relating to our generation, transmission and distribution operations.
The conduct of our physical and commercial operations subjects us to many risks, including risks of potential physical injury, property damage or other financial liability, caused to or by employees, customers, contractors, vendors, contractual or financial counterparties and other third parties.
Our facilities may not operate as planned, which may increase our expenses and decrease our revenues and have an adverse effect on our financial performance.
Operation of power plants, transmission and distribution facilities, information technology systems and other assets and activities subjects us to a variety of risks, including the breakdown or failure of equipment, accidents, security breaches, viruses or outages affecting information technology systems, labor disputes, obsolescence, delivery/transportation problems and disruptions of fuel supply and performance below expected levels. These events may impact our ability to conduct our businesses efficiently and lead to increased costs, expenses or losses. Operation of our delivery systems below our expectations may result in lost revenue and increased expense, including higher maintenance costs, which may not be recoverable from customers. Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them.
Although we maintain insurance coverage for certain of these risks, we do not carry insurance for all of these risks and no assurance can be given that such insurance coverage will be sufficient to compensate us in the event losses occur.
We are required to obtain, and to comply with, government permits and approvals.
We are required to obtain, and to comply with, numerous permits, approvals, licenses and certificates from governmental agencies. The process of obtaining and renewing necessary permits can be lengthy and complex and sometimes result in the establishment of permit conditions that make the project or activity for which a permit was sought unprofitable or otherwise unattractive. In addition, such permits or approvals may be subject to denial, revocation or modification under certain circumstances. Failure to obtain or comply with the conditions of permits or approvals, or failure to comply with any applicable laws or regulations, may result in delay or temporary suspension of our operations and electricity sales or the curtailment of our power delivery and may subject us to penalties and other sanctions. Although various regulators routinely renew existing licenses, renewal could be denied or jeopardized by various factors, including failure to provide adequate financial assurance for closure; failure to comply with environmental, health and safety laws and regulations or permit conditions; local community, political or other opposition; and executive, legislative or regulatory action.
Our cost or inability to obtain and comply with the permits and approvals required for our operations could have a material adverse effect on our operations and cash flows. In addition, new environmental legislation or regulations, if enacted, or changed interpretations of existing laws may elicit claims that historical routine modification activities at our facilities violated applicable laws and regulations. In addition to the possible imposition of fines in such cases, we may be required to undertake significant capital investments in pollution control technology and obtain additional operating permits or approvals, which could have an adverse impact on our business, results of operations, cash flows and financial condition.
War, other armed conflicts or terrorist attacks could have a material adverse effect on our business.
War, terrorist attacks and unrest have caused and may continue to cause instability in the world's financial and commercial markets. In addition, unrest could lead to acts of terrorism in the United States or elsewhere, and acts of terrorism could be directed against companies such as ours. Armed conflicts and terrorism and their effects on us or our markets may significantly affect our business and results of operations in the future. In addition, we may incur increased costs for security, including additional physical plant security and security personnel or increased capability following a terrorist incident.
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We are subject to counterparty performance, credit or other risk in the provision of goods or services to us, which could adversely affect our ability to operate our facilities or conduct business activities.
We purchase from a variety of suppliers energy, capacity, fuel, natural gas, transmission service and certain commodities used in the physical operation of our businesses, as well as goods or services, including information technology rights and services, used in the administration of our businesses. Delivery of these goods and services is dependent on the continuing operational performance and financial viability of our contractual counterparties and also the markets, infrastructure or third parties they use to provide such goods and services to us. As a result, we are subject to risks of disruptions, curtailments or increased costs in the operation of our businesses if such goods or services are unavailable or become subject to price spikes or if a counterparty fails to perform. Such disruptions could adversely affect our ability to operate our facilities or deliver services and collect revenues, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations. The performance of coal markets and producers may be the subject of increased counterparty risk to LG&E and KU currently due to weaknesses in such markets and suppliers. The coal industry is subject to increasing competitive pressures from natural gas markets, political pressures and new or more stringent environmental regulation, including regulation of combustion byproducts and water inputs or discharges.
We are subject to the risk that our workforce and its knowledge base may become depleted in coming years.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. We experience attrition due primarily to retiring employees, with the risk that critical knowledge will be lost and that it may be difficult to replace departed personnel, and to attract and retain new personnel, with appropriate skills and experience.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
ITEM 1C. CYBERSECURITY (All Registrants)
Processes for Identifying, Assessing and Managing Material Risks from Cybersecurity Threats
PPL's Chief Security Officer (CSO) is responsible for establishing, implementing and executing PPL's cyber-risk management strategy for PPL and the other Registrants and reports to PPL's Executive Vice President and Chief Technology and Innovation Officer. The CSO has over 30 years of experience leading technology and security organizations, has a degree in computer science, and holds professional certifications in information security, IT auditing, and privacy. He is also a member of nationally and internationally recognized industry and security organizations, including the Information Systems Audit and Control Association, International Association of Privacy Professionals, and the Domestic Security Alliance Council. The CSO has responsibility for and oversees teams comprised of seasoned experts in cyber and IT security who possess appropriate experience to safeguard the company's data, networks and systems, mitigate cyber risks and help prevent and combat cyber threats. Reporting to the CSO are PPL's Chief Technology Security Officer (CTSO) and the VP of Corporate Security. The CTSO has over 25 years of experience, is a certified information security professional, and manages PPL's cyber security operations overseeing the implementation of security strategies and solutions across the Registrants, threat management, access management, cloud security and artificial intelligence.
The Registrants manage cybersecurity risks through monitoring, defense and response tools, including independent third-party assessments, internal audit assessments of the program's effectiveness, intelligence reports, cybersecurity threat trends, implementation of governance models, industry collaboration and employee training and awareness. The Registrants are actively engaged in cybersecurity related industry forums, public-private partnerships with law enforcement, cross-industry peer groups, and other efforts to help improve the protection of the U.S. electric grid.
The Registrants utilize monitoring tools, including but not limited to, cybersecurity incident and event management, penetration testing, intrusion detection and prevention, vulnerability assessments and anti-virus systems to detect anomalous or suspicious system or network activity. The Registrants may also become aware of a potential cybersecurity event or incident through employee reports, notification by a third-party service provider or business partner with potential impact to the Registrants or their systems, customers or notification by a government agency. The Registrants' subject matter specialists from across the enterprise provide input and expertise into risk governance processes, including cybersecurity, information technology, legal, compliance, operations, and enterprise risk management.
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In developing their cybersecurity programs, the Registrants are guided by various frameworks including the NIST Cybersecurity Framework, a voluntary framework that consists of standards, guidelines and best practices for managing cybersecurity risk, that is widely used by critical infrastructure industries to help determine and address the highest priority cybersecurity risks. The Registrants conduct regular internal cybersecurity audits and vulnerability assessments and regularly engage with third-party cybersecurity experts for external assessments of their cybersecurity controls, including technical, physical and social aspects, to better comprehend the scope and magnitude of active threats to the industry and nation and their potential impact on our systems.
The CSO chairs the Corporate Security Council, consisting of senior executive management, which convenes regularly to and review and oversee cybersecurity risks. PPL and the other Registrants also maintain a process to review the cyber risks that arise from the use of third-party service providers as well as programs and procedures to mitigate such risks internally and to assess the extent to which such providers effectively manage their own cyber risks.
PPL has established an Executive Crisis Team comprised of PPL's executive leadership, including the CLC and additional officers as circumstances may warrant, to allow the company to respond quickly to a crisis, including a cyber event. This team governs and manages corporate crisis preparedness across the business lines, operations, and functions. Material or potentially material risks are escalated to the Executive Crisis Team and other appropriate leadership for review and action.
Also, the Registrants' workforce undertakes mandatory role-based annual training on identifying, reporting, and escalating cyber and physical security concerns to further assist in the identification of risks as well as the acceptable use of corporate electronic resources. Additionally, all employees and contractors are required to participate in the Registrants' ethical cyber phishing campaign program and complete annual cybersecurity awareness training.
In addition to these enterprise-wide initiatives, PPL's Kentucky, Pennsylvania and Rhode Island operations are subject to extensive and rigorous mandatory cybersecurity requirements that are developed and enforced by NERC and approved by FERC to protect grid security and reliability. LG&E is also subject to certain security directives related to cybersecurity issued by the Department of Homeland Security's Transportation Security Administration in 2021. See Note 12 to the Financial Statements for additional information on these directives.
The Registrants have been subject to attempted cybersecurity threats and will likely continue to be subject to such attempts in the future. While PPL has not determined that any cybersecurity incidents have materially affected the Registrants, including their business strategy, results of operations or financial condition, there can be no guarantee that the Registrants will not be the subject of future attacks, threats or incidents, the consequences of which may be material.
See "Risks Related to All Segments – Our business operations are continually subject to cyber-based security and data integrity risks from vulnerabilities related to our IT systems, operational technology infrastructure and supply chain relationships" in "Item 1A. Risk Factors" for a discussion of cybersecurity risks affecting the Registrants.
Oversight of Cybersecurity Risks by the Board of Directors and Management
PPL's Board of Directors (the Board) oversees the Registrants' management of cybersecurity risk through various processes identified below.
The Board has direct oversight of the Registrants' cybersecurity programs through periodic reports from the CSO, at least twice a year, regarding cybersecurity matters and risks as well as the adequacy and effectiveness of our cybersecurity risk management program. Through these reports, the Board monitors the Registrants' programs, processes and procedures related to cybersecurity. The Board has directed the CEO and CSO to promptly inform the Board in the event of a material or potentially material cybersecurity event. Each member of the Board has access to management, including the CEO and CSO, to ask questions and engage in the company's approach to prevent, detect, assess, and mitigate cybersecurity risk. PPL's Board has several Board members with experience in cybersecurity, including one with a certificate in Cyber-Risk Oversight from the National Association of Corporate Directors.
A primary function of the Audit Committee is to assist the Board in the oversight of the identification, assessment and management of risk. Cybersecurity risks are included in PPL's enterprise risk management process and are reported to the Audit Committee of the Board on a quarterly basis or more frequently, as needed.
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ITEM 2. PROPERTIES
Kentucky Regulated Segment (PPL, LG&E and KU)
LG&E's and KU's properties consist primarily of regulated generation facilities, electricity transmission and distribution assets and natural gas transmission and distribution assets in Kentucky. The capacity of generation units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances. The electricity generating capacity at December 31, 2025 was:

|  |  |  | LG&E |  | KU
Primary Fuel/Plant |  | Total MW Capacity Summer |  | % Ownership or Other Interest |  | Ownership or Other Interest in MW |  | % Ownership or Other Interest |  | Ownership or Other Interest in MW
Coal |  |  |  |  |  |  |  |  |  |
Ghent - Units 1- 4 |  | 1,919 |  |  |  |  |  | 100.00 |  | 1,919
Mill Creek - Units 2- 4 |  | 1,165 |  | 100.00 |  | 1,165 |  |  |  |
E.W. Brown - Unit 3 |  | 412 |  |  |  |  |  | 100.00 |  | 412
Trimble County - Unit 1 (a) |  | 493 |  | 75.00 |  | 370 |  |  |  |
Trimble County - Unit 2 (a) |  | 732 |  | 14.25 |  | 104 |  | 60.75 |  | 445
|  | 4,721 |  |  |  | 1,639 |  |  |  | 2,776
Natural Gas/Oil |  |  |  |  |  |  |  |  |  |
E.W. Brown Unit 5 (b) |  | 130 |  | 53.00 |  | 69 |  | 47.00 |  | 61
E.W. Brown Units 6 - 7 |  | 292 |  | 38.00 |  | 111 |  | 62.00 |  | 181
E.W. Brown Units 8 - 11 (b) |  | 484 |  |  |  |  |  | 100.00 |  | 484
Trimble County Units 5 - 6 |  | 318 |  | 29.00 |  | 92 |  | 71.00 |  | 226
Trimble County Units 7 - 10 |  | 636 |  | 37.00 |  | 235 |  | 63.00 |  | 401
Paddy's Run Unit 12 |  | 23 |  | 100.00 |  | 23 |  |  |  |
Paddy's Run Unit 13 |  | 147 |  | 53.00 |  | 78 |  | 47.00 |  | 69
Haefling - Units 1 - 2 |  | 24 |  |  |  |  |  | 100.00 |  | 24
Cane Run Unit 7 |  | 691 |  | 22.00 |  | 152 |  | 78.00 |  | 539
|  | 2,745 |  |  |  | 760 |  |  |  | 1,985
Hydro |  |  |  |  |  |  |  |  |  |
Ohio Falls - Units 1-8 |  | 64 |  | 100.00 |  | 64 |  |  |  |
Dix Dam - Units 1-3 |  | 32 |  |  |  |  |  | 100.00 |  | 32
|  | 96 |  |  |  | 64 |  |  |  | 32
Solar |  |  |  |  |  |  |  |  |  |
E.W. Brown Solar (c) |  | 8 |  | 39.00 |  | 3 |  | 61.00 |  | 5
Total |  | 7,570 |  |  |  | 2,466 |  |  |  | 4,798

(a)Trimble County Unit 1 and Trimble County Unit 2 are jointly owned with Illinois Municipal Electric Agency and Indiana Municipal Power Agency. Each owner is entitled to its proportionate share of the units' total output and funds its proportionate share of capital, fuel and other operating costs. See Note 11 to the Financial Statements for additional information.
(b)There is an inlet air cooling system attributable to these units. This inlet air cooling system is not jointly owned; however, it is used to increase production on the units to which it relates, resulting in an additional 12 MW of capacity for LG&E and an additional 86 MW of capacity for KU.
(c)This unit is a 10 MW facility and achieves such production. The 8 MW solar facility summer capacity rating is reflective of an average expected output across the peak hours during the summer period based on average weather conditions at the solar facility.
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For a description of LG&E's and KU's service areas, see "Item 1. Business - General - Segment Information - Kentucky Regulated Segment." At December 31, 2025, LG&E's and KU's electricity transmission and distribution systems and LG&E's natural gas transmission and distribution systems were:

|  | LG&E |  | KU
|  | Distribution |  | Transmission |  | Distribution |  | Transmission
Electricity System |  |  |  |  |  |  |  |
Substations (a) |  | 97 |  | 79 |  | 460 |  | 216
Capacity (in millions of kVA) |  | 6 |  | 8 |  | 8 |  | 16
Overhead lines (circuit miles) |  | 3,890 |  | 662 |  | 14,104 |  | 4,064
Underground lines (circuit miles) |  | 2,913 |  | 6 |  | 2,901 |  | 4
Natural Gas System |  |  |  |  |  |  |  |
Distribution mains (miles) |  | 4,475 |  | — |  | — |  | —
Transmission pipeline (miles) |  | — |  | 230 |  | — |  | —
Transmission storage lines (miles) |  | — |  | 83 |  | — |  | —
Combustion turbine lines (miles) |  | — |  | 19 |  | — |  | 11
Storage fields |  | — |  | 4 |  | — |  | —
Storage field capacity (Bcf) |  | — |  | 11 |  | — |  | —

(a)196 substations (62 at LG&E and 134 at KU) are shared between the distribution and transmission systems.
Substantially all of LG&E's and KU's respective real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and, in the case of LG&E, the storage and distribution of natural gas, is subject to the lien of either the LG&E 2010 Mortgage Indenture or the KU 2010 Mortgage Indenture. See Note 8 to the Financial Statements for additional information.
LG&E and KU continuously reexamine development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them or pursue other options. See Item 1. Business for a discussion related to LG&E's and KU's Solar Share program and 2022 and 2025 CPCN filings.
Pennsylvania Regulated Segment (PPL and PPL Electric)
For a description of PPL Electric's service area, see "Item 1. Business - General - Segment Information - Pennsylvania Regulated Segment." PPL Electric has electric transmission and distribution lines in public streets and highways pursuant to franchises and rights-of-way secured from property owners. At December 31, 2025, PPL Electric's transmission system includes 53 substations with a total capacity of 32 million kVA and 5,301 circuit miles in service. PPL Electric's distribution system includes 355 substations with a total capacity of 15 million kVA, 36,660 circuit miles of overhead lines and 9,102 underground circuit miles. All of PPL Electric's facilities are located in Pennsylvania. Substantially all of PPL Electric's distribution properties and certain transmission properties are subject to the lien of the PPL Electric 2001 Mortgage Indenture. See Note 8 to the Financial Statements for additional information.
Rhode Island Regulated Segment (PPL)
For a description of RIE's service area, see "Item 1. Business - General - Segment Information - Rhode Island Regulated Segment." At December 31, 2025, RIE's electric transmission system includes 45 substations with capacity of 33 kVA or higher, 361 circuit miles of overhead lines and 49 underground circuit miles. RIE's electric distribution system includes 59 substations, 6,600 circuit miles of overhead lines and 1,268 underground circuit miles. RIE also has distribution mains for its natural gas system with mileage of 3,220 miles. All of RIE's facilities are located in Rhode Island.
ITEM 3. LEGAL PROCEEDINGS
See Notes 6, 7, 9 and 12 to the Financial Statements for information regarding legal, tax and regulatory matters and proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash" for information regarding certain restrictions on the ability to pay dividends for all Registrants.
PPL Corporation
Additional information for this item is set forth in the sections entitled "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and "Shareowner and Investor Information" of this report. At January 30, 2026 there were 39,811 common stock shareowners of record.
There were no purchases by PPL of its common stock during the fourth quarter of 2025.
PPL Electric Utilities Corporation
There is no established public trading market for PPL Electric's common stock, as PPL owns 100% of the outstanding common shares. Dividends paid to PPL on those common shares are determined by PPL Electric's Board of Directors. PPL Electric paid common stock dividends to PPL of $401 million in 2025 and $375 million in 2024.
Louisville Gas and Electric Company
There is no established public trading market for LG&E's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by LG&E's Board of Directors. LG&E paid common stock dividends to LKE of $200 million in 2025 and $187 million in 2024.
Kentucky Utilities Company
There is no established public trading market for KU's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by KU's Board of Directors. KU paid common stock dividends to LKE of $249 million in 2025 and $232 million in 2024.
ITEM 6. RESERVED
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Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
(All Registrants)
This "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" is separately filed by PPL, PPL Electric, LG&E and KU. Information contained herein relating to any individual Registrant is filed by such Registrant solely on its own behalf, and no Registrant makes any representation as to information relating to any other Registrant. The specific Registrant to which disclosures are applicable is identified in parenthetical headings in italics above the applicable disclosure or within the applicable disclosure for each Registrant's related activities and disclosures. Within combined disclosures, amounts are disclosed for individual Registrants when significant.
The following should be read in conjunction with the Registrants' Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
•"Overview" provides a description of each Registrant's business strategy and a discussion of important financial and operational developments.
•"Results of Operations" for all Registrants includes a "Statement of Income Analysis," which discusses significant changes in principal line items on the Statements of Income, comparing 2025 with 2024. For PPL, "Results of Operations" also includes "Segment Earnings," which provides a detailed analysis of earnings by reportable segment. These discussions include the non-GAAP financial measure "Earnings from Ongoing Operations" and provide an explanation of the non-GAAP financial measure and a reconciliation of the measure to the most comparable GAAP measure.
•"Financial Condition - Liquidity and Capital Resources" provides an analysis of the Registrants' liquidity positions and credit profiles. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.
•"Financial Condition - Risk Management" provides an explanation of the Registrants' risk management programs relating to market and credit risk.
•"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of the Registrants and that require their management to make significant estimates, assumptions and other judgments of inherently uncertain matters.
For comparison of the Registrants' results of operations and cash flows for the years ended December 31, 2024 to December 31, 2023, refer to "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2024 Form 10-K, filed with the SEC on February 13, 2025.
Overview
For a description of the Registrants and their businesses, see "Item 1. Business."
Business Strategy (All Registrants)
PPL operates four regulated utilities located in Pennsylvania, Kentucky and Rhode Island. Each of these jurisdictions has distinct regulatory structures and each of the utilities has distinct customer classes.
PPL's strategy, which is supported by the other Registrants and subsidiaries, is focused on creating the utilities of the future to drive greater value for our customers and shareowners. Key objectives in support of this strategy include:
•Strengthening the reliability and resilience of our electric and gas networks to improve service and protect against current and future weather and storms.
•Advancing a cleaner energy future affordably and reliably. This includes expanding and modernizing our generation with natural gas, renewables and battery storage, while supporting research and development of low-carbon solutions.
•Driving operational efficiencies to improve customer service and help keep energy affordable.
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•Utilizing artificial intelligence and other advanced technologies to inform decision making, optimize asset planning and maintenance and better manage supply and demand on the grid.
•Empowering customers through expanded digital options and improved service.
•Engaging with key stakeholders to strengthen resource adequacy, power economic development, and support the growth and success of the regions we serve.
This strategy supports our mission to provide safe, affordable, reliable and sustainable energy to our customers and competitive, long-term returns to shareowners.
Financial and Operational Developments
Joint Venture Agreement with Blackstone Infrastructure (PPL)
PPL and Blackstone Infrastructure have created a joint venture to build, own and operate new electricity generation stations to power data centers in Pennsylvania under long-term energy services agreements (ESAs) to address underlying resource adequacy and affordability concerns in Pennsylvania and PJM more broadly. Construction of new generation stations will require the execution of ESAs with data center developers, including hyperscalers, or the regulated utilities in Pennsylvania. PPL owns 51% of the joint venture interest and Blackstone Infrastructure owns 49%. The joint venture is actively engaged with hyperscalers, landowners, natural gas pipeline companies and turbine manufacturers, and has secured multiple land parcels to enable this new generation build out; however, no ESAs with hyperscalers have been signed as of the filing date of this Form 10-K.
Regulatory Requirements
(All Registrants)
The Registrants cannot predict the impact that future regulatory requirements may have on their financial condition or results of operations.
Rate Case Proceedings
(PPL)
On November 26, 2025, RIE filed a request with the RIPUC for an increase in electric and natural gas base distribution rates, and approval of certain regulatory and accounting treatments. In its application, RIE seeks to implement a two-year rate plan. In the first year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect additional operating revenue of approximately $181 million ($66 million or 18.2% in electricity revenues and $115 million or 36.4% in gas revenues). In the second year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect the proposed base distribution rate increases for electric and gas in the first year of the rate plan and additional operating revenues of approximately $49 million ($17 million or 3.6% in electricity revenues and $32 million or 7.4% in gas revenues).
The application is based on a historical test year of September 1, 2024 through August 31, 2025 and requested an authorized ROE of 10.75%. Subject to RIPUC approval, new rates are expected to become effective on September 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the RIPUC is anticipated during the third quarter of 2026. PPL cannot predict the outcome of the proceeding.
S ee "Regulatory Matters – Rhode Island Activities – Hold Harmless Implementation Agreement" in Note 7 to the Financial Statements for discussion on an additional rate making initiative to mitigate customer rate impacts.
(PPL and PPL Electric)
On September 30, 2025, PPL Electric filed a request with the PAPUC for an increase in distribution base rates of approximately $356 million, more than $50 million of which is already included in customer bills through rate recovery mechanisms, and approval of certain regulatory and accounting treatments. The proposed increase in distribution base rates would increase PPL Electric's total annual revenue by approximately 8.6%. The application is based on a fully projected future test year of July 1, 2026 through June 30, 2027 and requested an authorized ROE of 11.3%. Subject to PAPUC approval, new rates are expected to become effective on July 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the PAPUC is anticipated during the second quarter of 2026. PPL and PPL Electric cannot predict the outcome of the proceeding.
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(PPL, LG&E and KU)
On May 30, 2025, LG&E and KU filed requests with the KPSC for an increase in annual electricity and gas revenues of approximately $391 million ($105 million and $226 million in electricity revenues at LG&E and KU and $60 million in gas revenues at LG&E) and approval of certain regulatory and accounting treatments. The revenue increases would be an increase of 8.3% and 11.5% in electricity revenues at LG&E and KU, and an increase of 14.0% in gas revenues at LG&E.
The applications were based on a forecasted test year of January 1, 2026 through December 31, 2026 and requested an authorized ROE of 10.95%. New interim rates became effective on January 1, 2026, subject to refund pursuant to the KPSC's final order. Certain counterparties have intervened in the proceedings.
On October 20, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation (the agreement) regarding a proposed resolution of issues with a majority of the intervenors in the proceedings.
Under the agreement, the parties proposed that the KPSC should issue orders granting a revised increase in annual electricity and gas revenues of approximately $235 million ($58 million and $132 million in electricity revenues at LG&E and KU and $45 million in gas revenues at LG&E.) The agreement proposed a revised authorized ROE of 9.90%.
The agreement proposed a "stay out" commitment from LG&E and KU to refrain from effective base rate increases before August 1, 2028, subject to certain exceptions. In connection with the stay out period, the agreement also proposed the establishment of two new rate adjustment clause mechanisms, a Generation Cost Recovery Adjustment Clause (GCR) and a Sharing Mechanism Adjustment Clause (SM).
The proposed GCR mechanism would provide LG&E and KU recovery of and return on investment of covered costs (excluding fuel amounts, which LG&E and KU can recover via an existing rate mechanism) of relevant new generation and energy storage assets authorized in the 2022 and 2025 CPCN proceedings (excluding the Mill Creek Unit 6 NGCC, see "2025 CPCN" for more information regarding the Mill Creek Unit 6 NGCC) as they are placed in service.
The proposed SM mechanism would address any base rate revenue deficiency or surplus during the final thirteen months of the stay out period, July 2027 through July 2028, below or above a suggested ROE band of 9.40% to 10.15%. Any such base rate revenue deficiency or surplus would be collected from or returned to customers over a thirteen-month billing period beginning November 2028.
Following issuance of the 2025 CPCN Order, LG&E and KU filed supplemental testimony with the KPSC in the rate case proceedings seeking recovery of the Mill Creek Unit 2 stay open costs through a proposed additional rate adjustment clause mechanism.
The agreement further proposed that LG&E and KU use regulatory deferral accounting for actual expenses above or below base rate levels for certain expenses including: pension and post-retirement benefits, storm restoration, vegetation management, transmission waivers and credits, and gas line or well activities, with recovery of such deferred asset or liability amounts to be addressed in future rate cases.
On February 16, 2026, the KPSC issued orders approving portions of the October 2025 stipulation and recommendation, with modifications.
The KPSC orders provide for increases in annual electricity and gas revenues of $233 million ($59 million and $128 million in electricity revenues at LG&E and KU and $46 million in gas revenues at LG&E.) The orders include authorized returns on equity of 9.775% for base rate purposes and 9.675% for capital rate adjustment mechanisms.
The KPSC orders approve LG&E's and KU's requests for establishment of certain new rate adjustment mechanisms or tariffs, with modifications:
• a temporary Pilot Generation Recovery Adjustment Clause (PGR) to provide recovery of and return on investment of applicable costs of certain new generation and storage assets being built or anticipated to be built by LG&E and KU as authorized in the 2022 CPCN proceeding;
• the inclusion in the PGR of recovery of and return on investment of certain costs associated with a potential extension of the operating life of LG&E's Mill Creek Unit 2 beyond its original 2027 retirement date; and
• an Extremely High Load Factor Tariff for future applicable customers, such as data centers, which includes requirements such as long-term contracts, minimum revenue payments and collateral security structures that help protect the interests of LG&E, KU and of other ratepayers.
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The PGR mechanism is similar to the GCR proposed in the stipulation, but restructured by the KPSC to be a pilot adjustment mechanism with a term until the earlier of ten months following the submission of LG&E's and KU's next base rate proceeding or the effective date of new rates in such proceeding, with the expectation that the mechanism would be reviewed in such proceeding. The pilot mechanism will apply to the planned Mill Creek Unit 5, Brown Battery Energy Storage System, Mercer County Solar and Marion County Solar generation-related projects. The KPSC also included Mill Creek Unit 2's potential stay-open costs in the PGR in lieu of approving the stipulation's request for a stand-alone adjustment mechanism for such costs. Finally, the KPSC excluded from coverage under the PGR costs related to Mill Creek Unit 6 and Brown Unit 12 planned new generation assets due to their anticipated in-service dates falling outside of the estimated pilot mechanism's duration, but without prejudice to LG&E and KU seeking recovery of such costs in future proceedings.
The KPSC orders also approved, approved with modifications, or denied in some cases, other requested accounting and rate matters relating to regulatory assets or liabilities, depreciation rates, and other areas.
The rate changes have a retroactive effective date as of January 1, 2026. Consistent with authorized rate case procedures, LG&E and KU will refund to customers amounts billed in excess of the final approved rates within sixty days.
The KPSC orders did not approve the SM adjustment clause that had been requested in the stipulation and made no modifications to the stay out offer by LG&E and KU to refrain from effective base rate increases prior to August 2028.
LG&E and KU and all intervenors have rights to request rehearing or appeal of the orders of the KPSC and because the KPSC orders modified or denied terms of the proposed stipulation, LG&E and KU and all stipulating parties have the right to withdraw from the stipulation.
LG&E and KU continue to evaluate the details contained in the orders and related matters as they consider next steps. PPL, LG&E and KU cannot predict the outcome of this matter.
In addition, pursuant to prior orders of the KPSC, the LG&E and KU rate case application included an assessment of a potential legal merger of LG&E and KU and concluded a legal merger may be appropriate. On December 30, 2025, LG&E filed a joint update with KU in the rate case proceedings stating that it expects to file necessary applications for merger approval in mid-2026 with the KPSC. Ultimately, formal approval for a merger would be required from the KPSC, VSCC and FERC via subsequent regulatory applications.
(PPL, LG&E and KU)
Environmental Considerations for Coal-Fired Generation
The businesses of LG&E and KU are subject to extensive federal, state and local environmental laws, rules and regulations, including those pertaining to CCRs, GHG, and ELGs. See Notes 7, 12 and 18 to the Financial Statements for a discussion of these significant environmental matters. These and other environmental requirements led PPL, LG&E and KU to retire approximately 1,500 MW of coal-fired generating plants in Kentucky since 2010. As part of the long-term generation planning process, LG&E and KU evaluate a range of factors including the impact of potential stricter environmental regulations, fuel price scenarios, the cost of replacement generation, continued operations and major maintenance costs and the risk of major equipment failures in determining when to retire generation assets.
As a result of environmental requirements and aging infrastructure, LG&E has sought and obtained approval to retire two older coal-fired units at the Mill Creek Plant. Mill Creek Unit 1, with 300 MW of capacity, was retired in 2024. Mill Creek Unit 2, with 297 MW of capacity, was approved to be retired in 2027, subject to certain conditions. On October 28, 2025, in LG&E and KU's 2025 CPCN proceeding, the KPSC declined to rule on a request to extend the operation of Mill Creek Unit 2. The KPSC indicated that a request for a new retirement approval proceeding may be required should LG&E elect to operate Mill Creek Unit 2 beyond its existing approved retirement date and seek to later retire the unit. See "Rate Case Proceedings" in Note 7 to the Financial Statements for additional information.
On October 4, 2024, LG&E submitted an application related to the retirement of Mill Creek Unit 1, which occurred on December 31, 2024, requesting recovery of associated costs under the RAR. On February 24, 2025, the KPSC issued an order approving LG&E's cost recovery for Mill Creek Unit 1 under the RAR of $125 million and related amounts were included in bills beginning in May 2025. See Note 7 to the Financial Statements for additional information on the Mill Creek Unit 1 RAR.
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2025 CPCN
On February 28, 2025, LG&E and KU filed an application with the KPSC regarding certain future plans for new generation and generation-related construction matters. The proposals included in the application were intended to serve anticipated load growth, including from potential data center demand in LG&E's or KU's service territory. The proposals did not include retirements of coal or other fossil-fueled plants, which would require additional KPSC approval procedures under Kentucky legislation enacted in 2023 and 2024.
LG&E and KU submitted a joint application to the KPSC for approval of certain certificates of public convenience and necessity, site compatibility certificates, and accounting treatment, where applicable, relating to a number of generation-related plans or projects that generally are expected to become operational or established within the next six years. The aggregate projected capital expenditures associated with these proposals were expected to be $3.7 billion. The application included proposals to build:
•a 645 MW NGCC generation unit at KU's E.W. Brown station (Brown Unit 12),
•a 645 MW NGCC generation unit at LG&E's Mill Creek station (Mill Creek Unit 6),
•a four-hour 400 MW (1600 MWh total) battery energy storage system (BESS) at LG&E's Cane Run station, and
•a selective catalytic reduction (SCR) environmental facility at KU's Ghent station Unit 2 (Ghent Unit 2).
The new NGCC units are anticipated to be wholly owned by LG&E and the BESS unit jointly owned by LG&E (32%) and KU (68%), with actual project costs allocated consistent with LG&E's and KU's ultimate ownership shares and existing shared dispatch, cost allocation, tariff or other frameworks. The proposed Mill Creek Unit 6 NGCC is in addition to a new NGCC unit currently under construction at that location (Mill Creek Unit 5).
The filing also noted projected in service dates for the projects, including the Brown Unit 12 NGCC in 2030, the Mill Creek Unit 6 NGCC in 2031, the Cane Run BESS in 2028 and the Ghent Unit 2 SCR in 2028.
On July 29, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation regarding a proposed resolution of issues with several of the intervenors in the CPCN proceeding (stipulation). The stipulation recommended to the KPSC the approval of the large majority of LG&E's and KU's requested generation-related projects and associated accounting matters, subject to certain changes. Under the stipulation, the parties agreed the KPSC should issue an order granting a CPCN for the proposed: (a) Brown Unit 12 NGCC; (b) Mill Creek Unit 6 NGCC; and (c) Ghent Unit 2 SCR. In addition, the proposal to build the $775 million Cane Run BESS would be withdrawn without prejudice, the relevant costs regarding the proposed $1.4 billion Mill Creek Unit 6 NGCC would be recovered through a new rate adjustment clause mechanism, the retirement date for the existing Mill Creek Unit 2 coal unit would be extended from 2027 to the operational date of the proposed Mill Creek Unit 6 NGCC or afterwards, subject to relevant future economic analysis, regulatory or environmental authorizations, and the relevant costs to continue to operate the Mill Creek Unit 2 coal unit would be recovered through a new rate adjustment clause mechanism. The stipulation also contained provisions relating to regulatory asset accounting, proposed data center tariffs, future renewable power requests-for-proposals and other matters. LG&E and KU would retain the right to seek approval of the potentially withdrawn Cane Run BESS or similar substitute project in future regulatory proceedings.
On October 28, 2025, the KPSC issued an order approving much of LG&E's and KU's July 2025 stipulation, with certain modifications. The order granted the requested CPCNs and site-related permits to construct the proposed Brown Unit 12 NGCC, Mill Creek Unit 6 NGCC, and Ghent Unit 2 SCR. The order authorized inclusion of relevant costs of the Ghent Unit 2 SCR in KU's existing environmental cost recovery rate mechanism. The order established a separate monitoring case to receive and consider information during the construction of Mill Creek Unit 6 NGCC.
The order approved requests regarding regulatory asset deferral accounting treatment for certain AFUDC related amounts and noted the KPSC's expectation that the stipulating parties would follow through with their commitments regarding tariffs and power supply contracts related to potential future data center or high load customers in LG&E's and KU's pending rate proceedings. The order also approved other elements of the stipulation or the originally-filed application, with minor modifications.
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The KPSC decided not to approve LG&E's and KU's proposed new rate adjustment cost recovery mechanisms for certain costs associated with Mill Creek Unit 6 NGCC and costs associated with operating the Mill Creek Unit 2 coal plant beyond its original retirement date in 2027. However, the denials were without prejudice to resubmission and the KPSC encouraged the parties to provide additional evidence on such matters in separate proceedings. LG&E and KU provided such evidence addressing recovery of the Mill Creek Unit 2 stay open costs in their pending rate case proceedings. Recovery of Mill Creek Unit 6 costs will be addressed in a future proceeding. The KPSC declined to rule on the matter related to the retirement date of Mill Creek Unit 2 coal plant. The KPSC indicated that a request for a new retirement approval proceeding may be required should LG&E elect to operate Mill Creek Unit 2 beyond its existing approved retirement date and seek to later retire the unit.
In light of the conditional withdrawal in the stipulation, the order did not include a CPCN for the Cane Run BESS. LG&E and KU retain the right to seek approval of the Cane Run BESS project or similar substitute projects at any time in future regulatory proceedings.
FERC Transmission Rate Filing
In 2018, LG&E and KU applied to the FERC requesting elimination of certain on-going waivers and credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the U.S. Court of Appeals - D.C. Circuit (D.C. Circuit Court of Appeals) regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. In August 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. On May 18, 2023, the FERC issued an order on remand reversing its 2019 decision and requiring LG&E and KU to refund credits previously withheld, including under such transition mechanism. LG&E and KU filed a petition for review of the FERC's May 18, 2023 order with the D.C. Circuit Court of Appeals and provided refunds in accordance with the FERC order on December 1, 2023. The FERC issued an order on LG&E's and KU's compliance filing on November 16, 2023, and LG&E and KU filed a petition for review of this November 16, 2023 order on February 14, 2024. The FERC issued the substantive order on rehearing on March 21, 2024, reaffirming its prior decision. On August 8, 2025, the D.C. Circuit Court of Appeals issued a procedural ruling vacating the FERC's prior orders and remanded the matter back to the FERC for further proceedings. LG&E and KU cannot predict the ultimate outcome of the proceedings or any other post decision process but do not expect the annual impact to have a material effect on their operations or financial condition. LG&E and KU currently receive recovery of certain waivers and credits primarily through existing base rate levels.
(PPL)
Hold Harmless Implementation Agreement
As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers required PPL to hold harmless Rhode Island customers from the impact of future rate increases resulting from changes in Accumulated Deferred Income Taxes as a result of the Acquisition (the Hold Harmless Commitment). On June 13, 2025, an agreement was entered into by and among RIE, PPL, PPL Rhode Island Holdings and the Rhode Island Division of Public Utilities and Carriers Advocacy Section (the Hold Harmless Implementation Agreement) to satisfy the Hold Harmless Commitment by providing approximately $155 million in miscellaneous bill credits issued to customers, with approximately $74 million to be issued in the first quarter of 2026 and approximately $81 million to be issued in the first quarter of 2027. The bill credits would be recorded as a reduction to revenue in the periods in which the credits are applied to customers' bills. On September 10, 2025, the Rhode Island Division of Public Utilities and Carriers issued an order confirming that RIE's provision of proposed miscellaneous bill credits as set forth in the Hold Harmless Implementation Agreement would satisfy the Hold Harmless Commitment. Also on September 10, 2025, the RIPUC opened a docket to evaluate the miscellaneous bill credit proposal set forth in the Hold Harmless Implementation Agreement, including the underlying rate accounting, and required RIE to file a tariff advice with the RIPUC, which RIE filed on October 2, 2025. After responding to discovery in that proceeding and before the evidentiary hearing was held or convened, RIE filed a notice of withdrawal of its tariff advice filing noting that it would hold in abeyance a comprehensive satisfaction of the Hold Harmless Commitment at this time. As a result of RIE's filing the notice of withdrawal, the Commission cancelled the evidentiary hearing. The docket remains open, but there has been no further activity since RIE's withdrawal of the tariff advice and the RIPUC's cancellation of the evidentiary hearing. PPL cannot predict whether there will be any further proceedings on the docket or the outcome of any further proceedings that may occur.
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Winter Bill Volatility Docket
At an Open Meeting on November 24, 2025, the RIPUC approved several measures to help mitigate winter bill increases for electric customers. First, the RIPUC approved miscellaneous bill credits for all residential electric customers of $23.54 per month for January, February, and March 2026. Second, the RIPUC paused the Storm Fund Replenishment Factor for usage on and after January 1, 2026, subject to further review through the 2026 Annual Retail Rate Filing. Third, the RIPUC paused the electric Energy Efficiency Charge for usage beginning January 1, 2026 through March 31, 2026. To offset the costs of the miscellaneous bill credits, the RIPUC directed RIE to apply the December 31, 2025 electric Energy Efficiency fund balance, net of any earned incentives, and directed RIE to transfer $11 million from the storm fund balance. The RIPUC approved future cost recovery for RIE of any unfunded balance of the miscellaneous bill credits through future identified offsets and/or a reconciling recovery mechanism to be determined in conjunction with the 2026 electric retail rate filing to allow recovery by December 31, 2026. Any remaining unfunded balance shall accrue at RIE's weighted average cost of capital.
FY 2027 Gas ISR Plan
On December 22, 2025, RIE filed its FY 2027 Gas ISR Plan with the RIPUC with a budget of $184 million that primarily included $166 million of capital investment spend and $17 million for spending on curb-to-curb paving. A decision from the RIPUC on the Plan is expected by March 31, 2026. RIE cannot predict the outcome of this matter.
FY 2027 Electric ISR Plan
On December 22, 2025, RIE filed its FY 2027 Electric ISR Plan with the RIPUC with a budget that primarily included $154 million of capital investment spend (including $18 million for Advanced Metering Functionality) and $13 million of vegetation operation and maintenance spend. A decision from the RIPUC is expected by March 31, 2026. RIE cannot predict the outcome of this matter.
DSIC Petition (PPL and PPL Electric)
On April 26, 2024, PPL Electric filed a Petition with the PAPUC requesting that the PAPUC waive PPL Electric's DSIC cap of 5% of billed revenues and increase the maximum allowable DSIC to 9% for bills rendered on or after January 1, 2025. On February 28, 2025, the PAPUC issued its written order permitting PPL Electric to increase its DSIC cap from 5% to 7.5% for bills rendered on or after March 13, 2025 until the effective date of rates established in PPL Electric's next base rate case or the end of the PPL Electric's 2023-2027 Long-term Infrastructure Improvement Plan, whichever occurs first, at which time it will return to 5%.
Results of Operations
(PPL)
The "Statement of Income Analysis" discussion below describes significant changes in principal line items on the Statements of Income, comparing 2025 with 2024. The "Segment Earnings" discussions provide a review of results by reportable segment. These discussions include the non-GAAP financial measure "Earnings from Ongoing Operations" and provide an explanation of the non-GAAP financial measure and a reconciliation of the measure to the most comparable GAAP measure.
(PPL Electric, LG&E and KU)
A "Statement of Income Analysis" is presented separately for PPL Electric, LG&E and KU. The "Statement of Income Analysis" discussion below describes significant changes in principal line items on the Statements of Income, comparing 2025 with 2024. The results of operations section for PPL Electric, LG&E and KU is presented in a reduced disclosure format in accordance with General Instructions (I)(2)(a) of Form 10-K.
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PPL: Statement of Income Analysis and Segment Earnings
Statement of Income Analysis
Net income for the years ended December 31 includes the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues | $ | 9,042 |  |  | $ | 8,462 |  |  | $ | 580 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Fuel | 855 |  |  | 783 |  |  | 72 |
Energy purchases | 1,892 |  |  | 1,679 |  |  | 213 |
Other operation and maintenance | 2,431 |  |  | 2,607 |  |  | (176) |
Depreciation | 1,312 |  |  | 1,279 |  |  | 33 |
Taxes, other than income | 423 |  |  | 374 |  |  | 49 |
Total Operating Expenses | 6,913 |  |  | 6,722 |  |  | 191 |
Operating Income | 2,129 |  |  | 1,740 |  |  | 389 |
Other Income (Expense) - net | 151 |  |  | 114 |  |  | 37 |
Interest Expense | 808 |  |  | 738 |  |  | 70 |
Income Before Income Taxes | 1,472 |  |  | 1,116 |  |  | 356 |
Income Taxes | 291 |  |  | 228 |  |  | 63 |
Net Income | $ | 1,181 |  |  | $ | 888 |  |  | $ | 293 |

Operating Revenues
The increase (decrease) in operating revenues was due to:

| 2025 vs. 2024
PPL Electric distribution volumes (a) | $ | 34 |
PPL Electric PLR (b) | 174 |
PPL Electric transmission formula rate (c) | 45 |
LG&E volumes (d) | 15 |
LG&E fuel and other energy purchases (e) | 67 |
LG&E off-system sales (f) | 11 |
KU volumes (d) | 34 |
KU fuel and other energy purchases (g) | 31 |
KU off-system sales (f) | 18 |
RIE energy purchases and other recoveries (h) | 140 |
RIE capital investment | 20 |
Other | (9) |
Total | $ | 580 |

(a)The increase was primarily due to weather and higher other usage in 2025.
(b)The increase was primarily due to higher energy prices, more PLR customers and higher customer volumes due to weather and other higher usage.
(c)The increase was primarily due to returns on additional transmission capital investments and return of depreciation expense.
(d)The increases were primarily due to weather.
(e)The increase was primarily due to higher recoveries of fuel expenses and energy purchases.
(f)The increases were primarily due to higher volumes.
(g)The increase was primarily due to higher recoveries of fuel expenses.
(h)The increase was primarily due to higher recoveries of energy purchases primarily due to net metering credits, transmission expenses and gross earnings taxes
Fuel
Fuel expense increased $72 million in 2025 compared with 2024, primarily due to a $40 million increase in commodity costs and a $32 million increase in volumes due to weather.
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Energy Purchases
The increase (decrease) in energy purchases was due to:

| 2025 vs. 2024
PPL Electric PLR volumes | $ | 57 |
PPL Electric PLR prices | 92 |
LG&E commodity costs | 14 |
LG&E volumes | 23 |
RIE net metering | 19 |
Other | 8 |
Total | $ | 213 |

Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:

| 2025 vs. 2024
PPL Electric DER projects impairment (a) | $ | (21) |
PPL Electric vegetation management expenses | (14) |
PPL Electric bad debt expenses | (21) |
PPL Electric storm expenses | (13) |
RIE gas maintenance expenses | 25 |
RIE transmission expenses | 62 |
RIE integration related expenses (b) | (57) |
RIE customer service expenses | 27 |
RIE pension alignment (c) | 22 |
IT costs (d) | 76 |
Transition costs associated with RIE (e) | (236) |
Other | (26) |
Total | $ | (176) |

(a)2024 impairment of DER project costs associated with a pilot solar program for which PPL will not seek regulatory recovery.
(b)Certain transition services agreement costs in 2024 for IT systems that will not be part of PPL's ongoing operations.
(c)The increase is primarily due to a reclassification of the pension adjustment mechanism to align with PPL's accounting for other revenue related recovery items.
(d)Primarily costs associated with PPL's restructuring and rebuilding of its IT infrastructure, organization and systems.
(e)See Note 9 to the Financial Statements for additional information.
Interest Expense
The increase (decrease) in interest expense was due to:

| 2025 vs. 2024
Long-term debt (a) | $ | 47 |
Short-term debt | 13 |
Other | 10 |
Total | $ | 70 |

(a)The increase was primarily due to increased borrowings, partially offset by debt extinguishment gains resulting from affiliated debt repurchases. See Note 8 to the Financial Statements for additional information.
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Income Taxes
The increase (decrease) in income taxes was due to:

| 2025 vs. 2024
Federal tax on change in pre-tax income | $ | 75 |
State income taxes | 8 |
Income tax credits | (8) |
Amortization of (excess)/deficient deferred taxes | (5) |
AFUDC Equity | (10) |
Other | 3 |
Total | $ | 63 |

See Note 6 to the Financial Statements for additional information on income taxes.
Segment Earnings
PPL's Net Income (Loss) by reportable segments was as follows:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Kentucky Regulated | $ | 674 |  |  | $ | 620 |  |  | $ | 54 |
Pennsylvania Regulated | 639 |  |  | 574 |  |  | 65 |
Rhode Island Regulated | 85 |  |  | 109 |  |  | (24) |
Corporate and Other (a) | (217) |  |  | (415) |  |  | 198 |
Net Income (Loss) | $ | 1,181 |  |  | $ | 888 |  |  | $ | 293 |

(a)Primarily represents financing and certain other costs incurred at the corporate level that have not been allocated or assigned to the segments, which are presented to reconcile segment information to PPL's consolidated results.
Earnings from Ongoing Operations
Management utilizes "Earnings from Ongoing Operations" as a non-GAAP financial measure that should not be considered as an alternative to net income, an indicator of operating performance determined in accordance with GAAP. PPL believes that Earnings from Ongoing Operations is useful and meaningful to investors because it provides management's view of PPL's earnings performance as another criterion in making investment decisions. In addition, PPL's management uses Earnings from Ongoing Operations in measuring achievement of certain corporate performance goals, including targets for certain executive incentive compensation. Other companies may use different measures to present financial performance.
Earnings from Ongoing Operations is adjusted for the impact of special items. Special items are presented in the financial tables on an after-tax basis with the related income taxes on special items separately disclosed. Income taxes on special items, when applicable, are calculated based on the statutory tax rate of the entity where the activity is recorded. Special items may include items such as:
• Gains and losses on sales of assets not in the ordinary course of business.
• Impairment charges.
• Significant workforce reduction and other restructuring effects.
• Acquisition and divestiture-related adjustments.
• Other charges or credits that are, in management's view, non-recurring or otherwise not reflective of the company's ongoing operations.
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PPL's Earnings from Ongoing Operations by reportable segment were as follows:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Kentucky Regulated | $ | 693 |  |  | $ | 624 |  |  | $ | 69 |
Pennsylvania Regulated | 640 |  |  | 607 |  |  | 33 |
Rhode Island Regulated | 142 |  |  | 155 |  |  | (13) |
Corporate and Other | (131) |  |  | (136) |  |  | 5 |
Earnings from Ongoing Operations | $ | 1,344 |  |  | $ | 1,250 |  |  | $ | 94 |

See "Reconciliation of Earnings from Ongoing Operations" below for a reconciliation of this non-GAAP financial measure to Net Income.
Kentucky Regulated Segment
The Kentucky Regulated segment consists primarily of LG&E's and KU's regulated electricity generation, transmission and distribution operations, as well as LG&E's regulated distribution and sale of natural gas.
Net Income and Earnings from Ongoing Operations include the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues | $ | 3,760 |  |  | $ | 3,562 |  |  | $ | 198 |
Fuel | 855 |  |  | 783 |  |  | 72 |
Energy purchases | 214 |  |  | 176 |  |  | 38 |
Other operation and maintenance | 818 |  |  | 803 |  |  | 15 |
Depreciation | 717 |  |  | 710 |  |  | 7 |
Taxes, other than income | 102 |  |  | 99 |  |  | 3 |
Total Operating Expenses | 2,706 |  |  | 2,571 |  |  | 135 |
Other Income (Expense) - net | 53 |  |  | 29 |  |  | 24 |
Interest Expense | 264 |  |  | 240 |  |  | 24 |
Income Taxes | 169 |  |  | 160 |  |  | 9 |
Net Income | 674 |  |  | 620 |  |  | 54 |
Less: Special Items | (19) |  |  | (4) |  |  | (15) |
Earnings from Ongoing Operations | $ | 693 |  |  | $ | 624 |  |  | $ | 69 |

The following after-tax gains (losses), which management considers special items, impacted the Kentucky Regulated segment's results and are excluded from Earnings from Ongoing Operations:

| Income Statement Line Item |  | 2025 |  | 2024
FERC transmission credit refund, net of tax of $0 (a) | Operating Revenues |  | $ | — |  |  | $ | 1 |
ECR beneficial reuse transition adjustment, net of tax of $2 (b) | Operating Revenues |  | — |  |  | (4) |
Strategic corporate initiatives, net of tax of $0 (c) | Other operation and maintenance |  | — |  |  | (1) |
IT transformation, net of tax of $5 (d) | Other operation and maintenance |  | (16) |  |  | — |
Office relocation and related costs, net of tax of $1 (e) | Other operation and maintenance |  | (3) |  |  | — |
Total |  |  | $ | (19) |  |  | $ | (4) |

(a)Prior period impact related to a FERC refund order.
(b)Prior period impact for an ECR mechanism revenue adjustment related to a KPSC order.
(c)Costs incurred related to PPL's corporate centralization efforts.
(d)Costs associated with PPL's restructuring and rebuilding of its IT infrastructure, organization and systems.
(e)Certain costs related to the relocation of corporate offices.
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The changes in the components of the Kentucky Regulated segment's results between these periods were due to the factors set forth below, which exclude the items that management considers special.

| 2025 vs. 2024
Operating Revenues | $ | 194 |
Fuel | (72) |
Energy purchases | (38) |
Other operation and maintenance | 9 |
Depreciation | (7) |
Taxes, other than income | (3) |
Other Income (Expense) - net | 24 |
Interest Expense | (24) |
Income Taxes | (14) |
Earnings from Ongoing Operations | 69 |
Special Items, after-tax | (15) |
Net Income | $ | 54 |

•Higher operating revenues in 2025 compared to 2024 primarily due to a $98 million increase in recoveries of fuel and energy purchases, a $50 million increase in sales volumes due to weather and a $29 million increase in off-system sales.
•Higher fuel expense in 2025 compared to 2024 primarily due to a $40 million increase in commodity costs and a $32 million increase in volumes due to weather.
•Higher energy purchases in 2025 compared to 2024 primarily due to a $24 million increase in volumes primarily due to weather and a $14 million increase in commodity costs.
Pennsylvania Regulated Segment
The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric.
Net Income and Earnings from Ongoing Operations include the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues | $ | 3,113 |  |  | $ | 2,876 |  |  | $ | 237 |
Energy purchases | 876 |  |  | 721 |  |  | 155 |
Other operation and maintenance | 630 |  |  | 705 |  |  | (75) |
Depreciation | 413 |  |  | 401 |  |  | 12 |
Taxes, other than income | 151 |  |  | 131 |  |  | 20 |
Total Operating Expenses | 2,070 |  |  | 1,958 |  |  | 112 |
Other Income (Expense) - net | 48 |  |  | 45 |  |  | 3 |
Interest Income from Affiliate | 9 |  |  | 33 |  |  | (24) |
Interest Expense | 257 |  |  | 246 |  |  | 11 |
Income Taxes | 204 |  |  | 176 |  |  | 28 |
Net Income | 639 |  |  | 574 |  |  | 65 |
Less: Special Items | (1) |  |  | (33) |  |  | 32 |
Earnings from Ongoing Operations | $ | 640 |  |  | $ | 607 |  |  | $ | 33 |

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The following after-tax gains (losses), which management considers special items, impacted the Pennsylvania Regulated segment's results and are excluded from Earnings from Ongoing Operations:

| Income Statement Line Item |  | 2025 |  | 2024
PPL Electric billing issue, net of tax of $5 (a) | Other operation and maintenance |  | $ | — |  |  | $ | (13) |
Strategic corporate initiatives, net of tax of $2 (b) | Other operation and maintenance |  | — |  |  | (5) |
DER projects impairment, net of tax of $6 (c) | Other operation and maintenance |  | — |  |  | (15) |
Office relocation and related costs, net of tax of $0 (d) | Other operation and maintenance |  | (2) |  |  | — |
Office relocation and related costs (e) | Income Taxes |  | 5 |  |  | — |
IT transformation, net of tax of $1 (f) | Other operation and maintenance |  | (4) |  |  | — |
Total |  |  | $ | (1) |  |  | $ | (33) |

(a)Certain expenses related to billing issues.
(b)Costs incurred related to PPL's corporate centralization efforts.
(c)Impairment of DER project costs associated with a pilot solar program for which PPL will not seek regulatory recovery.
(d)Certain costs related to the relocation of corporate offices.
(e)Tax benefit related to the sale of a corporate office.
(f)Costs associated with PPL's restructuring and rebuilding of its IT infrastructure, organization and systems.
The changes in the components of the Pennsylvania Regulated segment's results between these periods are due to the factors set forth below, which exclude the items that management considers special.

| 2025 vs. 2024
Operating Revenues | $ | 237 |
Energy purchases | (155) |
Other operation and maintenance | 36 |
Depreciation | (12) |
Taxes, other than income | (20) |
Other Income (Expense) - net | 3 |
Interest Income from Affiliate | (24) |
Interest Expense | (11) |
Income Taxes | (21) |
Earnings from Ongoing Operations | 33 |
Special Items, after-tax | 32 |
Net Income | $ | 65 |

•Higher operating revenues in 2025 compared to 2024 primarily due to a $174 million increase in PLR, a $45 million increase in transmission formula rate revenue and a $34 million increase in distribution volumes.
•Higher energy purchases in 2025 compared to 2024 primarily due to a $92 million increase in PLR prices and a $57 million increase in PLR volumes.
•Lower other operation and maintenance expense in 2025 compared to 2024 primarily due to a $14 million decrease in vegetation management expenses and a $13 million decrease in storm expenses.
Rhode Island Regulated Segment
The Rhode Island Regulated segment consists primarily of the regulated electricity transmission and distribution operations and regulated distribution and sale of natural gas conducted by RIE.
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Net Income and Earnings from Ongoing Operations include the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues | $ | 2,168 |  |  | $ | 2,024 |  |  | $ | 144 |
Energy purchases | 802 |  |  | 782 |  |  | 20 |
Other operation and maintenance | 851 |  |  | 731 |  |  | 120 |
Depreciation | 177 |  |  | 165 |  |  | 12 |
Taxes, other than income | 170 |  |  | 144 |  |  | 26 |
Total Operating Expenses | 2,000 |  |  | 1,822 |  |  | 178 |
Other Income (Expense) - net | 33 |  |  | 20 |  |  | 13 |
Interest Income from Affiliate | 3 |  |  | 4 |  |  | (1) |
Interest Expense | 111 |  |  | 95 |  |  | 16 |
Income Taxes | 8 |  |  | 22 |  |  | (14) |
Net Income | 85 |  |  | 109 |  |  | (24) |
Less: Special Items | (57) |  |  | (46) |  |  | (11) |
Earnings from Ongoing Operations | $ | 142 |  |  | $ | 155 |  |  | $ | (13) |

The following after-tax gains (losses), which management considers special items, impacted the Rhode Island Regulated segment's results and are excluded from Earnings from Ongoing Operations:

| Income Statement Line Item |  | 2025 |  |  |  | 2024 |  |
Acquisition integration, net of tax of $1 (a) | Operating Revenues |  | $ | (4) |  |  |  |  | $ | — |  |  |
Post TSA adjustments, net of tax of $3 (b) | Operating Revenues |  | (12) |  |  |  |  | — |  |  |
Acquisition integration, net of tax of $0, $13 (a) | Other operation and maintenance |  | (1) |  |  |  |  | (45) |  |  |
IT transformation, net of tax of $2 (c) | Other operation and maintenance |  | (8) |  |  |  |  | — |  |  |
Post TSA adjustments, net of tax of $1 (b) | Other operation and maintenance |  | (4) |  |  |  |  | — |  |  |
Customer system integration impacts, net of tax of $4 (d) | Other operation and maintenance |  | (15) |  |  |  |  | — |  |  |
Acquisition integration, net of tax of ($2), $0 (a) | Other Income (Expense) - net |  | 7 |  |  |  |  | (1) |  |  |
Energy efficiency programs settlement, net of tax of $2 (e) | Other Income (Expense) - net |  | (6) |  |  |  |  | — |  |  |
Post TSA adjustments, net of tax of $2 (b) | Other Income (Expense) - net |  | (9) |  |  |  |  | — |  |  |
Post TSA adjustments, net of tax of $1 (b) | Interest Expense |  | (5) |  |  |  |  | — |  |  |
Total |  |  | $ | (57) |  |  |  |  | $ | (46) |  |  |

(a)2025 primarily includes a final transition services agreement settlement and certain other acquisition related items. 2024 primarily includes certain transition services agreement costs for IT systems that will not be part of PPL's ongoing operations.
(b)Adjustments related to account reconciliations and process alignment subsequent to the end of the transition services agreement associated with the acquisition of RIE.
(c)Costs associated with PPL's restructuring and rebuilding of its IT infrastructure, organization and systems.
(d)Certain collection process costs incurred due to the timing and implementation of the customer system integration.
(e)See Note 12 to the Financial Statements for additional information.
The changes in the components of the Rhode Island Regulated segment's results between these periods are due to the factors set forth below, which exclude the items that management considers special.

| 2025 vs. 2024
Operating Revenues | $ | 165 |
Energy purchases | (20) |
Other operation and maintenance | (142) |
Depreciation | (12) |
Taxes, other than income | (26) |
Other Income (Expense) - net | 23 |
Interest Income from Affiliate | (1) |
Interest Expense | (10) |
Income Taxes | 10 |
Earnings from Ongoing Operations | (13) |
Special Items, after-tax | (11) |
Net Income | $ | (24) |

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•Higher operating revenues in 2025 compared to 2024 primarily due to a $140 million increase primarily from recovery of transmission expenses, gross earnings taxes and net metering credits and a $20 million increase related to capital investments.
•Higher energy purchases in 2025 compared to 2024 primarily due to an increase in net metering.
•Higher other operation and maintenance expense in 2025 compared to 2024 primarily due to a $62 million increase in transmission expenses, a $30 million increase in IT costs, a $27 million increase in customer service costs, a $25 million increase in gas maintenance expenses and a $22 million increase due to a reclassification of the pension adjustment mechanism to align with PPL's accounting for other revenue related recovery items, partially offset by a $22 million decrease in bad debt expenses.
•Higher depreciation in 2025 compared to 2024 primarily due to an increase in PP&E additions, net of retirements.
•Higher taxes, other than income in 2025 compared to 2024 primarily due to an increase in gross earnings taxes.
•Higher other income (expense) - net in 2025 compared to 2024 primarily due to a reclassification of the pension adjustment mechanism to align with PPL's accounting for other revenue related recovery items.
•Higher interest expense in 2025 compared to 2024 primarily due to increased borrowings.
•Lower income taxes in 2025 compared to 2024 primarily due to $5 million of lower pre-tax income and a $4 million deferred tax adjustment.
Reconciliation of Earnings from Ongoing Operations
The following tables contain after-tax gains (losses), in total, which management considers special items, that are excluded from Earnings from Ongoing Operations, and a reconciliation to PPL's "Net Income" for the years ended December 31.

|  |  | 2025 |  |  |  |  |  |  |  |  |  |
|  |  | KY Regulated |  | PA Regulated |  | RI Regulated |  | Corporate and Other |  |  |  | Total |  |  |  |  |  |  |  |  |  |
Net Income (Loss) |  |  | $ | 674 |  |  | $ | 639 |  |  | $ | 85 |  |  | $ | (217) |  |  |  |  | $ | 1,181 |  |  |  |  |  |  |  |  |  |  |
Less: Special Items (expense) benefit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Talen litigation costs, net of tax of ($1) (a) |  |  | — |  |  | — |  |  | — |  |  | 3 |  |  |  |  | 3 |  |  |  |  |  |  |  |  |  |  |
Acquisition integration, net of tax of $0, $15 (b) |  |  | — |  |  | — |  |  | 2 |  |  | (56) |  |  |  |  | (54) |  |  |  |  |  |  |  |  |  |  |
IT transformation, net of tax of $5, $1, $2, $9 (c) |  |  | (16) |  |  | (4) |  |  | (8) |  |  | (33) |  |  |  |  | (61) |  |  |  |  |  |  |  |  |  |  |
Energy efficiency programs settlement, net of tax of $2 (d) |  |  | — |  |  | — |  |  | (6) |  |  | — |  |  |  |  | (6) |  |  |  |  |  |  |  |  |  |  |
Office relocation and related costs, net of tax of $1, $5 (e) |  |  | (3) |  |  | 3 |  |  | — |  |  | — |  |  |  |  | — |  |  |  |  |  |  |  |  |  |  |
Post TSA adjustments, net of tax of $8 (f) |  |  | — |  |  | — |  |  | (30) |  |  | — |  |  |  |  | (30) |  |  |  |  |  |  |  |  |  |  |
Customer system integration impacts, net of tax of $4 (g) |  |  | — |  |  | — |  |  | (15) |  |  | — |  |  |  |  | (15) |  |  |  |  |  |  |  |  |  |  |
Total Special Items |  |  | (19) |  |  | (1) |  |  | (57) |  |  | (86) |  |  |  |  | (163) |  |  |  |  |  |  |  |  |  |  |
Earnings from Ongoing Operations |  |  | $ | 693 |  |  | $ | 640 |  |  | $ | 142 |  |  | $ | (131) |  |  |  |  | $ | 1,344 |  |  |  |  |  |  |  |  |  |  |

(a)PPL incurred legal expenses and received insurance reimbursement related to litigation associated with its former affiliate, Talen Montana, LLC and certain affiliated entities.
(b)Rhode Island Regulated primarily includes a final transition services agreement settlement and certain other acquisition related items. Corporate and Other primarily includes integration and related costs associated with the acquisition of RIE.
(c)Costs associated with PPL's restructuring and rebuilding of its IT infrastructure, organization and systems.
(d)See Note 12 to the Financial Statements for additional information.
(e)Certain costs and tax benefits related to the relocation of corporate offices.
(f)Adjustments related to account reconciliations and process alignment subsequent to the end of the transition services agreement associated with the acquisition of RIE.
(g)Certain collection process costs incurred due to the timing and implementation of the customer system integration.
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|  |  | 2024
|  |  | KY Regulated |  | PA Regulated |  | RI Regulated |  | Corporate and Other |  |  |  | Total
Net Income (Loss) |  |  | $ | 620 |  |  | $ | 574 |  |  | $ | 109 |  |  | $ | (415) |  |  |  |  | $ | 888 |
Less: Special Items (expense) benefit: |  |  |  |  |  |  |  |  |  |  |  |  |
Talen litigation costs, net of tax of $1 (a) |  |  | — |  |  | — |  |  | — |  |  | (2) |  |  |  |  | (2) |
Strategic corporate initiatives, net of tax of $0, $2, $2 (b) |  |  | (1) |  |  | (5) |  |  | — |  |  | (5) |  |  |  |  | (11) |
Acquisition integration, net of tax of $13, $66 (c) |  |  | — |  |  | — |  |  | (46) |  |  | (250) |  |  |  |  | (296) |
PPL Electric billing issue, net of tax of $5 (d) |  |  | — |  |  | (13) |  |  | — |  |  | — |  |  |  |  | (13) |
FERC transmission credit refund, net of tax of $0 (e) |  |  | 1 |  |  | — |  |  | — |  |  | — |  |  |  |  | 1 |
ECR beneficial reuse transition adjustment, net of tax of $2 (f) |  |  | (4) |  |  | — |  |  | — |  |  | — |  |  |  |  | (4) |
DER projects impairment, net of tax of $6 (g) |  |  | — |  |  | (15) |  |  | — |  |  | — |  |  |  |  | (15) |
IT transformation, net of tax of $5 (h) |  |  | — |  |  | — |  |  | — |  |  | (22) |  |  |  |  | (22) |
Total Special Items |  |  | (4) |  |  | (33) |  |  | (46) |  |  | (279) |  |  |  |  | (362) |
Earnings from Ongoing Operations |  |  | $ | 624 |  |  | $ | 607 |  |  | $ | 155 |  |  | $ | (136) |  |  |  |  | $ | 1,250 |

(a)PPL incurred legal expenses related to litigation associated with its former affiliate, Talen Montana, LLC and certain affiliated entities.
(b)Represents costs primarily related to PPL's centralization and other strategic efforts.
(c)Rhode Island Regulated primarily includes certain transition services agreement costs for IT systems that will not be part of PPL's ongoing operations. Corporate and Other primarily includes integration and related costs associated with the acquisition of RIE.
(d)Certain expenses related to billing issues.
(e)Prior period impact related to a FERC refund order.
(f)Prior period impact for an ECR mechanism revenue adjustment related to a KPSC order.
(g)Impairment of DER project costs associated with a pilot solar program for which PPL will not seek regulatory recovery.
(h)Costs associated with PPL's restructuring and rebuilding of its IT infrastructure, organization and systems.
PPL Electric: Statement of Income Analysis
Net income for the years ended December 31 includes the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues | $ | 3,113 |  |  | $ | 2,876 |  |  | $ | 237 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Energy purchases | 876 |  |  | 721 |  |  | 155 |
Other operation and maintenance | 630 |  |  | 705 |  |  | (75) |
Depreciation | 413 |  |  | 401 |  |  | 12 |
Taxes, other than income | 151 |  |  | 131 |  |  | 20 |
Total Operating Expenses | 2,070 |  |  | 1,958 |  |  | 112 |
Operating Income | 1,043 |  |  | 918 |  |  | 125 |
Other Income (Expense) - net | 48 |  |  | 45 |  |  | 3 |
Interest Income from Affiliate | 9 |  |  | 33 |  |  | (24) |
Interest Expense | 257 |  |  | 246 |  |  | 11 |
Income Before Income Taxes | 843 |  |  | 750 |  |  | 93 |
Income Taxes | 204 |  |  | 176 |  |  | 28 |
Net Income | $ | 639 |  |  | $ | 574 |  |  | $ | 65 |

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Operating Revenues
The increase (decrease) in operating revenues was due to:

| 2025 vs. 2024
Distribution price (a) | $ | (14) |
Distribution volume (b) | 34 |
PLR (c) | 174 |
Transmission formula rate (d) | 45 |
Other | (2) |
Total | $ | 237 |

(a)The decrease was primarily due to reconcilable cost recovery mechanisms approved by the PAPUC.
(b)The increase was primarily due to weather and higher other usage in 2025.
(c)The increase was primarily the result of higher energy prices, more PLR customers and higher customer volumes due to weather and other higher usage.
(d)The increase was primarily due to returns on additional transmission capital investments and return of depreciation expense.
Energy Purchases
Energy purchases increased $155 million in 2025 compared with 2024, primarily due to higher PLR prices of $92 million and higher PLR volumes of $57 million.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:

|  |  | 2025 vs. 2024
Vegetation management expenses |  |  | $ | (14) |
Bad debts |  |  | (21) |
DER projects impairment (a) |  |  | (21) |
Storm expenses |  |  | (13) |
Other |  |  | (6) |
Total |  |  | $ | (75) |

(a)2024 impairment of DER project costs associated with a pilot solar program for which PPL will not seek regulatory recovery.
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LG&E: Statement of Income Analysis
Net income for the years ended December 31 includes the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues |  |  |  |  |
Retail and wholesale | $ | 1,718 |  |  | $ | 1,617 |  |  | $ | 101 |
Electric revenue from affiliate | 30 |  |  | 31 |  |  | (1) |
Total Operating Revenues | 1,748 |  |  | 1,648 |  |  | 100 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Fuel | 338 |  |  | 308 |  |  | 30 |
Energy purchases | 187 |  |  | 151 |  |  | 36 |
Energy purchases from affiliate | 22 |  |  | 20 |  |  | 2 |
Other operation and maintenance | 364 |  |  | 349 |  |  | 15 |
Depreciation | 307 |  |  | 305 |  |  | 2 |
Taxes, other than income | 51 |  |  | 49 |  |  | 2 |
Total Operating Expenses | 1,269 |  |  | 1,182 |  |  | 87 |
Operating Income | 479 |  |  | 466 |  |  | 13 |
Other Income (Expense) - net | 24 |  |  | 12 |  |  | 12 |
Interest Income from Affiliate | — |  |  | 1 |  |  | (1) |
Interest Expense | 116 |  |  | 105 |  |  | 11 |
Income Before Income Taxes | 387 |  |  | 374 |  |  | 13 |
Income Taxes | 78 |  |  | 77 |  |  | 1 |
Net Income | $ | 309 |  |  | $ | 297 |  |  | $ | 12 |

Operating Revenues
The increase (decrease) in operating revenues was due to:

| 2025 vs. 2024
Fuel and other energy purchases (a) | $ | 60 |
Volumes (b) | 15 |
Off-system sales (c) | 17 |
Other | 8 |
Total | $ | 100 |

(a)The increase was primarily due to higher recoveries of fuel expenses and energy purchases.
(b)The increase was primarily due to weather.
(c)The increase was primarily due to higher volumes.
Fuel
Fuel expense increased $30 million in 2025 compared with 2024, primarily due to an increase in commodity costs.
Energy Purchases
Energy purchases increased $36 million in 2025 compared with 2024, primarily due to a $23 million increase in volumes primarily due to weather and a $14 million increase in commodity costs.
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KU: Statement of Income Analysis
Net income for the years ended December 31 includes the following results:

|  |  |  |  | Change
| 2025 |  | 2024 |  | 2025 vs. 2024
Operating Revenues |  |  |  |  |
Retail and wholesale | $ | 2,042 |  |  | $ | 1,944 |  |  | $ | 98 |
Electric revenue from affiliate | 22 |  |  | 20 |  |  | 2 |
Total Operating Revenues | 2,064 |  |  | 1,964 |  |  | 100 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Fuel | 517 |  |  | 476 |  |  | 41 |
Energy purchases | 26 |  |  | 25 |  |  | 1 |
Energy purchases from affiliate | 30 |  |  | 31 |  |  | (1) |
Other operation and maintenance | 416 |  |  | 413 |  |  | 3 |
Depreciation | 408 |  |  | 403 |  |  | 5 |
Taxes, other than income | 51 |  |  | 49 |  |  | 2 |
Total Operating Expenses | 1,448 |  |  | 1,397 |  |  | 51 |
Operating Income | 616 |  |  | 567 |  |  | 49 |
Other Income (Expense) - net | 29 |  |  | 15 |  |  | 14 |
Interest Expense | 148 |  |  | 137 |  |  | 11 |
Income Before Income Taxes | 497 |  |  | 445 |  |  | 52 |
Income Taxes | 99 |  |  | 89 |  |  | 10 |
Net Income | $ | 398 |  |  | $ | 356 |  |  | $ | 42 |

Operating Revenues
The increase (decrease) in operating revenues was due to:

| 2025 vs. 2024
Fuel and other energy purchases (a) | $ | 30 |
Volumes (b) | 34 |
Off-system sales (c) | 19 |
Other | 17 |
Total | $ | 100 |

(a)The increase was primarily due to higher recoveries of fuel expenses.
(b)The increase was primarily due to weather.
(c)The increase was primarily due to higher volumes.
Fuel
Fuel expense increased $41 million in 2025 compared with 2024, primarily due to a $24 million increase in volumes due to weather and an $18 million increase in commodity costs.
Financial Condition
The remainder of this Item 7 in this Form 10-K is presented on a combined basis, providing information, as applicable, for all Registrants.
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Liquidity and Capital Resources
(All Registrants)
The Registrants' cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties. See "Item 1A. Risk Factors" for a discussion of risks and uncertainties that could affect the Registrants' cash flows.
The Registrants had the following at:

| PPL |  | PPL Electric |  | LG&E |  | KU
December 31, 2025 |  |  |  |  |  |  |
Cash and cash equivalents | $ | 1,071 |  |  | $ | 30 |  |  | $ | 162 |  |  | $ | 10 |
Short-term debt | 456 |  |  | — |  |  | — |  |  | — |
Long-term debt due within one year | 904 |  |  | — |  |  | 90 |  |  | 164 |
Notes payable with affiliates |  |  | — |  |  | — |  |  | 36 |
December 31, 2024 |  |  |  |  |  |  |
Cash and cash equivalents | $ | 306 |  |  | $ | 24 |  |  | $ | 8 |  |  | $ | 13 |
Short-term debt | 303 |  |  | — |  |  | 25 |  |  | 140 |
Long-term debt due within one year | 551 |  |  | — |  |  | 300 |  |  | 250 |
Notes payable with affiliates |  |  | — |  |  | 43 |  |  | 73 |

(All Registrants)
Net cash provided by (used in) operating, investing and financing activities for the years ended December 31 and the changes between periods were as follows:

| PPL |  | PPL Electric |  | LG&E |  | KU
2025 |  |  |  |  |  |  |
Operating activities | $ | 2,629 |  |  | $ | 1,050 |  |  | $ | 599 |  |  | $ | 798 |
Investing activities | (4,004) |  |  | (1,503) |  |  | (803) |  |  | (986) |
Financing activities | 2,122 |  |  | 459 |  |  | 349 |  |  | 176 |
2024 |  |  |  |  |  |  |
Operating activities | $ | 2,340 |  |  | $ | 1,042 |  |  | $ | 554 |  |  | $ | 723 |
Investing activities | (2,818) |  |  | (1,455) |  |  | (444) |  |  | (643) |
Financing activities | 435 |  |  | 386 |  |  | (130) |  |  | (89) |
2025 vs. 2024 Change |  |  |  |  |  |  |
Operating activities | $ | 289 |  |  | $ | 8 |  |  | $ | 45 |  |  | $ | 75 |
Investing activities | (1,186) |  |  | (48) |  |  | (359) |  |  | (343) |
Financing activities | 1,687 |  |  | 73 |  |  | 479 |  |  | 265 |

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Operating Activities
The components of the change in cash provided by (used in) operating activities were as follows:

| PPL |  | PPL Electric |  | LG&E |  | KU
2025 vs. 2024 |  |  |  |  |  |  |
Change - Cash Provided (Used): |  |  |  |  |  |  |
Net income | $ | 293 |  |  | $ | 65 |  |  | $ | 12 |  |  | $ | 42 |
Non-cash components | 17 |  |  | (107) |  |  | (9) |  |  | 16 |
Working capital | 13 |  |  | 77 |  |  | 33 |  |  | 7 |
Other operating activities | (34) |  |  | (27) |  |  | 9 |  |  | 10 |
Total | $ | 289 |  |  | $ | 8 |  |  | $ | 45 |  |  | $ | 75 |

A majority of the Registrants' operating cash flows are provided by their electric and natural gas utilities, which are significantly influenced by factors such as weather, regulatory mechanisms, economic conditions, changes in working capital and operating costs.
(PPL)
PPL's cash provided by operating activities in 2025 increased $289 million compared with 2024.
•Net income increased $293 million between the periods and included an increase in non-cash components of $17 million.
•The $13 million increase in cash from changes in working capital was primarily due to an increase in regulatory liabilities, taxes payable and other current liabilities and a decrease in prepayments, partially offset by an increase in accounts receivable.
•The $34 million decrease in cash from other operating activities was primarily due to an increase in other noncurrent assets, partially offset by an increase in other noncurrent liabilities.
(PPL Electric)
PPL Electric's cash provided by operating activities in 2025 increased $8 million compared with 2024.
•Net income increased $65 million between the periods and included a decrease in non-cash components of $107 million, primarily due to a decrease in deferred income taxes and investment tax credits.
•The $77 million increase in cash from changes in working capital was primarily due to an increase in regulatory liabilities and taxes payable and a decrease in prepayments, partially offset by an increase in accounts receivable.
•The $27 million decrease in cash from other operating activities was primarily due to an increase in other noncurrent assets.
(LG&E)
LG&E's cash provided by operating activities in 2025 increased $45 million compared with 2024.
•Net income increased $12 million between the periods and included a decrease in non-cash components of $9 million.
•The $33 million increase in cash from changes in working capital was primarily due to an increase in taxes payable and a decrease in accounts receivable.
•The $9 million increase in cash from other operating activities was primarily due to an increase in other noncurrent liabilities, partially offset by an increase in other noncurrent assets.
(KU)
KU's cash provided by operating activities in 2025 increased $75 million compared with 2024.
•Net income increased $42 million between the periods and included an increase in non-cash components of $16 million.
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•The $7 million increase in cash from changes in working capital was primarily due to an increase in accounts payable and taxes payable, partially offset by a decrease in regulatory liabilities.
•The $10 million increase in cash from other operating activities was primarily due to an increase in other noncurrent assets.
Investing Activities
(All Registrants)
The components of the change in cash provided by (used in) investing activities were as follows:

| PPL |  | PPL Electric |  | LG&E |  | KU
2025 vs. 2024 |  |  |  |  |  |  |
Change - Cash Provided (Used): |  |  |  |  |  |  |
Expenditures for PP&E | $ | (1,225) |  |  | $ | (379) |  |  | $ | (323) |  |  | $ | (340) |
Notes receivable from affiliate | — |  |  | 301 |  |  | (36) |  |  | — |
Other investing activities | 39 |  |  | 30 |  |  | — |  |  | (3) |
Total | $ | (1,186) |  |  | $ | (48) |  |  | $ | (359) |  |  | $ | (343) |

For PPL, the increase in expenditures for PP&E was primarily due to an increase in project expenditures at PPL Electric, LG&E, KU and RIE. The increase in expenditures at PPL Electric was primarily due to increases in transmission and distribution projects. The increase in expenditures at LG&E was primarily due to Mill Creek Units 5 and 6, the E.W. Brown battery storage project and the Bullitt County system reinforcement project. The increase in expenditures at KU was primarily due to Mill Creek Unit 5.
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2026 through 2028.
For PPL Electric, the changes in "Notes receivable from affiliate" activity resulted from payments received in 2025 on the short-term note between affiliates, issued in 2024 to support general corporate purposes. See Note 13 to the Financial Statements for further discussion of intercompany borrowings.
Financing Activities
(All Registrants)
The components of the change in cash provided by (used in) financing activities were as follows:

| PPL |  | PPL Electric |  | LG&E |  | KU
2025 vs. 2024 |  |  |  |  |  |  |
Change - Cash Provided (Used): |  |  |  |  |  |  |
Long-term debt issuance/retirement, net | $ | 535 |  |  | $ | (153) |  |  | $ | 400 |  |  | $ | 450 |
Dividends | (47) |  |  | (26) |  |  | (13) |  |  | (17) |
Issuance of treasury stock | 399 |  |  | — |  |  | — |  |  | — |
Capital contributions/distributions, net | — |  |  | (258) |  |  | 237 |  |  | 138 |
Changes in net short-term debt | 842 |  |  | 509 |  |  | (50) |  |  | (187) |
Note payable with affiliate | — |  |  | — |  |  | (86) |  |  | (110) |
Other financing activities | (42) |  |  | 1 |  |  | (9) |  |  | (9) |
Total | $ | 1,687 |  |  | $ | 73 |  |  | $ | 479 |  |  | $ | 265 |

(All Registrants)
See Note 8 to the Financial Statements for information on 2025 activity.
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See "Long-term Debt and Equity Securities" below for additional information on current year activity. See "Forecasted Sources of Cash" for a discussion of the Registrants' plans to issue debt and equity securities, as well as a discussion of credit facility capacity available to the Registrants. Also see "Forecasted Uses of Cash" for a discussion of PPL's plans to pay dividends on common securities in the future, as well as the Registrants' maturities of long-term debt.
Long-term Debt and Equity Securities
Long-term debt and equity securities activity for 2025 included:

| Debt |  | Stock
| Issuances (a) |  | Retirements |  | Issuances (b) |  | Repurchases
Cash Flow Impact: |  |  |  |  |  |  |
PPL (c) | $ | 3,045 |  |  | $ | 616 |  |  | $ | 401 |  |  | $ | — |
PPL Electric | 496 |  |  | — |  |  | — |  |  | — |
LG&E | 700 |  |  | 300 |  |  | — |  |  | — |
KU | 700 |  |  | 250 |  |  | — |  |  | — |

(a)Issuances are net of pricing discounts, where applicable, and exclude the impact of debt issuance costs.
(b)Primarily includes issuances of treasury stock.
(c)Retirements include $65 million related to repurchased affiliate debt. See Note 8 to the Financial Statements for additional information.
See Note 8 to the Financial Statements for additional long-term debt information.
Forecasted Sources of Cash
(All Registrants)
The Registrants expect to continue to have adequate liquidity available from operating cash flows, cash and cash equivalents, credit facilities, commercial paper issuances and debt, hybrid, and equity issuances to meet their requirements with respect to their contractual obligations and anticipated capital expenditures. Equity capital for PPL can be provided from any combination of issuances from at the market stock plans, private placements, or public offerings. Additionally, subject to market conditions, the Registrants and their subsidiaries may access the capital markets, and PPL Electric, LG&E and KU anticipate receiving equity contributions from their parent or member in 2026, which are expected to be used to fund capital expenditures and for other general corporate purposes.
PPL Electric, LG&E and KU plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from PPL. Operating cash flows provide a substantial portion of these subsidiary Registrants' cash needs.
The amount, type, and timing of any financings in 2026, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals as applicable for the subsidiary Registrants, and other factors.
Credit Facilities
The Registrants maintain credit facilities to enhance liquidity, provide credit support and provide a backstop to commercial paper programs. Amounts borrowed under these credit facilities are reflected in "Short-term debt" on the Balance Sheets. At December 31, 2025, the total committed borrowing capacity under credit facilities and the borrowings under these facilities were:
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External

| Committed Capacity |  | Borrowed |  | Letters of Credit and Commercial Paper Issued (d) |  | Unused Capacity
PPL Capital Funding Credit Facilities (a) | $ | 1,600 |  |  | $ | — |  |  | $ | 456 |  |  | $ | 1,144 |
PPL Electric Credit Facilities | 750 |  |  | — |  |  | 6 |  |  | 744 |
LG&E Credit Facilities | 600 |  |  | — |  |  | — |  |  | 600 |
KU Credit Facilities | 600 |  |  | — |  |  | — |  |  | 600 |
Total Credit Facilities (b)(c) | $ | 3,550 |  |  | $ | — |  |  | $ | 462 |  |  | $ | 3,088 |

(a)Includes a $1.5 billion syndicated credit facility with a $400 million borrowing sublimit for RIE and a $1.1 billion sublimit for PPL Capital Funding. RIE's borrowing sublimit is adjustable, at the borrowers' option, from $0 to $600 million, with the remaining balance of the $1.5 billion available under the facility allocated to PPL Capital Funding. At December 31, 2025, PPL Capital Funding had $355 million of commercial paper outstanding and RIE had $101 million of commercial paper outstanding. See Note 8 to the Financial Statements for additional information.
(b)The syndicated credit facilities and PPL Capital Funding's bilateral facility, each contain a financial covenant requiring debt to total capitalization not to exceed 70% for PPL Capital Funding, RIE, PPL Electric, LG&E and KU, as calculated in accordance with the facility, and other customary covenants.
The commitments under the credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than the following percentages of the total committed capacity: PPL - 8%, PPL Electric - 7%, LG&E - 7% and KU - 7%.
(c)Each company pays customary fees under its respective syndicated credit facility. Borrowings generally bear interest at applicable SOFR, plus an applicable margin.
(d)Commercial paper issued reflects the undiscounted face value of the issuance.
In addition to the financial covenants noted in the table above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. The Registrants monitor compliance with the covenants on a regular basis. At December 31, 2025, the Registrants were in compliance with these covenants. As of December 31, 2025, the Registrants believe that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 8 to the Financial Statements for further discussion of the Registrants' credit facilities.
Intercompany (LG&E and KU)

| Committed Capacity |  | Borrowed |  | Commercial Paper Issued |  | Unused Capacity
LG&E Money Pool (a) | $ | 750 |  |  | $ | — |  |  | $ | — |  |  | $ | 750 |
KU Money Pool (a) | 650 |  |  | 36 |  |  | — |  |  | 614 |

(a)LG&E and KU participate in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E, and LKE and/or LG&E make available to KU funds up to the difference between LG&E's and KU's FERC borrowing limit and LG&E's and KU's commercial paper capacity limit, at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on the lower of a market index of commercial paper issues and two additional rate options based on SOFR.
See Note 13 to the Financial Statements for further discussion of intercompany credit facilities.
Commercial Paper (All Registrants)
The Registrants, PPL Capital Funding and RIE maintain commercial paper programs to provide an additional financing source to fund short-term liquidity needs, as necessary. Commercial paper issuances, included in "Short-term debt" on the Balance Sheets, are supported by the respective Registrant's credit facilities. The following commercial paper programs were in place at:

| December 31, 2025
| Capacity |  | Commercial Paper Issuances (b) |  | Unused Capacity
PPL Capital Funding (a) | $ | 1,600 |  |  | $ | 355 |  |  | $ | 1,245 |
Rhode Island Energy (a) | 400 |  |  | 101 |  |  | 299 |
PPL Electric | 750 |  |  | — |  |  | 750 |
LG&E | 600 |  |  | — |  |  | 600 |
KU | 600 |  |  | — |  |  | 600 |
Total PPL | $ | 3,950 |  |  | $ | 456 |  |  | $ | 3,494 |

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(a)Issuances under the PPL Capital Funding and RIE commercial paper programs are supported by the PPL Capital Funding syndicated credit facility, which at December 31, 2025, had a total capacity of $1.5 billion, with a $400 million borrowing sublimit for RIE and a $1.1 billion sublimit for PPL Capital Funding. The sublimits of each borrower may be decreased or increased at the borrowers' option up to a prescribed amount such that all borrowings under the syndicated credit facility cannot exceed the size of the credit facility of $1.5 billion. PPL Capital Funding's Commercial paper program is also backed by a separate bilateral credit facility for $100 million.
(b)Commercial paper issued reflects the undiscounted face value of the issuance.
Forecasted Uses of Cash
(All Registrants)
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, the Registrants currently expect to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock, and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows the Registrants' current capital expenditure projections for the years 2026 through 2028. Expenditures for the regulated utilities are expected to be recovered through rates, pending regulatory approval.

|  |  | Projected
| Total |  | 2026 (a) |  | 2027 |  | 2028 |  |  |
PPL |  |  |  |  |  |  |  |  |  |
Generating facilities | $ | 4,200 |  |  | $ | 1,100 |  |  | $ | 1,500 |  |  | $ | 1,600 |  |  |  |
Electric distribution facilities | 5,575 |  |  | 1,775 |  |  | 1,950 |  |  | 1,850 |  |  |  |
Gas distribution facilities | 1,225 |  |  | 375 |  |  | 400 |  |  | 450 |  |  |  |
Transmission facilities | 5,875 |  |  | 1,625 |  |  | 2,025 |  |  | 2,225 |  |  |  |
Other | 475 |  |  | 250 |  |  | 150 |  |  | 75 |  |  |  |
Total Capital Expenditures | $ | 17,350 |  |  | $ | 5,125 |  |  | $ | 6,025 |  |  | $ | 6,200 |  |  |  |
PPL Electric |  |  |  |  |  |  |  |  |  |
Electric distribution facilities | $ | 2,850 |  |  | $ | 1,000 |  |  | $ | 950 |  |  | $ | 900 |  |  |  |
Transmission facilities | 3,350 |  |  | 975 |  |  | 1,125 |  |  | 1,250 |  |  |  |
Total Capital Expenditures | $ | 6,200 |  |  | $ | 1,975 |  |  | $ | 2,075 |  |  | $ | 2,150 |  |  |  |
LG&E |  |  |  |  |  |  |  |  |  |
Generating facilities | $ | 2,500 |  |  | $ | 600 |  |  | $ | 850 |  |  | $ | 1,050 |  |  |  |
Electric distribution facilities | 825 |  |  | 200 |  |  | 325 |  |  | 300 |  |  |  |
Gas distribution facilities | 450 |  |  | 125 |  |  | 150 |  |  | 175 |  |  |  |
Transmission facilities | 450 |  |  | 125 |  |  | 175 |  |  | 150 |  |  |  |
Other | 250 |  |  | 125 |  |  | 75 |  |  | 50 |  |  |  |
Total Capital Expenditures | $ | 4,475 |  |  | $ | 1,175 |  |  | $ | 1,575 |  |  | $ | 1,725 |  |  |  |
KU |  |  |  |  |  |  |  |  |  |
Generating facilities | $ | 1,700 |  |  | $ | 500 |  |  | $ | 650 |  |  | $ | 550 |  |  |  |
Electric distribution facilities | 1,075 |  |  | 275 |  |  | 400 |  |  | 400 |  |  |  |
Transmission facilities | 1,350 |  |  | 300 |  |  | 475 |  |  | 575 |  |  |  |
Other | 225 |  |  | 125 |  |  | 75 |  |  | 25 |  |  |  |
Total Capital Expenditures | $ | 4,350 |  |  | $ | 1,200 |  |  | $ | 1,600 |  |  | $ | 1,550 |  |  |  |

(a)The 2026 total excludes amounts included in accounts payable as of December 31, 2025.
Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.
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Contractual Obligations
The Registrants have assumed various financial obligations and commitments in the ordinary course of conducting business. At December 31, 2025, estimated contractual cash obligations were as follows:

| Total |  | 2026 |  | 2027-2028 |  | 2028-2029 |  | After 2030
PPL |  |  |  |  |  |  |  |  |
Long-term Debt (a) | $ | 19,089 |  |  | $ | 904 |  |  | $ | 1,778 |  |  | $ | 2,297 |  |  | $ | 14,110 |
Interest on Long-term Debt (b) | 13,775 |  |  | 836 |  |  | 1,611 |  |  | 1,516 |  |  | 9,812 |
Operating Leases | 109 |  |  | 20 |  |  | 35 |  |  | 19 |  |  | 35 |
Purchase Obligations (c) | 5,476 |  |  | 1,940 |  |  | 1,845 |  |  | 1,002 |  |  | 689 |
Total Contractual Cash Obligations | $ | 38,449 |  |  | $ | 3,700 |  |  | $ | 5,269 |  |  | $ | 4,834 |  |  | $ | 24,646 |
PPL Electric |  |  |  |  |  |  |  |  |
Long-term Debt (a) | $ | 5,799 |  |  | $ | — |  |  | $ | 108 |  |  | $ | 116 |  |  | $ | 5,575 |
Interest on Long-term Debt (b) | 4,965 |  |  | 274 |  |  | 543 |  |  | 538 |  |  | 3,610 |
Unconditional Power Purchase Obligations | 739 |  |  | 63 |  |  | 144 |  |  | 143 |  |  | 389 |
Total Contractual Cash Obligations | $ | 11,503 |  |  | $ | 337 |  |  | $ | 795 |  |  | $ | 797 |  |  | $ | 9,574 |
LG&E |  |  |  |  |  |  |  |  |
Long-term Debt (a) | $ | 2,889 |  |  | $ | 90 |  |  | $ | 260 |  |  | $ | — |  |  | $ | 2,539 |
Interest on Long-term Debt (b) | 2,508 |  |  | 131 |  |  | 253 |  |  | 249 |  |  | 1,875 |
Operating Leases | 19 |  |  | 6 |  |  | 9 |  |  | 4 |  |  | — |
Coal and Natural Gas Purchase Obligations (d) | 856 |  |  | 314 |  |  | 357 |  |  | 162 |  |  | 23 |
Unconditional Power Purchase Obligations (e) | 299 |  |  | 19 |  |  | 48 |  |  | 48 |  |  | 184 |
Construction Obligations (f) | 369 |  |  | 319 |  |  | 48 |  |  | 2 |  |  | — |
Other Obligations | 72 |  |  | 45 |  |  | 22 |  |  | 5 |  |  | — |
Total Contractual Cash Obligations | $ | 7,012 |  |  | $ | 924 |  |  | $ | 997 |  |  | $ | 470 |  |  | $ | 4,621 |
KU |  |  |  |  |  |  |  |  |
Long-term Debt (a) | $ | 3,539 |  |  | $ | 164 |  |  | $ | 60 |  |  | $ | — |  |  | $ | 3,315 |
Interest on Long-term Debt (b) | 3,096 |  |  | 163 |  |  | 315 |  |  | 314 |  |  | 2,304 |
Operating Leases | 30 |  |  | 10 |  |  | 13 |  |  | 5 |  |  | 2 |
Coal and Natural Gas Purchase Obligations (d) | 1,088 |  |  | 372 |  |  | 536 |  |  | 180 |  |  | — |
Unconditional Power Purchase Obligations (e) | 133 |  |  | 8 |  |  | 21 |  |  | 21 |  |  | 83 |
Construction Obligations (f) | 356 |  |  | 288 |  |  | 62 |  |  | 6 |  |  | — |
Other Obligations | 49 |  |  | 19 |  |  | 18 |  |  | 12 |  |  | — |
Total Contractual Cash Obligations | $ | 8,291 |  |  | $ | 1,024 |  |  | $ | 1,025 |  |  | $ | 538 |  |  | $ | 5,704 |

(a)Reflects principal maturities based on stated maturity, sinking fund payments, or earlier put dates. See Note 8 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E and KU. The Registrants do not have any significant finance lease obligations. For PPL, reduced by $84 million of repurchased affiliate bonds as of December 31, 2025. See Note 8 to the Financial Statements for more information.
(b)Assumes interest payments through stated maturity or earlier put dates. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes, as applicable, the purchase obligations of electricity, coal, natural gas and limestone, as well as certain construction expenditures, which are also included in the Capital Expenditures discussion above.
(d)Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 12 to the Financial Statements for additional information.
(e)Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 12 to the Financial Statements for additional information.
(f)Represents construction commitments, which are also reflected in the Capital Expenditures table presented above.
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Dividends/Distributions
(PPL)
PPL views dividends as an integral component of shareowner return and expects to continue to pay dividends in amounts intended to maintain a capitalization structure that supports investment grade credit ratings. In November 2025, PPL declared its quarterly common stock dividend, payable January 2, 2026, at 27.25 cents per share (equivalent to $1.09 per annum). On February 20, 2026, PPL announced a quarterly common stock dividend of 28.50 cents per share, payable April 1, 2026, to shareowners of record as of March 10, 2026. Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other factors.
Subject to certain exceptions, PPL may not declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067. At December 31, 2025, no interest payments were deferred.
(PPL Electric, LG&E and KU)
From time to time, as determined by their respective Board of Directors, the Registrants pay dividends, distributions or return capital, as applicable, to their respective shareholders or members. Certain of the credit facilities of PPL Electric, LG&E and KU include minimum debt covenant ratios that could effectively restrict the payment of dividends or distributions.
(All Registrants)
See Note 8 to the Financial Statements for these and other restrictions related to distributions on capital interests for the Registrants and their subsidiaries.
Purchase or Redemption of Debt Securities
The Registrants will continue to evaluate outstanding debt securities and may decide to purchase or redeem these securities in open market or privately negotiated transactions, in exchange transactions or otherwise, depending upon prevailing market conditions, available cash and other factors, and may be commenced or suspended at any time. The amounts involved may be material.
Rating Agency Actions
Moody's and S&P periodically review the credit ratings of the debt of the Registrants and their subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of the Registrants and their subsidiaries are based on information provided by the Registrants and other sources. The ratings of Moody's and S&P are not a recommendation to buy, sell or hold any securities of the Registrants or their subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.
The credit ratings of the Registrants and their subsidiaries affect their liquidity, access to capital markets and cost of borrowing under their credit facilities. A downgrade in the Registrants' or their subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets. The Registrants and their subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
The following table sets forth the Registrants' and their subsidiaries' credit ratings for outstanding debt securities or commercial paper programs as of December 31, 2025.
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|  | Senior Unsecured |  | Senior Secured |  | Commercial Paper
Issuer |  | Moody's |  | S&P |  | Moody's |  | S&P |  | Moody's |  | S&P
PPL |  |  |  |  |  |  |  |  |  |  |  |
PPL Capital Funding |  | Baa1 |  | BBB+ |  |  |  |  |  | P-2 |  | A-2
Rhode Island Energy |  | A3 |  | A- |  |  |  |  |  | P-2 |  | A-2
PPL and PPL Electric |  |  |  |  |  |  |  |  |  |  |  |
PPL Electric |  |  |  |  |  | A1 |  | A+ |  | P-2 |  | A-1
PPL, LG&E and KU |  |  |  |  |  |  |  |  |  |  |  |
LG&E |  |  |  |  |  | A1 |  | A |  | P-2 |  | A-2
KU |  |  |  |  |  | A1 |  | A |  | P-2 |  | A-2

Since June 2023, the rating agencies have not taken rating actions related to the Registrants and their subsidiaries.
Ratings Triggers (PPL, LG&E and KU)
Various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, and interest rate instruments, contain provisions that require the posting of additional collateral or permit the counterparty to terminate the contract, if PPL's, LG&E's or KU's or their subsidiaries' credit rating, as applicable, were to fall below investment grade. See Note 16 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral requirements for derivative contracts in a net liability position at December 31, 2025.
Guarantees for Subsidiaries (PPL)
PPL guarantees certain consolidated affiliate financing arrangements. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, accelerate maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. At this time, PPL believes that these covenants will not limit access to relevant funding sources. See Note 12 to the Financial Statements for additional information about guarantees.
Other Contingent Obligations (All Registrants)
The Registrants have entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 12 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
(All Registrants)
See Notes 1, 15 and 16 to the Financial Statements for information about the Registrants' risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These are not precise indicators of expected future losses, but are rather only indicators of possible losses under normal market conditions at a given confidence level.
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Interest Rate Risk
PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. A variety of financial derivative instruments are utilized to adjust the mix of fixed and floating interest rates in their debt portfolios, adjust the duration of the debt portfolios and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under PPL's risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of the debt portfolio due to changes in benchmark interest rates. In addition, the interest rate risk of certain subsidiaries is potentially mitigated as a result of the existing regulatory framework or the timing of rate cases.
The following interest rate hedges were outstanding at December 31:

| 2025 |  | 2024
| Exposure Hedged |  | Fair Value, Net - Asset (Liability) (a) |  | Effect of a 10% Adverse Movement in Rates (b) |  | Maturities Ranging Through |  | Exposure Hedged |  | Fair Value, Net - Asset (Liability) (a) |  | Effect of a 10% Adverse Movement in Rates (b)
PPL and LG&E |  |  |  |  |  |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives | $ | 20 |  |  | $ | — |  |  | $ | (1) |  |  | 2026 |  | $ | — |  |  | $ | — |  |  | $ | — |
Economic hedges |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (c) | $ | 64 |  |  | $ | (5) |  |  | $ | (1) |  |  | 2033 |  | $ | 64 |  |  | $ | (3) |  |  | $ | (1) |

(a)Includes accrued interest, if applicable.
(b)Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability. Sensitivities represent a 10% adverse movement in interest rates.
(c)Realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in the fair value of these derivatives are included in regulatory assets or regulatory liabilities.
The Registrants are exposed to a potential increase in interest expense and to changes in the fair value of their debt portfolios. The estimated impact of a 10% adverse movement in interest rates on interest expense at December 31, 2025 and 2024 was insignificant for PPL, PPL Electric, LG&E, and KU. The estimated impact of a 10% adverse movement in interest rates on the fair value of debt at December 31 is shown below.

| 10% Adverse Movement in Rates on Fair Value of Debt |  |
| 2025 |  | 2024 |  |  |  |
PPL | $ | 720 |  |  | $ | 622 |  |  |  |  |
PPL Electric | 284 |  |  | 262 |  |  |  |  |
LG&E | 135 |  |  | 89 |  |  |  |  |
KU | 175 |  |  | 131 |  |  |  |  |

Commodity Price Risk
PPL is exposed to commodity price risk through its subsidiaries primarily from the purchases of electricity, natural gas and fuel but has cost recovery mechanisms to mitigate that risk. See Note 16 to the Financial Statements for further discussion of these risks.
Volumetric Risk
Volumetric risk is the risk related to the changes in volume of retail sales due to weather, economic conditions or other factors. PPL is exposed to volumetric risk through its subsidiaries as described below.
•PPL Electric, LG&E and KU are exposed to volumetric risk on retail sales, mainly due to weather and other economic conditions for which there is limited mitigation between rate cases.
•RIE is not materially exposed to volumetric risk. RIE's electric and gas distribution rates both have a revenue decoupling mechanism, which allows for annual adjustments to RIE's delivery rates.
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Defined Benefit Plans - Equity Securities Price Risk
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of equity securities price risk on plan assets.
Credit Risk
(All Registrants)
Credit risk is the potential loss that may be incurred due to a counterparty's non-performance.
PPL is exposed to credit risk from "in-the-money" transactions with counterparties as well as additional credit risk through certain of its subsidiaries, as discussed below.
In the event a supplier of PPL, PPL Electric, LG&E or KU defaults on its contractual obligation, those Registrants would be required to seek replacement power or replacement fuel in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities.
PPL and its subsidiaries have credit policies in place to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements or provisions. These agreements generally include credit mitigation provisions, such as margin, prepayment or collateral requirements. PPL and its subsidiaries may request additional credit assurance, in certain circumstances, if the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
(All Registrants)
Related Party Transactions
The Registrants are not aware of any material ownership interests or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with the Registrants. See Note 13 to the Financial Statements for additional information on related party transactions for PPL Electric, LG&E and KU.
Acquisitions, Development and Divestitures
The Registrants from time to time evaluate opportunities for potential acquisitions, divestitures, and development projects. See Note 9 to the Financial Statements for additional information on acquisition, development and divestiture activity. Development projects are reexamined based on market conditions and other factors to determine whether to proceed with, modify or terminate the projects. Any resulting transactions may impact future financial results.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to the Registrants' air emissions, water discharges and the management of hazardous and solid waste, as well as other aspects of the Registrants' businesses. The costs of compliance or alleged non-compliance cannot be predicted with certainty but could be significant. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed. Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the costs for their products or their demand for the Registrants' services. Increased capital and operating costs are expected to be subject to rate recovery. The Registrants can provide no assurances as to the ultimate outcome of future environmental or rate proceedings before regulatory authorities.
See "Legal Matters" in Note 12 to the Financial Statements for a discussion of the more significant environmental claims. See Note 18 to the Financial Statements for information related to the impacts of CCRs on AROs. See "Item 1. Business - Environmental Matters" for additional information.
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Sustainability
The Governance, Nominating and Sustainability Committee of PPL's Board of Directors has oversight of the company's practices and positions to further its sustainability strategy and corporate governance, including specific environmental and corporate social responsibility initiatives. Management considers several factors as part of the company's sustainability approach, including ongoing engagement with constituents such as shareholders and regulators on topics related to sustainability and other matters. To the extent sustainability issues have or may have a material impact on the Registrants' financial condition or results of operation, PPL discloses such matters in accordance with applicable securities law and SEC regulations.
In addition to disclosure required by applicable securities laws and SEC regulations, PPL provides additional disclosures on sustainability topics that it considers relevant to investors and stakeholders, which are available on the corporate website at https://www.pplweb.com/sustainability/reports-disclosures/. Primarily, PPL continues each spring to publish its annual sustainability report including data related to carbon emissions. PPL also participates in efforts by the Edison Electric Institute and American Gas Association to provide the appropriate subset of sustainability information that can be applied consistently across the electric and gas utility industries. Finally, PPL consults widely used reporting frameworks for discrete sustainability topics, including corporate political contributions and climate-related issues and maps its disclosure to various reporting frameworks such as Global Reporting Initiative (GRI) Standards and to the CDP Climate and Water Questionnaires.
Cybersecurity
See "Item 1A. Risk Factors" and "Item 1C. Cybersecurity" for a discussion of cybersecurity risks affecting the Registrants and the related strategies for managing these risks.
Competition
See "Competition" under each of PPL's reportable segments in "Item 1. Business - General - Segment Information" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting the Registrants.
New Accounting Guidance
See Note 1 and Note 20 to the Financial Statements for a discussion of significant new accounting guidance adopted and pending adoption as of December 31, 2025.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to an understanding of the reported financial condition or results of operations and require management to make estimates or other judgments of matters that are inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). Senior management has reviewed with PPL's Audit Committee these critical accounting policies, the following disclosures regarding their application, and the estimates and assumptions regarding them.
Defined Benefits (All Registrants)
Certain of the Registrants and/or their subsidiaries sponsor or participate in certain qualified funded and non-qualified unfunded defined benefit pension plans and both funded and unfunded other postretirement benefit plans. See Notes 1, 7 and 10 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
A summary of plan sponsors by Registrant and whether a Registrant or its subsidiaries sponsor (S) or participate in and receives allocations (P) from those plans is shown in the table below.

Plan Sponsor |  | PPL |  | PPL Electric |  |  |  | LG&E |  | KU
PPL Services |  | S |  | P |  |  |  |  |  |
LKE |  |  |  |  |  |  |  | P |  | P

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Management makes certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. As such, annual net periodic defined benefit costs are recorded in current earnings or regulatory assets and liabilities based on estimated results. Any differences between actual and estimated results are recorded in AOCI or, in the case of PPL Electric, LG&E and KU, regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in AOCI or regulatory assets and liabilities are amortized to income over future periods. The significant assumptions are:
•Discount Rate - In selecting the discount rates for defined benefit plans, the plan sponsors start with a cash flow analysis of the expected benefit payment stream for their plans. The plan-specific cash flows are matched against the coupons and expected maturity values of Aa-rated non-callable (or callable with make-whole provisions) bonds that could be purchased for a hypothetical settlement portfolio. The plan sponsors then use the single discount rate derived from matching the discounted benefit payment stream to the market value of the selected bond portfolio.
•Expected Return on Plan Assets - The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
•Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. In selecting a rate of compensation increase, plan sponsors consider past experience, the potential impact of movements in inflation rates and expectations of ongoing compensation practices.
See Note 10 to the Financial Statements for details of the assumptions selected for pension and other postretirement benefits. A variance in the assumptions could significantly impact accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and AOCI or regulatory assets and liabilities.
The following tables reflect changes in certain assumptions based on the Registrants' primary qualified defined benefit pension and other postretirement benefit plans. The inverse of this change would have the opposite impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and AOCI or regulatory assets and liabilities. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.

| Increase (Decrease)
Actuarial assumption |
Discount Rate | (0.25 | %)
Expected Return on Plan Assets | (0.25 | %)
Rate of Compensation Increase | 0.25 | %

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| Increase (Decrease) |  | (Increase) Decrease |  | (Increase) Decrease |  | Increase (Decrease) |  | Increase (Decrease)
Actuarial assumption | Defined Benefit Asset |  | Defined Benefit Liabilities |  | AOCI (pre-tax) |  | Net Regulatory Assets |  | Defined Benefit Costs
PPL |  |  |  |  |  |  |  |  |
Discount rates | $ | (17) |  |  | $ | (73) |  |  | $ | 26 |  |  | $ | 64 |  |  | $ | 4 |
Expected return on plan assets | n/a |  | n/a |  | n/a |  | n/a |  | 10 |
Rate of compensation increase | (2) |  |  | (6) |  |  | 2 |  |  | 6 |  |  | 1 |
PPL Electric |  |  |  |  |  |  |  |  |
Discount rates | — |  |  | (31) |  |  | — |  |  | 31 |  |  | 1 |
Expected return on plan assets | n/a |  | n/a |  | — |  |  | n/a |  | 3 |
Rate of compensation increase | — |  |  | (2) |  |  | — |  |  | 2 |  |  | — |
LG&E |  |  |  |  |  |  |  |  |
Discount rates | (7) |  |  | 1 |  |  | n/a |  | 8 |  |  | 1 |
Expected return on plan assets | n/a |  | n/a |  | n/a |  | n/a |  | 1 |
Rate of compensation increase | (1) |  |  | — |  |  | n/a |  | 1 |  |  | — |
KU |  |  |  |  |  |  |  |  |
Discount rates | (6) |  |  | 1 |  |  | n/a |  | 7 |  |  | 1 |
Expected return on plan assets | n/a |  | n/a |  | n/a |  | n/a |  | 1 |
Rate of compensation increase | (1) |  |  | — |  |  | n/a |  | 1 |  |  | — |

Income Taxes (All Registrants)
Significant management judgment is required in developing the Registrants' provision for income taxes, primarily due to valuation allowances on deferred tax assets.
The need for valuation allowances to reduce deferred tax assets requires significant management judgment. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers numerous factors in assessing the expected realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy considered in this assessment must meet the recognition and measurement criteria for the valuation of a deferred tax asset. When evaluating the need for valuation allowances, the uncertainty posed by potential or expected legislative change on such factors is also considered by management. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.
See Note 6 to the Financial Statements for income tax disclosures.
Regulatory Assets and Liabilities (All Registrants)
PPL Electric, LG&E, KU and RIE are subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities that result from the regulated ratemaking process may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.
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Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to the Registrants and other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels and is subject to change in the future. If future recovery of costs ceases to be probable, the regulatory asset would be written-off. There were no material write-offs of regulatory assets for the year ended December 31, 2025. Additionally, the regulatory agencies can provide flexibility in the manner and timing of recovery of regulatory assets.
See Note 7 to the Financial Statements for regulatory assets and regulatory liabilities recorded at December 31, 2025 and 2024, as well as additional information on those regulatory assets and liabilities. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
Price Risk Management (PPL)
See "Financial Condition - Risk Management" above.
Goodwill Impairment (PPL, LG&E and KU)
Goodwill is tested for impairment at the reporting unit level. The reporting units of PPL include the Kentucky Regulated reporting unit, the Pennsylvania Regulated reporting unit, and the Rhode Island Regulated reporting unit. LG&E and KU are each single reporting units. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the reporting unit's fair value.
The fair value of a reporting unit is compared with the carrying value and an impairment charge is recognized if the carrying amount exceeds the fair value of the reporting unit.
PPL, for its reporting units, and individually, LG&E and KU, may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a quantitative test.
As of October 1, 2025, PPL, for its reporting units, and individually, LG&E and KU, elected to perform the qualitative step zero evaluation of goodwill. These evaluations considered the excess of fair value over the carrying value of each reporting unit that was calculated during step one of the quantitative impairment tests performed in the fourth quarter of 2022, and the relevant events and circumstances that occurred since those tests were performed including:
•current year financial performance versus the prior year,
•changes in planned capital expenditures,
•the consistency of forecasted free cash flows,
•earnings quality and sustainability,
•changes in market participant discount rates,
•changes in long-term growth rates,
•changes in PPL's market capitalization, and
•the overall economic and regulatory environments in which these regulated entities operate.
Based on these evaluations, management concluded it was not more likely than not that the fair value of these reporting units was less than their carrying value. As such, the step one quantitative impairment test was not performed and no impairment was recognized.
See "Long-Lived and Intangible Assets - Asset Impairment (Excluding Investments)" in Note 1 to the Financial Statements for further discussion of goodwill impairment tests. See Note 17 to the Financial Statements for information on goodwill balances by reportable segment at December 31, 2025.
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Asset Retirement Obligations (LG&E and KU)
ARO liabilities are required to be recognized for legal obligations associated with the retirement of long-lived assets. Initial obligations are measured at estimated fair value. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount is recorded as an increase in the value of the capitalized asset and amortized to expense, regulatory assets or regulatory liabilities over the asset's useful life.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that consider estimated retirement costs in current period dollars, inflated to the anticipated retirement date and discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the ARO estimate. Any change to the capitalized asset is generally amortized over the remaining life of the associated long-lived asset.
See "Long-Lived and Intangible Assets - Asset Retirement Obligations" in Note 1, Note 7 and Note 18 to the Financial Statements for additional information on AROs.
At December 31, 2025, the total recorded balances and information on the most significant recorded AROs were as follows.

|  |  | Most Significant AROs
| Total ARO Recorded |  | Amount Recorded |  | % of Total |  | Description
LG&E | $ | 75 |  |  | $ | 52 |  |  | 69 |  |  | Ponds, landfills and natural gas mains
KU | 57 |  |  | 27 |  |  | 47 |  |  | Ponds and landfills

The most significant assumptions surrounding AROs are the forecasted retirement costs (including settlement dates and the timing of cash flows), discount and inflation rates. At December 31, 2025, a 10% increase to retirement cost would increase these ARO liabilities by $6 million at LG&E and $7 million at KU. A 0.25% decrease in the discount rate would increase these ARO liabilities by $4 million at LG&E and $1 million at KU and a 0.25% increase in the inflation rate would increase these ARO liabilities by $4 million at LG&E and $1 million at KU. There would be no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of these changes in assumptions.
Revenue Recognition - Unbilled Revenues (PPL, LG&E and KU)
For RIE, LG&E and KU, revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of actual meter reads taken throughout the month, estimates are recorded for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of deliveries to customers since the date of the last reading of their meters. The unbilled revenue estimates reflect consideration of factors including daily load models, estimated usage for each customer class, the effect of current and different rate schedules, the meter read schedule, the billing schedule, actual weather data, and, where applicable, the impact of weather normalization or other regulatory provisions of rate structures.
Other Information (All Registrants)
PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Reference is made to "Risk Management" for the Registrants in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations."
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareowners and the Board of Directors of PPL Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PPL Corporation and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2026 expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Regulatory Liabilities – Impact of Rate-Regulation on Regulatory Assets and Regulatory Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, the Company owns and operates four cost-based rate-regulated utilities for which rates are set by regulators to enable the regulated utility to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
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Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event. While the Company has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulators will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets and regulatory liabilities are probable of future recovery or refund by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management's internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and regulatory liabilities. We tested the effectiveness of management's internal controls over the recognition of amounts as regulatory assets or regulatory liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for the Company and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated the Company's disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Morristown, New Jersey
February 20, 2026
We have served as the Company's auditor since 2015.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareowner and the Board of Directors of PPL Electric Utilities Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PPL Electric Utilities Corporation and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Regulatory Liabilities – Impact of Rate-Regulation on Regulatory Assets and Regulatory Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, PPL Electric Utilities Company (PPL Electric) is a cost-based rate-regulated utility for which rates are set by regulators to enable the regulated utility to recover the costs of providing electric service and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
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Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event. While PPL Electric has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulators will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets and regulatory liabilities are probable of future recovery or refund by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management's internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and regulatory liabilities. We tested the effectiveness of management's internal controls over the recognition of amounts as regulatory assets or regulatory liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for PPL Electric and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated PPL Electric's disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Morristown, New Jersey
February 20, 2026
We have served as the Company's auditor since 2015.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder and the Board of Directors of Louisville Gas and Electric Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Louisville Gas and Electric Company (the "Company") as of December 31, 2025 and 2024, the related statements of income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Regulatory Liabilities – Impact of Rate-Regulation on Regulatory Assets and Regulatory Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, Louisville Gas and Electric Company (LG&E) is a cost-based rate-regulated utility for which rates are set by regulators to enable the regulated utility to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event. While LG&E has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulators will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets and regulatory liabilities are probable of future recovery or refund by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management's internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and regulatory liabilities. We tested the effectiveness of management's internal controls over the recognition of amounts as regulatory assets or regulatory liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for LG&E and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated LG&E's disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Louisville, Kentucky
February 20, 2026
We have served as the Company's auditor since 2015.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder and the Board of Directors of Kentucky Utilities Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Kentucky Utilities Company (the "Company") as of December 31, 2025 and 2024, the related statements of income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Regulatory Liabilities – Impact of Rate-Regulation on Regulatory Assets and Regulatory Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, Kentucky Utilities Company (KU) is a cost-based rate-regulated utility for which rates are set by regulators to enable the regulated utility to recover the costs of providing electric service and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event. While KU has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulators will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets and regulatory liabilities are probable of future recovery or refund by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management's internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and regulatory liabilities. We tested the effectiveness of management's internal controls over the recognition of amounts as regulatory assets or regulatory liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for KU and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated KU's disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Louisville, Kentucky
February 20, 2026
We have served as the Company's auditor since 2015.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, except share data)

| 2025 |  | 2024 |  | 2023
Operating Revenues | $ | 9,042 |  |  | $ | 8,462 |  |  | $ | 8,312 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Fuel | 855 |  |  | 783 |  |  | 733 |
Energy purchases | 1,892 |  |  | 1,679 |  |  | 1,841 |
Other operation and maintenance | 2,431 |  |  | 2,607 |  |  | 2,462 |
Depreciation | 1,312 |  |  | 1,279 |  |  | 1,254 |
Taxes, other than income | 423 |  |  | 374 |  |  | 392 |
Total Operating Expenses | 6,913 |  |  | 6,722 |  |  | 6,682 |
Operating Income | 2,129 |  |  | 1,740 |  |  | 1,630 |
Other Income (Expense) - net (Note 14) | 151 |  |  | 114 |  |  | (40) |
Interest Expense | 808 |  |  | 738 |  |  | 666 |
Income Before Income Taxes | 1,472 |  |  | 1,116 |  |  | 924 |
Income Taxes | 291 |  |  | 228 |  |  | 184 |
Net Income | $ | 1,181 |  |  | $ | 888 |  |  | $ | 740 |
Earnings Per Share of Common Stock: |
Net Income Available to PPL Common Shareowners: |  |  |  |  |
Basic | $ | 1.60 |  |  | $ | 1.20 |  |  | $ | 1.00 |
Diluted | $ | 1.59 |  |  | $ | 1.20 |  |  | $ | 1.00 |
Weighted-Average Shares of Common Stock Outstanding (in thousands) |  |  |  |  |
Basic | 739,406 |  |  | 737,756 |  |  | 737,036 |
Diluted | 743,348 |  |  | 739,853 |  |  | 738,166 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Net income | $ | 1,181 |  |  | $ | 888 |  |  | $ | 740 |
Other comprehensive income (loss): |  |  |  |  |
Amounts arising during the period - gains (losses), net of tax (expense) benefit: |  |  |  |  |
Qualifying derivatives, net of tax of ($1), $0, $0 | 1 |  |  | — |  |  | — |
Equity investees' other comprehensive income (loss), net tax of $0, $0, $0 | (1) |  |  | 1 |  |  | 1 |
Defined benefit plans: |  |  |  |  |
Net actuarial gain (loss), net of tax of $7, $8, $15 | (20) |  |  | (22) |  |  | (41) |
Reclassifications to net income - (gains) losses, net of tax expense (benefit): |  |  |  |  |
Qualifying derivatives, net of tax of ($1), $0, $0 | 2 |  |  | 3 |  |  | 3 |
Defined benefit plans: |  |  |  |  |
Prior service costs, net of tax of $0, $0, ($1) | 1 |  |  | 1 |  |  | 1 |
Net actuarial (gain) loss, net of tax of $1, $0, $0 | (1) |  |  | (4) |  |  | (3) |
Total other comprehensive income (loss) | (18) |  |  | (21) |  |  | (39) |
Comprehensive income | $ | 1,163 |  |  | $ | 867 |  |  | $ | 701 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Cash Flows from Operating Activities |  |  |  |  |
Net income | $ | 1,181 |  |  | $ | 888 |  |  | $ | 740 |
Adjustments to reconcile net income to net cash provided by operating activities |  |  |  |  |
Depreciation | 1,312 |  |  | 1,279 |  |  | 1,254 |
Amortization | 104 |  |  | 78 |  |  | 81 |
Defined benefit plans - income | (57) |  |  | (72) |  |  | (73) |
Deferred income taxes and investment tax credits | 192 |  |  | 196 |  |  | 322 |
Stock compensation expense | 49 |  |  | 46 |  |  | 33 |
Equity component of AFUDC | (81) |  |  | (47) |  |  | (30) |
Other | 8 |  |  | 30 |  |  | 1 |
Change in current assets and current liabilities |  |  |  |  |
Accounts receivable | (207) |  |  | 254 |  |  | (170) |
Accounts payable | (12) |  |  | (41) |  |  | (72) |
Unbilled revenues | (73) |  |  | (57) |  |  | 128 |
Fuel, materials and supplies | (28) |  |  | (2) |  |  | (60) |
Prepayments | 43 |  |  | (34) |  |  | 1 |
Taxes payable | 87 |  |  | (27) |  |  | 6 |
Regulatory assets and liabilities, net | 162 |  |  | (68) |  |  | (37) |
Accrued interest | 38 |  |  | 33 |  |  | 27 |
Other | (4) |  |  | (65) |  |  | 38 |
Other operating activities |  |  |  |  |
Defined benefit plans - funding | (12) |  |  | (10) |  |  | (13) |
Proceeds from transfer of excess benefit plan funds | — |  |  | 13 |  |  | — |
Other assets | (138) |  |  | (96) |  |  | (69) |
Other liabilities | 65 |  |  | 42 |  |  | (349) |
Net cash provided by operating activities | 2,629 |  |  | 2,340 |  |  | 1,758 |
Cash Flows from Investing Activities |  |  |  |  |
Expenditures for property, plant and equipment | (4,030) |  |  | (2,805) |  |  | (2,390) |
Other investing activities | 26 |  |  | (13) |  |  | 7 |
Net cash used in investing activities | (4,004) |  |  | (2,818) |  |  | (2,383) |
Cash Flows from Financing Activities |  |  |  |  |
Issuance of long-term debt | 3,045 |  |  | 1,894 |  |  | 3,252 |
Retirement of long-term debt | (616) |  |  | — |  |  | (1,854) |
Payment of common stock dividends | (794) |  |  | (747) |  |  | (704) |
Issuance of treasury stock | 401 |  |  | 2 |  |  | 5 |
Net increase (decrease) in short-term debt | 153 |  |  | (689) |  |  | 7 |
Debt issuance costs | (41) |  |  | (19) |  |  | (46) |
Other financing activities | (26) |  |  | (6) |  |  | (10) |
Net cash provided by financing activities | 2,122 |  |  | 435 |  |  | 650 |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | 747 |  |  | (43) |  |  | 25 |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 339 |  |  | 382 |  |  | 357 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 1,086 |  |  | $ | 339 |  |  | $ | 382 |
Supplemental Disclosures of Cash Flow Information |  |  |  |  |
Cash paid (received) during the period for: |  |  |  |  |
Interest - net of amount capitalized | $ | 745 |  |  | $ | 670 |  |  | $ | 604 |
Income taxes - net | $ | 93 |  |  | $ | (123) |  |  | $ | 281 |
Significant non-cash transactions: |  |  |  |  |
Accrued expenditures for property, plant and equipment at December 31, | $ | 630 |  |  | $ | 358 |  |  | $ | 220 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Assets |  |  |
Current Assets |  |  |
Cash and cash equivalents | $ | 1,071 |  |  | $ | 306 |
Accounts receivable (less reserve: 2025, $133; 2024, $147) |  |  |
Customer | 1,108 |  |  | 961 |
Other | 117 |  |  | 76 |
Unbilled revenues (less reserve: 2025, $6; 2024, $6) | 558 |  |  | 485 |
Fuel, materials and supplies | 551 |  |  | 511 |
Prepayments | 106 |  |  | 136 |
Regulatory assets | 308 |  |  | 320 |
Other current assets | 112 |  |  | 85 |
Total Current Assets | 3,931 |  |  | 2,880 |
Property, Plant and Equipment |  |  |
Regulated utility plant | 42,953 |  |  | 40,391 |
Less: accumulated depreciation - regulated utility plant | 10,303 |  |  | 9,682 |
Regulated utility plant, net | 32,650 |  |  | 30,709 |
Non-regulated property, plant and equipment | 71 |  |  | 79 |
Less: accumulated depreciation - non-regulated property, plant and equipment | 26 |  |  | 29 |
Non-regulated property, plant and equipment, net | 45 |  |  | 50 |
Construction work in progress | 3,437 |  |  | 2,390 |
Property, Plant and Equipment, net | 36,132 |  |  | 33,149 |
Other Noncurrent Assets |  |  |
Regulatory assets | 2,092 |  |  | 2,060 |
Goodwill | 2,247 |  |  | 2,247 |
Other intangibles | 327 |  |  | 314 |
Other noncurrent assets (less reserve for accounts receivable: 2025, $1; 2024, $1) | 515 |  |  | 419 |
Total Other Noncurrent Assets | 5,181 |  |  | 5,040 |
Total Assets | $ | 45,244 |  |  | $ | 41,069 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Liabilities and Equity |  |  |
Current Liabilities |  |  |
Short-term debt | $ | 456 |  |  | $ | 303 |
Long-term debt due within one year | 904 |  |  | 551 |
Accounts payable | 1,559 |  |  | 1,196 |
Taxes | 190 |  |  | 103 |
Interest | 195 |  |  | 157 |
Dividends | 198 |  |  | 186 |
Regulatory liabilities | 376 |  |  | 223 |
Other current liabilities | 668 |  |  | 614 |
Total Current Liabilities | 4,546 |  |  | 3,333 |
Long-term Debt | 17,990 |  |  | 15,952 |
Deferred Credits and Other Noncurrent Liabilities |  |  |
Deferred income taxes | 3,506 |  |  | 3,356 |
Investment tax credits | 109 |  |  | 111 |
Accrued pension obligations | 281 |  |  | 317 |
Asset retirement obligations | 133 |  |  | 136 |
Regulatory liabilities | 3,318 |  |  | 3,335 |
Other deferred credits and noncurrent liabilities | 480 |  |  | 452 |
Total Deferred Credits and Other Noncurrent Liabilities | 7,827 |  |  | 7,707 |
Commitments and Contingent Liabilities (Notes 7 and 12) |  |  |
Equity |  |  |
Common stock - $0.01 par value (a) | 8 |  |  | 8 |
Additional paid-in capital | 12,443 |  |  | 12,346 |
Treasury stock | (575) |  |  | (928) |
Earnings reinvested | 3,207 |  |  | 2,835 |
Accumulated other comprehensive loss | (202) |  |  | (184) |
Total Equity | 14,881 |  |  | 14,077 |
Total Liabilities and Equity | $ | 45,244 |  |  | $ | 41,069 |

(a)1,560,000 shares authorized; 770,978 shares issued and 751,041 shares outstanding at December 31, 2025. 1,560,000 shares authorized; 770,215 shares issued and 738,033 shares outstanding at December 31, 2024.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED STATEMENTS OF EQUITY
PPL Corporation and Subsidiaries
(Millions of Dollars)

| Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Treasury Stock | Earnings reinvested | Accumulated other comprehensive loss | Noncontrolling interest |  |  | Total
December 31, 2022 | 736,487 |  | $ | 8 |  | $ | 12,317 |  | $ | (967) |  | $ | 2,681 |  | $ | (124) |  | $ | 3 |  |  |  | $ | 13,918 |
Treasury stock issued | 643 |  |  | 4 |  | 19 |  |  |  |  |  |  | 23 |
Stock-based compensation |  |  | 5 |  |  |  |  |  |  |  | 5 |
Net income |  |  |  |  | 740 |  |  |  |  |  | 740 |
Dividends and dividend equivalents (b) |  |  |  |  | (711) |  |  |  |  |  | (711) |
Preferred stock |  |  |  |  |  |  | (3) |  |  |  | (3) |
Other comprehensive income (loss) |  |  |  |  |  | (39) |  |  |  |  | (39) |
December 31, 2023 | 737,130 |  | $ | 8 |  | $ | 12,326 |  | $ | (948) |  | $ | 2,710 |  | $ | (163) |  | $ | — |  |  |  | $ | 13,933 |
Common stock issued | 202 |  |  |  |  |  |  |  |  |  | — |
Treasury stock issued | 701 |  |  | 7 |  | 20 |  |  |  |  |  |  | 27 |
Stock-based compensation |  |  | 13 |  |  |  |  |  |  |  | 13 |
Net income |  |  |  |  | 888 |  |  |  |  |  | 888 |
Dividends and dividend equivalents (b) |  |  |  |  | (763) |  |  |  |  |  | (763) |
Other comprehensive income (loss) |  |  |  |  |  | (21) |  |  |  |  | (21) |
December 31, 2024 | 738,033 |  | $ | 8 |  | $ | 12,346 |  | $ | (928) |  | $ | 2,835 |  | $ | (184) |  | $ | — |  |  |  | $ | 14,077 |
Common stock issued | 763 |  |  | 26 |  |  |  |  |  |  |  | 26 |
Treasury stock issued | 12,245 |  |  | 67 |  | 353 |  |  |  |  |  |  | 420 |
Stock-based compensation |  |  | 4 |  |  |  |  |  |  |  | 4 |
Net income |  |  |  |  | 1,181 |  |  |  |  |  | 1,181 |
Dividends and dividend equivalents (b) |  |  |  |  | (809) |  |  |  |  |  | (809) |
Other comprehensive income (loss) |  |  |  |  |  | (18) |  |  |  |  | (18) |
December 31, 2025 | 751,041 |  | $ | 8 |  | $ | 12,443 |  | $ | (575) |  | $ | 3,207 |  | $ | (202) |  | $ | — |  |  |  | $ | 14,881 |

(a)Shares in thousands. Each share entitles the holder to one vote on any question presented at any shareowners' meeting.
(b)Dividends declared per share of common stock at December 31, 2025, 2024 and 2023 were: $1.09, $1.03 and $0.96.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Operating Revenues | $ | 3,113 |  |  | $ | 2,876 |  |  | $ | 3,008 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Energy purchases | 876 |  |  | 721 |  |  | 992 |
Other operation and maintenance | 630 |  |  | 705 |  |  | 605 |
Depreciation | 413 |  |  | 401 |  |  | 397 |
Taxes, other than income | 151 |  |  | 131 |  |  | 143 |
Total Operating Expenses | 2,070 |  |  | 1,958 |  |  | 2,137 |
Operating Income | 1,043 |  |  | 918 |  |  | 871 |
Other Income (Expense) - net (Note 14) | 48 |  |  | 45 |  |  | 39 |
Interest Income from Affiliate | 9 |  |  | 33 |  |  | — |
Interest Expense | 257 |  |  | 246 |  |  | 223 |
Income Before Income Taxes | 843 |  |  | 750 |  |  | 687 |
Income Taxes | 204 |  |  | 176 |  |  | 168 |
Net Income (a) | $ | 639 |  |  | $ | 574 |  |  | $ | 519 |

(a)Net income equals comprehensive income.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Cash Flows from Operating Activities |  |  |  |  |
Net income | $ | 639 |  |  | $ | 574 |  |  | $ | 519 |
Adjustments to reconcile net income to net cash provided by operating activities |  |  |  |  |
Depreciation | 413 |  |  | 401 |  |  | 397 |
Amortization | 48 |  |  | 45 |  |  | 41 |
Defined benefit plans - income | (29) |  |  | (39) |  |  | (42) |
Deferred income taxes and investment tax credits | 24 |  |  | 129 |  |  | 46 |
Equity component of AFUDC | (30) |  |  | (23) |  |  | (16) |
Other | 4 |  |  | 24 |  |  | (8) |
Change in current assets and current liabilities |  |  |  |  |
Accounts receivable | (142) |  |  | 89 |  |  | (78) |
Accounts payable | 99 |  |  | 64 |  |  | 13 |
Unbilled revenues | (50) |  |  | (10) |  |  | 75 |
Materials and supplies | (40) |  |  | 6 |  |  | (30) |
Prepayments | 49 |  |  | (32) |  |  | 2 |
Regulatory assets and liabilities, net | 67 |  |  | (101) |  |  | (38) |
Taxes payable | 45 |  |  | (49) |  |  | 15 |
Accrued interest | 11 |  |  | 12 |  |  | 8 |
Other | (8) |  |  | (25) |  |  | 9 |
Other operating activities |  |  |  |  |
Defined benefit plans - funding | — |  |  | — |  |  | (5) |
Other assets | (50) |  |  | (32) |  |  | 3 |
Other liabilities | — |  |  | 9 |  |  | 1 |
Net cash provided by operating activities | 1,050 |  |  | 1,042 |  |  | 912 |
Cash Flows from Investing Activities |  |  |  |  |
Expenditures for property, plant and equipment | (1,608) |  |  | (1,229) |  |  | (956) |
Expenditures for intangible assets | (12) |  |  | (9) |  |  | (6) |
Net (increase) decrease in notes receivable from affiliate | 79 |  |  | (222) |  |  | — |
Other investing activities | 38 |  |  | 5 |  |  | 4 |
Net cash used in investing activities | (1,503) |  |  | (1,455) |  |  | (958) |
Cash Flows from Financing Activities |  |  |  |  |
Issuance of long-term debt | 496 |  |  | 649 |  |  | 1,329 |
Retirement of long-term debt | — |  |  | — |  |  | (1,240) |
Contributions from parent | 540 |  |  | 688 |  |  | 206 |
Payment of common stock dividends to parent | (401) |  |  | (375) |  |  | (323) |
Return of capital to parent | (170) |  |  | (60) |  |  | (250) |
Net increase (decrease) in short-term debt | — |  |  | (509) |  |  | 364 |
Debt issuance costs | (6) |  |  | (7) |  |  | (14) |
Net cash provided by financing activities | 459 |  |  | 386 |  |  | 72 |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | 6 |  |  | (27) |  |  | 26 |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 24 |  |  | 51 |  |  | 25 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 30 |  |  | $ | 24 |  |  | $ | 51 |
Supplemental Disclosures of Cash Flow Information |  |  |  |  |
Cash paid during the period for: |  |  |  |  |
Interest - net of amount capitalized | $ | 236 |  |  | $ | 224 |  |  | $ | 205 |
Income taxes - net | $ | 129 |  |  | $ | 83 |  |  | $ | 92 |
Significant non-cash transactions: |  |  |  |  |
Accrued expenditures for property, plant and equipment at December 31, | $ | 213 |  |  | $ | 173 |  |  | $ | 122 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Assets |  |  |
Current Assets |  |  |
Cash and cash equivalents | $ | 30 |  |  | $ | 24 |
Accounts receivable (less reserve: 2025, $34; 2024, $37) |  |  |
Customer | 450 |  |  | 353 |
Other | 29 |  |  | 8 |
Accounts receivable from affiliates | 7 |  |  | 10 |
Notes receivable from affiliate | 143 |  |  | 222 |
Unbilled revenues (less reserve: 2025, $4; 2024, $3) | 209 |  |  | 159 |
Materials and supplies | 151 |  |  | 104 |
Prepayments | 38 |  |  | 74 |
Regulatory assets | 112 |  |  | 133 |
Other current assets | 46 |  |  | 30 |
Total Current Assets | 1,215 |  |  | 1,117 |
Property, Plant and Equipment |  |  |
Regulated utility plant | 17,476 |  |  | 16,469 |
Less: accumulated depreciation - regulated utility plant | 4,124 |  |  | 4,052 |
Regulated utility plant, net | 13,352 |  |  | 12,417 |
Construction work in progress | 1,216 |  |  | 898 |
Property, Plant and Equipment, net | 14,568 |  |  | 13,315 |
Other Noncurrent Assets |  |  |
Regulatory assets | 725 |  |  | 673 |
Intangibles | 282 |  |  | 274 |
Other noncurrent assets (less reserve for accounts receivable: 2025, $1; 2024, $1) | 96 |  |  | 96 |
Total Other Noncurrent Assets | 1,103 |  |  | 1,043 |
Total Assets | $ | 16,886 |  |  | $ | 15,475 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Liabilities and Equity |  |  |
Current Liabilities |  |  |
Accounts payable | $ | 690 |  |  | $ | 565 |
Accounts payable to affiliates | 54 |  |  | 44 |
Taxes | 47 |  |  | 2 |
Interest | 66 |  |  | 55 |
Customer deposits | 92 |  |  | 25 |
Regulatory liabilities | 103 |  |  | 57 |
Other current liabilities | 58 |  |  | 58 |
Total Current Liabilities | 1,110 |  |  | 806 |
Long-term Debt | 5,707 |  |  | 5,214 |
Deferred Credits and Other Noncurrent Liabilities |  |  |
Deferred income taxes | 1,781 |  |  | 1,726 |
Regulatory liabilities | 828 |  |  | 839 |
Other deferred credits and noncurrent liabilities | 122 |  |  | 160 |
Total Deferred Credits and Other Noncurrent Liabilities | 2,731 |  |  | 2,725 |
Commitments and Contingent Liabilities (Notes 7 and 12) |  |  |
Equity |  |  |
Common stock - no par value (a) | 364 |  |  | 364 |
Additional paid-in capital | 5,038 |  |  | 4,668 |
Earnings reinvested | 1,936 |  |  | 1,698 |
Total Equity | 7,338 |  |  | 6,730 |
Total Liabilities and Equity | $ | 16,886 |  |  | $ | 15,475 |

(a)170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2025 and December 31, 2024.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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CONSOLIDATED STATEMENTS OF EQUITY
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)

| Common stock shares outstanding (a) |  | Common stock |  | Additional paid-in capital |  | Earnings reinvested |  | Total
December 31, 2022 | 66,368 |  |  | $ | 364 |  |  | $ | 4,084 |  |  | $ | 1,303 |  |  | $ | 5,751 |
Net income |  |  |  |  |  |  | 519 |  |  | 519 |
Capital contributions from parent |  |  |  |  | 206 |  |  |  |  | 206 |
Return of capital to parent |  |  |  |  | (250) |  |  |  |  | (250) |
Dividends declared |  |  |  |  |  |  | (323) |  |  | (323) |
December 31, 2023 | 66,368 |  |  | $ | 364 |  |  | $ | 4,040 |  |  | $ | 1,499 |  |  | $ | 5,903 |
Net income |  |  |  |  |  |  | 574 |  |  | 574 |
Capital contributions from parent |  |  |  |  | 688 |  |  |  |  | 688 |
Return of capital to parent |  |  |  |  | (60) |  |  |  |  | (60) |
Dividends declared |  |  |  |  |  |  | (375) |  |  | (375) |
December 31, 2024 | 66,368 |  |  | $ | 364 |  |  | $ | 4,668 |  |  | $ | 1,698 |  |  | $ | 6,730 |
Net income |  |  |  |  |  |  | 639 |  |  | 639 |
Capital contributions from parent |  |  |  |  | 540 |  |  |  |  | 540 |
Return of capital to parent |  |  |  |  | (170) |  |  |  |  | (170) |
Dividends declared |  |  |  |  |  |  | (401) |  |  | (401) |
December 31, 2025 | 66,368 |  |  | $ | 364 |  |  | $ | 5,038 |  |  | $ | 1,936 |  |  | $ | 7,338 |

(a)Shares in thousands. All common shares of PPL Electric stock are owned by PPL.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Operating Revenues |  |  |  |  |
Retail and wholesale | $ | 1,718 |  |  | $ | 1,617 |  |  | $ | 1,580 |
Electric revenue from affiliate | 30 |  |  | 31 |  |  | 33 |
Total Operating Revenues | 1,748 |  |  | 1,648 |  |  | 1,613 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Fuel | 338 |  |  | 308 |  |  | 286 |
Energy purchases | 187 |  |  | 151 |  |  | 168 |
Energy purchases from affiliate | 22 |  |  | 20 |  |  | 12 |
Other operation and maintenance | 364 |  |  | 349 |  |  | 364 |
Depreciation | 307 |  |  | 305 |  |  | 302 |
Taxes, other than income | 51 |  |  | 49 |  |  | 48 |
Total Operating Expenses | 1,269 |  |  | 1,182 |  |  | 1,180 |
Operating Income | 479 |  |  | 466 |  |  | 433 |
Other Income (Expense) - net (Note 14) | 24 |  |  | 12 |  |  | 3 |
Interest Income from Affiliate | — |  |  | 1 |  |  | 1 |
Interest Expense | 116 |  |  | 105 |  |  | 102 |
Income Before Income Taxes | 387 |  |  | 374 |  |  | 335 |
Income Taxes | 78 |  |  | 77 |  |  | 69 |
Net Income (a) | $ | 309 |  |  | $ | 297 |  |  | $ | 266 |

(a)Net income equals comprehensive income.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Cash Flows from Operating Activities |  |  |  |  |
Net income | $ | 309 |  |  | $ | 297 |  |  | $ | 266 |
Adjustments to reconcile net income to net cash provided by (used in) operating activities |  |  |  |  |
Depreciation | 307 |  |  | 305 |  |  | 302 |
Amortization | 24 |  |  | 16 |  |  | 14 |
Equity component of AFUDC | (16) |  |  | (8) |  |  | (3) |
Deferred income taxes and investment tax credits | (9) |  |  | 6 |  |  | (14) |
Other | 6 |  |  | 2 |  |  | (4) |
Change in current assets and current liabilities |  |  |  |  |
Accounts receivable | (10) |  |  | (25) |  |  | 40 |
Accounts receivable from affiliates | (6) |  |  | (11) |  |  | 7 |
Accounts payable | 14 |  |  | 12 |  |  | (40) |
Accounts payable to affiliates | 6 |  |  | 15 |  |  | (8) |
Unbilled revenues | (10) |  |  | 1 |  |  | 24 |
Fuel, materials and supplies | (2) |  |  | (13) |  |  | 24 |
Regulatory assets and liabilities, net | (12) |  |  | (3) |  |  | 25 |
Taxes payable | 20 |  |  | (1) |  |  | — |
Accrued interest | 13 |  |  | — |  |  | 5 |
Other | (5) |  |  | — |  |  | 1 |
Other operating activities |  |  |  |  |
Expenditures for asset retirement obligations | (9) |  |  | (11) |  |  | (11) |
Other assets | (43) |  |  | (27) |  |  | (21) |
Other liabilities | 22 |  |  | (1) |  |  | 2 |
Net cash provided by operating activities | 599 |  |  | 554 |  |  | 609 |
Cash Flows from Investing Activities |  |  |  |  |
Expenditures for property, plant and equipment | (767) |  |  | (444) |  |  | (378) |
Notes receivable from affiliates | (36) |  |  | — |  |  | — |
Net cash used in investing activities | (803) |  |  | (444) |  |  | (378) |
Cash Flows from Financing Activities |  |  |  |  |
Net increase (decrease) in notes payable with affiliates | (43) |  |  | 43 |  |  | — |
Issuance of long-term debt | 700 |  |  | — |  |  | 464 |
Retirement of long-term debt | (300) |  |  | — |  |  | (300) |
Payment of common stock dividends to parent | (200) |  |  | (187) |  |  | (166) |
Contributions from parent | 281 |  |  | 65 |  |  | 67 |
Return of capital to parent | (55) |  |  | (76) |  |  | (161) |
Debt issuance costs | (9) |  |  | — |  |  | (5) |
Net increase (decrease) in short-term debt | (25) |  |  | 25 |  |  | (179) |
Net cash provided by (used in) financing activities | 349 |  |  | (130) |  |  | (280) |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | 145 |  |  | (20) |  |  | (49) |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 24 |  |  | 44 |  |  | 93 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 169 |  |  | $ | 24 |  |  | $ | 44 |
Supplemental Disclosures of Cash Flow Information |  |  |  |  |
Cash paid during the period for: |  |  |  |  |
Interest - net of amount capitalized | $ | 103 |  |  | $ | 101 |  |  | $ | 93 |
Income taxes - net | $ | 81 |  |  | $ | 73 |  |  | $ | 84 |
Significant non-cash transactions: |  |  |  |  |
Accrued expenditures for property, plant and equipment at December 31, | $ | 142 |  |  | $ | 64 |  |  | $ | 30 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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BALANCE SHEETS AT DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Assets |  |  |
Current Assets |  |  |
Cash and cash equivalents | $ | 162 |  |  | $ | 8 |
Accounts receivable (less reserve: 2025, $5; 2024, $3) |  |  |
Customer | 154 |  |  | 134 |
Other | 26 |  |  | 23 |
Unbilled revenues (less reserve: 2025, $0; 2024, $0) | 97 |  |  | 87 |
Accounts receivable from affiliates | 46 |  |  | 40 |
Notes receivable from affiliates | 36 |  |  | — |
Fuel, materials and supplies | 160 |  |  | 157 |
Prepayments | 11 |  |  | 9 |
Regulatory assets | 19 |  |  | 8 |
Other current assets | 2 |  |  | 2 |
Total Current Assets | 713 |  |  | 468 |
Property, Plant and Equipment |  |  |
Regulated utility plant | 8,270 |  |  | 7,748 |
Less: accumulated depreciation - regulated utility plant | 1,842 |  |  | 1,643 |
Regulated utility plant, net | 6,428 |  |  | 6,105 |
Construction work in progress | 689 |  |  | 443 |
Property, Plant and Equipment, net | 7,117 |  |  | 6,548 |
Other Noncurrent Assets |  |  |
Regulatory assets | 482 |  |  | 491 |
Goodwill | 389 |  |  | 389 |
Other intangibles | 11 |  |  | 12 |
Other noncurrent assets | 106 |  |  | 84 |
Total Other Noncurrent Assets | 988 |  |  | 976 |
Total Assets | $ | 8,818 |  |  | $ | 7,992 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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BALANCE SHEETS AT DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Liabilities and Equity |  |  |
Current Liabilities |  |  |
Short-term debt | $ | — |  |  | $ | 25 |
Notes payable with affiliates | — |  |  | 43 |
Long-term debt due within one year | 90 |  |  | 300 |
Accounts payable | 262 |  |  | 158 |
Accounts payable to affiliates | 73 |  |  | 64 |
Customer deposits | 37 |  |  | 36 |
Taxes | 60 |  |  | 40 |
Regulatory liabilities | 13 |  |  | 14 |
Interest | 34 |  |  | 21 |
Asset retirement obligations | 2 |  |  | 11 |
Other current liabilities | 54 |  |  | 50 |
Total Current Liabilities | 625 |  |  | 762 |
Long-term Debt | 2,775 |  |  | 2,171 |
Deferred Credits and Other Noncurrent Liabilities |  |  |
Deferred income taxes | 819 |  |  | 803 |
Investment tax credits | 29 |  |  | 30 |
Price risk management liabilities | 4 |  |  | 3 |
Asset retirement obligations | 73 |  |  | 73 |
Regulatory liabilities | 809 |  |  | 815 |
Other deferred credits and noncurrent liabilities | 78 |  |  | 64 |
Total Deferred Credits and Other Noncurrent Liabilities | 1,812 |  |  | 1,788 |
Commitments and Contingent Liabilities (Notes 7 and 12) |  |  |
Equity |  |  |
Common stock - no par value (a) | 424 |  |  | 424 |
Additional paid-in capital | 2,208 |  |  | 1,982 |
Earnings reinvested | 974 |  |  | 865 |
Total Equity | 3,606 |  |  | 3,271 |
Total Liabilities and Equity | $ | 8,818 |  |  | $ | 7,992 |

(a)75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2025 and December 31, 2024.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF EQUITY
Louisville Gas and Electric Company
(Millions of Dollars)

| Common stock shares outstanding (a) |  | Common stock |  | Additional paid-in capital |  | Earnings reinvested |  | Total
December 31, 2022 | 21,294 |  |  | $ | 424 |  |  | $ | 2,087 |  |  | $ | 655 |  |  | $ | 3,166 |
Net income |  |  |  |  |  |  | 266 |  |  | 266 |
Capital contributions from parent |  |  |  |  | 67 |  |  |  |  | 67 |
Return of capital to parent |  |  |  |  | (161) |  |  |  |  | (161) |
Cash dividends declared |  |  |  |  |  |  | (166) |  |  | (166) |
December 31, 2023 | 21,294 |  |  | $ | 424 |  |  | $ | 1,993 |  |  | $ | 755 |  |  | $ | 3,172 |
Net income |  |  |  |  |  |  | 297 |  |  | 297 |
Capital contributions from parent |  |  |  |  | 65 |  |  |  |  | 65 |
Return of capital to parent |  |  |  |  | (76) |  |  |  |  | (76) |
Cash dividends declared |  |  |  |  |  |  | (187) |  |  | (187) |
December 31, 2024 | 21,294 |  |  | $ | 424 |  |  | $ | 1,982 |  |  | $ | 865 |  |  | $ | 3,271 |
Net income |  |  |  |  |  |  | 309 |  |  | 309 |
Capital contributions from parent |  |  |  |  | 281 |  |  |  |  | 281 |
Return of capital to parent |  |  |  |  | (55) |  |  |  |  | (55) |
Cash dividends declared |  |  |  |  |  |  | (200) |  |  | (200) |
December 31, 2025 | 21,294 |  |  | $ | 424 |  |  | $ | 2,208 |  |  | $ | 974 |  |  | $ | 3,606 |

(a)Shares in thousands. All common shares of LG&E stock are owned by LKE.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Operating Revenues |  |  |  |  |
Retail and wholesale | $ | 2,042 |  |  | $ | 1,944 |  |  | $ | 1,872 |
Electric revenue from affiliate | 22 |  |  | 20 |  |  | 12 |
Total Operating Revenues | 2,064 |  |  | 1,964 |  |  | 1,884 |
Operating Expenses |  |  |  |  |
Operation |  |  |  |  |
Fuel | 517 |  |  | 476 |  |  | 447 |
Energy purchases | 26 |  |  | 25 |  |  | 24 |
Energy purchases from affiliate | 30 |  |  | 31 |  |  | 33 |
Other operation and maintenance | 416 |  |  | 413 |  |  | 427 |
Depreciation | 408 |  |  | 403 |  |  | 392 |
Taxes, other than income | 51 |  |  | 49 |  |  | 45 |
Total Operating Expenses | 1,448 |  |  | 1,397 |  |  | 1,368 |
Operating Income | 616 |  |  | 567 |  |  | 516 |
Other Income (Expense) - net (Note 14) | 29 |  |  | 15 |  |  | 8 |
Interest Expense | 148 |  |  | 137 |  |  | 134 |
Interest Expense from Affiliate | — |  |  | — |  |  | 1 |
Income Before Income Taxes | 497 |  |  | 445 |  |  | 389 |
Income Taxes | 99 |  |  | 89 |  |  | 77 |
Net Income (a) | $ | 398 |  |  | $ | 356 |  |  | $ | 312 |

(a)Net income equals comprehensive income.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars)

| 2025 |  | 2024 |  | 2023
Cash Flows from Operating Activities |  |  |  |  |
Net income | $ | 398 |  |  | $ | 356 |  |  | $ | 312 |
Adjustments to reconcile net income to net cash provided by (used in) operating activities |  |  |  |  |
Depreciation | 408 |  |  | 403 |  |  | 392 |
Amortization | 21 |  |  | 21 |  |  | 20 |
Defined benefit plans - income | (3) |  |  | (5) |  |  | (5) |
Equity component of AFUDC | (21) |  |  | (9) |  |  | (3) |
Deferred income taxes and investment tax credits | — |  |  | (15) |  |  | (10) |
Other | 11 |  |  | 5 |  |  | 1 |
Change in current assets and current liabilities |  |  |  |  |
Accounts receivable | (2) |  |  | (21) |  |  | 16 |
Accounts payable | 1 |  |  | (23) |  |  | (26) |
Accounts payable to affiliates | 7 |  |  | 29 |  |  | (24) |
Unbilled revenues | (4) |  |  | (5) |  |  | 17 |
Fuel, materials and supplies | (8) |  |  | 14 |  |  | (17) |
Regulatory assets and liabilities, net | (6) |  |  | 23 |  |  | 25 |
Taxes payable | 26 |  |  | 5 |  |  | 5 |
Accrued interest | 14 |  |  | — |  |  | 5 |
Other | (4) |  |  | (5) |  |  | (4) |
Other operating activities |  |  |  |  |
Expenditures for asset retirement obligations | (11) |  |  | (10) |  |  | (28) |
Other assets | (21) |  |  | (41) |  |  | (25) |
Other liabilities | (8) |  |  | 1 |  |  | (4) |
Net cash provided by operating activities | 798 |  |  | 723 |  |  | 647 |
Cash Flows from Investing Activities |  |  |  |  |
Expenditures for property, plant and equipment | (983) |  |  | (643) |  |  | (572) |
Other investing activities | (3) |  |  | — |  |  | 6 |
Net cash used in investing activities | (986) |  |  | (643) |  |  | (566) |
Cash Flows from Financing Activities |  |  |  |  |
Net increase (decrease) in notes payable with affiliates | (37) |  |  | 73 |  |  | — |
Issuance of long-term debt | 700 |  |  | — |  |  | 459 |
Retirement of long-term debt | (250) |  |  | — |  |  | (313) |
Payment of common stock dividends to parent | (249) |  |  | (232) |  |  | (190) |
Contributions from parent | 198 |  |  | 126 |  |  | 76 |
Return of capital to parent | (37) |  |  | (103) |  |  | (84) |
Debt issuance costs | (9) |  |  | — |  |  | (4) |
Net increase (decrease) in short-term debt | (140) |  |  | 47 |  |  | (8) |
Net cash provided by (used in) financing activities | 176 |  |  | (89) |  |  | (64) |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | (12) |  |  | (9) |  |  | 17 |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 29 |  |  | 38 |  |  | 21 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 17 |  |  | $ | 29 |  |  | $ | 38 |
Supplemental Disclosures of Cash Flow Information |  |  |  |  |
Cash paid during the period for: |  |  |  |  |
Interest - net of amount capitalized | $ | 138 |  |  | $ | 135 |  |  | $ | 125 |
Income taxes - net | $ | 94 |  |  | $ | 102 |  |  | $ | 78 |
Significant non-cash transactions: |  |  |  |  |
Accrued expenditures for property, plant and equipment at December 31, | $ | 101 |  |  | $ | 74 |  |  | $ | 38 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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BALANCE SHEETS AT DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Assets |  |  |
Current Assets |  |  |
Cash and cash equivalents | $ | 10 |  |  | $ | 13 |
Accounts receivable (less reserve: 2025, $4; 2024, $2) |  |  |
Customer | 171 |  |  | 160 |
Other | 26 |  |  | 22 |
Unbilled revenues (less reserve: 2025, $0; 2024, $0) | 106 |  |  | 102 |
Fuel, materials and supplies | 183 |  |  | 173 |
Prepayments | 12 |  |  | 11 |
Regulatory assets | 1 |  |  | 1 |
Other current assets | 16 |  |  | 9 |
Total Current Assets | 525 |  |  | 491 |
Property, Plant and Equipment |  |  |
Regulated utility plant | 10,929 |  |  | 10,419 |
Less: accumulated depreciation - regulated utility plant | 2,934 |  |  | 2,652 |
Regulated utility plant, net | 7,995 |  |  | 7,767 |
Construction work in progress | 952 |  |  | 567 |
Property, Plant and Equipment, net | 8,947 |  |  | 8,334 |
Other Noncurrent Assets |  |  |
Regulatory assets | 467 |  |  | 458 |
Goodwill | 607 |  |  | 607 |
Other intangibles | 34 |  |  | 28 |
Other noncurrent assets | 178 |  |  | 155 |
Total Other Noncurrent Assets | 1,286 |  |  | 1,248 |
Total Assets | $ | 10,758 |  |  | $ | 10,073 |

The accompanying Notes to Financial Statements are an integral part of the financial statements.
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BALANCE SHEETS AT DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars, shares in thousands)

| 2025 |  | 2024
Liabilities and Equity |  |  |
Current Liabilities |  |  |
Short-term debt | $ | — |  |  | $ | 140 |
Notes payable with affiliates | 36 |  |  | 73 |
Long-term debt due within one year | 164 |  |  | 250 |
Accounts payable | 137 |  |  | 96 |
Accounts payable to affiliates | 106 |  |  | 100 |
Customer deposits | 41 |  |  | 39 |
Taxes | 63 |  |  | 37 |
Regulatory liabilities | 16 |  |  | 22 |
Interest | 38 |  |  | 24 |
Asset retirement obligations | 6 |  |  | 10 |
Other current liabilities | 69 |  |  | 58 |
Total Current Liabilities | 676 |  |  | 849 |
Long-term Debt | 3,346 |  |  | 2,816 |
Deferred Credits and Other Noncurrent Liabilities |  |  |
Deferred income taxes | 956 |  |  | 924 |
Investment tax credits | 79 |  |  | 81 |
Asset retirement obligations | 51 |  |  | 54 |
Regulatory liabilities | 997 |  |  | 1,009 |
Other deferred credits and noncurrent liabilities | 44 |  |  | 41 |
Total Deferred Credits and Other Noncurrent Liabilities | 2,127 |  |  | 2,109 |
Commitments and Contingent Liabilities (Notes 7 and 12) |  |  |
Equity |  |  |
Common stock - no par value (a) | 308 |  |  | 308 |
Additional paid-in capital | 3,217 |  |  | 3,056 |
Earnings reinvested | 1,084 |  |  | 935 |
Total Equity | 4,609 |  |  | 4,299 |
Total Liabilities and Equity | $ | 10,758 |  |  | $ | 10,073 |

(a) 80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2025 and December 31, 2024.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF EQUITY
Kentucky Utilities Company
(Millions of Dollars)

| Common stock shares outstanding (a) |  | Common stock |  | Additional paid-in capital |  | Earnings reinvested |  | Total
December 31, 2022 | 37,818 |  |  | $ | 308 |  |  | $ | 3,041 |  |  | $ | 689 |  |  | $ | 4,038 |
Net income |  |  |  |  |  |  | 312 |  |  | 312 |
Capital contributions from parent |  |  |  |  | 76 |  |  |  |  | 76 |
Return of capital to parent |  |  |  |  | (84) |  |  |  |  | (84) |
Cash dividends declared |  |  |  |  |  |  | (190) |  |  | (190) |
December 31, 2023 | 37,818 |  |  | $ | 308 |  |  | $ | 3,033 |  |  | $ | 811 |  |  | $ | 4,152 |
Net income |  |  |  |  |  |  | 356 |  |  | 356 |
Capital contributions from parent |  |  |  |  | 126 |  |  |  |  | 126 |
Return of capital to parent |  |  |  |  | (103) |  |  |  |  | (103) |
Cash dividends declared |  |  |  |  |  |  | (232) |  |  | (232) |
December 31, 2024 | 37,818 |  |  | $ | 308 |  |  | $ | 3,056 |  |  | $ | 935 |  |  | $ | 4,299 |
Net income |  |  |  |  |  |  | 398 |  |  | 398 |
Capital contributions from parent |  |  |  |  | 198 |  |  |  |  | 198 |
Return of capital to parent |  |  |  |  | (37) |  |  |  |  | (37) |
Cash dividends declared |  |  |  |  |  |  | (249) |  |  | (249) |
December 31, 2025 | 37,818 |  |  | $ | 308 |  |  | $ | 3,217 |  |  | $ | 1,084 |  |  | $ | 4,609 |

(a)Shares in thousands. All common shares of KU stock are owned by LKE.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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COMBINED NOTES TO FINANCIAL STATEMENTS
Index to Combined Notes to Consolidated Financial Statements
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:

|  | Registrant
|  | PPL |  | PPL Electric |  | LG&E |  | KU
1. Summary of Significant Accounting Policies |  | x |  | x |  | x |  | x
2. Segment and Related Information |  | x |  | x |  | x |  | x
3. Revenue from Contracts with Customers |  | x |  | x |  | x |  | x
4. Preferred Securities |  | x |  | x |  | x |  | x
5. Earnings Per Share |  | x |  |  |  |  |  |
6. Income and Other Taxes |  | x |  | x |  | x |  | x
7. Utility Rate Regulation |  | x |  | x |  | x |  | x
8. Financing Activities |  | x |  | x |  | x |  | x
9. Acquisitions, Development and Divestitures |  | x |  |  |  | x |  | x
10. Retirement and Postemployment Benefits |  | x |  | x |  | x |  | x
11. Jointly Owned Facilities |  | x |  |  |  | x |  | x
12. Commitments and Contingencies |  | x |  | x |  | x |  | x
13. Related Party Transactions |  |  |  | x |  | x |  | x
14. Other Income (Expense) - net |  | x |  | x |  | x |  | x
15. Fair Value Measurements |  | x |  | x |  | x |  | x
16. Derivative Instruments and Hedging Activities |  | x |  | x |  | x |  | x
17. Goodwill and Other Intangible Assets |  | x |  | x |  | x |  | x
18. Asset Retirement Obligations |  | x |  | x |  | x |  | x
19. Accumulated Other Comprehensive Income (Loss) |  | x |  |  |  |  |  |
20. New Accounting Guidance Pending Adoption |  | x |  | x |  | x |  | x

1. Summary of Significant Accounting Policies
(All Registrants)
General
Capitalized terms and abbreviations appearing in the combined notes to financial statements are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted. The specific Registrant to which disclosures are applicable is identified in parenthetical headings in italics above the applicable disclosure or within the applicable disclosure for each Registrants' related activities and disclosures. Within combined disclosures, amounts are disclosed for any Registrant when significant.
Business and Consolidation
(PPL)
PPL is a utility holding company that, through its regulated subsidiaries, is primarily engaged in: 1) the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas, primarily in Kentucky; 2) the transmission, distribution and sale of electricity in Pennsylvania; and 3) the transmission, distribution and sale of electricity and the distribution and sale of natural gas in Rhode Island. Headquartered in Allentown, PA, PPL's principal subsidiaries are LG&E, KU, RIE and PPL Electric. PPL's corporate level financing subsidiary is PPL Capital Funding.
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(PPL and PPL Electric)
PPL Electric's principal business is the transmission and distribution of electricity to serve retail customers in its franchised territory in eastern and central Pennsylvania and the regulated supply of electricity to retail customers in that territory as a PLR.
(PPL, LG&E and KU)
LG&E and KU are engaged in the generation, transmission, distribution and sale of electricity. LG&E also engages in the distribution and sale of natural gas. LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name.
(All Registrants)
The financial statements of the Registrants include each company's own accounts as well as the accounts of all entities in which the company has a controlling financial interest. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for Variable Interest Entities (VIEs). The Registrants consolidate a VIE when they are determined to have a controlling interest in the VIE and, as a result, are the primary beneficiary of the entity. Amounts consolidated under the VIE guidance are not material to the Registrants.
All significant intercompany transactions have been eliminated.
The financial statements of PPL, LG&E and KU include their share of any undivided interests in jointly owned facilities, as well as their share of the related operating costs of those facilities. See Note 11 for additional information.
Regulation
(All Registrants)
PPL Electric, RIE, LG&E and KU are cost-based rate-regulated utilities for which rates are set by regulators to enable PPL Electric, RIE, LG&E and KU to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. Base rates are generally established based on a future test period. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by GAAP and reflect the effects of regulatory actions. Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover expected future costs, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC or the applicable state regulatory commissions. See Note 7 for additional details regarding regulatory matters.
Accounting Records
The system of accounts for regulated entities is maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the applicable state regulatory commissions.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Loss Accruals
Potential losses are accrued when (1) information is available that indicates it is "probable" that a loss has been incurred, given the likelihood of uncertain future events and (2) the amount of loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur."
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The Registrants continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss accruals for environmental remediation are discounted when appropriate.
The accrual of contingencies that might result in gains is not recorded, unless realization is assured.
Earnings Per Share (PPL)
EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareowners. Share-based payment awards that provide recipients a non-forfeitable right to dividends or dividend equivalents are considered participating securities. The if-converted method, which assumes the securities were converted to common stock at the start of the period (or issuance), is used to determine the dilutive effects of convertible securities.
Price Risk Management
(All Registrants)
Interest rate contracts are used to hedge exposure to changes in the fair value of debt instruments and to hedge exposure to variability in expected cash flows associated with existing floating-rate debt instruments or forecasted fixed-rate issuances of debt. Derivative instruments pursuant to regulator approved plans to manage commodity price risk associated with natural gas purchases to reduce fluctuations in natural gas prices and costs associated with these derivatives instruments are generally recoverable through approved cost recovery mechanism. Similar derivatives may receive different accounting treatment, depending on management's intended use and documentation.
Certain contracts may not meet the definition of a derivative because they lack a notional amount or a net settlement provision. In cases where there is no net settlement provision, markets are periodically assessed to determine whether market mechanisms have evolved to facilitate net settlement. Certain derivative contracts may be excluded from the requirements of derivative accounting treatment because NPNS has been elected. These contracts are accounted for using accrual accounting. Contracts that have been classified as derivative contracts are reflected on the balance sheets at fair value.
Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing activities on the Statements of Cash Flows, depending on the classification of the hedged items.
PPL and its subsidiaries have elected not to offset net derivative positions against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
Derivative transactions may be marked to fair value through regulatory assets/liabilities at PPL Electric, RIE, LG&E and KU, if approved by the appropriate regulatory body. These transactions generally include the effect of interest rate swaps or commodity gas contracts that are included in customer rates.
See Notes 15 and 16 for additional information on derivatives.
(PPL and PPL Electric)
To meet their obligations as last resort providers of electricity supply to their customers, PPL Electric and RIE have entered into certain contracts that meet the definition of a derivative. However, NPNS has been elected for these contracts.
Revenue
(All Registrants)
Operating revenues are primarily recorded based on energy deliveries through the end of each calendar month. Unbilled retail revenues result because customers' bills are rendered throughout the month, rather than at the end of the month. For RIE, LG&E and KU, unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh or Mcf by the estimated average price per kWh or Mcf. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. For PPL Electric, unbilled revenues for a month are calculated by multiplying the actual unbilled volumes by the applicable tariff price.
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PPL Electric's, RIE's, LG&E's and KU's base rates are determined based on cost of service. Some regulators have also authorized the use of additional alternative revenue programs, which enable PPL Electric, RIE, LG&E and KU to adjust future rates based on past activities or completed events. Revenues from alternative revenue programs are recognized when the specific events permitting future billings have occurred. Revenues from alternative revenue programs are required to be presented separately from revenues from contracts with customers. These amounts are, however, presented as revenues from contracts with customers, with an offsetting adjustment to alternative revenue program revenue, when they are billed to customers in future periods. See Note 3 for additional information.
Financing and Other Receivables
(All Registrants)
Accounts receivable are reported on the Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Financing receivables include accounts receivable, with the exception of those items within accounts receivable that are not subject to the current expected credit loss model.
Financing receivable collectability is evaluated using a current expected credit loss model, consisting of a combination of factors, including past due status based on contractual terms, trends in write-offs and the age of the receivable. Specific events, such as bankruptcies, are also considered when applicable. The Registrants also evaluate the impact of observable external factors on the collectability of the financing receivables to determine if adjustments to the allowance for doubtful accounts should be made based on current conditions or reasonable and supportable forecasts. Adjustments to the allowance for doubtful accounts are made based on the results of these analyses. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
PPL Electric, RIE, LG&E and KU have identified one class of financing receivables, "accounts receivable - customer", which includes financing receivables for all billed and unbilled sales with customers. All other financing receivables are classified as other.
The changes in the allowance for doubtful accounts are included in the following table. Amounts relate to financing receivables, except as noted.

|  |  | Additions |  |  |  |  |
| Balance at Beginning of Period |  | Charged to Income |  | Deductions (a) |  | Balance at End of Period |
PPL |  |  |  |  |  |  |  |
2025 | $ | 154 |  |  | $ | 84 |  |  | $ | 98 |  |  | $ | 140 |  | (b)
2024 | 130 |  |  | 109 |  |  | 85 |  |  | 154 |  | (b)
2023 | 95 |  |  | 87 |  |  | 52 |  |  | 130 |  | (b)
PPL Electric |  |  |  |  |  |  |  |
2025 | $ | 41 |  |  | $ | 33 |  |  | $ | 35 |  |  | $ | 39 |  | (c)
2024 | 50 |  |  | 56 |  |  | 65 |  |  | 41 |  | (c)
2023 | 33 |  |  | 52 |  |  | 35 |  |  | 50 |  | (c)
LG&E |  |  |  |  |  |  |  |
2025 | $ | 3 |  |  | $ | 4 |  |  | $ | 2 |  |  | $ | 5 |  |
2024 | 6 |  |  | 4 |  |  | 7 |  |  | 3 |  |
2023 | 4 |  |  | 4 |  |  | 2 |  |  | 6 |  |
KU |  |  |  |  |  |  |  |
2025 | $ | 2 |  |  | $ | 5 |  |  | $ | 3 |  |  | $ | 4 |  |
2024 | 2 |  |  | 4 |  |  | 4 |  |  | 2 |  |
2023 | 3 |  |  | 3 |  |  | 4 |  |  | 2 |  |

(a)Primarily related to uncollectible accounts written off.
(b)Includes $43 million, $39 million and $41 million related to other accounts receivable at December 31, 2025, 2024 and 2023.
(c)Includes $2 million, $2 million and $3 million related to other accounts receivable at December 31, 2025, 2024 and 2023.
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Cash
(All Registrants)
Cash Equivalents
All highly liquid investments with original maturities of three months or less are considered to be cash equivalents.
(PPL, LG&E and KU)
Restricted Cash and Cash Equivalents
Bank deposits and other cash equivalents that are restricted by agreement or that have been clearly designated for a specific purpose are classified as restricted cash and cash equivalents. On the Balance Sheets, the current portion of restricted cash and cash equivalents is included in "Other current assets," while the noncurrent portion is included in "Other noncurrent assets." See Note 15 for a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the Balance Sheets to the amounts shown on the Statements of Cash Flows.
(All Registrants)
Fair Value Measurements
The Registrants value certain financial and non-financial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to price risk management assets and liabilities, investments in securities in defined benefit plans, and cash and cash equivalents. PPL and its subsidiaries use, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.
The Registrants classify fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:
•Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
•Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability.
•Level 3 - unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value.
Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, the Registrants' assessment of the significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy.
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Investments
Generally, the original maturity date of an investment and management's intent and ability to sell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for other than current operations or are clearly designated for expenditure in the acquisition or construction of noncurrent assets or for the liquidation of long-term debts, are classified as long-term.
Investments in entities in which a company has the ability to exercise significant influence but does not have a controlling financial interest are accounted for under the equity method. All other investments are carried at cost or fair value. These investments are included in "Other noncurrent assets" on the Balance Sheets. Earnings from these investments are recorded in "Other Income (Expense) - net" on the Statements of Income.
Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and less than a year, as well as investments with original maturities of greater than a year that management has the ability and intent to sell within a year, are included in "Other current assets" on the Balance Sheets.
Long-Lived and Intangible Assets
Property, Plant and Equipment
PP&E is recorded at original cost, unless impaired. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. PP&E acquired in business combinations is recorded at fair value at the time of acquisition. Original cost for constructed assets includes material, labor, contractor costs, certain overheads and financing costs, where applicable. Included in PP&E are capitalized costs of software projects that were developed or obtained for internal use. The cost of repairs and minor replacements are charged to expense as incurred. The Registrants record costs associated with planned major maintenance projects in the period in which work is performed and costs are incurred.
AFUDC is capitalized at PPL Electric and RIE as part of the construction costs for cost-based rate-regulated projects for which a return on such costs is recovered after the project is placed in service. AFUDC is capitalized at LG&E and KU for certain projects as part of the construction cost of approved projects. LG&E and KU are generally provided a return on construction work in progress for other projects. The debt component of AFUDC is credited to "Interest Expense" and the equity component is credited to "Other Income (Expense) - net" on the Statements of Income.
The Registrants capitalize interest costs as part of construction costs. Capitalized interest, including the debt component of AFUDC, for the years ended December 31 is as follows:

| 2025 |  | 2024 |  | 2023
PPL | $ | 32 |  |  | $ | 20 |  |  | $ | 12 |
PPL Electric | 13 |  |  | 9 |  |  | 7 |
LG&E | 6 |  |  | 3 |  |  | 1 |
KU | 8 |  |  | 4 |  |  | 1 |

Depreciation
Depreciation is recorded over the estimated useful lives of property using various methods including the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant portion of an operating unit that was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income, unless otherwise required by regulators. RIE, LG&E and KU accrue costs of removal net of estimated salvage value through depreciation, which is included in the calculation of customer rates over the assets' depreciable lives in accordance with regulatory practices. Cost of removal amounts accrued through depreciation rates are accumulated as a regulatory liability until the removal costs are incurred. For LG&E and KU, all ARO depreciation expenses are reclassified to a regulatory asset or regulatory liability. See "Asset Retirement Obligations" below and Note 7 for additional information. PPL Electric records net costs of removal when incurred as a regulatory asset. The regulatory asset is subsequently amortized through depreciation over a five-year period, which is recoverable in customer rates in accordance with regulatory practices.
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Following are the weighted-average annual rates of depreciation, for regulated utility plant, for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL | 3.06 | % |  | 3.20 | % |  | 3.26 | %
PPL Electric | 2.46 | % |  | 2.52 | % |  | 2.62 | %
LG&E | 3.69 | % |  | 4.02 | % |  | 4.00 | %
KU | 3.68 | % |  | 3.86 | % |  | 3.95 | %

Goodwill and Other Intangible Assets
Goodwill represents the excess of the purchase price paid over the fair value of the identifiable net assets acquired in a business combination.
Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed or otherwise used. Costs incurred to obtain, renew or extend terms of an intangible asset are capitalized.
When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, PPL and its subsidiaries consider:
•the expected use of the asset;
•the expected useful life of other assets to which the useful life of the intangible asset may relate;
•legal, regulatory, or contractual provisions that may limit the useful life;
•the company's historical experience as evidence of its ability to support renewal or extension;
•the effects of obsolescence, demand, competition, and other economic factors; and,
•the level of maintenance expenditures required to obtain the expected future cash flows from the asset.
Asset Impairment (Excluding Investments)
The Registrants review long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or circumstances indicate carrying amounts may not be recoverable.
A long-lived asset classified as held and used is impaired when the carrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value.
A long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell.
PPL, LG&E and KU review goodwill for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the reporting unit's fair value. Additionally, goodwill must be tested for impairment in circumstances when a portion of goodwill has been allocated to a business to be disposed. PPL's, LG&E's and KU's reporting units are primarily at the operating segment level.
PPL, for its reporting units, and individually, LG&E and KU, may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a quantitative test. If the qualitative evaluation (referred to as step zero) is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the quantitative impairment test is not necessary. However, the quantitative impairment test is required if management concludes it is more likely than not that the fair value of a reporting unit is less than the carrying amount based on the step zero assessment. If the carrying amount of the reporting unit, including goodwill, exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit.
As of October 1, 2025, PPL, for its reporting units, and individually, LG&E and KU, elected to perform the qualitative step zero evaluation of goodwill. These evaluations considered the excess of fair value over the carrying value of each reporting unit that was calculated during step one of the quantitative impairment tests performed in the fourth quarter of 2022, and the relevant events and circumstances that occurred since those tests were performed including:
•current year financial performance versus the prior year,
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•changes in planned capital expenditures,
•the consistency of forecasted free cash flows,
•earnings quality and sustainability,
•changes in market participant discount rates,
•changes in long-term growth rates,
•changes in PPL's market capitalization, and
•the overall economic and regulatory environments in which these regulated entities operate.
Based on these evaluations, management concluded it was not more likely than not that the fair value of these reporting units was less than their carrying value. As such, the step one quantitative impairment test was not performed and no impairment was recognized.
(PPL, LG&E and KU)
Asset Retirement Obligations
PPL and its subsidiaries record liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and offset with an increase in the value of the capitalized asset, which is depreciated over the asset's useful life. Until the obligation is settled, the liability is increased through the recognition of accretion expense classified within "Other operation and maintenance" on the Statements of Income to reflect changes in the obligation due to the passage of time. For LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal.
Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset. See Note 7 and Note 18 for additional information on AROs.
Compensation and Benefits
Defined Benefits (All Registrants)
Certain PPL subsidiaries sponsor various defined benefit pension and other postretirement plans. An asset or liability is recorded to recognize the funded status of all defined benefit plans with an offsetting entry to AOCI or, for PPL Electric, LG&E, KU and RIE, to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.
The expected return on plan assets is determined based on a market-related value of plan assets, which is calculated by rolling forward the prior year market-related value with contributions, disbursements and long-term expected return on investments. One-fifth of the difference between the actual value and the expected value is added (or subtracted if negative) to the expected value to determine the new market-related value.
PPL and its subsidiaries, excluding RIE, use an accelerated amortization method for the recognition of gains and losses for its defined benefit pension plans. Under the accelerated method, actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the required amortization period. Actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the full required amortization period. RIE uses the standard amortization method under GAAP for recognition of gains and losses for its defined benefit pension plan.
See Note 7 for a discussion of the regulatory treatment of defined benefit costs and Note 10 for a discussion of defined benefits.
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Stock-Based Compensation (PPL)
PPL has several stock-based compensation plans for purposes of granting stock options, restricted stock, restricted stock units and performance units to certain employees as well as stock units and restricted stock units to directors. PPL grants most stock-based compensation awards in the first quarter of each year. PPL recognizes compensation expense for stock-based compensation awards based on the fair value method. Forfeitures of awards are recognized when they occur. All awards are recorded as equity or a liability on the Balance Sheets. Stock-based compensation expense is primarily included in "Other operation and maintenance" on the Statements of Income.
Taxes
Income Taxes
(All Registrants)
PPL and its subsidiaries file a consolidated U.S. federal income tax return.
Significant management judgment is required in developing the Registrants' provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken on tax returns and valuation allowances on deferred tax assets.
The Registrants use a two-step process to evaluate uncertain tax positions. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in its financial statements the amount of the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization upon settlement that exceeds 50%. Unrecognized tax benefits are classified as current to the extent management expects to settle the uncertain tax position by payment or receipt of cash within one year of the reporting date. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements of the Registrants in future periods. At December 31, 2025, no significant changes in unrecognized tax benefits were projected over the next 12 months.
Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, as well as the tax effects of net operating losses and tax credit carryforwards.
The Registrants record valuation allowances to reduce deferred income tax assets to the amounts that are more-likely-than-not to be realized. The need for valuation allowances requires significant management judgment. If the Registrants determine that they are able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made. Likewise, if the Registrants determine that they are not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.
The Registrants defer investment tax credits when the credits are generated and amortize the deferred amounts over the average lives of the related assets. With respect to acquired renewable tax credits, pursuant to the IRA, any benefit is recognized in the period the credits can be utilized.
The Registrants recognize tax-related interest and penalties in "Income Taxes" on their Statements of Income.
The Registrants use the portfolio approach method of accounting for deferred taxes related to pre-tax OCI transactions. The portfolio approach involves a strict period-by-period cumulative incremental allocation of income taxes to the change in income and losses reflected in OCI. Under this approach, the net cumulative tax effect is ignored. The net change in unrealized gains and losses recorded in AOCI under this approach would be eliminated only on the date the investment portfolio is classified as held for sale or is liquidated.
See Note 6 for income tax disclosures.
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The provision for the Registrants' deferred income taxes related to regulatory assets and liabilities is based upon the ratemaking principles reflected in rates established by relevant regulators. The difference in the provision for deferred income taxes for regulatory assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included on the Balance Sheets in noncurrent "Regulatory assets" or "Regulatory liabilities."
(PPL Electric, LG&E and KU)
The income tax provision for PPL Electric, LG&E and KU is calculated in accordance with an intercompany tax sharing agreement, which provides that taxable income be calculated as if PPL Electric, LG&E, KU and any subsidiaries each filed a separate return. Tax benefits are not shared between companies. The entity that generates a tax benefit is the entity that is entitled to the tax benefit. The effect of PPL filing a consolidated tax return is taken into account in the settlement of current taxes and the recognition of deferred taxes.
At December 31, the following intercompany tax payables were recorded:

| 2025 |  | 2024
PPL Electric | $ | (27) |  |  | $ | (2) |
LG&E | (7) |  |  | (2) |
KU | (10) |  |  | (5) |

Taxes, Other Than Income (All Registrants)
The Registrants present sales taxes in "Other current liabilities" on the Balance Sheets. These taxes are not reflected on the Statements of Income. See Note 6 for details of taxes included in "Taxes, other than income" on the Statements of Income.
Other
(All Registrants)
Fuel, Materials and Supplies
Fuel, natural gas stored underground and materials and supplies are valued using the average cost method. Fuel costs for electricity generation are charged to expense as used. For RIE, natural gas supply costs are charged to expense when delivered to customers. For LG&E, natural gas supply costs are charged to expense as delivered to the distribution system. See Note 7 for further discussion of the gas supply clause.
"Fuel, materials and supplies" on the Balance Sheets consisted of the following at December 31:

| 2025
| PPL |  | PPL Electric |  | LG&E |  | KU
Fuel | $ | 157 |  |  | $ | — |  |  | $ | 58 |  |  | $ | 99 |
Natural gas stored underground | 50 |  |  | — |  |  | 33 |  |  | — |
Materials and supplies | 344 |  |  | 151 |  |  | 69 |  |  | 84 |
Total | $ | 551 |  |  | $ | 151 |  |  | $ | 160 |  |  | $ | 183 |

| 2024
| PPL |  | PPL Electric |  | LG&E |  | KU
Fuel | $ | 153 |  |  | $ | — |  |  | $ | 64 |  |  | $ | 89 |
Natural gas stored underground | 49 |  |  | — |  |  | 29 |  |  | — |
Materials and supplies | 309 |  |  | 104 |  |  | 64 |  |  | 84 |
Total | $ | 511 |  |  | $ | 104 |  |  | $ | 157 |  |  | $ | 173 |

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(PPL and PPL Electric)
Renewable Energy Standard Obligation
Purchased Renewable Energy Certificates (RECs) are stated at cost and are used to measure compliance with state renewable energy standards. RECs support new renewable generation standards and are held primarily to be utilized in fulfillment of RIE's and PPL Electric's compliance obligations.
(All Registrants)
Guarantees
Generally, the initial measurement of a guarantee liability is the fair value of the guarantee at its inception. However, there are certain guarantees excluded from the scope of accounting guidance and other guarantees that are not subject to the initial recognition and measurement provisions of accounting guidance that only require disclosure. See Note 12 for further discussion of guarantees.
New Accounting Guidance Adopted (All Registrants)
Improvements to Income Tax Disclosures
Effective December 31, 2025, the Registrants retrospectively adopted accounting guidance to improve income tax disclosures. The guidance requires enhanced disclosures about disaggregated rate reconciliation in eight specific categories, presented in both percentages and currency amounts. Further disaggregation by jurisdiction or nature of the item, or both, is required if over a 5% threshold. The utility industry has specific tax rate impacts due to federal and state rate-making requirements, which frequently exceed the 5% threshold. Accordingly, a ninth category is used to disaggregate the utility rate-making tax adjustments. The guidance also requires disclosure of the amount of income taxes paid disaggregated by federal, state, and foreign. See Note 6 for additional information.
2. Segment and Related Information
(PPL)
PPL is organized into three segments, broken down by geographic location: Kentucky Regulated, Pennsylvania Regulated, and Rhode Island Regulated.
The Kentucky Regulated segment consists primarily of the regulated electricity generation, transmission and distribution operations conducted by LG&E and KU, as well as LG&E's regulated distribution and sale of natural gas.
The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric.
The Rhode Island Regulated segment includes the regulated electricity transmission and distribution and natural gas distribution operations of RIE.
"Corporate and Other" primarily includes corporate level financing costs, certain unallocated corporate costs, and certain non-recoverable costs incurred in conjunction with the acquisition of RIE. "Corporate and Other" is presented to reconcile segment information to PPL's consolidated results and is not a reportable segment.
PPL's Chief Operating Decision Maker (CODM) is the CLC. The CLC uses financial metrics including segment net income, earnings from ongoing operations, earnings per share and return on equity, as well as various operational metrics to assess segment performance and make investment and resource decisions. Segment net income is the measure of segment profit or loss that most closely aligns with GAAP and is being presented for disclosure purposes.
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The tables below provide information about PPL's segments and include a reconciliation of segment net income to consolidated net income for the year ended December 31, 2025:

| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total
Operating Revenues from external customers (a) | $ | 3,760 |  |  | $ | 3,113 |  |  | $ | 2,168 |  |  | $ | 9,041 |
Reconciliation of revenue |  |  |  |  |  |  |
Corporate and other revenues |  |  |  |  |  |  | 1 |
Total consolidated revenues |  |  |  |  |  |  | $ | 9,042 |
Less: |  |  |  |  |  |  |
Fuel | 855 |  |  | — |  |  | — |  |  | 855 |
Energy Purchases | 214 |  |  | 876 |  |  | 802 |  |  | 1,892 |
Operation and maintenance | 818 |  |  | 630 |  |  | 851 |  |  | 2,299 |
Depreciation | 717 |  |  | 413 |  |  | 177 |  |  | 1,307 |
Taxes, other than income | 102 |  |  | 151 |  |  | 170 |  |  | 423 |
Other (income) expense - net | (53) |  |  | (48) |  |  | (33) |  |  | (134) |
Interest (income) from affiliate | — |  |  | (9) |  |  | (3) |  |  | (12) |
Interest expense | 264 |  |  | 257 |  |  | 111 |  |  | 632 |
Income taxes | 169 |  |  | 204 |  |  | 8 |  |  | 381 |
Segment net income | $ | 674 |  |  | $ | 639 |  |  | $ | 85 |  |  | $ | 1,398 |
Reconciliation of segment profit or loss to consolidated net income |  |  |  |  |  |  |
Corporate and other net loss |  |  |  |  |  |  | (217) |
Net Income |  |  |  |  |  |  | $ | 1,181 |

(a)See Note 1 and Note 3 for additional information on Operating Revenues.
Other information for the segments and reconciliation to PPL's Consolidated results for the year ended December 31, 2025 are as follows:

| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total Segments |  | Corporate and Other |  | Consolidated Total
Other Segment Disclosures |  |  |  |  |  |  |  |  |  |  |
Amortization (a) | $ | 43 |  |  | $ | 48 |  |  | $ | 1 |  |  | $ | 92 |  |  | $ | 12 |  |  | $ | 104 |
Deferred income taxes and investment tax credits (b) | (9) |  |  | 24 |  |  | 28 |  |  | 43 |  |  | 149 |  |  | 192 |
Expenditures for long lived assets | 1,752 |  |  | 1,620 |  |  | 668 |  |  | 4,040 |  |  | 2 |  |  | 4,042 |

(a)Represents non-cash expense items that include amortization of operating lease right-of-use assets, regulatory assets and liabilities, debt discounts and premiums and debt issuance costs.
(b)Represents a non-cash expense item that is also included in "Income Taxes."
The tables below provide information about PPL's segments and include a reconciliation of segment net income to consolidated net income for the year ended December 31, 2024:

| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total
Operating Revenues from external customers (a) | $ | 3,562 |  |  | $ | 2,876 |  |  | $ | 2,024 |  |  | $ | 8,462 |
Reconciliation of revenue |  |  |  |  |  |  |
Corporate and other revenues |  |  |  |  |  |  | — |
Total consolidated revenues |  |  |  |  |  |  | $ | 8,462 |

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| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total
Less: |  |  |  |  |  |  |
Fuel | 783 |  |  | — |  |  | — |  |  | 783 |
Energy Purchases | 176 |  |  | 721 |  |  | 782 |  |  | 1,679 |
Operation and maintenance | 803 |  |  | 705 |  |  | 731 |  |  | 2,239 |
Depreciation | 710 |  |  | 401 |  |  | 165 |  |  | 1,276 |
Taxes, other than income | 99 |  |  | 131 |  |  | 144 |  |  | 374 |
Other (income) expense - net | (29) |  |  | (45) |  |  | (20) |  |  | (94) |
Interest (income) from affiliate | — |  |  | (33) |  |  | (4) |  |  | (37) |
Interest expense | 240 |  |  | 246 |  |  | 95 |  |  | 581 |
Income taxes | 160 |  |  | 176 |  |  | 22 |  |  | 358 |
Segment net income | $ | 620 |  |  | $ | 574 |  |  | $ | 109 |  |  | $ | 1,303 |
Reconciliation of segment profit or loss to consolidated net income |  |  |  |  |  |  |
Corporate and other net loss |  |  |  |  |  |  | (415) |
Net Income |  |  |  |  |  |  | $ | 888 |

(a)See Note 1 and Note 3 for additional information on Operating Revenues.
Other information for the segments and reconciliation to PPL's Consolidated results for the year ended December 31, 2024 are as follows:

| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total Segments |  | Corporate and Other |  | Consolidated Total
Other Segment Disclosures |  |  |  |  |  |  |  |  |  |  |
Amortization (a) | $ | 24 |  |  | $ | 45 |  |  | $ | 1 |  |  | $ | 70 |  |  | $ | 8 |  |  | $ | 78 |
Deferred income taxes and investment tax credits (b) | 2 |  |  | 129 |  |  | 38 |  |  | 169 |  |  | 27 |  |  | 196 |
Expenditures for long lived assets | 1,088 |  |  | 1,229 |  |  | 495 |  |  | 2,812 |  |  | (7) |  |  | 2,805 |

(a)Represents non-cash expense items that include amortization of operating lease right-of-use assets, regulatory assets and liabilities, debt discounts and premiums and debt issuance costs.
(b)Represents a non-cash expense item that is also included in "Income Taxes."
The tables below provide information about PPL's segments and include a reconciliation of segment net income to consolidated net income for the year ended December 31, 2023:

| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total
Operating Revenues from external customers (a) | $ | 3,452 |  |  | $ | 3,008 |  |  | $ | 1,851 |  |  | $ | 8,311 |
Reconciliation of revenue |  |  |  |  |  |  |
Corporate and other revenues |  |  |  |  |  |  | 1 |
Total consolidated revenues |  |  |  |  |  |  | $ | 8,312 |
Less: |  |  |  |  |  |  |
Fuel | 733 |  |  | — |  |  | — |  |  | 733 |
Energy Purchases | 192 |  |  | 992 |  |  | 658 |  |  | 1,842 |
Operation and maintenance | 826 |  |  | 605 |  |  | 705 |  |  | 2,136 |
Depreciation | 696 |  |  | 397 |  |  | 156 |  |  | 1,249 |
Taxes, other than income | 93 |  |  | 143 |  |  | 156 |  |  | 392 |
Other (income) expense - net | (12) |  |  | (39) |  |  | (19) |  |  | (70) |
Interest expense | 235 |  |  | 223 |  |  | 83 |  |  | 541 |
Income taxes | 137 |  |  | 168 |  |  | 16 |  |  | 321 |
Segment net income | $ | 552 |  |  | $ | 519 |  |  | $ | 96 |  |  | $ | 1,167 |
Reconciliation of segment profit or loss to consolidated net income |  |  |  |  |  |  |
Corporate and other net loss |  |  |  |  |  |  | (427) |
Net Income |  |  |  |  |  |  | $ | 740 |

(a)See Note 1 and Note 3 for additional information on Operating Revenues.
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Other information for the segments and reconciliation to PPL's Consolidated results for the year ended December 31, 2023 are as follows:

| Kentucky Regulated |  | Pennsylvania Regulated |  | Rhode Island Regulated |  | Total Segments |  | Corporate and Other |  | Consolidated Total
Other Segment Disclosures |  |  |  |  |  |  |  |  |  |  |
Amortization (a) | $ | 33 |  |  | $ | 41 |  |  | $ | 1 |  |  | $ | 75 |  |  | $ | 6 |  |  | $ | 81 |
Deferred income taxes and investment tax credits (b) | (17) |  |  | 46 |  |  | 48 |  |  | 77 |  |  | 245 |  |  | 322 |
Expenditures for long lived assets | 950 |  |  | 956 |  |  | 454 |  |  | 2,360 |  |  | 30 |  |  | 2,390 |

(a)Represents non-cash expense items that include amortization of operating lease right-of-use assets, regulatory assets and liabilities, debt discounts and premiums and debt issuance costs.
(b)Represents a non-cash expense item that is also included in "Income Taxes."
The following provides Balance Sheet data for the segments and reconciliation to PPL's consolidated results as of:

| As of December 31,
| 2025 |  | 2024
Total Assets |  |  |
Kentucky Regulated | $ | 19,060 |  |  | $ | 17,626 |
Pennsylvania Regulated | 16,886 |  |  | 15,475 |
Rhode Island Regulated | 7,510 |  |  | 7,055 |
Corporate and Other (a) | 1,788 |  |  | 913 |
Total | $ | 45,244 |  |  | $ | 41,069 |

(a)Primarily consists of unallocated items, including cash, PP&E, goodwill, and the elimination of inter-segment transactions.
(PPL Electric)
PPL Electric has two operating segments, distribution and transmission, which are aggregated into a single reportable segment. PPL Electric's CODM is the President of PPL Electric.
The President uses financial metrics including segment net income, earnings from ongoing operations, earnings per share and return on equity, as well as various operational metrics to assess segment performance and make investment and resource decisions.
The significant segment expenses of and measure of profit and loss for PPL Electric regularly provided to the President are included on the face of PPL Electric's Statements of Income.
The measure of segment assets is reported on PPL Electric's Balance Sheets as total consolidated assets. The measures of significant non-cash segment expenses as well as expenditures for long lived assets are reported on PPL Electric's Statements of Cash Flows.
(LG&E and KU)
Each of LG&E and KU operates as a single operating and reportable segment, and the CODM for each of LG&E and KU is its President.
The President manages LG&E and KU as a single consolidated entity. Financial metrics including net income, earnings from ongoing operations, earnings per share and return on equity, as well as various operational metrics are used to assess segment performance and make investment and resource decisions.
The significant segment expenses of and measure of profit and loss for each of LG&E and KU regularly provided to its President are included on the face of the Statements of Income of LG&E and KU.
The measures of segment assets are reported on the Balance Sheets of LG&E and KU as total assets. The measures of significant non-cash segment expenses as well as expenditures for long lived assets are reported on the Statements of Cash Flows of LG&E and KU.
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3. Revenue from Contracts with Customers
(All Registrants)
The following is a description of the principal activities from which the Registrants and PPL's segments generate their revenues.
(PPL and PPL Electric)
Pennsylvania Regulated Segment Revenue
The Pennsylvania Regulated segment generates substantially all of its revenues from contracts with customers from PPL Electric's tariff-based distribution and transmission of electricity.
Distribution Revenue
PPL Electric provides distribution services to residential, commercial, industrial, municipal and governmental end users of energy. PPL Electric satisfies its performance obligation to its distribution customers and revenue is recognized over time as electricity is delivered and simultaneously consumed by the customer. The amount of revenue recognized is the volume of electricity delivered during the period multiplied by the price per tariff, plus a monthly fixed charge and include unbilled amounts, which represent the amounts due from customers as a result of customer's bills being rendered throughout the month, rather than at the end of the month. This method of recognition fairly presents PPL Electric's transfer of electric service to the customer as the calculation is based on volumes delivered, and the price per tariff and the monthly fixed charge are set by the PAPUC. Customers are typically billed monthly and outstanding amounts are normally due within 21 days of the date of the bill.
Distribution customers are "at will" customers of PPL Electric with no term contract and no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with PPL Electric's retail account contracts.
Certain customers have the option to obtain electricity from other suppliers where PPL Electric facilitates the delivery. In those circumstances, revenue is only recognized for providing delivery of the commodity to the customer.
Transmission Revenue
PPL Electric generates transmission revenues from a FERC-approved PJM Open Access Transmission Tariff. An annual revenue requirement for PPL Electric to provide transmission services is calculated using a formula-based rate. This revenue requirement is converted into a daily rate (dollars per day). PPL Electric satisfies its performance obligation to provide transmission services and revenue is recognized over time as transmission services are provided and consumed. This method of recognition fairly presents PPL Electric's transfer of transmission services as the daily rate is set by a FERC approved formula-based rate. PJM remits payment on a weekly basis.
PPL Electric's agreement to provide transmission services contains no minimum purchase commitment. The performance obligation is limited to the service requested and received to date. Accordingly, PPL Electric has no unsatisfied performance obligations.
(PPL)
Rhode Island Regulated Segment Revenues
The Rhode Island Regulated segment generates substantially all of its revenues from contracts with customers from RIE's regulated tariff-based transmission and distribution of electricity and regulated tariff-based distribution of natural gas.
Distribution Revenue
Distribution revenues are primarily from the sale of electricity, natural gas, and related services to retail customers. Distribution sales are regulated by the RIPUC, which is responsible for approving the rates and other terms of services as part of the rate making process. Natural gas and electric distribution revenues are derived from the regulated sale and distribution of electricity and natural gas to residential, commercial, and industrial customers within RIE's service territory under the tariff rates. The performance obligation related to distribution sales is to provide electricity and natural gas to customers on demand.
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The performance obligation is satisfied over time because the customer simultaneously receives and consumes the electricity or natural gas as services are provided. RIE records revenues related to the distribution sales based upon the approved tariff rate and the volume delivered to the customers, which corresponds with the amount RIE has the right to invoice. Customers are typically billed monthly and outstanding amounts are normally due within 21 days of date of the bill.
Distribution revenue also includes estimated unbilled amounts, which represent the estimated amounts due from retail customers as a result of customer's bills being rendered throughout the month, rather than at the end of the month. Unbilled revenues are determined based on estimated unbilled sales volumes and then applying tariff rates to those volumes. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. This method of recognition fairly presents RIE's transfer of electricity and natural gas to the customer as the amount recognized is based on actual and estimated volumes delivered and the tariff rate per unit of energy and any applicable fixed charges or regulatory mechanisms as approved by the respective regulatory body.
Distribution customers are "at will" customers of RIE with no term contract and no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with RIE's retail account contracts.
Certain customers have the option to obtain electricity or natural gas from other suppliers where RIE facilitates the delivery. In those circumstances, revenue is only recognized for providing delivery of the commodity to the customer.
Transmission Revenue
RIE's transmission services are regulated by the FERC and coordinated with ISO – New England (ISO-NE). As of January 1, 2023, RIE is a transmission operator. These revenues arise under tariff/rate agreements and are collected primarily from RIE's distribution customers. The revenue is recognized over time as transmission services are provided and consumed. This method of recognition fairly presents RIE's transfer of transmission services as the daily rate is set by a FERC-approved formula-based rate.
RIE's agreement to provide transmission services contains no minimum purchase commitment. The performance obligation is limited to the service requested and received to date. Accordingly, RIE has no unsatisfied performance obligations.
(PPL, LG&E and KU)
Kentucky Regulated Segment Revenue
The Kentucky Regulated Segment generates substantially all of its revenues from contracts with customers from LG&E's and KU's regulated tariff-based sales of electricity and LG&E's regulated tariff-based sales of natural gas.
LG&E and KU are engaged in the generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, Virginia. LG&E also engages in the distribution and sale of natural gas in Kentucky. Revenue from these activities is generated from tariffs approved by applicable regulatory authorities including the FERC, KPSC and VSCC. LG&E and KU satisfy their performance obligations upon LG&E's and KU's delivery of electricity and LG&E's delivery of natural gas to customers. This revenue is recognized over time as the customer simultaneously receives and consumes the benefits provided by LG&E and KU. The amount of revenue recognized is the billed volume of electricity or natural gas delivered multiplied by a tariff rate per-unit of energy, plus any applicable fixed charges or additional regulatory mechanisms. Customers are billed monthly and outstanding amounts are typically due within 22 days of the date of the bill. Additionally, unbilled revenues are recognized as a result of customers' bills being rendered throughout the month, rather than at the end of the month. Unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh or Mcf delivered but not yet billed by the estimated average cents per kWh or Mcf. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. This method of recognition fairly presents LG&E's and KU's transfer of electricity and LG&E's transfer of natural gas to the customer as the amount recognized is based on actual and estimated volumes delivered and the tariff rate per-unit of energy and any applicable fixed charges or regulatory mechanisms as set by the respective regulatory body.
LG&E's and KU's customers generally have no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with these customers.
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(All Registrants)
The following table reconciles "Operating Revenues" included in each Registrant's Statement of Income with revenues generated from contracts with customers for the years ended December 31:

| 2025
| PPL |  | PPL Electric |  | LG&E |  | KU
Operating Revenues (a)(b) | $ | 9,042 |  |  | $ | 3,113 |  |  | $ | 1,748 |  |  | $ | 2,064 |
Revenues derived from: |  |  |  |  |  |  |
Alternative revenue programs (c) | 153 |  |  | 21 |  |  | (2) |  |  | — |
Other (d) | (25) |  |  | (17) |  |  | (4) |  |  | (4) |
Revenues from Contracts with Customers | $ | 9,170 |  |  | $ | 3,117 |  |  | $ | 1,742 |  |  | $ | 2,060 |

| 2024
| PPL |  | PPL Electric |  | LG&E |  | KU
Operating Revenues (a)(b) | $ | 8,462 |  |  | $ | 2,876 |  |  | $ | 1,648 |  |  | $ | 1,964 |
Revenues derived from: |  |  |  |  |  |  |
Alternative revenue programs (c) | 5 |  |  | (19) |  |  | 13 |  |  | 16 |
Other (d) | (23) |  |  | (15) |  |  | (4) |  |  | (4) |
Revenues from Contracts with Customers | $ | 8,444 |  |  | $ | 2,842 |  |  | $ | 1,657 |  |  | $ | 1,976 |

| 2023
| PPL |  | PPL Electric |  | LG&E |  | KU
Operating Revenues (a)(b) | $ | 8,312 |  |  | $ | 3,008 |  |  | $ | 1,613 |  |  | $ | 1,884 |
Revenues derived from: |  |  |  |  |  |  |
Alternative revenue programs (c) | 1 |  |  | 5 |  |  | (1) |  |  | (5) |
Other (d) | (23) |  |  | (15) |  |  | (4) |  |  | (4) |
Revenues from Contracts with Customers | $ | 8,290 |  |  | $ | 2,998 |  |  | $ | 1,608 |  |  | $ | 1,875 |

(a)PPL includes $2,168 million, $2,024 million and $1,851 million for the twelve months ended December 31, 2025, 2024, and 2023 of revenues from external customers reported by the Rhode Island Regulated segment. PPL Electric represents revenues from external customers reported by the Pennsylvania Regulated segment and LG&E and KU, net of intercompany power sales and transmission revenues, represent revenues from external customers reported by the Kentucky Regulated segment. See Note 2 for additional information.
(b)PPL's transition services agreement associated with the RIE acquisition ended in the third quarter of 2024. In conjunction with the completion of the agreement, PPL conformed the presentation of RIE's and the Rhode Island Regulated segment's net metering charges with the presentation of the other segments, resulting in an increase in "Operating Revenues" and a corresponding increase in "Energy purchases" beginning on January 1, 2024. For the year ended December 31, 2023, $146 million of net metering was presented as a reduction of "Operating Revenues" on PPL's Statement of Income.
(c)This line item shows the over/under collection of rate mechanisms deemed alternative revenue programs with over-collections of revenue shown as positive amounts and under collections as negative amounts.
(d)Represents additional revenues outside the scope of revenues from contracts with customers such as leases and other miscellaneous revenues.
The following table shows revenues from contracts with customers disaggregated by customer class for the years ended December 31:

| Residential |  | Commercial |  | Industrial |  | Other (a) |  | Wholesale - municipality |  | Wholesale - other (b) |  | Transmission |  | Revenues from Contracts with Customers
PPL |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PA Regulated | $ | 1,656 |  |  | $ | 448 |  |  | $ | 56 |  |  | $ | 54 |  |  | $ | — |  |  | $ | — |  |  | $ | 903 |  |  | $ | 3,117 |
RI Regulated (c) | 1,249 |  |  | 671 |  |  | 83 |  |  | 86 |  |  | — |  |  | — |  |  | 213 |  |  | 2,302 |
KY Regulated | 1,616 |  |  | 1,063 |  |  | 627 |  |  | 309 |  |  | 25 |  |  | 111 |  |  | — |  |  | 3,751 |
Total PPL | $ | 4,521 |  |  | $ | 2,182 |  |  | $ | 766 |  |  | $ | 449 |  |  | $ | 25 |  |  | $ | 111 |  |  | $ | 1,116 |  |  | $ | 9,170 |

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| Residential |  | Commercial |  | Industrial |  | Other (a) |  | Wholesale - municipality |  | Wholesale - other (b) |  | Transmission |  | Revenues from Contracts with Customers
2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PA Regulated | $ | 1,502 |  |  | $ | 418 |  |  | $ | 47 |  |  | $ | 57 |  |  | $ | — |  |  | $ | — |  |  | $ | 818 |  |  | $ | 2,842 |
RI Regulated (c) | 1,150 |  |  | 593 |  |  | 91 |  |  | 10 |  |  | — |  |  | — |  |  | 176 |  |  | 2,020 |
KY Regulated | 1,510 |  |  | 1,028 |  |  | 635 |  |  | 323 |  |  | 23 |  |  | 63 |  |  | — |  |  | 3,582 |
Total PPL | $ | 4,162 |  |  | $ | 2,039 |  |  | $ | 773 |  |  | $ | 390 |  |  | $ | 23 |  |  | $ | 63 |  |  | $ | 994 |  |  | $ | 8,444 |
2023 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PA Regulated | $ | 1,649 |  |  | $ | 444 |  |  | $ | 55 |  |  | $ | 54 |  |  | $ | — |  |  | $ | — |  |  | $ | 796 |  |  | $ | 2,998 |
RI Regulated | 640 |  |  | 228 |  |  | 20 |  |  | 793 |  |  | — |  |  | — |  |  | 170 |  |  | 1,851 |
KY Regulated | 1,458 |  |  | 1,001 |  |  | 637 |  |  | 272 |  |  | 22 |  |  | 50 |  |  | — |  |  | 3,440 |
Corp and Other | — |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  | — |  |  | — |  |  | 1 |
Total PPL | $ | 3,747 |  |  | $ | 1,673 |  |  | $ | 712 |  |  | $ | 1,120 |  |  | $ | 22 |  |  | $ | 50 |  |  | $ | 966 |  |  | $ | 8,290 |
PPL Electric |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2025 | $ | 1,656 |  |  | $ | 448 |  |  | $ | 56 |  |  | $ | 54 |  |  | $ | — |  |  | $ | — |  |  | $ | 903 |  |  | $ | 3,117 |
2024 | $ | 1,502 |  |  | $ | 418 |  |  | $ | 47 |  |  | $ | 57 |  |  | $ | — |  |  | $ | — |  |  | $ | 818 |  |  | $ | 2,842 |
2023 | $ | 1,649 |  |  | $ | 444 |  |  | $ | 55 |  |  | $ | 54 |  |  | $ | — |  |  | $ | — |  |  | $ | 796 |  |  | $ | 2,998 |
LG&E |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2025 | $ | 809 |  |  | $ | 540 |  |  | $ | 187 |  |  | $ | 139 |  |  | $ | — |  |  | $ | 67 |  |  | $ | — |  |  | $ | 1,742 |
2024 | $ | 754 |  |  | $ | 518 |  |  | $ | 188 |  |  | $ | 147 |  |  | $ | — |  |  | $ | 50 |  |  | $ | — |  |  | $ | 1,657 |
2023 | $ | 751 |  |  | $ | 517 |  |  | $ | 189 |  |  | $ | 104 |  |  | $ | — |  |  | $ | 47 |  |  | $ | — |  |  | $ | 1,608 |
KU |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2025 | $ | 807 |  |  | $ | 523 |  |  | $ | 440 |  |  | $ | 169 |  |  | $ | 25 |  |  | $ | 96 |  |  | $ | — |  |  | $ | 2,060 |
2024 | $ | 756 |  |  | $ | 510 |  |  | $ | 447 |  |  | $ | 176 |  |  | $ | 23 |  |  | $ | 64 |  |  | $ | — |  |  | $ | 1,976 |
2023 | $ | 707 |  |  | $ | 484 |  |  | $ | 448 |  |  | $ | 168 |  |  | $ | 22 |  |  | $ | 46 |  |  | $ | — |  |  | $ | 1,875 |

(a)Primarily includes revenues from pole attachments, street lighting, other public authorities and other non-core businesses. For the years ended December 31, 2023, the Rhode Island Regulated segment primarily includes open access tariff revenues, which are calculated on combined customer classes.
(b)Includes wholesale power and transmission revenues. LG&E and KU amounts include intercompany power sales and transmission revenues, which are eliminated upon consolidation at PPL.
(c)PPL's transition services agreement associated with the RIE acquisition ended in the third quarter of 2024. In conjunction with the completion of the agreement, PPL disaggregated the 2024 revenues of the Rhode Island Regulated segment in a manner consistent with that of its other segments. This resulted in certain customer revenues for the Rhode Island Regulated segment, which were previously presented in the "Other" category, being presented in the "Residential", "Commercial" or "Industrial" customer classes beginning on January 1, 2024. Applying the previous methodology to 2025 revenues would result in $534 million of Residential, $409 million of Commercial and $83 million of Industrial for the Rhode Island Regulated segment being presented as "Other" for the year ended December 31, 2025. Applying the previous methodology to 2024 revenues would result in $469 million of Residential, $372 million of Commercial and $88 million of Industrial for the Rhode Island Regulated segment being presented as "Other" for the year ended December 31, 2024.
As discussed in Note 2, PPL segments its business by geographic location. Revenues from external customers for each segment/geographic location are reconciled to revenues from contracts with customers in the footnotes to the tables above. PPL Electric's revenues from contracts with customers are further disaggregated by distribution and transmission as indicated in the above tables.
Contract receivables from customers are primarily included in "Accounts receivable - Customer" and "Unbilled revenues" on the Balance Sheets.
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The following table shows the accounts receivable and unbilled revenues balances that were impaired for the year ended December 31:

| 2025 |  | 2024 |  | 2023
PPL (a) | $ | 101 |  |  | $ | 103 |  |  | $ | 79 |
PPL Electric (a) | 32 |  |  | 52 |  |  | 47 |
LG&E | 4 |  |  | 4 |  |  | 4 |
KU | 5 |  |  | 4 |  |  | 2 |

(a)2024 and 2023 includes amounts impaired related to PPL Electric's billing issues. See Note 7 in PPL's 2024 Form 10-K for additional information.
Contract liabilities result from recording contractual billings in advance for customer attachments to the Registrants' infrastructure and payments received in excess of revenues earned to date. Advanced billings for customer attachments are recognized as revenue ratably over the billing period. Payments received in excess of revenues earned to date are recognized as revenue as services are delivered in subsequent periods. The Registrants' contract liabilities are not material at December 31, 2025, 2024 and 2023.
4. Preferred Securities
(PPL)
PPL is authorized to issue up to 10 million shares of preferred stock. No PPL preferred stock was issued or outstanding in 2025, 2024 or 2023.
(PPL Electric)
PPL Electric is authorized to issue up to 20,629,936 shares of preferred stock. No PPL Electric preferred stock was issued or outstanding in 2025, 2024 or 2023.
(LG&E)
LG&E is authorized to issue up to 1,720,000 shares of preferred stock at a $25 par value and 6,750,000 shares of preferred stock without par value. LG&E had no preferred stock issued or outstanding in 2025, 2024 or 2023.
(KU)
KU is authorized to issue up to 5,300,000 shares of preferred stock and 2,000,000 shares of preference stock. KU had no preferred or preference stock issued or outstanding in 2025, 2024 or 2023.
5. Earnings Per Share
(PPL)
Basic EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding during the applicable period. Diluted EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding, increased by the number of incremental shares that would be outstanding if potentially dilutive share-based payment awards were converted to common shares as calculated using the Two-Class Method or Treasury Stock Method. The If-Converted Method is applied to the Exchangeable Senior Notes due 2028 and 2030 (Exchangeable Notes) issued in February 2023 and November 2025.
Incremental non-participating securities that have a dilutive impact are detailed in the table below. In 2025, these securities include forward sales of PPL common stock issued through an ATM Program and the number of shares needed to settle the conversion premium on the Exchangeable Notes. The forward sale agreements are dilutive under the Treasury Stock Method to the extent the average stock price of PPL's common shares exceeds the forward sale price prescribed in the agreements. See Note 8 for additional information on the ATM Program and the Exchangeable Senior Notes due 2030 and Note 8 in PPL's Annual Report on Form 10-K for the year ended December 31, 2023 for additional information on the Exchangeable Notes due 2028.
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Reconciliations of the amounts of income and shares of PPL common stock (in thousands) for the periods ended December 31, used in the EPS calculation are:

| 2025 |  | 2024 |  | 2023
Income (Numerator) |  |  |  |  |
Net income | $ | 1,181 |  |  | $ | 888 |  |  | $ | 740 |
Less amounts allocated to participating securities | 2 |  |  | 2 |  |  | 1 |
Net income available to PPL common shareowners - Basic and Diluted | $ | 1,179 |  |  | $ | 886 |  |  | $ | 739 |
Shares of Common Stock (Denominator) |  |  |  |  |
Weighted-average shares - Basic EPS | 739,406 |  |  | 737,756 |  |  | 737,036 |
Add incremental non-participating securities: |  |  |  |  |
Dilutive share-based payment awards (a) | 2,724 |  |  | 2,097 |  |  | 1,130 |
Forward sale agreements | 170 |  |  | — |  |  | — |
Exchangeable Notes | 1,048 |  |  | — |  |  | — |
Weighted-average shares - Diluted EPS | 743,348 |  |  | 739,853 |  |  | 738,166 |
Basic EPS |  |  |  |  |
Net Income available to PPL common shareowners | $ | 1.60 |  |  | $ | 1.20 |  |  | $ | 1.00 |
Diluted EPS |  |  |  |  |
Net Income available to PPL common shareowners | $ | 1.59 |  |  | $ | 1.20 |  |  | $ | 1.00 |

(a)The Treasury Stock Method was applied to non-participating share-based payment awards.
For the years ended December 31, PPL issued common stock related to the DRIP as follows (in thousands):

| 2025 |  | 2024 |  | 2023
DRIP | 762 |  |  | 202 |  |  | — |

For the years ended December 31, the following shares (in thousands) were excluded from the computations of diluted EPS because the effect would have been antidilutive:

| 2025 |  | 2024 |  | 2023
Stock-based compensation awards | 106 |  |  | — |  |  | 243 |
Forward sale agreements | 10,040 |  |  | — |  |  | — |

6. Income and Other Taxes
(PPL)
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes and the tax effects of net operating loss and tax credit carryforwards. The provision for PPL's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles of the applicable jurisdiction. See Notes 1 and 7 for additional information.
Net deferred tax assets have been recognized based on management's estimates of future taxable income.
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Significant components of PPL's deferred income tax assets and liabilities were as follows:

| 2025 |  | 2024
Deferred Tax Assets |  |  |
Deferred investment tax credits | $ | 27 |  |  | $ | 28 |
Regulatory liabilities | 186 |  |  | 133 |
Income taxes due to customers | 397 |  |  | 418 |
Accrued pension and postretirement costs | 99 |  |  | 112 |
State loss carryforwards | 181 |  |  | 224 |
Federal and state tax credit carryforwards | 35 |  |  | 24 |
Internal Revenue Code Section 197 intangibles | 67 |  |  | 72 |
Contributions in aid of construction | 206 |  |  | 163 |
Bad debt | 34 |  |  | 37 |
Other | 130 |  |  | 114 |
Valuation allowances | (184) |  |  | (224) |
Total deferred tax assets | 1,178 |  |  | 1,101 |
Deferred Tax Liabilities |  |  |
Plant - net | 4,105 |  |  | 3,898 |
Regulatory assets | 432 |  |  | 432 |
Prepayments | 49 |  |  | 39 |
Goodwill | 52 |  |  | 38 |
Other | 37 |  |  | 38 |
Total deferred tax liabilities | 4,675 |  |  | 4,445 |
Net deferred tax liability | $ | 3,497 |  |  | $ | 3,344 |

State deferred taxes are determined by entity and by jurisdiction. As a result, $9 million and $12 million of net deferred tax assets are shown as "Other noncurrent assets" on the Balance Sheets for 2025 and 2024.
At December 31, 2025, PPL had the following loss and tax credit carryforwards, related deferred tax assets and valuation allowances recorded against the deferred tax assets:

| Gross |  | Deferred Tax Asset |  | Valuation Allowance |  | Expiration
Loss and other carryforwards |  |  |  |  |  |  |
State net operating losses | $ | 4,281 |  |  | $ | 181 |  |  | $ | (181) |  |  | 2026-2045
State charitable contributions | 1 |  |  | — |  |  | — |  |  | 2026-2030
Foreign capital loss | 8 |  |  | 2 |  |  | (2) |  |  | Indefinite

| Gross |  | Deferred Tax Asset |  | Valuation Allowance |  | Expiration
Credit carryforwards |  |  |  |  |  |  |
Federal investment tax credit |  |  | $ | 26 |  |  | $ | — |  |  | 2045
Federal - other |  |  | 2 |  |  | — |  |  | 2045
State recycling credit |  |  | 6 |  |  | — |  |  | 2028
State - other |  |  | 2 |  |  | — |  |  | Indefinite

Valuation allowances have been established for the amount that, more likely than not, will not be realized. The changes in deferred tax valuation allowances were as follows:

|  |  | Additions |  |  |  |
| Balance at Beginning of Period |  | Charged to Income |  | Charged to Other Accounts |  | Deductions |  | Balance at End of Period
2025 | $ | 224 |  |  | $ | 4 |  |  | $ | — |  |  | $ | 44 |  | (a) | $ | 184 |
2024 | 245 |  |  | 3 |  |  | 1 |  |  | 25 |  | (b) | 224 |
2023 | 213 |  |  | 54 |  | (c) | — |  |  | 22 |  | (d) | 245 |

(a)In 2025, PPL recorded a $41 million decrease in a valuation allowance on a 2005 state net operating loss carryforward that expired in 2025.
(b)In 2024, PPL recorded a $23 million decrease in a valuation allowance on a 2004 state net operating loss carryforward that expired in 2024.
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(c)PPL has a Pennsylvania net operating loss fully offset by a valuation allowance. In 2023, PPL adjusted the net operating loss and related valuation allowance to be recorded at the current estimate of the applicable rate at which each portion of the net operating loss that will expire and be written off as the rate is reduced annually by one half a percentage point until the rate reaches to 4.99% in 2031.
(d)In 2023, PPL recorded a $22 million decrease in a valuation allowance on a 2003 state net operating loss carryforward that expired in 2023.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were as follows:

| 2025 |  | 2024 |  | 2023
Income Tax Expense (Benefit) |  |  |  |  |
Current - Federal (a) | $ | 46 |  |  | $ | 23 |  |  | $ | (175) |
Current - State | 53 |  |  | 9 |  |  | 37 |
Total Current Expense (Benefit) | 99 |  |  | 32 |  |  | (138) |
Deferred - Federal (a) | 172 |  |  | 137 |  |  | 286 |
Deferred - State | 27 |  |  | 64 |  |  | 48 |
Total Deferred Expense (Benefit), excluding operating loss carryforwards | 199 |  |  | 201 |  |  | 334 |
Amortization of investment tax credit | (3) |  |  | (3) |  |  | (3) |
Tax expense (benefit) of operating loss carryforwards |  |  |  |  |
Deferred - Federal | 1 |  |  | 1 |  |  | 3 |
Deferred - State | (5) |  |  | (3) |  |  | (12) |
Total Tax Expense (Benefit) of Operating Loss Carryforwards | (4) |  |  | (2) |  |  | (9) |
Total income tax expense (benefit) | $ | 291 |  |  | $ | 228 |  |  | $ | 184 |
Total income tax expense (benefit) - Federal | $ | 216 |  |  | $ | 158 |  |  | $ | 111 |
Total income tax expense (benefit) - State | 75 |  |  | 70 |  |  | 73 |
Total income tax expense (benefit) | $ | 291 |  |  | $ | 228 |  |  | $ | 184 |

(a)In 2025, 2024, and 2023, PPL purchased approximately $153 million, $27 million and $300 million of renewable tax credits and recorded a current tax benefit and a deferred tax expense for utilization of approximately $138 million, $61 million and $250 million of the credits, respectively.
In the table above, the following income tax expense (benefit) are excluded from income taxes:

| 2025 |  | 2024 |  | 2023
Other comprehensive income | $ | (6) |  |  | $ | (8) |  |  | $ | (14) |
Valuation allowance recorded to other comprehensive income | — |  |  | — |  |  | (1) |
Total | $ | (6) |  |  | $ | (8) |  |  | $ | (15) |

| 2025 |  | 2024 |  | 2023
| Amount |  | Percent |  | Amount |  | Percent |  | Amount |  | Percent
Reconciliation of Income Tax Expense (Benefit) |  |  |  |  |  |  |  |  |  |  |
Federal income tax on Income Before Income Taxes at statutory tax rate | $ | 309 |  |  | 21.0 | % |  | $ | 234 |  |  | 21.0 | % |  | $ | 194 |  |  | 21.0 | %
Increase (decrease) due to: |  |  |  |  |  |  |  |  |  |  |
State income taxes, net of federal income tax benefit (a) | 75 |  |  | 5.0 | % |  | 67 |  |  | 6.1 | % |  | 69 |  |  | 7.5 | %
Tax credits (federal): |  |  |  |  |  |  |  |  |  |  |
Investment tax credits | (17) |  |  | (1.1) | % |  | (5) |  |  | (0.5) | % |  | (19) |  |  | (2.1) | %
Other tax credits | (1) |  |  | (0.1) | % |  | (5) |  |  | (0.5) | % |  | (7) |  |  | (0.7) | %
Subtotal | (18) |  |  | (1.2) | % |  | (10) |  |  | (1.0) | % |  | (26) |  |  | (2.8) | %
Utility rate-making tax adjustments (federal and state): |  |  |  |  |  |  |  |  |  |  |
Amortization of excess deferred taxes | (51) |  |  | (3.4) | % |  | (46) |  |  | (4.1) | % |  | (48) |  |  | (5.2) | %
AFUDC Equity | (20) |  |  | (1.3) | % |  | (10) |  |  | (0.9) | % |  | (6) |  |  | (0.7) | %
Flow-through rate-making (b) | (10) |  |  | (0.6) | % |  | (11) |  |  | (1.0) | % |  | (4) |  |  | (0.5) | %
Subtotal | (81) |  |  | (5.3) | % |  | (67) |  |  | (6.0) | % |  | (58) |  |  | (6.4) | %
Other | 6 |  |  | 0.3 | % |  | 4 |  |  | 0.3 | % |  | 5 |  |  | 0.6 | %
Total increase (decrease) | (18) |  |  | (1.2) | % |  | (6) |  |  | (0.6) | % |  | (10) |  |  | (1.1) | %
Total income tax expense | $ | 291 |  |  | 19.8 | % |  | $ | 228 |  |  | 20.4 | % |  | $ | 184 |  |  | 19.9 | %

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(a) Jurisdictions that make up the majority of state income taxes, net of federal effect, are Kentucky and Pennsylvania.
(b) Flow-through occurs when the regulator excludes deferred tax expense or benefit from recoverable costs when determining income tax expense.
Income tax cash payments (refunds) by federal and state jurisdictions:

| 2025 |  | 2024 |  | 2023 |
Federal | $ | 66 |  | (a) | $ | (149) |  | (b) | $ | 252 |  | (c)
Pennsylvania | 20 |  |  | 21 |  |  | 24 |  |
Kentucky | 6 |  |  | 4 |  |  | 4 |  |
Other states | 1 |  |  | 1 |  |  | 1 |  |
Total | $ | 93 |  |  | $ | (123) |  |  | $ | 281 |  |

(a) Includes purchase price of transferable tax credits of $40 million.
(b) Includes refund for the carry-back of acquired transferable tax credits applied to the 2021 tax return of $200 million and purchase price of transferable tax credits of $20 million.
(c) Includes refund of $55 million and purchase price of transferable tax credits of $282 million.

| 2025 |  | 2024 |  | 2023
Taxes, other than income |  |  |  |  |
State gross earnings and state gross receipts | $ | 214 |  |  | $ | 167 |  |  | $ | 195 |
Property and other | 209 |  |  | 207 |  |  | 197 |
Total | $ | 423 |  |  | $ | 374 |  |  | $ | 392 |

(PPL Electric)
The provision for PPL Electric's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the PAPUC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of PPL Electric's deferred income tax assets and liabilities were as follows:

| 2025 |  | 2024
Deferred Tax Assets |  |  |
Accrued pension and postretirement costs | $ | 29 |  |  | $ | 36 |
Contributions in aid of construction | 156 |  |  | 120 |
Regulatory liabilities | 57 |  |  | 40 |
Income taxes due to customers | 177 |  |  | 184 |
Other | 25 |  |  | 22 |
Total deferred tax assets | 444 |  |  | 402 |
Deferred Tax Liabilities |  |  |
Electric utility plant - net | 2,028 |  |  | 1,934 |
Regulatory assets | 165 |  |  | 160 |
Prepayments | 30 |  |  | 30 |
Other | 2 |  |  | 4 |
Total deferred tax liabilities | 2,225 |  |  | 2,128 |
Net deferred tax liability | $ | 1,781 |  |  | $ | 1,726 |

PPL Electric expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were as follows:
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| 2025 |  | 2024 |  | 2023
Income Tax Expense |  |  |  |  |
Current - Federal | $ | 136 |  |  | $ | 44 |  |  | $ | 91 |
Current - State | 44 |  |  | 4 |  |  | 31 |
Total Current Expense | 180 |  |  | 48 |  |  | 122 |
Deferred - Federal | 17 |  |  | 86 |  |  | 28 |
Deferred - State | 7 |  |  | 42 |  |  | 18 |
Total Deferred Expense, excluding operating loss carryforwards | 24 |  |  | 128 |  |  | 46 |
Total income tax expense | $ | 204 |  |  | $ | 176 |  |  | $ | 168 |
Total income tax expense - Federal | $ | 153 |  |  | $ | 130 |  |  | $ | 119 |
Total income tax expense - State | 51 |  |  | 46 |  |  | 49 |
Total income tax expense | $ | 204 |  |  | $ | 176 |  |  | $ | 168 |

| 2025 |  | 2024 |  | 2023
| Amount |  | Percent |  | Amount |  | Percent |  | Amount |  | Percent
Reconciliation of Income Tax Expense (Benefit) |  |  |  |  |  |  |  |  |  |  |
Taxes at statutory tax rate | $ | 177 |  |  | 21.0 | % |  | $ | 158 |  |  | 21.0 | % |  | $ | 144 |  |  | 21.0 | %
Increase (decrease) due to: |  |  |  |  |  |  |  |  |  |  |
State income taxes, net of federal income tax benefit (a) | 52 |  |  | 6.1 | % |  | 47 |  |  | 6.2 | % |  | 48 |  |  | 7.1 | %
Utility rate-making tax adjustments (federal and state): |  |  |  |  |  |  |  |  |  |  |
Amortization of excess deferred federal income taxes | (10) |  |  | (1.2) | % |  | (10) |  |  | (1.3) | % |  | (11) |  |  | (1.6) | %
AFUDC Equity | (8) |  |  | (1.0) | % |  | (6) |  |  | (0.7) | % |  | (4) |  |  | (0.7) | %
Flow-through rate-making (b) | (10) |  |  | (1.2) | % |  | (11) |  |  | (1.5) | % |  | (4) |  |  | (0.7) | %
Subtotal | (28) |  |  | (3.4) | % |  | (27) |  |  | (3.5) | % |  | (19) |  |  | (3.0) | %
Other | 3 |  |  | 0.5 | % |  | (2) |  |  | (0.2) | % |  | (5) |  |  | (0.6) | %
Total increase (decrease) | 27 |  |  | 3.2 | % |  | 18 |  |  | 2.5 | % |  | 24 |  |  | 3.5 | %
Total income tax expense | $ | 204 |  |  | 24.2 | % |  | $ | 176 |  |  | 23.5 | % |  | $ | 168 |  |  | 24.5 | %

(a) The jurisdiction that makes up the majority of state income taxes, net of federal effect, is Pennsylvania.
(b) Flow-through occurs when the regulator excludes deferred tax expense or benefit from recoverable costs when determining income tax expense.
Income tax cash payments by federal and state jurisdictions:

| 2025 |  | 2024 |  | 2023 |
Federal | $ | 109 |  |  | $ | 62 |  |  | $ | 68 |  |
Pennsylvania | 20 |  |  | 21 |  |  | 24 |  |
Total | $ | 129 |  |  | $ | 83 |  |  | $ | 92 |  |

| 2025 |  | 2024 |  | 2023
Taxes, other than income |  |  |  |  |
State gross receipts | $ | 144 |  |  | $ | 122 |  |  | $ | 136 |
Property and other | 7 |  |  | 9 |  |  | 7 |
Total | $ | 151 |  |  | $ | 131 |  |  | $ | 143 |

(LG&E)
The provision for LG&E's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of LG&E's deferred income tax assets and liabilities were as follows:
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| 2025 |  | 2024
Deferred Tax Assets |  |  |
Contributions in aid of construction | $ | 17 |  |  | $ | 18 |
Regulatory liabilities | 18 |  |  | 18 |
Accrued pension and postretirement costs | — |  |  | 4 |
Deferred investment tax credits | 7 |  |  | 7 |
Income taxes due to customers | 104 |  |  | 110 |
State tax credit carryforwards | 5 |  |  | 6 |
Lease liabilities | 4 |  |  | 4 |
Other | 9 |  |  | 6 |
Valuation allowances | (5) |  |  | (6) |
Total deferred tax assets | 159 |  |  | 167 |
Deferred Tax Liabilities |  |  |
Plant - net | 884 |  |  | 875 |
Regulatory assets | 87 |  |  | 88 |
Lease right-of-use assets | 4 |  |  | 4 |
Other | 3 |  |  | 3 |
Total deferred tax liabilities | 978 |  |  | 970 |
Net deferred tax liability | $ | 819 |  |  | $ | 803 |

At December 31, 2025, LG&E had $5 million of state credit carryforwards that expire in 2028 and a $5 million valuation allowance related to state credit carryforwards due to insufficient projected Kentucky taxable income.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were:

| 2025 |  | 2024 |  | 2023
Income Tax Expense (Benefit) |  |  |  |  |
Current - Federal | $ | 72 |  |  | $ | 60 |  |  | $ | 70 |
Current - State | 14 |  |  | 11 |  |  | 13 |
Total Current Expense (Benefit) | 86 |  |  | 71 |  |  | 83 |
Deferred - Federal | (10) |  |  | 1 |  |  | (15) |
Deferred - State | 3 |  |  | 6 |  |  | 2 |
Total Deferred Expense (Benefit) | (7) |  |  | 7 |  |  | (13) |
Amortization of investment tax credit - Federal | (1) |  |  | (1) |  |  | (1) |
Total income tax expense (benefit) | $ | 78 |  |  | $ | 77 |  |  | $ | 69 |
Total income tax expense (benefit) - Federal | $ | 61 |  |  | $ | 60 |  |  | $ | 54 |
Total income tax expense (benefit) - State | 17 |  |  | 17 |  |  | 15 |
Total income tax expense (benefit) | $ | 78 |  |  | $ | 77 |  |  | $ | 69 |

| 2025 |  | 2024 |  | 2023
| Amount |  | Percent |  | Amount |  | Percent |  | Amount |  | Percent
Reconciliation of Income Tax Expense (Benefit) |  |  |  |  |  |  |  |  |  |  |
Taxes at statutory tax rate | $ | 81 |  |  | 21.0 | % |  | $ | 79 |  |  | 21.0 | % |  | $ | 70 |  |  | 21.0 | %
Increase (decrease) due to: |  |  |  |  |  |  |  |  |  |  |
State income taxes, net of federal income tax benefit (a) | 15 |  |  | 3.8 | % |  | 14 |  |  | 3.7 | % |  | 13 |  |  | 3.8 | %
Utility rate-making tax adjustments (federal and state): |  |  |  |  |  |  |  |  |  |  |
Amortization of excess deferred taxes | (14) |  |  | (3.5) | % |  | (13) |  |  | (3.4) | % |  | (13) |  |  | (3.9) | %
AFUDC Equity | (4) |  |  | (1.1) | % |  | (2) |  |  | (0.4) | % |  | (1) |  |  | (0.3) | %
Subtotal | (18) |  |  | (4.6) | % |  | (15) |  |  | (3.8) | % |  | (14) |  |  | (4.2) | %
Other | — |  |  | — | % |  | (1) |  |  | (0.3) | % |  | — |  |  | — | %
Total increase (decrease) | (3) |  |  | (0.8) | % |  | (2) |  |  | (0.4) | % |  | (1) |  |  | (0.4) | %
Total income tax expense | $ | 78 |  |  | 20.2 | % |  | $ | 77 |  |  | 20.6 | % |  | $ | 69 |  |  | 20.6 | %

(a)The jurisdiction that makes up the majority of state income taxes, net of federal effect, is Kentucky.
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Income tax cash payments by federal and state jurisdictions:

| 2025 |  | 2024 |  | 2023 |
Federal | $ | 67 |  |  | $ | 62 |  |  | $ | 71 |  |
Kentucky | 14 |  |  | 11 |  |  | 13 |  |
Total | $ | 81 |  |  | $ | 73 |  |  | $ | 84 |  |

| 2025 |  | 2024 |  | 2023
Taxes, other than income |  |  |  |  |
Property and other | $ | 51 |  |  | $ | 49 |  |  | $ | 48 |
Total | $ | 51 |  |  | $ | 49 |  |  | $ | 48 |

(KU)
The provision for KU's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC, the VSCC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of KU's deferred income tax assets and liabilities were as follows:

| 2025 |  | 2024
Deferred Tax Assets |  |  |
Contributions in aid of construction | $ | 17 |  |  | $ | 12 |
Regulatory liabilities | 31 |  |  | 29 |
Deferred investment tax credits | 20 |  |  | 20 |
Income taxes due to customers | 117 |  |  | 124 |
State tax credit carryforwards | 3 |  |  | 4 |
Lease liabilities | 7 |  |  | 6 |
Other | 8 |  |  | 4 |
Valuation allowances | (1) |  |  | (2) |
Total deferred tax assets | 202 |  |  | 197 |
Deferred Tax Liabilities |  |  |
Plant - net | 1,085 |  |  | 1,053 |
Regulatory assets | 56 |  |  | 55 |
Pension and postretirement costs | 8 |  |  | 6 |
Lease right-of-use assets | 7 |  |  | 6 |
Other | 2 |  |  | 1 |
Total deferred tax liabilities | 1,158 |  |  | 1,121 |
Net deferred tax liability | $ | 956 |  |  | $ | 924 |

At December 31, 2025, KU had $3 million of state credit carryforwards of which $1 million will expire in 2028 and $2 million that has an indefinite carryforward period. At December 31, 2025, KU had a $1 million valuation allowance related to state credit carryforwards due to insufficient projected Kentucky taxable income.
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Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were:

| 2025 |  | 2024 |  | 2023
Income Tax Expense (Benefit) |  |  |  |  |
Current - Federal | $ | 83 |  |  | $ | 87 |  |  | $ | 73 |
Current - State | 16 |  |  | 17 |  |  | 13 |
Total Current Expense (Benefit) | 99 |  |  | 104 |  |  | 86 |
Deferred - Federal | (4) |  |  | (15) |  |  | (11) |
Deferred - State | 6 |  |  | 2 |  |  | 4 |
Total Deferred Expense (Benefit) | 2 |  |  | (13) |  |  | (7) |
Amortization of investment tax credit - Federal | (2) |  |  | (2) |  |  | (2) |
Total income tax expense (benefit) | $ | 99 |  |  | $ | 89 |  |  | $ | 77 |
Total income tax expense (benefit) - Federal | $ | 77 |  |  | $ | 70 |  |  | $ | 60 |
Total income tax expense (benefit) - State | 22 |  |  | 19 |  |  | 17 |
Total income tax expense (benefit) | $ | 99 |  |  | $ | 89 |  |  | $ | 77 |

| 2025 |  | 2024 |  | 2023
| Amount |  | Percent |  | Amount |  | Percent |  | Amount |  | Percent
Reconciliation of Income Tax Expense (Benefit) |  |  |  |  |  |  |  |  |  |  |
Taxes at statutory tax rate | $ | 104 |  |  | 21.0 | % |  | $ | 93 |  |  | 21.0 | % |  | $ | 82 |  |  | 21.0 | %
Increase (decrease) due to: |  |  |  |  |  |  |  |  |  |  |
State income taxes, net of federal income tax benefit (a) | 19 |  |  | 3.8 | % |  | 16 |  |  | 3.7 | % |  | 15 |  |  | 3.8 | %
Utility rate-making tax adjustment (federal and state): |  |  |  |  |  |  |  |  |  |  |
Amortization of excess deferred federal and state income taxes | (18) |  |  | (3.6) | % |  | (17) |  |  | (3.7) | % |  | (17) |  |  | (4.3) | %
AFUDC Equity | (5) |  |  | (1.0) | % |  | (2) |  |  | (0.6) | % |  | — |  |  | — | %
Subtotal | (23) |  |  | (4.6) | % |  | (19) |  |  | (4.3) | % |  | (17) |  |  | (4.3) | %
Other | (1) |  |  | (0.3) | % |  | (1) |  |  | (0.4) | % |  | (3) |  |  | (0.7) | %
Total decrease | (5) |  |  | (1.1) | % |  | (4) |  |  | (1.0) | % |  | (5) |  |  | (1.2) | %
Total income tax expense | $ | 99 |  |  | 19.9 | % |  | $ | 89 |  |  | 20.0 | % |  | $ | 77 |  |  | 19.8 | %

(a)The jurisdiction that makes up the majority of state income taxes, net of federal effect, is Kentucky.
Income tax cash payments by federal and state jurisdictions:

| 2025 |  | 2024 |  | 2023
Federal | $ | 78 |  |  | $ | 85 |  |  | $ | 65 |
Kentucky | 15 |  |  | 16 |  |  | 12 |
Other | 1 |  |  | 1 |  |  | 1 |
Total | $ | 94 |  |  | $ | 102 |  |  | $ | 78 |

| 2025 |  | 2024 |  | 2023
Taxes, other than income |  |  |  |  |
Property and other | $ | 51 |  |  | $ | 49 |  |  | $ | 45 |
Total | $ | 51 |  |  | $ | 49 |  |  | $ | 45 |

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(All Registrants)
Unrecognized Tax Benefits
PPL or its subsidiaries file tax returns in four major tax jurisdictions. The income tax provisions for PPL Electric, LG&E and KU are calculated in accordance with an intercompany tax sharing agreement, which provides that taxable income be calculated as if each subsidiary filed a separate consolidated return. PPL Electric or its subsidiaries indirectly or directly file tax returns in three major tax jurisdictions, and LG&E and KU indirectly or directly file tax returns in two major tax jurisdictions. With few exceptions, at December 31, 2025, these jurisdictions, as well as the tax years that are no longer subject to examination, were as follows.

| PPL |  | PPL Electric |  | LG&E |  | KU
U.S. (federal) | 2020 and prior |  | 2020 and prior |  | 2020 and prior |  | 2020 and prior
Pennsylvania (state) | 2021 and prior |  | 2021 and prior |  | n/a |  | n/a
Kentucky (state) | 2020 and prior |  | 2020 and prior |  | 2020 and prior |  | 2020 and prior

Other
One Big Beautiful Bill Act (All Registrants)
On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act. The Registrants are continuing to review the law to assess any material impacts to the financial statements.
Additionally, on July 7, 2025, President Trump issued an Executive Order directing the Treasury to take action to strictly enforce the termination of clean electricity tax credits under IRC Sections 45Y and 48E for wind and solar. On August 15, 2025, the IRS issued Notice 2025-42, primarily tightening the rules regarding when a solar project is considered to have commenced construction. In addition, the One Big Beautiful Bill Act included new rules addressing Foreign Entities of Concern (FEOC). These rules are supply‑chain, foreign entity ownership and debt issuance restrictions that may limit eligibility for certain U.S. clean energy tax credits such as those provided for in IRC Sections 45Y and 48E.
On February 12, 2026, the Treasury and the IRS issued Notice 2026-15, which provides interim guidance on the FEOC restrictions on certain clean electricity tax credits. Additionally, the IRS is expected to issue further guidance on the tax provisions of the One Big Beautiful Bill Act. The Registrants do not currently anticipate these rules or guidance to result in limitations on its clean energy projects and associated tax credits but will continue to monitor closely.
7. Utility Rate Regulation
Regulatory Assets and Liabilities
(All Registrants)
PPL, PPL Electric, LG&E and KU reflect the effects of regulatory actions in the financial statements for their rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to an item will be recovered or refunded within a year of the balance sheet date.
(PPL)
RIE is subject to the jurisdiction of the RIPUC, the Rhode Island Division of Public Utilities and Carriers, and the FERC. RIE operates under a FERC-approved open access transmission tariff. RIE's base distribution rates are calculated based on recovery of costs as well as a return on rate base. Certain other recovery mechanisms exist to recover expenses and capital investments with a return on rate base separate from the base distribution rate case process.
(PPL, LG&E and KU)
LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the VSCC and the FERC.
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Prior to January 1, 2026, LG&E's and KU's Kentucky base rates were calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. Effective January 1, 2026, pursuant to the KPSC rate case, Kentucky base rates are calculated based on a return on rate base (net utility plant plus certain regulatory assets and working capital less accumulated deferred income taxes and certain regulatory liabilities) and include recovery of applicable operations and maintenance expenses.
(PPL and KU)
KU's Virginia base rates are calculated based on recovery of costs as well as a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except for regulatory assets and liabilities related to the levelized fuel factor, accumulated deferred income taxes, pension and postretirement benefits, and AROs related to certain CCR impoundments, are excluded from the return on rate base utilized in the calculation of Virginia base rates, no return is earned on the related assets.
KU's rates to municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets.
(PPL and PPL Electric)
PPL Electric is subject to the jurisdiction of the PAPUC and the FERC. PPL Electric's distribution base rates are calculated based on recovery of costs as well as a return on distribution rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions) and an annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.
(All Registrants)
The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations at December 31:
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| PPL |  | PPL Electric |  | LG&E |  | KU
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
Current Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas supply clause | $ | 10 |  |  | $ | 3 |  |  | $ | — |  |  | $ | — |  |  | $ | 10 |  |  | $ | 3 |  |  | $ | — |  |  | $ | — |
Rate adjustment mechanisms | 86 |  |  | 95 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Renewable energy certificates | 21 |  |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm damage expense rider | 53 |  |  | 68 |  |  | 53 |  |  | 68 |  |  | — |  |  | — |  |  | — |  |  | — |
Transmission service charge | 61 |  |  | 44 |  |  | — |  |  | 27 |  |  | — |  |  | — |  |  | — |  |  | — |
ISR deferral | 6 |  |  | 22 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
TCJA | 40 |  |  | 21 |  |  | 40 |  |  | 21 |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 31 |  |  | 53 |  |  | 19 |  |  | 17 |  |  | 9 |  |  | 5 |  |  | 1 |  |  | 1 |
Total current regulatory assets | $ | 308 |  |  | $ | 320 |  |  | $ | 112 |  |  | $ | 133 |  |  | $ | 19 |  |  | $ | 8 |  |  | $ | 1 |  |  | $ | 1 |
Noncurrent Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Defined benefit plans | $ | 961 |  |  | $ | 967 |  |  | $ | 477 |  |  | $ | 473 |  |  | $ | 212 |  |  | $ | 226 |  |  | $ | 144 |  |  | $ | 149 |
Plant outage costs | 23 |  |  | 30 |  |  | — |  |  | — |  |  | 5 |  |  | 7 |  |  | 18 |  |  | 23 |
Net metering | 164 |  |  | 147 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Environmental cost recovery | 102 |  |  | 96 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Storm costs | 113 |  |  | 113 |  |  | 42 |  |  | 22 |  |  | 24 |  |  | 20 |  |  | 38 |  |  | 29 |
Unamortized loss on debt | 18 |  |  | 20 |  |  | 2 |  |  | 3 |  |  | 8 |  |  | 9 |  |  | 6 |  |  | 6 |
Terminated interest rate swaps | 47 |  |  | 53 |  |  | — |  |  | — |  |  | 28 |  |  | 31 |  |  | 19 |  |  | 22 |
Accumulated cost of removal of utility plant | 184 |  |  | 173 |  |  | 184 |  |  | 173 |  |  | — |  |  | — |  |  | — |  |  | — |
AROs | 263 |  |  | 280 |  |  | — |  |  | — |  |  | 73 |  |  | 75 |  |  | 190 |  |  | 205 |
RAR | 76 |  |  | 83 |  |  | — |  |  | — |  |  | 76 |  |  | 83 |  |  | — |  |  | — |
Gas line inspections | 24 |  |  | 24 |  |  | — |  |  | — |  |  | 22 |  |  | 22 |  |  | 2 |  |  | 2 |
Advanced metering infrastructure | 67 |  |  | 28 |  |  | — |  |  | — |  |  | 28 |  |  | 14 |  |  | 39 |  |  | 14 |
IT system costs | 18 |  |  | — |  |  | 18 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 32 |  |  | 46 |  |  | 2 |  |  | 2 |  |  | 6 |  |  | 4 |  |  | 11 |  |  | 8 |
Total noncurrent regulatory assets | $ | 2,092 |  |  | $ | 2,060 |  |  | $ | 725 |  |  | $ | 673 |  |  | $ | 482 |  |  | $ | 491 |  |  | $ | 467 |  |  | $ | 458 |

| PPL |  | PPL Electric |  | LG&E |  | KU
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
Current Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Generation supply charge | $ | 45 |  |  | $ | 52 |  |  | $ | 45 |  |  | $ | 52 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Transmission service charge | 17 |  |  | — |  |  | 17 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Universal service rider | 17 |  |  | 3 |  |  | 17 |  |  | 3 |  |  | — |  |  | — |  |  | — |  |  | — |
Transmission formula rate | 62 |  |  | 1 |  |  | 23 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Rate adjustment mechanisms | 124 |  |  | 71 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Energy efficiency | 26 |  |  | 25 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
DSM | 21 |  |  | 17 |  |  | — |  |  | — |  |  | 8 |  |  | 7 |  |  | 13 |  |  | 10 |
Environmental cost recovery | 6 |  |  | 12 |  |  | — |  |  | — |  |  | 3 |  |  | 6 |  |  | 3 |  |  | 6 |
Revenue decoupling mechanism | 55 |  |  | 10 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other | 3 |  |  | 32 |  |  | 1 |  |  | 2 |  |  | 2 |  |  | 1 |  |  | — |  |  | 6 |
Total current regulatory liabilities | $ | 376 |  |  | $ | 223 |  |  | $ | 103 |  |  | $ | 57 |  |  | $ | 13 |  |  | $ | 14 |  |  | $ | 16 |  |  | $ | 22 |
Noncurrent Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accumulated cost of removal of utility plant | $ | 1,043 |  |  | $ | 1,022 |  |  | $ | — |  |  | $ | — |  |  | $ | 334 |  |  | $ | 314 |  |  | $ | 415 |  |  | $ | 408 |
Net deferred taxes | 1,798 |  |  | 1,899 |  |  | 708 |  |  | 739 |  |  | 415 |  |  | 439 |  |  | 467 |  |  | 498 |
Defined benefit plans | 342 |  |  | 294 |  |  | 120 |  |  | 100 |  |  | 23 |  |  | 24 |  |  | 69 |  |  | 65 |
Terminated interest rate swaps | 52 |  |  | 54 |  |  | — |  |  | — |  |  | 26 |  |  | 27 |  |  | 26 |  |  | 27 |
Advanced metering infrastructure | 30 |  |  | 13 |  |  | — |  |  | — |  |  | 10 |  |  | 4 |  |  | 20 |  |  | 9 |
Other | 53 |  |  | 53 |  |  | — |  |  | — |  |  | 1 |  |  | 7 |  |  | — |  |  | 2 |
Total noncurrent regulatory liabilities | $ | 3,318 |  |  | $ | 3,335 |  |  | $ | 828 |  |  | $ | 839 |  |  | $ | 809 |  |  | $ | 815 |  |  | $ | 997 |  |  | $ | 1,009 |

Following is an overview of selected regulatory assets and liabilities presented in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."
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Defined Benefit Plans
(All Registrants)
Defined benefit plan regulatory assets and liabilities represent prior service cost and net actuarial gains and losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices and, generally, are amortized over the average remaining service lives of plan participants. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is remeasured.
(PPL, LG&E and KU)
As a result of previous rate case settlements and orders, the difference between pension cost calculated in accordance with LG&E's and KU's pension accounting policy and pension cost calculated using a 15-year amortization period for actuarial gains and losses and settlements are recorded as a regulatory asset. As of December 31, 2025, the balances were $72 million for PPL, $41 million for LG&E and $31 million for KU. As of December 31, 2024, the balances were $79 million for PPL, $44 million for LG&E and $35 million for KU.
(PPL)
RIE is subject to a pension rate adjustment mechanism whereby the difference in amounts allowed to be recovered in base rates and the actual costs of RIE's pension and other postretirement benefit plans that are to be recovered from or passed back to customers in future periods, are also recorded as regulatory assets and liabilities.
(All Registrants)
Storm Costs
PPL Electric, LG&E and KU have the ability to establish or request regulatory assets for expenses related to specific extraordinary storms from the PAPUC, the KPSC and the VSCC, for regulatory accounting and reporting purposes. Once such authority is granted, LG&E and KU can request recovery of those expenses in a base rate case and begin amortizing the costs when recovery starts. PPL Electric can recover qualifying expenses caused by major storm events, as defined in its retail tariff, over three years through the Storm Damage Expense Rider commencing in the application year after the storm occurred. LG&E's and KU's regulatory assets for storm costs approved for base rate recovery are being amortized through various dates ending in 2031.
As provided in the Amended Settlement Agreement (ASA), RIE has the authority from the RIPUC to treat certain incremental O&M expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once all expenses for the extraordinary storm have been finalized, RIE files a final accounting of those storm expenses with the RIPUC that is subject to review by the RIPUC and the Rhode Island Division of Public Utilities and Carriers.
Unamortized Loss on Debt
Unamortized loss on debt represents losses on long-term debt refinanced, reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2053 for PPL Electric, through 2042 for KU, and through 2044 for LG&E.
Accumulated Cost of Removal of Utility Plant
RIE, LG&E and KU charge costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred.
PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.
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Net Deferred Taxes
Regulatory liabilities associated with net deferred taxes represent the future revenue impact from the adjustment of deferred income taxes required primarily for excess deferred taxes and unamortized investment tax credits, largely a result of the TCJA.
(PPL and PPL Electric)
Generation Supply Charge (GSC)
The GSC is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service. The recovery includes charges for generation supply, as well as administration of the acquisition process. In addition, the GSC contains a reconciliation mechanism whereby any over- or under-recovery from prior periods is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent rate filing period.
Transmission Service Charge (TSC)
PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PAPUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
RIE arranges transmission service on behalf of its customers and bills the costs of those services to customers, pursuant to its Transmission Service Cost Adjustment Provision. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
Transmission Formula Rate
PPL Electric's transmission revenues are billed in accordance with a FERC-approved Open Access Transmission Tariff that utilizes a formula-based rate recovery mechanism. Under this formula, rates are put into effect on January 1st of each year based upon actual expenditures from the most recently filed FERC Form 1, forecasted capital additions, and other data based on PPL Electric's books and records. Rates are compared during the year to the estimated annual expenses and capital additions that will be filed in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts. Under the mechanism, any difference between the revenue requirement in effect and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability, and the regulatory asset or regulatory liability is to be recovered from or returned to customers starting one year after the conclusion of the rate year.
Storm Damage Expense Rider (SDER)
The SDER is a reconcilable automatic adjustment clause under which PPL Electric annually will compare actual storm costs to storm costs allowed in base rates and refund or recover any differences from customers. In the 2015 rate case settlement approved by the PAPUC in November 2015, it was determined that reportable storm damage expenses to be recovered annually through base rates will be set at $20 million. The SDER will recover from or refund to customers the applicable expenses from reportable storms as compared to the $20 million recovered annually through base rates.
Universal Service Rider (USR)
The USR provides for recovery of costs associated with universal service programs, OnTrack and Winter Relief Assistance Program (WRAP), provided by PPL Electric to residential customers. OnTrack is a special payment program for low-income households and WRAP provides low-income customers a means to reduce electric bills through energy saving methods. The USR rate is applied to residential customers who receive distribution service. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.
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TCJA
As a result of the reduced U.S federal corporate income tax rate as enacted by the TCJA, the PAPUC ruled that these tax benefits should be refunded to customers. Timing differences between the recognition of these tax benefits and the refund of the benefit to the customer creates a regulatory liability. PPL Electric's liability is being credited back to distribution customers through a temporary negative surcharge and remains in place until PPL Electric files and the PAPUC approves new base rates. The TCJA is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.
IT System Costs
IT system costs represent expenditures incurred associated with implementing strategic information technology investments. As part of the ongoing rate case proceedings, PPL Electric has requested certain of these implementation costs to be treated as capital for ratemaking purposes to be recovered over the useful life of the associated IT asset. Recovery of these costs is subject to approval by the PAPUC, but PPL and PPL Electric believe recovery of these costs is probable.
(PPL, LG&E and KU)
AROs
As discussed in Note 1, for LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal.
Terminated Interest Rate Swaps
Net realized gains and losses on all interest rate swaps are recovered through regulated rates. As such, any gains and losses on these derivatives are included in regulatory assets or liabilities and are primarily recognized in "Interest Expense" on the Statements of Income over the life of the associated debt.
Plant Outage Costs
From July 1, 2017 through June 30, 2021, plant outage costs were normalized for ratemaking purposes based on an average level of expenses. Plant outage expenses that were greater or less than the average would be collected from or returned to customers, through future base rates. Effective July 1, 2021, under-recovered plant outage costs are being amortized through 2029 for LG&E and KU.
Advanced Metering Infrastructure (AMI)
In 2021 base rate case orders from the KPSC, LG&E and KU received approval to record regulatory assets comprised of the operating expenses associated with implementation of the AMI project, the incremental difference between AFUDC accrued at LG&E's and KU's weighted average cost of capital and that calculated using the methodology approved by the FERC, and the remaining net book value of the retired legacy meters replaced by AMI. Additionally, LG&E and KU received approval to record regulatory liabilities comprised of meter reading and field service expense savings since their previous rate case and the cost of capital impact for legacy meters replaced and retired during the AMI implementation. Recovery and/or return of these costs was approved effective January 1, 2026 in the base rate case proceedings.
(PPL)
Energy Efficiency
The energy efficiency mechanism is designed to collect the estimated costs of RIE's energy efficiency plan for the upcoming calendar year. Any differences between revenue billed to customers through RIE's energy efficiency charge and the costs of RIE's energy efficiency programs, as approved by the RIPUC, are recorded as regulatory assets or regulatory liabilities. The final annual over or under collection is reconciled in the next year's energy efficiency plan filing, as part of the reconciliation factor calculation. RIE may file to change the energy efficiency plan charge at any time should significant over-or under-recoveries occur.
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Net Metering
The net metering mechanism provides for recovery of costs associated with customer-installed on-site generation facilities, including the costs of renewable generation credits. Net metering is reconcilable annually, and any over- or under-recovery from customers will be refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
Rate Adjustment Mechanisms
In addition to commodity costs, RIE is subject to a number of additional rate adjustment mechanisms whereby a regulatory asset or regulatory liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the RIPUC. The rate adjustment mechanisms are reconcilable, and any over- or under-recovery from customers are to be refunded or recovered annually in the subsequent year.
Renewable Energy Certificates
The Renewable Energy Certificates regulatory asset represents deferred costs associated with RIE's compliance obligation with the Rhode Island Renewable Portfolio Standard (RPS). The RPS is legislation established to foster the development of new renewable energy sources. The regulatory asset will be recovered over the next year.
Environmental Cost Recovery
(PPL, LG&E and KU)
Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Clean Air Act and those federal, state or local environmental requirements, which apply to coal combustion wastes and by-products from coal-fired electricity generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the opportunity to roll-in ECR amounts to base rates each two-year period. The KPSC has authorized a return on equity of 9.35% for existing approved ECR projects. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is typically recovered or refunded within 12 months.
(PPL)
RIE's rate plans provide for specific rate allowances for RIE's share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated, with variances deferred for future recovery from, or return to, customers. RIE believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. The regulatory asset represents the excess of amounts incurred for RIE's actual site investigation and remediation costs versus amounts received in rates.
(PPL and LG&E)
Gas Supply Clause
LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs and customer usage from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause previously included a separate natural gas procurement incentive mechanism, which allowed LG&E's rates to be adjusted annually to share savings between the actual cost of gas purchases and market indices, with the shareholders and the customers during each performance-based rate year (12 months ending October 31). The operation of this incentive mechanism expired on October 31, 2024, but savings achieved through October 31, 2024 will be included in LG&E's rates through October 31, 2026. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are typically recovered or refunded within 18 months.
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RAR
The RAR rider was established by KPSC orders in 2021 to provide recovery of and return on the retirement costs of certain electric generating units, including the remaining net book value of each unit, materials and supplies that cannot be used at other plants and any associated removal costs, upon their retirement over a ten-year period following retirement. Costs included as of December 31, 2025 represent the remaining retirement costs of Mill Creek Unit 1 to be recovered through April 2034.
Regulatory Matters
Rhode Island Activities (PPL)
Rate Case Proceeding
On November 26, 2025, RIE filed a request with the RIPUC for an increase in electric and natural gas base distribution rates, and approval of certain regulatory and accounting treatments. In its application, RIE seeks to implement a two-year rate plan. In the first year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect additional operating revenue of approximately $181 million ($66 million or 18.2% in electricity revenues and $115 million or 36.4% in gas revenues). In the second year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect the proposed base distribution rate increases for electric and gas in the first year of the rate plan and additional operating revenues of approximately $49 million ($17 million or 3.6% in electricity revenues and $32 million or 7.4% in gas revenues).
The application is based on a historical test year of September 1, 2024 through August 31, 2025 and requested an authorized ROE of 10.75%. Subject to RIPUC approval, new rates are expected to become effective on September 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the RIPUC is anticipated during the third quarter of 2026. PPL cannot predict the outcome of the proceeding.
Hold Harmless Implementation Agreement
As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers required PPL to hold harmless Rhode Island customers from the impact of future rate increases resulting from changes in Accumulated Deferred Income Taxes as a result of the Acquisition (the Hold Harmless Commitment). On June 13, 2025, an agreement was entered into by and among RIE, PPL, PPL Rhode Island Holdings and the Rhode Island Division of Public Utilities and Carriers Advocacy Section (the Hold Harmless Implementation Agreement) to satisfy the Hold Harmless Commitment by providing approximately $155 million in miscellaneous bill credits issued to customers, with approximately $74 million to be issued in the first quarter of 2026 and approximately $81 million to be issued in the first quarter of 2027. The bill credits would be recorded as a reduction to revenue in the periods in which the credits are applied to customers' bills. On September 10, 2025, the Rhode Island Division of Public Utilities and Carriers issued an order confirming that RIE's provision of proposed miscellaneous bill credits as set forth in the Hold Harmless Implementation Agreement would satisfy the Hold Harmless Commitment. Also on September 10, 2025, the RIPUC opened a docket to evaluate the miscellaneous bill credit proposal set forth in the Hold Harmless Implementation Agreement, including the underlying rate accounting, and required RIE to file a tariff advice with the RIPUC, which RIE filed on October 2, 2025. After responding to discovery in that proceeding and before the evidentiary hearing was held or convened, RIE filed a notice of withdrawal of its tariff advice filing noting that it would hold in abeyance a comprehensive satisfaction of the Hold Harmless Commitment at this time. As a result of RIE's filing the notice of withdrawal, the Commission cancelled the evidentiary hearing. The docket remains open, but there has been no further activity since RIE's withdrawal of the tariff advice and the RIPUC's cancellation of the evidentiary hearing. PPL cannot predict whether there will be any further proceedings on the docket or the outcome of any further proceedings that may occur.
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Winter Bill Volatility Docket
At an Open Meeting on November 24, 2025, the RIPUC approved several measures to help mitigate winter bill increases for electric customers. First, the RIPUC approved miscellaneous bill credits for all residential electric customers of $23.54 per month for January, February, and March 2026. Second, the RIPUC paused the Storm Fund Replenishment Factor for usage on and after January 1, 2026, subject to further review through the 2026 Annual Retail Rate Filing. Third, the RIPUC paused the electric Energy Efficiency Charge for usage beginning January 1, 2026 through March 31, 2026. To offset the costs of the miscellaneous bill credits, the RIPUC directed RIE to apply the December 31, 2025 electric Energy Efficiency fund balance, net of any earned incentives, and directed RIE to transfer $11 million from the storm fund balance. The RIPUC approved future cost recovery for RIE of any unfunded balance of the miscellaneous bill credits through future identified offsets and/or a reconciling recovery mechanism to be determined in conjunction with the 2026 electric retail rate filing to allow recovery by December 31, 2026. Any remaining unfunded balance shall accrue at RIE's weighted average cost of capital.
FY 2026 Gas ISR Plan
On March 28, 2025, the RIPUC approved the FY 2026 Gas ISR Plan of $165 million, of which $147 million is for capital investment spend and $18 million is spend for paving costs as operation and maintenance (O&M), plus a potential additional $15 million is available if certain regulations are implemented by the PHMSA. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025.
FY 2027 Gas ISR Plan
On December 22, 2025, RIE filed its FY 2027 Gas ISR Plan with the RIPUC with a budget of $184 million that primarily included $166 million of capital investment spend and $17 million for spending on curb-to-curb paving. A decision from the RIPUC on the Plan is expected by March 31, 2026. RIE cannot predict the outcome of this matter.
FY 2026 Electric ISR Plan
On March 28, 2025, the RIPUC approved a FY 2026 Electric ISR Plan of $219 million for capital investment spend (including $88 million for Advanced Metering Functionality), $14 million for vegetation operations and maintenance spend and $1 million for Other O&M spend. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025.
FY 2027 Electric ISR Plan
On December 22, 2025, RIE filed its FY 2027 Electric ISR Plan with the RIPUC with a budget that primarily included $154 million of capital investment spend (including $18 million for Advanced Metering Functionality) and $13 million of vegetation operation and maintenance spend. A decision from the RIPUC is expected by March 31, 2026. RIE cannot predict the outcome of this matter.
Kentucky Activities
(PPL, LG&E and KU)
Rate Case Proceedings
On May 30, 2025, LG&E and KU filed requests with the KPSC for an increase in annual electricity and gas revenues of approximately $391 million ($105 million and $226 million in electricity revenues at LG&E and KU and $60 million in gas revenues at LG&E) and approval of certain regulatory and accounting treatments. The revenue increases would be an increase of 8.3% and 11.5% in electricity revenues at LG&E and KU, and an increase of 14.0% in gas revenues at LG&E.
The applications were based on a forecasted test year of January 1, 2026 through December 31, 2026 and requested an authorized ROE of 10.95%. New interim rates became effective on January 1, 2026, subject to refund pursuant to the KPSC's final order. Certain counterparties have intervened in the proceedings.
On October 20, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation (the agreement) regarding a proposed resolution of issues with a majority of the intervenors in the proceedings.
Under the agreement, the parties proposed that the KPSC should issue orders granting a revised increase in annual electricity and gas revenues of approximately $235 million ($58 million and $132 million in electricity revenues at LG&E and KU and $45 million in gas revenues at LG&E.) The agreement proposed a revised authorized ROE of 9.90%.
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The agreement proposed a "stay out" commitment from LG&E and KU to refrain from effective base rate increases before August 1, 2028, subject to certain exceptions. In connection with the stay out period, the agreement also proposed the establishment of two new rate adjustment clause mechanisms, a Generation Cost Recovery Adjustment Clause (GCR) and a Sharing Mechanism Adjustment Clause (SM).
The proposed GCR mechanism would provide LG&E and KU recovery of and return on investment of covered costs (excluding fuel amounts, which LG&E and KU can recover via an existing rate mechanism) of relevant new generation and energy storage assets authorized in the 2022 and 2025 CPCN proceedings (excluding the Mill Creek Unit 6 NGCC, see "2025 CPCN" for more information regarding the Mill Creek Unit 6 NGCC) as they are placed in service.
The proposed SM mechanism would address any base rate revenue deficiency or surplus during the final thirteen months of the stay out period, July 2027 through July 2028, below or above a suggested ROE band of 9.40% to 10.15%. Any such base rate revenue deficiency or surplus would be collected from or returned to customers over a thirteen-month billing period beginning November 2028.
Following issuance of the 2025 CPCN Order, LG&E and KU filed supplemental testimony with the KPSC in the rate case proceedings seeking recovery of the Mill Creek Unit 2 stay open costs through a proposed additional rate adjustment clause mechanism.
The agreement further proposed that LG&E and KU use regulatory deferral accounting for actual expenses above or below base rate levels for certain expenses including: pension and post-retirement benefits, storm restoration, vegetation management, transmission waivers and credits, and gas line or well activities, with recovery of such deferred asset or liability amounts to be addressed in future rate cases.
On February 16, 2026, the KPSC issued orders approving portions of the October 2025 stipulation and recommendation, with modifications.
The KPSC orders provide for increases in annual electricity and gas revenues of $233 million ($59 million and $128 million in electricity revenues at LG&E and KU and $46 million in gas revenues at LG&E.) The orders include authorized returns on equity of 9.775% for base rate purposes and 9.675% for capital rate adjustment mechanisms.
The KPSC orders approve LG&E's and KU's requests for establishment of certain new rate adjustment mechanisms or tariffs, with modifications:
• a temporary Pilot Generation Recovery Adjustment Clause (PGR) to provide recovery of and return on investment of applicable costs of certain new generation and storage assets being built or anticipated to be built by LG&E and KU as authorized in the 2022 CPCN proceeding;
• the inclusion in the PGR of recovery of and return on investment of certain costs associated with a potential extension of the operating life of LG&E's Mill Creek Unit 2 beyond its original 2027 retirement date; and
• an Extremely High Load Factor Tariff for future applicable customers, such as data centers, which includes requirements such as long-term contracts, minimum revenue payments and collateral security structures that help protect the interests of LG&E, KU and of other ratepayers.
The PGR mechanism is similar to the GCR proposed in the stipulation, but restructured by the KPSC to be a pilot adjustment mechanism with a term until the earlier of ten months following the submission of LG&E's and KU's next base rate proceeding or the effective date of new rates in such proceeding, with the expectation that the mechanism would be reviewed in such proceeding. The pilot mechanism will apply to the planned Mill Creek Unit 5, Brown Battery Energy Storage System, Mercer County Solar and Marion County Solar generation-related projects. The KPSC also included Mill Creek Unit 2's potential stay-open costs in the PGR in lieu of approving the stipulation's request for a stand-alone adjustment mechanism for such costs. Finally, the KPSC excluded from coverage under the PGR costs related to Mill Creek Unit 6 and Brown Unit 12 planned new generation assets due to their anticipated in-service dates falling outside of the estimated pilot mechanism's duration, but without prejudice to LG&E and KU seeking recovery of such costs in future proceedings.
The KPSC orders also approved, approved with modifications, or denied in some cases, other requested accounting and rate matters relating to regulatory assets or liabilities, depreciation rates, and other areas.
The rate changes have a retroactive effective date as of January 1, 2026. Consistent with authorized rate case procedures, LG&E and KU will refund to customers amounts billed in excess of the final approved rates within sixty days.
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The KPSC orders did not approve the SM adjustment clause that had been requested in the stipulation and made no modifications to the stay out offer by LG&E and KU to refrain from effective base rate increases prior to August 2028.
LG&E and KU and all intervenors have rights to request rehearing or appeal of the orders of the KPSC and because the KPSC orders modified or denied terms of the proposed stipulation, LG&E and KU and all stipulating parties have the right to withdraw from the stipulation.
LG&E and KU continue to evaluate the details contained in the orders and related matters as they consider next steps. PPL, LG&E and KU cannot predict the outcome of this matter.
2025 CPCN
On February 28, 2025, LG&E and KU filed an application with the KPSC regarding certain future plans for new generation and generation-related construction matters. The proposals included in the application were intended to serve anticipated load growth, including from potential data center demand in LG&E's or KU's service territory. The proposals did not include retirements of coal or other fossil-fueled plants, which would require additional KPSC approval procedures under Kentucky legislation enacted in 2023 and 2024.
LG&E and KU submitted a joint application to the KPSC for approval of certain certificates of public convenience and necessity, site compatibility certificates, and accounting treatment, where applicable, relating to a number of generation-related plans or projects that generally are expected to become operational or established within the next six years. The aggregate projected capital expenditures associated with these proposals were expected to be $3.7 billion. The application included proposals to build:
•a 645 MW NGCC generation unit at KU's E.W. Brown station (Brown Unit 12),
•a 645 MW NGCC generation unit at LG&E's Mill Creek station (Mill Creek Unit 6),
•a four-hour 400 MW (1600 MWh total) battery energy storage system (BESS) at LG&E's Cane Run station, and
•a selective catalytic reduction (SCR) environmental facility at KU's Ghent station Unit 2 (Ghent Unit 2).
The new NGCC units are anticipated to be wholly owned by LG&E and the BESS unit jointly owned by LG&E (32%) and KU (68%), with actual project costs allocated consistent with LG&E's and KU's ultimate ownership shares and existing shared dispatch, cost allocation, tariff or other frameworks. The proposed Mill Creek Unit 6 NGCC is in addition to a new NGCC unit currently under construction at that location (Mill Creek Unit 5).
The filing also noted projected in service dates for the projects, including the Brown Unit 12 NGCC in 2030, the Mill Creek Unit 6 NGCC in 2031, the Cane Run BESS in 2028 and the Ghent Unit 2 SCR in 2028.
On July 29, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation regarding a proposed resolution of issues with several of the intervenors in the CPCN proceeding (stipulation). The stipulation recommended to the KPSC the approval of the large majority of LG&E's and KU's requested generation-related projects and associated accounting matters, subject to certain changes. Under the stipulation, the parties agreed the KPSC should issue an order granting a CPCN for the proposed: (a) Brown Unit 12 NGCC; (b) Mill Creek Unit 6 NGCC; and (c) Ghent Unit 2 SCR. In addition, the proposal to build the $775 million Cane Run BESS would be withdrawn without prejudice, the relevant costs regarding the proposed $1.4 billion Mill Creek Unit 6 NGCC would be recovered through a new rate adjustment clause mechanism, the retirement date for the existing Mill Creek Unit 2 coal unit would be extended from 2027 to the operational date of the proposed Mill Creek Unit 6 NGCC or afterwards, subject to relevant future economic analysis, regulatory or environmental authorizations, and the relevant costs to continue to operate the Mill Creek Unit 2 coal unit would be recovered through a new rate adjustment clause mechanism. The stipulation also contained provisions relating to regulatory asset accounting, proposed data center tariffs, future renewable power requests-for-proposals and other matters. LG&E and KU would retain the right to seek approval of the potentially withdrawn Cane Run BESS or similar substitute project in future regulatory proceedings.
On October 28, 2025, the KPSC issued an order approving much of LG&E's and KU's July 2025 stipulation, with certain modifications. The order granted the requested CPCNs and site-related permits to construct the proposed Brown Unit 12 NGCC, Mill Creek Unit 6 NGCC, and Ghent Unit 2 SCR. The order authorized inclusion of relevant costs of the Ghent Unit 2 SCR in KU's existing environmental cost recovery rate mechanism. The order established a separate monitoring case to receive and consider information during the construction of Mill Creek Unit 6 NGCC.
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The order approved requests regarding regulatory asset deferral accounting treatment for certain AFUDC related amounts and noted the KPSC's expectation that the stipulating parties would follow through with their commitments regarding tariffs and power supply contracts related to potential future data center or high load customers in LG&E's and KU's pending rate proceedings. The order also approved other elements of the stipulation or the originally-filed application, with minor modifications.
The KPSC decided not to approve LG&E's and KU's proposed new rate adjustment cost recovery mechanisms for certain costs associated with Mill Creek Unit 6 NGCC and costs associated with operating the Mill Creek Unit 2 coal plant beyond its original retirement date in 2027. However, the denials were without prejudice to resubmission and the KPSC encouraged the parties to provide additional evidence on such matters in separate proceedings. LG&E and KU provided such evidence addressing recovery of the Mill Creek Unit 2 stay open costs in their pending rate case proceedings. Recovery of Mill Creek Unit 6 costs will be addressed in a future proceeding. The KPSC declined to rule on the matter related to the retirement date of Mill Creek Unit 2 coal plant. The KPSC indicated that a request for a new retirement approval proceeding may be required should LG&E elect to operate Mill Creek Unit 2 beyond its existing approved retirement date and seek to later retire the unit.
In light of the conditional withdrawal in the stipulation, the order did not include a CPCN for the Cane Run BESS. LG&E and KU retain the right to seek approval of the Cane Run BESS project or similar substitute projects at any time in future regulatory proceedings.
Kentucky January 2025 Storm
In January 2025, LG&E and KU experienced snow, ice, sleet and freezing rain in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets. On January 31, 2025, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance (O&M) expenses portion of the costs incurred related to the storm. On March 19, 2025, the KPSC issued an order authorizing LG&E and KU to establish, for accounting purposes only, regulatory assets based on the jurisdictional incremental costs of extraordinary O&M expense incurred by LG&E and KU as a result of the 2025 winter storm, with recovery amounts and amortization thereof to be determined in subsequent base rate proceedings. LG&E and KU cannot predict the outcome of these matters. As of December 31, 2025, LG&E and KU had recorded regulatory assets related to the storm of $2 million and $7 million.
Mill Creek Unit 1 and Unit 2 RAR Application (PPL and LG&E)
In November 2023, the KPSC issued an order approving, among other items, the requested retirement of Mill Creek Units 1 and 2.
On October 4, 2024, LG&E submitted an application related to the retirement of Mill Creek Unit 1, which occurred on December 31, 2024, requesting recovery of associated costs under the RAR. On February 24, 2025, the KPSC issued an order approving LG&E's cost recovery for Mill Creek Unit 1 under the RAR of $125 million and related amounts were included in bills beginning in May 2025.
LG&E anticipates the recovery of associated costs, including the remaining net book value, for Mill Creek Unit 2 through the RAR. The remaining net book value of Mill Creek Unit 2 was approximately $199 million at December 31, 2025 and LG&E is continuing to depreciate using the current approved rates through its retirement date. LG&E expects to reclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period of ten years in accordance with the RAR. There can be no assurance that these costs will be recovered in the amounts or over the time periods that LG&E expects. See the "2025 CPCN" and "Rate Case Proceedings" discussions above for information regarding potential changes in the retirement date of Mill Creek Unit 2.
Pennsylvania Activities (PPL and PPL Electric)
Rate Case Proceeding
On September 30, 2025, PPL Electric filed a request with the PAPUC for an increase in distribution base rates of approximately $356 million, more than $50 million of which is already included in customer bills through rate recovery mechanisms, and approval of certain regulatory and accounting treatments. The proposed increase in distribution base rates would increase PPL Electric's total annual revenue by approximately 8.6%. The application is based on a fully projected future test year of July 1, 2026 through June 30, 2027 and requested an authorized ROE of 11.3%. Subject to PAPUC approval, new rates are expected to become effective on July 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the PAPUC is anticipated during the second quarter of 2026. PPL and PPL Electric cannot predict the outcome of the proceeding.
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DSIC Petition
On April 26, 2024, PPL Electric filed a Petition with the PAPUC requesting that the PAPUC waive PPL Electric's DSIC cap of 5% of billed revenues and increase the maximum allowable DSIC to 9% for bills rendered on or after January 1, 2025. On February 28, 2025, the PAPUC issued its written order permitting PPL Electric to increase its DSIC cap from 5% to 7.5% for bills rendered on or after March 13, 2025 until the effective date of rates established in PPL Electric's next base rate case or the end of the PPL Electric's 2023-2027 Long-term Infrastructure Improvement Plan, whichever occurs first, at which time it will return to 5%.
Federal Matters
FERC Transmission Rate Filing (PPL, LG&E and KU)
In 2018, LG&E and KU applied to the FERC requesting elimination of certain on-going waivers and credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the U.S. Court of Appeals - D.C. Circuit (D.C. Circuit Court of Appeals) regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. In August 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. On May 18, 2023, the FERC issued an order on remand reversing its 2019 decision and requiring LG&E and KU to refund credits previously withheld, including under such transition mechanism. LG&E and KU filed a petition for review of the FERC's May 18, 2023 order with the D.C. Circuit Court of Appeals and provided refunds in accordance with the FERC order on December 1, 2023. The FERC issued an order on LG&E's and KU's compliance filing on November 16, 2023, and LG&E and KU filed a petition for review of this November 16, 2023 order on February 14, 2024. The FERC issued the substantive order on rehearing on March 21, 2024, reaffirming its prior decision. On August 8, 2025, the D.C. Circuit Court of Appeals issued a procedural ruling vacating the FERC's prior orders and remanded the matter back to the FERC for further proceedings. LG&E and KU cannot predict the ultimate outcome of the proceedings or any other post decision process but do not expect the annual impact to have a material effect on their operations or financial condition. LG&E and KU currently receive recovery of certain waivers and credits primarily through existing base rate levels.
Recovery of Transmission Costs (PPL)
NE-ISO allocates RIE's costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT).
The ROE for transmission rates under the ISO-NE OATT is the subject of four complaints that are pending before the FERC. On October 16, 2014, the FERC issued an order on the first complaint, Opinion No. 531-A, resetting the base ROE applicable to transmission assets under the ISO-NE OATT from 11.14% to 10.57% effective as of October 16, 2014 and establishing a maximum ROE of 11.74%. On April 14, 2017, this order was vacated and remanded by the D.C. Circuit Court of Appeals (Court of Appeals). After the remand, the FERC issued an order on October 16, 2018 applicable to all four pending cases where it proposed a new base ROE methodology that, with subsequent input and support from the New England Transmission Owners (NETO), yielded a base ROE of 10.41%. Subsequent to the FERC's October 2018 order in the New England Transmission Owners cases, the FERC further refined its ROE methodology in another proceeding and has applied that refined methodology to transmission owners' ROEs in other jurisdictions, and the NETOs filed further information in the New England matters to distinguish their case. Those determinations in other jurisdictions have been vacated and remanded back to the FERC for further proceedings by the D.C. Circuit Court of Appeals. The proceeding and the final base rate ROE determination in the New England matters remain open, pending a final order from the FERC. PPL cannot predict the outcome of this matter, and an estimate of the impact cannot be determined.
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Other
Purchase of Receivables Program
(PPL and PPL Electric)
In accordance with RIPUC-approved and PAPUC-approved purchase of accounts receivable programs, RIE and PPL Electric purchase certain accounts receivable from alternative electricity suppliers at a discount, which reflects a provision for uncollectible accounts. The alternative electricity suppliers have no continuing involvement or interest in the purchased accounts receivable. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition.
During 2025, 2024 and 2023, RIE purchased $314 million, $299 million and $235 million of accounts receivable from alternative suppliers.
During 2025, 2024 and 2023, PPL Electric purchased $1.6 billion, $1.5 billion and $1.5 billion of accounts receivable from alternative suppliers.
8. Financing Activities
Credit Arrangements and Short-term Debt
(All Registrants)
The Registrants maintain credit facilities to enhance liquidity, provide credit support and provide a backstop to commercial paper programs. For reporting purposes, on a consolidated basis, the credit facilities and commercial paper programs of PPL Electric, LG&E and KU also apply to PPL. The amounts listed in the borrowed column below are recorded as "Short-term debt" on the Balance Sheets. The following credit facilities were in place at:

| December 31, 2025 |  | December 31, 2024
| Expiration Date |  | Capacity |  | Borrowed |  | Letters of Credit and Commercial Paper Issued (a) |  | Unused Capacity |  | Borrowed |  | Letters of Credit and Commercial Paper Issued (a)
PPL |  |  |  |  |  |  |  |  |  |  |  |  |
PPL Capital Funding (b) |  |  |  |  |  |  |  |  |  |  |  |  |
Syndicated Credit Facility (c)(d)(e) | Dec. 2029 |  | $ | 1,500 |  |  | $ | — |  |  | $ | 456 |  |  | $ | 1,044 |  |  | $ | — |  |  | $ | 138 |
Bilateral Credit Facility (c)(d) | Feb. 2026 |  | 100 |  |  | — |  |  | — |  |  | 100 |  |  | — |  |  | — |
Bilateral Credit Facility (c)(d) | Feb. 2026 |  | 100 |  |  | — |  |  | 17 |  |  | 83 |  |  | — |  |  | 15 |
Total PPL Capital Funding Credit Facilities |  |  | $ | 1,700 |  |  | $ | — |  |  | $ | 473 |  |  | $ | 1,227 |  |  | $ | — |  |  | $ | 153 |
PPL Electric |  |  |  |  |  |  |  |  |  |  |  |  |
Syndicated Credit Facility (c)(d) | Dec. 2029 |  | 750 |  |  | — |  |  | 6 |  |  | 744 |  |  | — |  |  | 1 |
Total PPL Electric Credit Facilities |  |  | $ | 750 |  |  | $ | — |  |  | $ | 6 |  |  | $ | 744 |  |  | $ | — |  |  | $ | 1 |
LG&E |  |  |  |  |  |  |  |  |  |  |  |  |
Syndicated Credit Facility (c)(d) | Dec. 2029 |  | 600 |  |  | — |  |  | — |  |  | 600 |  |  | — |  |  | 25 |
Total LG&E Credit Facilities |  |  | $ | 600 |  |  | $ | — |  |  | $ | — |  |  | $ | 600 |  |  | $ | — |  |  | $ | 25 |
KU |  |  |  |  |  |  |  |  |  |  |  |  |
Syndicated Credit Facility (c)(d) | Dec. 2029 |  | 600 |  |  | — |  |  | — |  |  | 600 |  |  | — |  |  | 140 |
Total KU Credit Facilities |  |  | $ | 600 |  |  | $ | — |  |  | $ | — |  |  | $ | 600 |  |  | $ | — |  |  | $ | 140 |

(a)Commercial paper issued reflects the undiscounted face value of the issuance.
(b)PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL.
(c)Each company pays customary fees under its respective facility and borrowings generally bear interest at applicable secured overnight financing rates or base rates, plus an applicable margin.
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(d)The facilities contain a financial covenant requiring debt to total capitalization not to exceed 70% for PPL Capital Funding, RIE, PPL Electric, LG&E and KU, as calculated in accordance with the facilities and other customary covenants. Additionally, subject to certain conditions, PPL Capital Funding may request that the capacity of one of its bilateral credit facilities expiring in February 2026 be increased by up to $30 million and that the capacity of its syndicated credit facility be increased by up to $400 million. PPL Electric, LG&E and KU may each request up to a $250 million increase in its syndicated credit facility's capacity, subject to regulatory approval of the increased capacity. Participation in any such increase is at the sole discretion of each lender.
(e)Includes a $400 million borrowing sublimit for RIE and a $1.1 billion sublimit for PPL Capital Funding at December 31, 2025 and a $250 million borrowing sublimit for RIE and a $1 billion sublimit for PPL Capital Funding at December 31, 2024. At December 31, 2025, PPL Capital Funding had $355 million of commercial paper outstanding and RIE had $101 million commercial paper outstanding. At December 31, 2024, PPL Capital Funding had $138 million of commercial paper outstanding and RIE had no commercial paper outstanding. RIE's obligations under the facility are not guaranteed by PPL.
(PPL)
In January 2026, PPL Capital Funding amended its existing $1.50 billion syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030.
(PPL and PPL Electric)
In January 2026, PPL Electric amended its existing $750 million syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030.
(PPL and LG&E)
In January 2026, LG&E amended its existing $600 million syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030.
(PPL and KU)
In January 2026, KU amended its existing $600 million syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030.
(All Registrants)
The Registrants maintain commercial paper programs to provide an additional financing source to fund short-term liquidity needs. Commercial paper issuances, included in "Short-term debt" on the Balance Sheets, are supported by the respective Registrant's credit facilities. The following commercial paper programs were in place at:

| December 31, 2025 |  | December 31, 2024
| Weighted - Average Interest Rate |  | Capacity |  | Commercial Paper Issuances (a) |  | Unused Capacity |  | Weighted - Average Interest Rate |  | Commercial Paper Issuances (a)
PPL Capital Funding (b)(c) | 4.16% |  | $ | 1,600 |  |  | $ | 355 |  |  | $ | 1,245 |  |  | 4.76% |  | $ | 138 |
RIE (c) | 4.21% |  | 400 |  |  | 101 |  |  | 299 |  |  |  |  | — |
PPL Electric |  |  | 750 |  |  | — |  |  | 750 |  |  |  |  | — |
LG&E |  |  | 600 |  |  | — |  |  | 600 |  |  | 4.72% |  | 25 |
KU |  |  | 600 |  |  | — |  |  | 600 |  |  | 4.71% |  | 140 |
Total |  |  | $ | 3,950 |  |  | $ | 456 |  |  | $ | 3,494 |  |  |  |  | $ | 303 |

(a)Commercial paper issued reflects the undiscounted face value of the issuance.
(b)PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL.
(c)Issuances under the PPL Capital Funding and RIE commercial paper programs are supported by the PPL Capital Funding syndicated credit facility, which at December 31, 2025, had a total capacity of $1.50 billion, with a $400 million borrowing sublimit for RIE and a $1.1 billion sublimit for PPL Capital Funding. At December 31, 2024, the borrowing sublimits were $250 million for RIE and $1 billion for PPL Capital Funding. RIE's obligations under the facility are not guaranteed by PPL. The sublimits of each borrower may be decreased or increased at the borrowers' option up to a prescribed amount such that all borrowings under the syndicated credit facility cannot exceed the size of the credit facility of $1.50 billion. PPL Capital Funding's commercial paper program is also backed by a separate bilateral credit facility for $100 million.
(PPL Electric, LG&E and KU)
See Note 13 for a discussion of intercompany borrowings.
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Long-term Debt (All Registrants)

|  |  |  |  | December 31,
| Weighted-Average Rate (d) |  | Maturities (d) |  | 2025 |  | 2024
PPL |  |  |  |  |  |  |
Senior Unsecured Notes | 4.34 | % |  | 2026 - 2047 |  | $ | 4,316 |  |  | $ | 4,316 |
Senior Secured Notes/First Mortgage Bonds (a)(b)(c) | 4.64 | % |  | 2026 - 2055 |  | 12,227 |  |  | 10,878 |
Exchangeable Senior Unsecured Notes | 2.94 | % |  | 2028 - 2030 |  | 2,150 |  |  | 1,000 |
Junior Subordinated Notes | 6.61 | % |  | 2067 |  | 480 |  |  | 480 |
Total Long-term Debt before adjustments |  |  |  |  | 19,173 |  |  | 16,674 |
Long-term Debt, repurchased affiliate bonds |  |  |  |  | (84) |  |  | — |
Unamortized premium and (discount), net |  |  |  |  | (58) |  |  | (57) |
Unamortized debt issuance costs |  |  |  |  | (137) |  |  | (114) |
Total Long-term Debt |  |  |  |  | 18,894 |  |  | 16,503 |
Less current portion of Long-term Debt |  |  |  |  | 904 |  |  | 551 |
Total Long-term Debt, noncurrent |  |  |  |  | $ | 17,990 |  |  | $ | 15,952 |
PPL Electric |  |  |  |  |  |  |
Senior Secured Notes/First Mortgage Bonds (a)(b) | 4.72 | % |  | 2027 - 2055 |  | $ | 5,799 |  |  | $ | 5,299 |
Total Long-term Debt Before Adjustments |  |  |  |  | 5,799 |  |  | 5,299 |
Unamortized discount |  |  |  |  | (45) |  |  | (42) |
Unamortized debt issuance costs |  |  |  |  | (47) |  |  | (43) |
Total Long-term Debt |  |  |  |  | 5,707 |  |  | 5,214 |
Less current portion of Long-term Debt |  |  |  |  | — |  |  | — |
Total Long-term Debt, noncurrent |  |  |  |  | $ | 5,707 |  |  | $ | 5,214 |
LG&E |  |  |  |  |  |  |
Senior Secured Notes/First Mortgage Bonds (a)(c) | 4.52 | % |  | 2026 - 2055 |  | $ | 2,889 |  |  | $ | 2,489 |
Total Long-term Debt Before Adjustments |  |  |  |  | 2,889 |  |  | 2,489 |
Unamortized discount |  |  |  |  | (4) |  |  | (4) |
Unamortized debt issuance costs |  |  |  |  | (20) |  |  | (14) |
Total Long-term Debt |  |  |  |  | 2,865 |  |  | 2,471 |
Less current portion of Long-term Debt |  |  |  |  | 90 |  |  | 300 |
Total Long-term Debt, noncurrent |  |  |  |  | $ | 2,775 |  |  | $ | 2,171 |
KU |  |  |  |  |  |  |
Senior Secured Notes/First Mortgage Bonds (a)(c) | 4.60 | % |  | 2026 - 2055 |  | $ | 3,539 |  |  | $ | 3,089 |
Total Long-term Debt Before Adjustments |  |  |  |  | 3,539 |  |  | 3,089 |
Unamortized premium |  |  |  |  | 4 |  |  | 4 |
Unamortized discount |  |  |  |  | (8) |  |  | (8) |
Unamortized debt issuance costs |  |  |  |  | (25) |  |  | (19) |
Total Long-term Debt |  |  |  |  | 3,510 |  |  | 3,066 |
Less current portion of Long-term Debt |  |  |  |  | 164 |  |  | 250 |
Total Long-term Debt, noncurrent |  |  |  |  | $ | 3,346 |  |  | $ | 2,816 |

(a)Includes PPL Electric's senior secured and first mortgage bonds that are secured by the lien of PPL Electric's 2001 Mortgage Indenture, which covers substantially all of PPL Electric's tangible distribution properties and certain of its tangible transmission properties located in Pennsylvania, subject to certain exceptions and exclusions. The carrying value of PPL Electric's property, plant and equipment was approximately $14.6 billion and $13.3 billion at December 31, 2025 and 2024.
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Includes LG&E's first mortgage bonds that are secured by the lien of the LG&E 2010 Mortgage Indenture which creates a lien, subject to certain exceptions and exclusions, on substantially all of LG&E's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage and distribution of natural gas. The aggregate carrying value of the property subject to the lien was $6.4 billion and $6.0 billion at December 31, 2025 and 2024.
Includes KU's first mortgage bonds that are secured by the lien of the KU 2010 Mortgage Indenture which creates a lien, subject to certain exceptions and exclusions, on substantially all of KU's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity. The aggregate carrying value of the property subject to the lien was $8.0 billion and $7.5 billion at December 31, 2025 and 2024.
(b)Includes PPL Electric's series of senior secured bonds that secure its obligations to make payments with respect to each series of Pollution Control Bonds that were issued by the LCIDA on behalf of PPL Electric. These senior secured bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such Pollution Control Bonds. These senior secured bonds were issued under PPL Electric's 2001 Mortgage Indenture and are secured as noted in (a) above. The tax-exempt revenue bonds are subject to mandatory redemption upon determination that the interest rate on the bonds would be included in the holders' gross income for federal tax purposes.
(c)Includes LG&E's and KU's series of first mortgage bonds that were issued to the respective trustees of tax-exempt revenue bonds to secure its respective obligations to make payments with respect to each series of bonds. The first mortgage bonds were issued in the same principal amounts, contain payment and redemption provisions that correspond to and bear the same interest rate as such tax-exempt revenue bonds. These first mortgage bonds were issued under the LG&E 2010 Mortgage Indenture and the KU 2010 Mortgage Indenture and are secured as noted in (a) above. The related tax-exempt revenue bonds were issued by various governmental entities, principally counties in Kentucky, on behalf of LG&E and KU. The related revenue bond documents allow LG&E and KU to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, term rate of at least one year or, in some cases, an auction rate or a SOFR index rate. At December 31, 2025, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a term rate mode totaled $894 million for PPL, comprised of $538 million and $356 million for LG&E and KU. At December 31, 2025, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a variable rate mode totaled $66 million and $33 million for LG&E and KU. These variable rate tax-exempt revenue bonds are subject to tender for purchase by LG&E and KU at the option of the holder and to mandatory tender for purchase by LG&E and KU upon the occurrence of certain events.
(d)The table reflects principal maturities only, based on stated maturities, sinking fund requirements, or earlier put dates, and the weighted-average rates as of December 31, 2025.
The aggregate maturities of long-term debt, based on sinking fund requirements, stated maturities or earlier put dates, for the periods 2026 through 2030 and thereafter are as follows:

| PPL (a) |  | PPL Electric |  |  |  | LG&E |  | KU
2026 | $ | 904 |  |  | $ | — |  |  |  |  | $ | 90 |  |  | $ | 164 |
2027 | 428 |  |  | 108 |  |  |  |  | 260 |  |  | 60 |
2028 | 1,350 |  |  | — |  |  |  |  | — |  |  | — |
2029 | 116 |  |  | 116 |  |  |  |  | — |  |  | — |
2030 | 2,181 |  |  | — |  |  |  |  | — |  |  | — |
Thereafter | 14,110 |  |  | 5,575 |  |  |  |  | 2,539 |  |  | 3,315 |
Total | $ | 19,089 |  |  | $ | 5,799 |  |  |  |  | $ | 2,889 |  |  | $ | 3,539 |

(a)Reduced by $84 million of repurchased affiliate bonds as of December 31, 2025. See "Open Market Repurchase Program" below for additional information.
Exchangeable Notes
(PPL)
In November 2025, PPL Capital Funding issued $1.15 billion of 3.000% Exchangeable Senior Notes due 2030 (the Notes). PPL Capital Funding received proceeds of $1.14 billion, net of underwriting fees, which were used to repay short-term debt and for general corporate purposes. The Notes are senior unsecured obligations of PPL Capital Funding, fully and unconditionally guaranteed on a senior unsecured basis by PPL. The Notes are scheduled to mature on December 1, 2030, unless earlier exchanged, redeemed or repurchased.
The Notes are exchangeable at an initial exchange rate of approximately 23.44 shares of PPL's common stock per $1,000 principal amount (equivalent to an initial exchange price of approximately $42.66 per share of common stock). The initial exchange rate is subject to adjustment, as provided in the indenture for anti-dilutive events and fundamental change and redemption provisions. Upon exchange of the Notes, PPL Capital Funding expects to redeem the aggregate principal amount of the Notes in cash. PPL Capital Funding will pay cash, deliver shares of common stock or a combination of cash and shares of common stock, at PPL Capital Funding's election, in respect of the remainder, if any, of its exchange obligation in excess of the aggregate principal amount of the Notes being exchanged. Prior to the close of business on the business day immediately preceding September 1, 2030, the Notes will be exchangeable at the option of the noteholders only upon the satisfaction of specified conditions and during certain periods described in the indenture pursuant to which the Notes were issued. On or after the close of business on the business day immediately preceding September 1, 2030 until the maturity date, the Notes will be exchangeable at the option of the noteholders at any time regardless of these conditions or periods.
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PPL Capital Funding may not redeem the Notes prior to December 5, 2028. PPL Capital Funding may redeem for cash all or any portion of the Notes, at its option, on or after December 5, 2028, if the last reported sale price of the common stock has been at least 130% of the exchange price then in effect for at least 20 trading days (whether or not consecutive), during any 30 consecutive trading day period, at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus any accrued and unpaid interest to, but excluding, the redemption date. No sinking fund is provided for the Notes.
Subject to certain conditions, holders of the Notes will have the right to require PPL Capital Funding to repurchase all or a portion of their Notes upon the occurrence of a fundamental change, as defined in the indenture pursuant to which the Notes were issued at a repurchase price of 100% of their principal amount plus any accrued and unpaid interest. In connection with certain corporate events or if PPL Capital Funding calls any Notes for redemption, PPL Capital Funding will, under certain circumstances, increase the exchange rate for noteholders who elect to exchange their Notes in connection with any such corporate event or exchange their Notes called for redemption.
Open Market Repurchase Program
In the fourth quarter of 2025, PPL repurchased $84 million of affiliate bonds that included $36 million of PPL Electric bonds, $8 million of LG&E bonds and $40 million of KU bonds. On a consolidated basis, PPL's repurchases have been accounted for as debt extinguishments and resulted in a pre-tax gain of $18 million, net of unamortized debt issuance fees and discounts, which has been recorded as a reduction of Interest Expense on PPL's Consolidated Statements of Income. Intercompany interest expense related to the repurchased bonds was immaterial for the year ended December 31, 2025.
First Mortgage Bond Issuances
(PPL and PPL Electric)
In August 2025, PPL Electric issued $500 million of 5.55% First Mortgage Bonds due 2055. PPL Electric received proceeds of $491 million, net of discounts and underwriting fees, to be used to repay short-term debt and for other general corporate purposes.
(PPL and LG&E)
In August 2025, LG&E issued $700 million of 5.85% First Mortgage Bonds due 2055. LG&E received proceeds of $694 million, net of discounts and underwriting fees, to be used to repay short-term debt, the current portion of certain long-term debt and for other general corporate purposes.
(PPL and KU)
In August 2025, KU issued $700 million of 5.85% First Mortgage Bonds due 2055. KU received proceeds of $694 million, net of discounts and underwriting fees, to be used to repay short-term debt, the current portion of certain long-term debt and for other general corporate purposes.
(PPL Electric, LG&E and KU)
See Note 13 for additional information related to intercompany borrowings.
Legal Separateness (All Registrants)
The subsidiaries of PPL are separate legal entities. PPL's subsidiaries are not liable for the debts of PPL. Accordingly, creditors of PPL may not satisfy their debts from the assets of PPL's subsidiaries absent a specific contractual undertaking by a subsidiary to pay PPL's creditors or as required by applicable law or regulation. Similarly, other than PPL's guarantee of PPL Capital Funding's obligations, PPL is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of PPL's subsidiaries may not satisfy their debts from the assets of PPL or its other subsidiaries absent a specific contractual undertaking by PPL or its other subsidiaries to pay the creditors or as required by applicable law or regulation.
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Similarly, the subsidiaries of PPL Electric are each separate legal entities. These subsidiaries are not liable for the debts of PPL Electric. Accordingly, creditors of PPL Electric may not satisfy its debts from the assets of its subsidiaries absent a specific contractual undertaking by a subsidiary to pay the creditors or as required by applicable law or regulation. Similarly, PPL Electric is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of these subsidiaries may not satisfy their debts from the assets of PPL Electric (or its other subsidiaries) absent a specific contractual undertaking by PPL Electric or any such other subsidiary to pay such creditors or as required by applicable law or regulation.
(PPL)
Equity Securities
ATM Program
In February 2025, PPL entered into an equity distribution agreement, pursuant to which PPL may sell, from time to time, up to an aggregate of $2 billion of its common stock through an ATM Program, which may utilize an optional forward sales component. Each forward contract under the agreement must be settled within 24 months. The compensation paid to the selling agents by PPL may be up to 2% of the gross offering proceeds of the shares. As of December 31, 2025, PPL had entered into forward contracts to sell approximately 38.7 million shares of its common stock at a blended initial forward price of approximately $35.62 per share. The forward sale price may be adjusted based on changes in daily interest rates, for certain stock loan fees as determined by a third-party agent, and will be subject to predetermined reductions based on expected dividends. Each outstanding forward contract must be settled on or before dates ranging from December 30, 2025 to August 11, 2027. PPL may elect, at its discretion, to physically settle, net share settle or net cash settle the forward contracts. On December 29, 2025, PPL settled forward sale contracts with physical delivery of approximately 11.3 million shares of common stock for proceeds of approximately $394 million, net of issuance fees. At December 31, 2025, PPL could have settled the remaining forward sale contracts with physical delivery of approximately 27.4 million shares of common stock for proceeds of approximately $981 million. The forward contracts under the ATM program are classified as equity transactions.
Distributions and Related Restrictions
In November 2025, PPL declared its quarterly common stock dividend, payable January 2, 2026, at 27.25 cents per share (equivalent to $1.09 per annum). On February 20, 2026, PPL announced a quarterly common stock dividend of 28.50 cents per share, payable April 1, 2026, to shareowners of record as of March 10, 2026. Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other factors.
Neither PPL Capital Funding nor PPL may declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067. At December 31, 2025, no interest payments were deferred.
9. Acquisitions, Development and Divestitures
(PPL)
Acquisitions
Acquisition of Narragansett Electric
On May 25, 2022, PPL Rhode Island Holdings acquired 100% of the outstanding shares of common stock of Narragansett Electric from National Grid U.S., a subsidiary of National Grid plc (the Acquisition). Narragansett Electric, whose service area covers substantially all of Rhode Island, is primarily engaged in the transmission and distribution of electricity and distribution of natural gas.
In connection with the Acquisition, National Grid USA Service Company, Inc., National Grid U.S. and Narragansett Electric entered into a transition services agreement (TSA), pursuant to which the National Grid entities agreed to provide certain transition services to Narragansett Electric to facilitate the transition of the operation of Narragansett Electric to PPL following the Acquisition, as agreed upon in the Narragansett share purchase agreement. The TSA was for an initial two-year term and was completed in the third quarter of 2024. TSA costs of $137 million and $228 million were incurred for the years ended December 31, 2024 and 2023. RIE will not seek to recover in rates any markup charged by National Grid U.S. and/or its affiliates under the TSA which were $10 million, and $7 million for the years ended December 31, 2024 and 2023.
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As a condition to the Acquisition, RIE will forgo potential recovery of any and all transition costs, which includes (1) the installation of certain information technology systems; (2) modification and enhancements to physical facilities in Rhode Island; and (3) severance payments, communications and branding changes, and other transition related costs. These costs, which are being expensed as incurred, were $71 million, $307 million, and $262 million for the years ended December 31, 2025, 2024, and 2023.
Developments (PPL, LG&E and KU)
Mill Creek Unit 5 Construction
In December 2022, LG&E and KU filed a CPCN with the KPSC requesting approval to construct a 645 MW net summer rating Natural Gas Combined Cycle (NGCC) combustion turbine at LG&E's Mill Creek Generating Station. In November 2023, the KPSC issued an order approving the request as well as the requested AFUDC accounting treatment for associated financing costs relating to the NGCC. The new NGCC facility will be jointly owned by LG&E (31%) and KU (69%). In February 2024, LG&E and KU entered into agreements to begin construction of Mill Creek Unit 5. Total project costs are estimated at approximately $1.0 billion, including AFUDC. Commercial operation of the facility is anticipated to begin in mid-2027.
10. Retirement and Postemployment Benefits
(All Registrants)
Defined Benefits
Certain employees of PPL's subsidiaries are eligible for pension benefits under non-contributory defined benefit pension plans with benefits based on length of service and final average pay, as defined by the plans.
Effective January 1, 2012, PPL's primary defined benefit pension plan was closed to all newly hired salaried employees. Effective July 1, 2014, PPL's primary defined benefit pension plan was closed to all newly hired bargaining unit employees. Newly hired employees are eligible to participate in the PPL Retirement Savings Plan, a 401(k) savings plan with enhanced employer contributions.
The defined benefit pension plans of LKE and its subsidiaries were closed to new salaried and bargaining unit employees hired after December 31, 2005. Employees hired after December 31, 2005 receive additional company contributions above the standard matching contributions to their savings plans. The pension plans sponsored by LKE and LG&E were merged effective January 1, 2020 into the LG&E and KU Pension Plan. The merged plan is sponsored by LKE. LG&E and KU participate in this plan.
The RIE defined benefit plans were closed to new salaried employees in 2012 and bargaining unit employees in 2013. Employees hired after the defined benefit plans were closed receive additional company contributions above the standard matching contributions to their savings plans.
PPL and certain of its subsidiaries also provide supplemental retirement benefits to executives and other key management employees through unfunded nonqualified retirement plans.
Certain employees of PPL's subsidiaries are eligible for certain health care and life insurance benefits upon retirement through contributory plans. Effective January 1, 2014, the PPL Postretirement Medical Plan was closed to all newly hired salaried employees. Effective July 1, 2014, the PPL Postretirement Medical Plan was closed to all newly hired bargaining unit employees. Effective January 1, 2024, newly hired salaried employees and certain bargaining unit employees of LKE will no longer be eligible for postretirement medical benefits under the LKE Postretirement Plan. Postretirement health benefits may be paid from 401(h) accounts established as part of the PPL Retirement Plan and the LG&E and KU Pension Plan within the PPL Services Corporation Master Trust, funded VEBA trusts and company funds.
The Rhode Island postretirement benefit plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.
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(PPL)
The following table provides the components of net periodic defined benefit costs (credits) for PPL's pension and other postretirement benefit plans for the years ended December 31.

| Pension Benefits |  | Other Postretirement Benefits
| 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
Net periodic defined benefit costs (credits): |  |  |  |  |  |  |  |  |  |  |
Service cost | $ | 31 |  |  | $ | 35 |  |  | $ | 34 |  |  | $ | 6 |  |  | $ | 6 |  |  | $ | 6 |
Interest cost | 185 |  |  | 183 |  |  | 188 |  |  | 30 |  |  | 29 |  |  | 30 |
Expected return on plan assets | (287) |  |  | (299) |  |  | (309) |  |  | (30) |  |  | (30) |  |  | (30) |
Amortization of: |  |  |  |  |  |  |  |  |  |  |
Prior service cost (credit) | — |  |  | 3 |  |  | 6 |  |  | 2 |  |  | 1 |  |  | 1 |
Actuarial (gain) loss | 18 |  |  | 10 |  |  | 2 |  |  | (4) |  |  | (5) |  |  | (5) |
Net periodic defined benefit costs (credits) | $ | (53) |  |  | $ | (68) |  |  | $ | (79) |  |  | $ | 4 |  |  | $ | 1 |  |  | $ | 2 |
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets/Liabilities - Gross: |  |  |  |  |  |  |  |  |  |  |
Net (gain) loss | $ | 27 |  |  | $ | 134 |  |  | $ | 193 |  |  | $ | — |  |  | $ | 1 |  |  | $ | (6) |
Prior service cost (credit) | (5) |  |  | (13) |  |  | 2 |  |  | 2 |  |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |  |  |  |  |
Prior service (cost) credit | — |  |  | (3) |  |  | (6) |  |  | (2) |  |  | (1) |  |  | (1) |
Actuarial gain (loss) | (18) |  |  | (10) |  |  | (2) |  |  | 4 |  |  | 5 |  |  | 5 |
Total recognized in OCI and regulatory assets/liabilities | 4 |  |  | 108 |  |  | 187 |  |  | 4 |  |  | 5 |  |  | (2) |
Total recognized in net periodic defined benefit costs, OCI and regulatory assets/liabilities | $ | (49) |  |  | $ | 40 |  |  | $ | 108 |  |  | $ | 8 |  |  | $ | 6 |  |  | $ | — |

For PPL's pension and postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities for the years ended December 31 were as follows:

| Pension Benefits |  | Other Postretirement Benefits
| 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
OCI | $ | 21 |  |  | $ | 25 |  |  | $ | 52 |  |  | $ | 2 |  |  | $ | 2 |  |  | $ | — |
Regulatory assets/liabilities | (17) |  |  | 83 |  |  | 135 |  |  | 2 |  |  | 3 |  |  | (2) |
Total recognized in OCI and regulatory assets/liabilities | $ | 4 |  |  | $ | 108 |  |  | $ | 187 |  |  | $ | 4 |  |  | $ | 5 |  |  | $ | (2) |

(PPL)
PPL uses base mortality tables issued by the Society of Actuaries for all defined benefit pension and other postretirement benefit plans. The Pri-2012 base table and the MP-2020 projection scale with varying adjustment factors based on the underlying demographic and geographic differences and experience of the plan participants was used for all periods.
The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31.

| Pension Benefits |  | Other Postretirement Benefits
| 2025 |  | 2024 |  | 2025 |  | 2024
PPL |  |  |  |  |  |  |
Discount rate | 5.72 | % |  | 5.93 | % |  | 5.74 | % |  | 5.91 | %
Rate of compensation increase | 3.43 | % |  | 3.43 | % |  | 3.43 | % |  | 3.44 | %

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The following weighted-average assumptions were used to determine the net periodic defined benefit costs for the years ended December 31.

| Pension Benefits |  | Other Postretirement Benefits
| 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |  |  |  |  |  |  |
Discount rate | 5.93 | % |  | 5.52 | % |  | 5.52 | % |  | 5.91 | % |  | 5.54 | % |  | 5.54 | %
Rate of compensation increase | 3.43 | % |  | 3.43 | % |  | 3.43 | % |  | 3.44 | % |  | 3.43 | % |  | 3.43 | %
Expected return on plan assets (a) | 8.25 | % |  | 8.25 | % |  | 8.25 | % |  | 7.27 | % |  | 7.28 | % |  | 7.38 | %

(a)The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
The following table provides the assumed health care cost trend rates for the years ended December 31:

| 2025 |  | 2024 |  | 2023
PPL |  |  |  |  |
Health care cost trend rate assumed for next year |  |  |  |  |
– obligations | 7.50 | % |  | 7.00 | % |  | 6.25 | %
– cost | 7.00 | % |  | 6.25 | % |  | 6.50 | %
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) |  |  |  |  |
– obligations | 4.50 | % |  | 5.00 | % |  | 5.00 | %
– cost | 5.00 | % |  | 5.00 | % |  | 5.00 | %
Year that the rate reaches the ultimate trend rate |  |  |  |  |
– obligations | 2038 |  | 2033 |  | 2029
– cost | 2033 |  | 2029 |  | 2029

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The funded status of PPL's plans at December 31 was as follows:

| Pension Benefits |  | Other Postretirement Benefits
| 2025 |  | 2024 |  | 2025 |  | 2024
Change in Benefit Obligation |  |  |  |  |  |  |
Benefit Obligation, beginning of period | $ | 3,244 |  |  | $ | 3,454 |  |  | $ | 523 |  |  | $ | 538 |
Service cost | 31 |  |  | 35 |  |  | 6 |  |  | 6 |
Interest cost | 185 |  |  | 183 |  |  | 30 |  |  | 29 |
Participant contributions | — |  |  | — |  |  | 8 |  |  | 8 |
Plan amendments | (5) |  |  | (13) |  |  | 1 |  |  | — |
Actuarial (gain) loss | 77 |  |  | (131) |  |  | 20 |  |  | (4) |
Gross benefits paid | (297) |  |  | (284) |  |  | (51) |  |  | (56) |
Federal subsidy | — |  |  | — |  |  | — |  |  | 2 |
Benefit Obligation, end of period | 3,235 |  |  | 3,244 |  |  | 537 |  |  | 523 |
Change in Plan Assets |  |  |  |  |  |  |
Plan assets at fair value, beginning of period | 2,936 |  |  | 3,176 |  |  | 417 |  |  | 438 |
Actual return on plan assets | 338 |  |  | 34 |  |  | 51 |  |  | 25 |
Employer contributions | 10 |  |  | 10 |  |  | 11 |  |  | 14 |
Participant contributions | — |  |  | — |  |  | 7 |  |  | 7 |
Transfer out (a) | — |  |  | — |  |  | — |  |  | (13) |
Gross benefits paid | (297) |  |  | (284) |  |  | (54) |  |  | (54) |
Plan assets at fair value, end of period | 2,987 |  |  | 2,936 |  |  | 432 |  |  | 417 |
Funded Status, end of period | $ | (248) |  |  | $ | (308) |  |  | $ | (105) |  |  | $ | (106) |
Amounts recognized in the Balance Sheets consist of: |  |  |  |  |  |  |
Noncurrent asset | $ | 44 |  |  | $ | 19 |  |  | $ | 9 |  |  | $ | 8 |
Current liability | (11) |  |  | (10) |  |  | (10) |  |  | (13) |
Noncurrent liability | (281) |  |  | (317) |  |  | (104) |  |  | (101) |
Net amount recognized, end of period | $ | (248) |  |  | $ | (308) |  |  | $ | (105) |  |  | $ | (106) |
Amounts recognized in AOCI and regulatory assets/liabilities (pre-tax) consist of: |  |  |  |  |  |  |
Prior service cost (credit) | $ | (11) |  |  | $ | (6) |  |  | $ | 8 |  |  | $ | 9 |
Net actuarial (gain) loss | 1,173 |  |  | 1,164 |  |  | (86) |  |  | (90) |
Total | $ | 1,162 |  |  | $ | 1,158 |  |  | $ | (78) |  |  | $ | (81) |
Total accumulated benefit obligation for defined benefit pension plans | $ | 3,105 |  |  | $ | 3,116 |  |  |  |  |

(a)Transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to be used to pay medical claims of active bargaining unit employees.
For PPL's pension and other postretirement benefit plans, the amounts recognized in AOCI and regulatory assets/liabilities at December 31 were as follows:

| Pension Benefits |  | Other Postretirement Benefits
| 2025 |  | 2024 |  | 2025 |  | 2024
AOCI | $ | 304 |  |  | $ | 283 |  |  | $ | 18 |  |  | $ | 16 |
Regulatory assets/liabilities | 858 |  |  | 875 |  |  | (96) |  |  | (97) |
Total | $ | 1,162 |  |  | $ | 1,158 |  |  | $ | (78) |  |  | $ | (81) |

The actuarial loss for pension plans in 2025 was primarily related to a change in the discount rate used to measure the benefit obligations of those plans. The actuarial gain for pension plans in 2024 was related to a change in the discount rate used to measure the benefit obligations of those plans.
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The following tables provide information on pension plans where the projected benefit obligation (PBO) or accumulated benefit obligation (ABO) exceed the fair value of plan assets:

| PBO in excess of plan assets
| 2025 |  | 2024
Projected benefit obligation | $ | 2,704 |  |  | $ | 2,719 |
Fair value of plan assets | 2,412 |  |  | 2,392 |
| ABO in excess of plan assets
| 2025 |  | 2024
Accumulated benefit obligation | $ | 2,600 |  |  | $ | 2,618 |
Fair value of plan assets | 2,412 |  |  | 2,392 |

(PPL Electric)
Although PPL Electric does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by PPL Services based on its participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retirees are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to PPL Electric resulted in assets/(liabilities) at December 31 as follows:

| 2025 |  | 2024
Pension | $ | (62) |  |  | $ | (83) |
Other postretirement benefits | (53) |  |  | (60) |

(LG&E)
Although LG&E does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE. LG&E is also allocated costs of defined benefits plans from LKS for defined benefit plans sponsored by LKE. See Note 13 for additional information on costs allocated to LG&E from LKS. These allocations are based on LG&E's participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of LG&E are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to LG&E resulted in assets/(liabilities) at December 31 as follows:

| 2025 |  | 2024
Pension | $ | 46 |  |  | $ | 29 |
Other postretirement benefits | (46) |  |  | (44) |

(KU)
Although KU does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE. KU is also allocated costs of defined benefit plans from LKS for defined benefit plans sponsored by LKE. See Note 13 for additional information on costs allocated to KU from LKS. These allocations are based on KU's participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of KU are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to KU resulted in assets/(liabilities) at December 31 as follows.

| 2025 |  | 2024
Pension | $ | 56 |  |  | $ | 46 |
Other postretirement benefits | (10) |  |  | (8) |

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Plan Assets - Pension Plans
(PPL)
All of PPL's qualified pension plans are invested in the PPL Services Corporation Master Trust (the Master Trust) that also includes 401(h) accounts that are restricted for certain other postretirement benefit obligations of PPL, RIE and LKE. The investment strategy for the Master Trust is to achieve a risk-adjusted return on a mix of assets that, in combination with PPL's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments, while also managing the duration of the assets to complement the duration of the liabilities. The Master Trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore has no significant concentration of risk.
The investment policy of the Master Trust outlines investment objectives and defines the responsibilities of the EBPB, external investment managers, investment advisor and trustee and custodian. The investment policy is reviewed annually by PPL's Board of Directors.
The EBPB created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios: growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return at a reasonable risk, including equity securities, certain debt securities and alternative investments. The immunizing portfolio consists of debt securities, generally with long durations, and derivative positions. The immunizing portfolio is designed to offset a portion of the change in the pension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of cash and cash equivalents.
Target allocation ranges have been developed for each portfolio based on input from external consultants with a goal of limiting funded status volatility. The EBPB monitors the investments in each portfolio and seeks to obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the EBPB establishes revised guidelines from time to time. EBPB investment guidelines as of the end of 2025 are presented below.
The asset allocation for the trust and the target allocation by portfolio at December 31 are as follows:

| Percentage of trust assets |  | 2025
| 2025 |  | 2024 |  | Target Asset Allocation
Growth Portfolio | 55 | % |  | 55 | % |  | 55 | %
Equity securities | 30 | % |  | 30 | % |  |
Debt securities (a) | 13 | % |  | 13 | % |  |
Alternative investments | 12 | % |  | 12 | % |  |
Immunizing Portfolio | 43 | % |  | 43 | % |  | 43 | %
Debt securities (a) | 31 | % |  | 35 | % |  |
Derivatives (b) | 12 | % |  | 8 | % |  |
Liquidity Portfolio | 2 | % |  | 2 | % |  | 2 | %
Total | 100 | % |  | 100 | % |  | 100 | %

(a)Includes commingled debt funds, which PPL treats as debt securities for asset allocation purposes.
(b)Includes posted collateral to support derivative instruments subject to counterparty risk.
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(PPL)
The fair value of net assets in the Master Trust by asset class and level within the fair value hierarchy was:

| December 31, 2025 |  | December 31, 2024
| Fair Value Measurements Using |  | Fair Value Measurements Using
| Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3
PPL Services Corporation Master Trust |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | 239 |  |  | $ | 239 |  |  | $ | — |  |  | $ | — |  |  | $ | 212 |  |  | $ | 212 |  |  | $ | — |  |  | $ | — |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. Equity | 69 |  |  | 69 |  |  | — |  |  | — |  |  | 63 |  |  | 63 |  |  | — |  |  | — |
U.S. Equity fund measured at NAV (a) | 469 |  |  | — |  |  | — |  |  | — |  |  | 461 |  |  | — |  |  | — |  |  | — |
International equity fund measured at NAV (a) | 375 |  |  | — |  |  | — |  |  | — |  |  | 376 |  |  | — |  |  | — |  |  | — |
Commingled debt measured at NAV (a) | 464 |  |  | — |  |  | — |  |  | — |  |  | 461 |  |  | — |  |  | — |  |  | — |
Debt securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
U.S. Treasury and U.S. government sponsored agency | 273 |  |  | 273 |  |  | — |  |  | — |  |  | 150 |  |  | 149 |  |  | 1 |  |  | — |
Corporate | 753 |  |  | — |  |  | 742 |  |  | 11 |  |  | 867 |  |  | — |  |  | 848 |  |  | 19 |
Other | 7 |  |  | — |  |  | 7 |  |  | — |  |  | 13 |  |  | — |  |  | 13 |  |  | — |
Alternative investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Real estate measured at NAV (a) | 71 |  |  | — |  |  | — |  |  | — |  |  | 72 |  |  | — |  |  | — |  |  | — |
Private equity measured at NAV (a) | 122 |  |  | — |  |  | — |  |  | — |  |  | 114 |  |  | — |  |  | — |  |  | — |
Private credit partnerships measured at NAV (a) | 20 |  |  | — |  |  | — |  |  | — |  |  | 16 |  |  | — |  |  | — |  |  | — |
Hedge funds measured at NAV (a) | 179 |  |  | — |  |  | — |  |  | — |  |  | 181 |  |  | — |  |  | — |  |  | — |
Derivatives | (7) |  |  | — |  |  | (7) |  |  | — |  |  | (38) |  |  | — |  |  | (38) |  |  | — |
PPL Services Corporation Master Trust assets, at fair value | 3,034 |  |  | $ | 581 |  |  | $ | 742 |  |  | $ | 11 |  |  | 2,948 |  |  | $ | 424 |  |  | $ | 824 |  |  | $ | 19 |
Receivables and payables, net (b) | 69 |  |  |  |  |  |  |  |  | 102 |  |  |  |  |  |  |
401(h) accounts restricted for other postretirement benefit obligations | (116) |  |  |  |  |  |  |  |  | (114) |  |  |  |  |  |  |
Total PPL Services Corporation Master Trust pension assets | $ | 2,987 |  |  |  |  |  |  |  |  | $ | 2,936 |  |  |  |  |  |  |

(a)In accordance with accounting guidance, certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.
(b)Receivables and payables, net represents amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received.
A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2025 is as follows:

| Corporate debt |  |  |  |  |  |
Balance at beginning of period | $ | 19 |  |  |  |  |  |  |
Actual return on plan assets: |  |  |  |  |  |  |
Relating to assets sold during the period | (1) |  |  |  |  |  |  |
Purchases, sales and settlements | (7) |  |  |  |  |  |  |
Balance at end of period | $ | 11 |  |  |  |  |  |  |

A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2024 is as follows:

| Corporate debt |  |  |  |  |  |
Balance at beginning of period | $ | 10 |  |  |  |  |  |  |
Actual return on plan assets: |  |  |  |  |  |  |
Relating to assets still held at the reporting date | (2) |  |  |  |  |  |  |
Relating to assets sold during the period | 7 |  |  |  |  |  |  |
Purchases, sales and settlements | 4 |  |  |  |  |  |  |
Balance at end of period | $ | 19 |  |  |  |  |  |  |

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Cash and cash equivalents include deposits in banks, collateral accounts with brokers, and short-term investment funds, for which the carrying amounts disclosed approximate fair value based on their short-term nature.
The market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and passively managed investments that are managed against various equity indices.
Investments in commingled equity and debt funds are categorized as equity securities within the fair value hierarchy, however, the debt funds are treated as fixed income for asset allocation and target allocation purposes. Investments in commingled equity funds include funds that invest in U.S. and international equity securities. Investments in commingled debt funds include funds that invest in a diversified portfolio of emerging market debt obligations, as well as funds that invest in investment grade long-duration fixed-income securities.
The fair value measurements of debt securities are generally based on evaluations that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. The fair value of debt securities is generally measured using a market approach, including the use of pricing models, which incorporate observable inputs. Common inputs include benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as payment data, future predicted cash flows, collateral performance and new issue data. For the Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by residential mortgages, auto loans, credit cards and other pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries; investments in debt securities issued by foreign governments and corporations.
Investments in real estate represent an investment in a partnership whose purpose is to manage investments in U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value.
Investments in private equity represent interests in partnerships in multiple early-stage venture capital funds and private equity fund of funds that use a number of diverse investment strategies. The partnerships have limited lives of at least 10 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.
Investments in private credit represent pools of actively managed loans that span capital structure and borrower type. Strategies carry different types and levels of risk. Returns from those strategies will vary in terms of yield, fees generated, loan loss rates and the pace of principal repayment. Investments have limited lives of approximately 2-8 years. The investment cannot be redeemed with the general partner; however, the interest may be sold to other parties, subject to the general partner's approval. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.
At December 31, 2025, the Master Trust had unfunded commitments of $49 million that may be required during the lives of the real estate, private equity and private credit partnerships.
Investments in hedge funds represent investments in a fund of hedge funds. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under most market conditions. Major investment strategies for the fund of hedge funds include long/short equity, tactical trading, event driven, and relative value. Shares may be redeemed with 45 days prior written notice. The fund is subject to short term lockups and other restrictions. The fair value for the fund has been estimated using the net asset value per share.
The fair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard option valuation models and standard industry models. These securities primarily represent investments in treasury futures, total return swaps, interest rate swaps and swaptions (the option to enter into an interest rate swap), which are valued based on quoted prices, changes in the value of the underlying exposure or on the swap details, such as swap curves, notional amount, index and term of index, reset frequency, volatility and payer/receiver credit ratings.
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Plan Assets - Other Postretirement Benefit Plans
The investment strategy with respect to other postretirement benefit obligations is to fund VEBA trusts and/or 401(h) accounts with voluntary contributions and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the Master Trust, other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers and, therefore, have no significant concentration of risk. Equity securities include investments in a large-cap commingled fund and a global equity exchange-traded fund. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities within the fair value hierarchy, but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes. The asset allocation for the PPL VEBA trusts and the target allocation, by asset class, at December 31 are detailed below.

| Percentage of plan assets |  | Target Asset Allocation
| 2025 |  | 2024 |  | 2025
Asset Class |  |  |  |  |
Equity securities | 46 | % |  | 45 | % |  | 45 | %
Debt securities (a) | 48 | % |  | 49 | % |  | 49 | %
Cash and cash equivalents (b) | 6 | % |  | 6 | % |  | 6 | %
Total | 100 | % |  | 100 | % |  | 100 | %

(a)Includes commingled debt funds and debt securities.
(b)Includes money market funds.
The fair value of assets in the other postretirement benefit plans by asset class and level within the fair value hierarchy was:

| December 31, 2025 |  | December 31, 2024
| Fair Value Measurement Using |  | Fair Value Measurement Using
| Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3
Money market funds | $ | 19 |  |  | $ | 19 |  |  | $ | — |  |  | $ | — |  |  | $ | 19 |  |  | $ | 19 |  |  | $ | — |  |  | $ | — |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Large-cap equity fund measure at NAV (a) | 75 |  |  | — |  |  | — |  |  | — |  |  | 71 |  |  | — |  |  | — |  |  | — |
Commingled debt fund measured at NAV (a) | 82 |  |  | — |  |  | — |  |  | — |  |  | 78 |  |  | — |  |  | — |  |  | — |
Global equity exchange-traded fund | 74 |  |  | 74 |  |  | — |  |  | — |  |  | 70 |  |  | 70 |  |  | — |  |  | — |
Long-term bond exchange-traded fund | 75 |  |  | 75 |  |  | — |  |  | — |  |  | 74 |  |  | 74 |  |  | — |  |  | — |
Total VEBA trust assets, at fair value | 325 |  |  | $ | 168 |  |  | $ | — |  |  | $ | — |  |  | 312 |  |  | $ | 163 |  |  | $ | — |  |  | $ | — |
Receivables and payables, net (b) | (9) |  |  |  |  |  |  |  |  | (9) |  |  |  |  |  |  |
401(h) account assets | 116 |  |  |  |  |  |  |  |  | 114 |  |  |  |  |  |  |
Total other postretirement benefit plan assets | $ | 432 |  |  |  |  |  |  |  |  | $ | 417 |  |  |  |  |  |  |

(a)In accordance with accounting guidance certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.
(b)Receivables and payables represent amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received.
Investments in money market funds represent investments in funds that invest primarily in a diversified portfolio of investment grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The primary objective of the fund is a level of current income consistent with stability of principal and liquidity. Redemptions can be made daily on this fund.
Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Fair value measurements are not obtained from a quoted price in an active market but are based on firm quotes of net asset values per share as provided by the trustee of the fund. Redemptions can be made daily on this fund.
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Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade long-duration fixed income securities. Redemptions can be made daily on these funds.
Investments in global equity exchange-traded fund represents a passively-managed pooled investment vehicle that invests in developed market equities and is designed to track the performance of the MSCI World Index. Fair value measurements can be obtained from a quoted price on the exchange. Redemptions can be made daily on this fund.
Investments in long-term bond exchange-traded fund represents a passively-managed pooled investment vehicle that is designed to track the performance of the Bloomberg U.S. Long Government/Credit Float Adjusted Index, which includes all medium and larger issues of U.S. Government, investment-grade corporate and investment-grade international dollar-denominated bonds that have maturities of greater than 10 years. Fair value measurements can be obtained from a quoted price on the exchange. Redemptions can be made daily on this fund.
Expected Cash Flows - Defined Benefit Plans (PPL)
PPL does not plan to contribute to its pension plans in 2026, as PPL's defined benefit pension plans have the option to utilize available prior year credit balances to meet current and future contribution requirements.
PPL sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. PPL expects to make approximately $11 million of benefit payments under these plans in 2026.
PPL is not required to make contributions to its other postretirement benefit plans that are funded through VEBA trusts and 401(h) accounts. However, postretirement benefits for certain non-union employees are not funded in such trusts. PPL pays for these benefits from its general assets and expects to make $10 million of postretirement benefit plan payments for these employees in 2025.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the plans and the following federal subsidy payments are expected to be received by PPL.

|  |  | Other Postretirement
| Pension |  | Benefit Payment |  | Expected Federal Subsidy
2026 | $ | 307 |  |  | $ | 50 |  |  | $ | — |
2027 | 294 |  |  | 49 |  |  | — |
2028 | 287 |  |  | 49 |  |  | — |
2029 | 279 |  |  | 48 |  |  | — |
2030 | 272 |  |  | 48 |  |  | — |
2031-2035 | 1,271 |  |  | 224 |  |  | — |

Savings Plans (All Registrants)
Substantially all employees of PPL's subsidiaries are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were:

| 2025 |  | 2024 |  | 2023
PPL | $ | 60 |  |  | $ | 53 |  |  | $ | 48 |
PPL Electric | 10 |  |  | 9 |  |  | 8 |
LG&E | 10 |  |  | 8 |  |  | 8 |
KU | 8 |  |  | 6 |  |  | 6 |

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11. Jointly Owned Facilities
(PPL, LG&E and KU)
At December 31, 2025 and 2024, the Balance Sheets reflect the owned interests in the generating plants listed below.

|  | Ownership Interest |  | Electric Plant |  | Accumulated Depreciation |  | Construction Work in Progress
PPL |  |  |  |  |  |  |
| December 31, 2025 |  |  |  |  |  |  |
| Trimble County Unit 1 | 75.00 | % |  | $ | 464 |  |  | $ | 141 |  |  | $ | 20 |
| Trimble County Unit 2 | 75.00 | % |  | 1,543 |  |  | 344 |  |  | 20 |
| December 31, 2024 |  |  |  |  |  |  |
| Trimble County Unit 1 | 75.00 | % |  | $ | 462 |  |  | $ | 124 |  |  | $ | 1 |
| Trimble County Unit 2 | 75.00 | % |  | 1,549 |  |  | 323 |  |  | 10 |
LG&E |  |  |  |  |  |  |
| December 31, 2025 |  |  |  |  |  |  |
| E.W. Brown Units 6-7 | 38.00 | % |  | $ | 53 |  |  | $ | 31 |  |  | $ | — |
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 53.00 | % |  | 52 |  |  | 32 |  |  | — |
| Trimble County Unit 1 | 75.00 | % |  | 464 |  |  | 141 |  |  | 20 |
| Trimble County Unit 2 | 14.25 | % |  | 474 |  |  | 88 |  |  | 9 |
| Trimble County Units 5-6 | 29.00 | % |  | 37 |  |  | 20 |  |  | — |
| Trimble County Units 7-10 | 37.00 | % |  | 82 |  |  | 44 |  |  | 2 |
| Cane Run Unit 7 | 22.00 | % |  | 137 |  |  | 31 |  |  | 2 |
| E.W. Brown Solar Unit | 39.00 | % |  | 10 |  |  | 4 |  |  | — |
| Solar Share | 44.00 | % |  | 3 |  |  | 1 |  |  | — |
| Mercer Solar | 37.00 | % |  | 7 |  |  | — |  |  | 14 |
| Mill Creek Unit 5 | 31.00 | % |  | 1 |  |  | — |  |  | 219 |
| Brown Wind | 36.00 | % |  | — |  |  | — |  |  | — |
| December 31, 2024 |  |  |  |  |  |  |
| E.W. Brown Units 6-7 | 38.00 | % |  | $ | 53 |  |  | $ | 29 |  |  | $ | — |
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 53.00 | % |  | 52 |  |  | 30 |  |  | — |
| Trimble County Unit 1 | 75.00 | % |  | 462 |  |  | 124 |  |  | 1 |
| Trimble County Unit 2 | 14.25 | % |  | 472 |  |  | 79 |  |  | 5 |
| Trimble County Units 5-6 | 29.00 | % |  | 37 |  |  | 19 |  |  | — |
| Trimble County Units 7-10 | 37.00 | % |  | 82 |  |  | 41 |  |  | 1 |
| Cane Run Unit 7 | 22.00 | % |  | 137 |  |  | 27 |  |  | — |
| E.W. Brown Solar Unit | 39.00 | % |  | 10 |  |  | 4 |  |  | — |
| Solar Share | 44.00 | % |  | 3 |  | — |  |  | — |
| Mercer Solar | 37.00 | % |  | 10 |  | — |  |  | 1 |
| Mill Creek Unit 5 | 31.00 | % |  | — |  |  | — |  |  | 74
| Brown Wind | 36.00 | % |  | — |  |  | — |  |  | — |

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|  | Ownership Interest |  | Electric Plant |  | Accumulated Depreciation |  | Construction Work in Progress
KU |  |  |  |  |  |  |
| December 31, 2025 |  |  |  |  |  |  |
| E.W. Brown Units 6-7 | 62.00 | % |  | $ | 88 |  |  | $ | 51 |  |  | $ | — |
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 47.00 | % |  | 47 |  |  | 28 |  |  | — |
| Trimble County Unit 2 | 60.75 | % |  | 1,069 |  |  | 256 |  |  | 12 |
| Trimble County Units 5-6 | 71.00 | % |  | 87 |  |  | 47 |  |  | — |
| Trimble County Units 7-10 | 63.00 | % |  | 136 |  |  | 74 |  |  | 3 |
| Cane Run Unit 7 | 78.00 | % |  | 486 |  |  | 109 |  |  | 6 |
| E.W. Brown Solar Unit | 61.00 | % |  | 16 |  |  | 7 |  |  | — |
| Solar Share | 56.00 | % |  | 4 |  |  | 1 |  |  | — |
| Mercer Solar | 63.00 | % |  | 13 |  | — |  |  | 23
| Mill Creek Unit 5 | 69.00 | % |  | 1 |  |  | — |  |  | 486
| Brown Wind | 64.00 | % |  | 1 |  |  | — |  |  | — |
| December 31, 2024 |  |  |  |  |  |  |
| E.W. Brown Units 6-7 | 62.00 | % |  | $ | 87 |  |  | $ | 48 |  |  | $ | — |
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 47.00 | % |  | 46 |  |  | 26 |  |  | — |
| Trimble County Unit 2 | 60.75 | % |  | 1,077 |  |  | 224 |  |  | 5 |
| Trimble County Units 5-6 | 71.00 | % |  | 87 |  |  | 44 |  |  | — |
| Trimble County Units 7-10 | 63.00 | % |  | 136 |  |  | 69 |  |  | 1 |
| Cane Run Unit 7 | 78.00 | % |  | 485 |  |  | 95 |  |  | 1 |
| E.W. Brown Solar Unit | 61.00 | % |  | 16 |  |  | 6 |  |  | — |
| Solar Share | 56.00 | % |  | 4 |  |  | 1 |  |  | — |
| Mercer Solar | 63.00 | % |  | 16 |  |  | — |  |  | 2 |
| Mill Creek Unit 5 | 69.00 | % |  | — |  |  | — |  |  | 164 |
| Brown Wind | 64.00 | % |  | 1 |  |  | — |  |  | — |

Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs associated with the plants is included in the corresponding operating expenses on the Statements of Income.
12. Commitments and Contingencies
Energy Purchase Commitments
(PPL, LG&E and KU)
LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's retail natural gas supply operations. These contracts include the following commitments:

Contract Type | Maximum Maturity Date
Natural Gas Fuel | 2027
Natural Gas Retail Supply | 2026
Coal | 2030
Coal Transportation and Fleeting Services | 2033
Natural Gas Transportation | 2055

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LG&E and KU have a PPA with OVEC expiring in June 2040. See footnote (d) to the table in "Guarantees and Other Assurances" below for information on the OVEC power purchase contract. Future obligations for power purchases from OVEC are demand payments, comprised of debt-service payments and contractually-required reimbursements of plant operating, maintenance and other expenses, and are projected as follows:

| LG&E |  | KU |  | Total
2026 | $ | 19 |  |  | $ | 8 |  |  | $ | 27 |
2027 | 24 |  |  | 10 |  |  | 34 |
2028 | 24 |  |  | 11 |  |  | 35 |
2029 | 25 |  |  | 11 |  |  | 36 |
2030 | 23 |  |  | 10 |  |  | 33 |
Thereafter | 184 |  |  | 83 |  |  | 267 |
Total | $ | 299 |  |  | $ | 133 |  |  | $ | 432 |

LG&E and KU had total energy purchases under the OVEC PPA for the years ended December 31 as follows:

| 2025 |  | 2024 |  | 2023
LG&E | $ | 26 |  |  | $ | 21 |  |  | $ | 20 |
KU | 11 |  |  | 9 |  |  | 9 |
Total | $ | 37 |  |  | $ | 30 |  |  | $ | 29 |

(PPL)
RIE enters into purchase contracts to supply electricity for electricity distribution operations and for the delivery, storage and supply of natural gas for RIE's retail natural gas operations.
These contracts include the following commitments:

Contract Type | Maximum Maturity Date
Electric power | 2027
Gas-related | 2043

RIE's commitments under these long-term contracts subsequent to December 31, 2025 are summarized in the table below.

| Total |  | 2026 |  | 2027-2028 |  | 2029-2030 |  | Thereafter
Energy Purchase Obligations | $ | 939 |  |  | $ | 268 |  |  | $ | 199 |  |  | $ | 126 |  |  | $ | 346 |

Long-term Contracts for Renewable Energy (PPL)
Several of the obligations included in the table above relate to certain long-term contracts for renewable energy, including:
•the Deepwater Wind PPA, a small-scale renewable energy generation project of up to eight offshore wind turbines with an aggregate nameplate capacity of up to 30 MW to benefit the Town of New Shoreham and an underwater cable to Block Island, placed into service in 2016;
•the Three-State Procurement, involving six clean energy long-term contracts pursuant to the Rhode Island Long-Term Contracting Standard (LTCS) of which approximately 36 MW is currently operational and with respect to which RIE collects 2.75% remunerations in the annual payments pursuant to the LTCS; and
•the Offshore Wind Energy Procurement, pursuant to a 20-year PPA with Deep Water Wind Rev I, LLC (Revolution Wind), with an expected nameplate capacity of 407 MW and is expected to be operational in 2026; this contract was approved without remuneration but allows RIE to seek costs incurred under the agreement.
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In addition, RIE is obligated under the LTCS (as amended in 2014) to annually solicit for renewable projects until 90 MW of renewable contracting capacity has been secured. The RIPUC-approved solicitations currently in service include: (i) a 15-year PPA with Orbit Energy Rhode Island, LLC for a 3.2 MW nameplate anaerobic digester biogas project located in Johnston, Rhode Island, placed in service in 2017, (ii) a 15-year PPA with Black Bear Development Holdings, LLC for a 3.9 MW nameplate run-of-river hydroelectric plant located in Orono, Maine, placed in service in 2013, (iii) a 15-year PPA with Copenhagen Wind Farm, LLC for an 80 MW nameplate land-based wind project located in Denmark, New York, placed in service in 2018, and (iv) a 15-year PPA with Rhode Island LFG Genco, LLC for a 32.1 MW nameplate combined cycle combustion turbine generating facility fueled by a landfill gas project located in Johnston, Rhode Island, placed in service in 2013. On December 23, 2025, the RIPUC approved the RFP for soliciting renewable energy under LTCS. Under the approved schedule, the RFP will be released, and the solicitation will commence on May 13, 2026 with the deadline for the submission of bids proposals on August 12, 2026.
In addition to the LTCS, on December 19, 2025, RIE along with state agencies and utilities in Maine, Massachusetts, Connecticut and Vermont, released a multi-state RFP to identify competitive proposals for renewable energy and associated transmission infrastructure in Northern Maine under the Affordable Clean Energy Security Act (ACES), as amended in 2022. Bids are due at the end of February 2026 and the selection process will conclude in the third quarter of 2026.
As approved by the RIPUC, RIE is allowed to pass through commodity-related/purchased power costs to customers and collect remuneration equal to 2.75% for long-term contracts approved prior to January 1, 2022, pursuant to LTCS as amended in 2022, and that have achieved commercial operation. For long-term contracts approved pursuant to LTCS or ACES, both as amended, on or after January 1, 2022, RIE is entitled to financial remuneration equal to 1.0% through December 31, 2026, for those projects that are commercially operating. For long-term contracts approved pursuant to LTCS or ACES on or after January 1, 2027, RIE is not entitled to any financial remuneration, unless otherwise granted by the RIPUC. Also, the 2022 amendments to LTCS and ACES added a provision, which provides that for any calendar year in which RIE's actual return on equity exceeds the return on equity allowed by the RIPUC in the last general rate case, the RIPUC may adjust any or all remuneration to assure that such remuneration does not result in or contribute toward RIE earning above its allowed return for such calendar year.
Legal Matters
(All Registrants)
PPL and its subsidiaries are involved in legal proceedings, claims and litigation in the ordinary course of business. PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.
Narragansett Electric Litigation (PPL)
Energy Efficiency Programs Investigation
Narragansett Electric, while under the ownership of National Grid, performed an internal investigation into conduct associated with its energy efficiency programs. On June 27, 2022, the RIPUC opened a new docket (RIPUC Docket No. 22-05-EE) to investigate RIE's actions and the actions of employees of National Grid USA and affiliates during the time RIE was a National Grid USA affiliate being provided services by National Grid USA Service Company, Inc. relating to the manipulation of the reporting of invoices affecting the calculation of past energy efficiency shareholder incentives and the resulting impact on customers. The Rhode Island Attorney General and National Grid USA intervened in the docket and the Rhode Island Division of Public Utilities and Carriers (the Division) is an automatic party in the docket.
On February 21, 2025, the Division filed testimony confirming its initial testimony that $12 million is the appropriate amount to be refunded to the energy efficiency program. On March 4, 2025, a Settlement Agreement between RIE, the Division, and the Rhode Island Attorney General was filed with the RIPUC requiring refunds of $10 million. Of this amount, $2 million has already been refunded through the energy efficiency mechanism with the remaining $8 million to reduce the storm cost regulatory asset recorded on PPL's balance sheet. The settlement also included reimbursement of minor consulting fees and various other compliance actions. On March 5, 2025, the RIPUC approved the Settlement Agreement.
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E.W. Brown Environmental Assessment (PPL and KU)
KU is undertaking extensive remedial measures at the E.W. Brown plant including closure of the former ash pond, implementation of a groundwater remedial action plan and performance of a corrective action plan including aquatic study of adjacent surface waters and risk assessment. The aquatic study and risk assessment are being undertaken pursuant to a 2017 Agreed Order with the Kentucky Energy and Environment Cabinet (KEEC). KU conducted sampling of Herrington Lake in 2017 and 2018. In June 2019, KU submitted to the KEEC the required aquatic study and risk assessment, conducted by an independent third-party consultant, finding that discharges from the E.W. Brown plant have not had any significant impact on Herrington Lake and that the water in the lake is safe for recreational use and meets safe drinking water standards. On May 31, 2021, the KEEC approved the report and released a response to public comments. On August 6, 2021, KU submitted a Supplemental Remedial Alternatives Analysis report to the KEEC that outlines proposed additional fish, water, and sediment testing. On February 18, 2022, the KEEC provided approval to KU to proceed with the proposed sampling, which commenced in the spring of 2022. On November 17, 2022, KU submitted a Supplemental Performance Monitoring Report to the KEEC finding that there are no significant unaddressed risks to human health or the environment at the plant. KU revised the Supplemental Performance Monitoring Report on June 8, 2023, in response to KEEC comments from April 24, 2023. On September 1, 2023, the KEEC requested KU to propose additional monitoring or remedial measures. KU submitted a revised Supplemental Performance Monitoring and Corrective Action Completion on December 28, 2023. In August 2024, KU submitted a proposed environmental covenant to the KEEC specifying certain site restrictions. Discussions between KU and the KEEC are ongoing, but KU cannot predict the outcome of this matter.
(PPL, LG&E and KU)
EPA Deregulatory Initiative
On March 12, 2025, the EPA announced a plan to reconsider 31 environmental rules including the Section 111 performance standards and emissions limits for greenhouse gases, the endangerment finding for greenhouse gases, the Good Neighbor Plan, the Mercury and Air Toxics Standards, revisions to the fine particulate matter standard, the ELGs, and the CCRs Rule. Supplementing previous Executive Orders directing various regulatory changes, on April 9, 2025, President Trump issued an Executive Order and Presidential Memorandum directing review of existing rules, repeal of unlawful rules, and initiation of a zero-based budgeting process by which certain rules would automatically expire unless extended. While the current Presidential administration may seek to implement some regulatory changes outside of the rulemaking process, changes to existing rules are generally expected to require formal rulemaking proceedings. Any final EPA actions repealing or revising current rules will likely result in legal challenges. PPL, LG&E, and KU are unable to predict future regulatory changes, if any, that may result from the EPA's deregulatory plan or the outcome of any associated legal challenges. PPL, LG&E, and KU are closely monitoring the ongoing EPA initiative and any related litigation for the impact to our business including planned capital expenditures to comply with the EPA rules.
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Water/Waste
ELGs
In 2015, the EPA finalized ELGs for wastewater discharge permits for new and existing steam electricity generating facilities. These guidelines require deployment of additional control technologies providing physical, chemical and biological treatment and mandate operational changes including "zero discharge" requirements for certain wastewaters. The implementation date for individual generating stations was to be determined by the states on a case-by-case basis according to criteria provided by the EPA. In September 2017, the EPA issued a rule to postpone the compliance date for certain requirements. In October 2020, the EPA issued revisions to its best available technology standards for certain wastewaters and potential extensions to compliance dates (the Reconsideration Rule). On May 9, 2024, the EPA issued a final rule modifying the 2020 ELG revisions. The rule increases the stringency of previous control technology and zero discharge requirements, revises certain exemptions for generating units planned for retirement, and requires case-by-case limitations for legacy wastewaters based on the best professional judgment of the state regulators. Legal challenges to the final rule have been consolidated before the U.S. Court of Appeals for the Eighth Circuit. The final rule could potentially result in significant operational changes and additional controls for LG&E and KU plants, but in March 2025 the EPA announced its plan to reconsider the rule. The ELGs are expected to be implemented by the states or applicable permitting authorities in the course of their normal permitting activities. Certain costs are included in the Registrants' capital plans and expected to be recovered from customers through rate recovery mechanisms, but additional costs and recovery will depend on further regulatory developments at the state level. On December 31, 2025, the EPA issued a final rule extending the retirement exemption category application deadline an additional six years, from December 2025 to December 2031 and a five-year extension to the zero liquid discharge deadlines, from December 2029 to December 2034. The EPA announced that it will conduct a technology review of the zero liquid discharge technology in a future rulemaking.
CCRs
In 2015, the EPA issued a final rule governing management of CCRs, which include fly ash, bottom ash and sulfur dioxide scrubber wastes (2015 CCR Rule). The 2015 CCR Rule imposed extensive new requirements for certain CCR impoundments and landfills, including public notifications, location restrictions, design and operating standards, groundwater monitoring and corrective action requirements, and closure and post-closure care requirements, and specifies restrictions relating to the beneficial use of CCRs. In January 2022, the EPA issued several proposed regulatory determinations, facility notifications, and public announcements which indicate increased scrutiny by the EPA to determine the adequacy of measures taken by facility owners and operators to achieve closure of CCR surface impoundments and landfills. In particular, the agency indicated that it will focus on certain practices which it views as posing a threat of continuing groundwater contamination. On May 8, 2024, the EPA issued a final rule (2024 CCR Rule) establishing regulatory requirements for inactive surface impoundments at inactive electricity generation facilities (legacy impoundments). The 2024 CCR Rule also establishes identification, groundwater monitoring, corrective action, closure, and post-closure care requirements for all CCR management units, as defined in the rule, at regulated CCR facilities regardless of how or when the CCR was placed. The rule also requires LG&E and KU to complete applicability determinations, implement site security measures, initiate weekly inspections and monthly monitoring of the impoundment, create a website, and complete hazard assessments and reports for its legacy impoundments. Additionally, the rule could potentially subject CCR management units that have previously completed remedial action and closure and certain beneficial use projects to additional federal regulatory requirements. Legal challenges to the rule have been filed in the D.C. Circuit Court. In March 2025, the EPA announced its plan to update the rule. On July 22, 2025, the EPA published a proposed rule to extend the deadline for select CCR management units for the Facility Evaluation Report Part 1 and Part 2 by one year to February 2027 and February 2028, respectively. The proposed rule would also extend the groundwater monitoring deadline to August 8, 2030, with the initial groundwater monitoring report extended to January 31, 2031.
In connection with the 2015 CCR Rule, LG&E and KU recorded adjustments to existing AROs beginning in 2015. In connection with the 2024 CCR Rule, in the second quarter of 2024, LG&E and KU recognized ARO obligations related to preliminary risk assessments, facility evaluations, feasibility studies and sampling. See Note 18 for additional information. The results of those evaluations, as well as future guidance, regulatory determinations, rulemakings, implementation determinations and other developments could potentially require revisions to current LG&E and KU compliance plans including additional monitoring and remediation at surface impoundments and landfills, the cost of which could be material. PPL, LG&E and KU are unable to predict the outcome of the ongoing litigation, rulemaking, and regulatory determinations or potential impacts on current LG&E and KU compliance plans. PPL, LG&E and KU are currently finalizing or revising closure plans and schedules in accordance with applicable regulations and further material changes to AROs, current capital plans or operating costs may be required as estimates are refined based on closure developments, groundwater monitoring results, and regulatory or legal proceedings. Costs relating to this rule are expected to be subject to rate recovery.
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LG&E and KU received KPSC approval for a compliance plan associated with the 2015 CCR Rule providing for the closure of impoundments at the Mill Creek, Trimble County, E.W. Brown, and Ghent stations, and construction of process water management facilities at those plants. In addition to the foregoing measures required for compliance with the federal CCR Rule, KU also received KPSC approval for its plans to close impoundments at the retired Green River, Pineville and Tyrone plants to comply with applicable state law. LG&E and KU have completed planned closure measures at most of the subject impoundments and have commenced post closure groundwater monitoring as required at those facilities. Associated costs are subject to rate recovery through the Companies' ECR adjustment clause.
Superfund and Other Remediation
(All Registrants)
The Registrants are potentially responsible for investigating and remediating contamination under the federal Superfund program and similar state programs. Actions are under way at certain sites including former manufactured gas plants in Pennsylvania, Rhode Island and Kentucky previously owned or operated by, or currently owned by predecessors or affiliates of, PPL subsidiaries.
Depending on the outcome of investigations at identified sites where investigations have not begun or been completed, or developments at sites for which information is incomplete, additional costs of remediation could be incurred. PPL, PPL Electric, LG&E and KU lack sufficient information about such additional sites to estimate any potential liability or range of reasonably possible losses, if any, related to these sites. Such costs, however, are not currently expected to be significant.
The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of manufactured gas plant operations. As a result, individual states may establish stricter standards for water quality and soil cleanup, that could require several PPL subsidiaries to take more extensive assessment and remedial actions at former manufactured gas plants. The Registrants cannot reasonably estimate a range of possible losses, if any, related to these matters.
(PPL and PPL Electric)
PPL Electric is a potentially responsible party for a share of clean-up costs at certain sites. Cleanup actions have been or are being undertaken at these sites as requested by governmental agencies, the costs of which have not been and are not expected to be significant to PPL Electric.
At December 31, 2025 and December 31, 2024, PPL Electric had a recorded liability of $8 million and $8 million, representing its best estimate of the probable loss incurred to remediate these sites.
(PPL)
RIE is a potentially responsible party for a share of clean-up costs at certain sites including former manufactured gas plant facilities formerly owned by the Blackstone Valley Gas and Electric Company and the Rhode Island gas distribution assets of the New England Gas division of Southern Union Company and electric operations at certain RIE facilities. RIE is currently investigating and remediating, as necessary, those sites and certain other properties under agreements with governmental agencies, the costs of which have not been and are not expected to be significant to PPL.
At December 31, 2025 and December 31, 2024, RIE had a recorded liability of $98 million and $98 million, representing its best estimate of the remaining costs of environmental remediation activities. These undiscounted costs are expected to be incurred over approximately 30 years and to be subject to rate recovery. However, remediation costs for each site may be materially higher than estimated, depending on changing technologies and regulatory standards, selected end uses for each site, and actual environmental conditions encountered. RIE has recovered amounts from certain insurers and potentially responsible parties, and, where appropriate, may seek additional recovery from other insurers and potentially responsible parties, but it is uncertain whether, and to what extent, such efforts will be successful.
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The RIPUC has approved two settlement agreements that provide for rate recovery of qualified remediation costs of certain contaminated sites located in Rhode Island and Massachusetts. Rate-recoverable contributions for electric operations of approximately $3 million are added annually to RIE's Environmental Response Fund, established with RIPUC approval in March 2000 to address such costs, along with interest and any recoveries from insurance carriers and other third-parties. In addition, RIE recovers approximately $1 million annually for gas operations under a distribution adjustment charge in which the qualified remediation costs are amortized over 10 years. See Note 7 for additional information on RIE's recorded environmental regulatory assets and liabilities.
Regulatory Issues
See Note 7 for information on regulatory matters related to utility rate regulation.
Electricity - Reliability Standards
The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk electric system in North America. The FERC oversees this process and independently enforces the Reliability Standards.
The Reliability Standards have the force and effect of law and apply to certain users of the bulk electric system, including electric utility companies, generators and marketers. Under the Federal Power Act, the FERC may assess civil penalties for certain violations.
PPL Electric, LG&E, KU and RIE monitor their compliance with the Reliability Standards and self-report or self-log potential violations of applicable reliability requirements whenever identified, and submit accompanying mitigation plans, as required. The resolution of a small number of potential violations is pending. Penalties incurred to date have not been significant. Any Regional Reliability Entity determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC.
In the course of implementing their programs to ensure compliance with the Reliability Standards by those PPL affiliates subject to the standards, certain other instances of potential non-compliance may be identified from time to time. The Registrants cannot predict the outcome of these matters, and an estimate or range of possible losses cannot be determined.
Gas - Security Directives (PPL and LG&E)
In May and July of 2021, the Department of Homeland Security's (DHS) Transportation Security Administration issued two security directives applicable to certain notified owners and operators of natural gas pipeline facilities (including local distribution companies) that the Transportation Security Administration has determined to be critical. Both security directives have been updated and extended multiple times. The Transportation Security Administration has determined that LG&E is within the scope of the directives, while RIE has not been notified of this distinction. The first directive, most recently updated and now effective through January 2027, requires notified owners/operators to report specified cybersecurity incidents to the DHS, designate a cybersecurity coordinator, and perform a gap assessment of current entity cybersecurity practices against certain voluntary Transportation Security Administration security guidelines and report results and proposed mitigation to the DHS. The second security directive, updated and effective through May 2026, requires refinement of a Transportation Security Administration-approved Cybersecurity Implementation Plan (CIP) and the Cybersecurity Assessment Plan (CAP). The Transportation Security Administration has transitioned to a performance‑based regulatory model, requiring operators to meet defined cybersecurity outcomes rather than implement prescriptive controls. Key requirements now include: maintaining a Transportation Security Administration‑approved CIP; reporting significant cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (CISA) within 24 hours; completing annual CAPs with all CIP measures assessed on a three‑year cycle; conducting annual testing of at least two Cybersecurity Incident Response Plan (CIRP) objectives; meeting new 2026 vetting requirements for non‑U.S. citizen cybersecurity coordinators (who must participate in a trusted traveler program); and complying with clarified rules governing shared responsibilities when third parties support pipeline operations. LG&E does not believe these security directives or their updates have had, or are expected to have, a material impact on its operations or financial condition.
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Other
Guarantees and Other Assurances
(All Registrants)
In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. Examples of such agreements include: guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage.
(PPL)
PPL fully and unconditionally guarantees all of the debt securities and loan obligations of PPL Capital Funding.
(All Registrants)
The table below details guarantees provided as of December 31, 2025. "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee. The Registrants believe the probability of expected payment/performance under each of these guarantees is remote, except for the guarantee related to the payment obligations of Safari under certain sale/leaseback financing transactions and PPL's agreement to fund any increases in the fair value of those obligations, which PPL believes are reasonably possible of occurring. For reporting purposes, on a consolidated basis, the guarantees of PPL include the guarantees of its subsidiary Registrants.

| Exposure at December 31, 2025 |  | Expiration Date
PPL |  |  |
Indemnifications related to certain tax liabilities related to the sale of the U.K. utility business | £ | 50 |  | (a) | 2028
PPL guarantees related to certain sale/leaseback financing transactions related to the sale of Safari Holdings | $ | 71 |  | (b) | 2028
Indemnifications for losses suffered related to items not covered by Aspen Power's representation and warranty insurance associated with the sale of Safari Holdings | 140 |  | (c) | 2028
LG&E and KU |  |  |
LG&E and KU obligation of shortfall related to OVEC |  | (d) |

(a)PPL WPD Limited entered into a Tax Deed dated June 9, 2021 in which it agreed to a tax indemnity regarding certain potential tax liabilities of the entities sold with respect to periods prior to the completion of the sale, subject to customary exclusions and limitations. Because National Grid Holdings One plc, the buyer, agreed to purchase indemnity insurance, the amount of the cap on the indemnity for these liabilities is £1, except with respect to certain surrenders of tax losses, for which the amount of the cap on the indemnity is £50 million. In June 2025, the indemnifications were novated to PPL Energy Holdings.
(b)PPL guaranteed the payment obligations of Safari under certain sale/leaseback financing transactions executed by Safari. These guarantees will remain in place until Safari exercises its option to buy-out the projects under the sale/leaseback financings by the year 2028. Safari will indemnify PPL for any payments made by PPL or claims against PPL under the sale/leaseback transaction guarantees up to $25 million.
Separately, PPL has agreed to fund incremental payment obligations under the buy-outs resulting from increases in the fair market value of the projects from the initial fair market value determined at the time of PPL's sale of Safari Holdings to the time the buy-out options are exercised by Safari. As of December 31, 2025, PPL cannot reasonably estimate its payment obligations related to the remaining buy-out options.
(c)Aspen Power has obtained representation and warranty insurance, therefore, PPL generally has no liability for its representations and warranties under the agreement except for losses suffered related to items not covered. Expiration of these indemnifications range from 18 months to 6 years from the date of the closing of the transaction, and PPL's aggregate liability for these claims will not exceed $140 million subject to certain adjustments.
(d)Pursuant to the OVEC power purchase contract, LG&E and KU are obligated to pay for their share of OVEC's excess debt service, post-retirement and decommissioning costs, as well as any shortfall from amounts included within a demand charge designed and expected to cover these costs over the term of the contract. PPL's proportionate share of OVEC's outstanding debt was $71 million at December 31, 2025, consisting of LG&E's share of $49 million and KU's share of $22 million. The maximum exposure and the expiration date of these potential obligations are not presently determinable. See "Energy Purchase Commitments" above for additional information on the OVEC power purchase contract.
The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business. These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration. The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is remote.
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PPL, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage. The coverage provides maximum aggregate coverage of $231 million for non-wildfire liability losses and maximum aggregate coverage of $181 million for wildfire liability losses. This insurance may be applicable to obligations under certain of these contractual arrangements.
13. Related Party Transactions
Wholesale Sales and Purchases (LG&E and KU)
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail customers. When LG&E has excess generation capacity after serving its own retail customers and its generation cost is lower than that of KU, KU purchases electricity from LG&E and vice versa. These transactions are reflected in the Statements of Income as "Electric revenue from affiliate" and "Energy purchases from affiliate" and are recorded at a price equal to the seller's fuel cost plus any split savings. Savings realized from such intercompany transactions are shared equally between both companies. The volume of energy each company has to sell to the other is dependent on its retail customers' needs and its available generation.
Support Costs (PPL Electric, LG&E and KU)
PPL Services and LKS provide the Registrants, their respective subsidiaries and each other with administrative, management and support services. For all services companies, the costs of directly assignable and attributable services are charged to the respective recipients as direct support costs. General costs that cannot be directly attributed to a specific entity are allocated and charged to the respective recipients as indirect support costs. PPL Services and LKS use a three-factor methodology that includes the applicable recipients' invested capital, operation and maintenance expenses and number of employees to allocate indirect costs. PPL Services may also use a ratio of overall direct and indirect costs or a weighted average cost ratio. PPL Services and LKS charged the following amounts for the years ended December 31, including amounts applied to accounts that are further distributed between capital and expense on the books of the recipients, based on methods that are believed to be reasonable.

| 2025 |  | 2024 |  | 2023
PPL Electric from PPL Services | $ | 261 |  |  | $ | 227 |  |  | $ | 222 |
LG&E from LKS | 113 |  |  | 105 |  |  | 115 |
LG&E from PPL Services | 135 |  |  | 66 |  |  | 42 |
KU from LKS | 141 |  |  | 130 |  |  | 150 |
KU from PPL Services | 131 |  |  | 65 |  |  | 48 |

In addition to the charges for services noted above, LKS makes payments on behalf of LG&E and KU for fuel purchases and other costs for products or services provided by third parties. LG&E and KU also provide services to each other and to LKS. Billings between LG&E and KU relate to labor and overheads associated with union and hourly employees performing work for the other company, charges related to jointly-owned generating units and other miscellaneous charges. Tax settlements between PPL and LG&E and KU are reimbursed through LKS.
Intercompany Borrowings
(PPL Electric)
CEP Reserves maintains a $800 million revolving line of credit with a PPL Electric subsidiary. At December 31, 2025, CEP Reserves had $143 million of borrowings outstanding. At December 31, 2024, CEP Reserves had $222 million borrowings outstanding. The interest rates on borrowings are equal to one-month SOFR plus a spread. Interest income is reflected in "Interest Income from Affiliate" on the Income Statements.
(LG&E and KU)
LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to the difference between LG&E's FERC borrowing limit and LG&E's commercial paper limit at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on SOFR. At December 31, 2025, LG&E's money pool unused capacity was $750 million. At December 31, 2025 LG&E had no borrowings from KU and/or LKE. At December 31, 2024, LG&E's borrowings outstanding from KU and/or LKE were $43 million.
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KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to the difference between KU's FERC borrowing limit and KU's commercial paper limit at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on SOFR. At December 31, 2025, KU's money pool unused capacity was $614 million. At December 31, 2025 KU had borrowings outstanding of $36 million from LG&E and/or LKE. At December 31, 2024, KU's borrowings outstanding from LG&E and/or LKE were $73 million.
VEBA Funds Receivable
(PPL Electric)
In 2018, PPL received a favorable private letter ruling from the IRS permitting a transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to a new subaccount within the VEBA, to be used to pay medical claims of active bargaining unit employees. In October 2024, additional excess funds were removed from the PPL Bargaining Unit Retiree Health Plan VEBA and deposited into the existing subaccount within the VEBA to be used to pay medical claims of active bargaining unit employees. Based on PPL Electric's participation in PPL's Other Postretirement Benefit plan, PPL Electric was allocated a portion of the excess funds from PPL Services. These funds have been recorded as an intercompany receivable on PPL Electric's balance sheets. The receivable balance decreases as PPL Electric pays incurred medical claims and is reimbursed by PPL Services. There was no intercompany receivable balance associated with these funds at December 31, 2025, as PPL Electric's allocation of excess funds was depleted. The intercompany receivable balance associated with these funds was $7 million at December 31, 2024, of which $4 million was reflected in "Accounts receivable from affiliates" and $3 million was reflected in "Other noncurrent assets" on PPL Electric's balance sheets.
Other (PPL Electric, LG&E and KU)
See Note 1 for discussions regarding the intercompany tax sharing agreement (for PPL Electric, LG&E and KU) and intercompany allocations of stock-based compensation expense (for PPL Electric). For PPL Electric, LG&E and KU, see Note 10 for discussions regarding intercompany allocations associated with defined benefits.
14. Other Income (Expense) - net
(PPL)
The components of "Other Income (Expense) - net" for the years ended December 31, were:

| 2025 |  | 2024 |  | 2023
Defined benefit plans - non-service credits (Note 10) | $ | 59 |  |  | $ | 42 |  |  | $ | 40 |
Interest income | 20 |  |  | 33 |  |  | 32 |
AFUDC - equity component | 81 |  |  | 47 |  |  | 30 |
Talen litigation (a) | — |  |  | (2) |  |  | (124) |
Miscellaneous | (9) |  |  | (6) |  |  | (18) |
Other Income (Expense) - net | $ | 151 |  |  | $ | 114 |  |  | $ | (40) |

(a)PPL incurred legal expenses related to litigation associated with its former affiliate, Talen Montana, LLC, and certain affiliated entities (collectively, Talen), which was settled in December 2023.
(PPL Electric)
The components of "Other Income (Expense) - net" for the years ended December 31, were:

| 2025 |  | 2024 |  | 2023
Defined benefit plans - non-service credits (Note 10) | $ | 14 |  |  | $ | 17 |  |  | $ | 20 |
Interest income | 8 |  |  | 8 |  |  | 8 |
AFUDC - equity component | 30 |  |  | 23 |  |  | 16 |
Miscellaneous | (4) |  |  | (3) |  |  | (5) |
Other Income (Expense) - net | $ | 48 |  |  | $ | 45 |  |  | $ | 39 |

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(LG&E)
The components of "Other Income (Expense) - net" for the years ended December 31, were:

| 2025 |  | 2024 |  | 2023
Defined benefit plans - non-service credits (Note 10) | $ | 3 |  |  | $ | 3 |  |  | $ | — |
AFUDC - equity component | 16 |  |  | 8 |  |  | 3 |
Miscellaneous | 5 |  |  | 1 |  |  | — |
Other Income (Expense) - net | $ | 24 |  |  | $ | 12 |  |  | $ | 3 |

(KU)
The components of "Other Income (Expense) - net" for the years ended December 31, were:

| 2025 |  | 2024 |  | 2023
Defined benefit plans - non-service credits (Note 10) | $ | 7 |  |  | $ | 8 |  |  | $ | 6 |
AFUDC - equity component | 21 |  |  | 9 |  |  | 3 |
Miscellaneous | 1 |  |  | (2) |  |  | (1) |
Other Income (Expense) - net | $ | 29 |  |  | $ | 15 |  |  | $ | 8 |

15. Fair Value Measurements
(All Registrants)
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). A market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models), and/or a cost approach (generally, replacement cost) are used to measure the fair value of an asset or liability, as appropriate. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk. The fair value of a group of financial assets and liabilities is measured on a net basis. See Note 1 for information on the levels in the fair value hierarchy.
Recurring Fair Value Measurements
The assets and liabilities measured at fair value were:

| December 31, 2025 |  | December 31, 2024
| Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3
PPL |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | 1,071 |  |  | $ | 1,071 |  |  | $ | — |  |  | $ | — |  |  | $ | 306 |  |  | $ | 306 |  |  | $ | — |  |  | $ | — |
Restricted cash and cash equivalents (a) | 15 |  |  | 15 |  |  | — |  |  | — |  |  | 33 |  |  | 33 |  |  | — |  |  | — |
Total Cash, Cash Equivalents and Restricted Cash (b) | 1,086 |  |  | 1,086 |  |  | — |  |  | — |  |  | 339 |  |  | 339 |  |  | — |  |  | — |
Special use funds (a): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Money market fund | 1 |  |  | 1 |  |  | — |  |  | — |  |  | 1 |  |  | 1 |  |  | — |  |  | — |
Commingled debt fund measured at NAV (c) | 5 |  |  | — |  |  | — |  |  | — |  |  | 10 |  |  | — |  |  | — |  |  | — |
Commingled equity fund measured at NAV (c) | 5 |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | — |  |  | — |  |  | — |
Total special use funds | 11 |  |  | 1 |  |  | — |  |  | — |  |  | 19 |  |  | 1 |  |  | — |  |  | — |

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| December 31, 2025 |  | December 31, 2024
| Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3
Price risk management assets (d): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas contracts | 6 |  |  | — |  |  | 2 |  |  | 4 |  |  | 9 |  |  | — |  |  | 4 |  |  | 5 |
Total assets | $ | 1,103 |  |  | $ | 1,087 |  |  | $ | 2 |  |  | $ | 4 |  |  | $ | 367 |  |  | $ | 340 |  |  | $ | 4 |  |  | $ | 5 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price risk management liabilities (d): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives | $ | 5 |  |  | $ | — |  |  | $ | 5 |  |  | $ | — |  |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |  |  | $ | — |
Gas contracts | 10 |  |  | — |  |  | 6 |  |  | 4 |  |  | 13 |  |  | — |  |  | 10 |  |  | 3 |
Total price risk management liabilities | $ | 15 |  |  | $ | — |  |  | $ | 11 |  |  | $ | 4 |  |  | $ | 16 |  |  | $ | — |  |  | $ | 13 |  |  | $ | 3 |
PPL Electric |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | 30 |  |  | $ | 30 |  |  | $ | — |  |  | $ | — |  |  | $ | 24 |  |  | $ | 24 |  |  | $ | — |  |  | $ | — |
Total assets | $ | 30 |  |  | $ | 30 |  |  | $ | — |  |  | $ | — |  |  | $ | 24 |  |  | $ | 24 |  |  | $ | — |  |  | $ | — |
LG&E |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | 162 |  |  | $ | 162 |  |  | $ | — |  |  | $ | — |  |  | $ | 8 |  |  | $ | 8 |  |  | $ | — |  |  | $ | — |
Restricted cash and cash equivalents (a) | 7 |  |  | 7 |  |  | — |  |  | — |  |  | 16 |  |  | 16 |  |  | — |  |  | — |
Total Cash, Cash Equivalents and Restricted Cash (b) | 169 |  |  | 169 |  |  | — |  |  | — |  |  | 24 |  |  | 24 |  |  | — |  |  | — |
Total assets | $ | 169 |  |  | $ | 169 |  |  | $ | — |  |  | $ | — |  |  | $ | 24 |  |  | $ | 24 |  |  | $ | — |  |  | $ | — |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price risk management liabilities (e): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives | $ | 5 |  |  | $ | — |  |  | $ | 5 |  |  | $ | — |  |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |  |  | $ | — |
Total price risk management liabilities | $ | 5 |  |  | $ | — |  |  | $ | 5 |  |  | $ | — |  |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |  |  | $ | — |
KU |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents | $ | 10 |  |  | $ | 10 |  |  | $ | — |  |  | $ | — |  |  | $ | 13 |  |  | $ | 13 |  |  | $ | — |  |  | $ | — |
Restricted cash and cash equivalents (a) | 7 |  |  | 7 |  |  | — |  |  | — |  |  | 16 |  |  | 16 |  |  | — |  |  | — |
Total Cash, Cash Equivalents and Restricted Cash (b) | 17 |  |  | 17 |  |  | — |  |  | — |  |  | 29 |  |  | 29 |  |  | — |  |  | — |
Total assets | $ | 17 |  |  | $ | 17 |  |  | $ | — |  |  | $ | — |  |  | $ | 29 |  |  | $ | 29 |  |  | $ | — |  |  | $ | — |

(a)Current portion is included in "Other current assets" and noncurrent portion is included in "Other noncurrent assets" on the Balance Sheets.
(b)Total Cash, Cash Equivalents and Restricted Cash provides a reconciliation of these items reported within the Balance Sheets to the sum shown on the Statements of Cash Flows.
(c)In accordance with accounting guidance, certain investments that are measured at fair value using net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.
(d)Current portion is included in "Other current assets" and "Other current liabilities" and noncurrent portion is included in "Other noncurrent assets" "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
(e)Current portion is included in "Other current liabilities" on the Balance Sheets.
A reconciliation of net assets classified as Level 3 for the year ended December 31 is as follows:

| Gas Contracts
2025 |
Balance at beginning of period | $ | 2 |
Total unrealized gains (losses) recognized as Regulatory Assets/Regulatory Liabilities | (2) |
Balance at end of period | $ | — |

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Special Use Funds (PPL)
The special use funds are investments restricted for paying active union employee medical costs. In 2018, PPL received a favorable private letter ruling from the IRS permitting a transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to a new subaccount within the VEBA to be used to pay medical claims of active bargaining unit employees. In 2024, additional excess funds were removed from the PPL Bargaining Unit Retiree Health Plan VEBA and deposited in the existing subaccount within the VEBA to be used to pay medical claims of active bargaining unit employees. The funds are invested primarily in commingled debt and equity funds measured at NAV and are classified as investments in equity securities. Changes in the fair value of the funds are recorded to the Statements of Income.
Price Risk Management Assets/Liabilities
Interest Rate Derivatives (PPL, LG&E and KU)
To manage interest rate risk, PPL, LG&E and KU use interest rate derivatives such as treasury locks, forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps. An income approach is used to measure the fair value of these derivatives, utilizing readily observable inputs, such as forward interest rates (e.g., SOFR and government security rates), as well as inputs that may not be observable, such as credit valuation adjustments. In certain cases, market information cannot practicably be obtained to value credit risk and therefore internal models are relied upon. These models use projected probabilities of default and estimated recovery rates based on historical observances. When the credit valuation adjustment is significant to the overall valuation, the contracts are classified as Level 3.
Gas Contracts (PPL)
To manage gas commodity price risk associated with natural gas purchases, RIE utilizes over-the-counter (OTC) gas swaps contracts with pricing inputs obtained from the New York Mercantile Exchange (NYMEX) and the Intercontinental Exchange (ICE), except in cases where the ICE publishes seasonal averages or where there were no transactions within the last seven days. RIE may utilize discounting based on quoted interest rate curves, including consideration of non-performance risk, and may include a liquidity reserve calculated based on bid/ask spread. Substantially all of these price curves are observable in the marketplace throughout at least 95% of the remaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of 95% or higher. These contracts are classified as Level 2.
RIE also utilizes gas option and purchase and capacity transactions, which are valued based on internally developed models. Industry-standard valuation techniques, such as the Black-Scholes pricing model, are used for valuing such instruments. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is classified as Level 3. This includes derivative instruments valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are classified as Level 3 as the model inputs generally are not observable. RIE considers non-performance risk and liquidity risk in the valuation of derivative instruments classified as Level 2 and Level 3.
The significant unobservable inputs used in the fair value measurement of the gas derivative instruments are implied volatility and gas forward curves. A relative change in commodity price at various locations underlying the open positions can result in significantly different fair value estimates.
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Financial Instruments Not Recorded at Fair Value (All Registrants)
The carrying amounts of long-term debt on the Balance Sheets and their estimated fair values are set forth below. Long-term debt is classified as Level 2. The effect of third-party credit enhancements is not included in the fair value measurement.

| December 31, 2025 |  | December 31, 2024
| Carrying Amount (a) |  | Fair Value |  | Carrying Amount (a) |  | Fair Value
PPL | $ | 18,894 |  |  | $ | 18,488 |  |  | $ | 16,503 |  |  | $ | 15,562 |
PPL Electric | 5,707 |  |  | 5,473 |  |  | 5,214 |  |  | 4,862 |
LG&E | 2,865 |  |  | 2,784 |  |  | 2,471 |  |  | 2,295 |
KU | 3,510 |  |  | 3,304 |  |  | 3,066 |  |  | 2,750 |

(a)Amounts are net of debt issuance costs.
The carrying amounts of other current financial instruments (except for long-term debt due within one year) approximate their fair values because of their short-term nature.
16. Derivative Instruments and Hedging Activities
(All Registrants)
Risk Management Objectives
PPL has a risk management policy approved by the Board of Directors to manage market risk associated with commodities, interest rates on debt issuances (including price, liquidity and volumetric risk) and credit risk (including non-performance risk and payment default risk). The Risk Management Committee, comprised of senior management and chaired by the Vice President-Financial Strategy and Chief Risk Officer, oversees the risk management function. Key risk control activities designed to ensure compliance with the risk policy and detailed programs include, but are not limited to, credit review and approval, validation of transactions, verification of risk and transaction limits, value-at-risk analyses (VaR, a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level) and the coordination and reporting of the Enterprise Risk Management program.
Market Risk
Market risk includes the potential loss that may be incurred as a result of price changes associated with a particular financial or commodity instrument as well as market liquidity and volumetric risks. Forward contracts, futures contracts, options, swaps and structured transactions are utilized as part of risk management strategies to minimize unanticipated fluctuations in earnings caused by changes in commodity prices and interest rates. Many of these contracts meet the definition of a derivative. All derivatives are recognized on the Balance Sheets at their fair value, unless NPNS is elected.
The following summarizes the market risks that affect PPL and its subsidiaries.
Interest Rate Risk
•PPL and its subsidiaries are exposed to interest rate risk associated with forecasted fixed-rate and existing floating-rate debt issuances. PPL and LG&E utilize over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt. PPL, LG&E and KU utilize hedging instruments to limit exposure to fluctuations in benchmark interest rates, when appropriate, in connection with future debt issuance.
•PPL and its subsidiaries are exposed to interest rate risk associated with debt securities and derivatives held by defined benefit plans. This risk is significantly mitigated to the extent that the plans are sponsored at, or sponsored on behalf of, the regulated utilities due to the recovery methods in place.
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Commodity Price Risk
PPL is exposed to commodity price risk through its subsidiaries as described below.
•PPL Electric is required to purchase electricity to fulfill its obligation as a PLR. Potential commodity price risk is mitigated through its PAPUC-approved cost recovery mechanism and full-requirement supply agreements to serve its PLR customers which transfer the risk to energy suppliers.
•LG&E's and KU's rates include certain mechanisms for fuel, fuel-related expenses and energy purchases. In addition, LG&E's rates include a mechanism for natural gas supply costs. These mechanisms generally provide for timely recovery of market price fluctuations associated with these costs.
•RIE utilizes derivative instruments pursuant to its RIPUC-approved plan to manage commodity price risk associated with its natural gas purchases. RIE's commodity price risk management strategy is to reduce fluctuations in firm gas sales prices to its customers. RIE's costs associated with derivatives instruments are recoverable through its RIPUC-approved cost recovery mechanisms. RIE is also required to purchase electricity to fulfill its obligation to provide LRS. Potential commodity price risk is mitigated through its RIPUC-approved cost recovery mechanisms and full requirements service agreements to serve LRS customers, which transfer the risk to energy suppliers. Additionally, RIE is required to contract through long-term agreements for clean energy supply under the Rhode Island Renewable Energy Growth program and Long-term Clean Energy Standard. Potential commodity price risk is mitigated through its RIPUC-approved cost recovery mechanisms, which true-up cost differences between contract prices and market prices.
Volumetric Risk
Volumetric risk is the risk related to the changes in volume of retail sales mainly due to weather, economic conditions or other factors. PPL is exposed to volumetric risk through its subsidiaries as described below:
•PPL Electric, LG&E and KU are exposed to volumetric risk on retail sales, mainly due to weather and other economic conditions for which there is limited mitigation between rate cases.
•RIE is exposed to volumetric risk, which is significantly mitigated by regulatory mechanisms. RIE's electric and gas distribution rates both have a revenue decoupling mechanism, which allows for annual adjustments to RIE's delivery rates.
Equity Securities Price Risk
•PPL and its subsidiaries are exposed to equity securities price risk associated with the fair value of the defined benefit plans' assets. This risk is significantly mitigated due to the recovery methods in place.
•PPL is exposed to equity securities price risk from future stock sales and/or purchases.
Credit Risk
Credit risk is the potential loss that may be incurred due to a counterparty's non-performance.
PPL is exposed to credit risk from "in-the-money" transactions with counterparties as well as additional credit risk through certain of its subsidiaries, as discussed below.
In the event a supplier of PPL, PPL Electric, LG&E or KU defaults on its contractual obligation, those Registrants would be required to seek replacement power or replacement fuel in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities.
PPL and its subsidiaries have credit policies in place to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements or provisions. These agreements generally include credit mitigation provisions, such as margin, prepayment or collateral requirements. PPL and its subsidiaries may request additional credit assurance, in certain circumstances, if the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
Master Netting Arrangements (PPL, LG&E and KU)
Net derivative positions on the balance sheets are not offset against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
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PPL, LG&E and KU had no obligation to return or post cash collateral under master netting arrangements at December 31, 2025 and 2024.
See "Offsetting Derivative Instruments" below for a summary of derivative positions presented in the balance sheets where a right of setoff exists under these arrangements.
Interest Rate Risk
(All Registrants)
PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. A variety of financial derivative instruments are utilized to adjust the mix of fixed and floating interest rates in their debt portfolios, adjust the duration of the debt portfolios and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under PPL's risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of the debt portfolio due to changes in benchmark interest rates. In addition, the interest rate risk of certain subsidiaries is potentially mitigated as a result of the existing regulatory framework or the timing of rate cases.
Cash Flow Hedges (PPL)
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. Financial interest rate derivatives that qualify as cash flow hedges may be entered into to hedge floating interest rate risk associated with both existing and anticipated debt issuances. As of December 31, 2025, PPL held an aggregate notional value in interest rate derivatives of $20 million that mature on June 15, 2026.
Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time period and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedged transaction is not probable of occurring.
For 2025, 2024 and 2023, PPL had no cash flow hedges reclassified into earnings associated with discontinued cash flow hedges.
At December 31, 2025, the amount of accumulated net unrecognized after-tax gains (losses) on qualifying derivatives expected to be reclassified into earnings during the next 12 months is insignificant. Amounts are reclassified as the hedged interest expense is recorded.
Economic Activity (PPL and LG&E)
LG&E enters into interest rate swap contracts that economically hedge interest payments. Because realized gains and losses from the swaps, including terminated swap contracts, are recoverable through regulated rates, any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities until they are realized as interest expense. Realized gains and losses are recognized in "Interest Expense" on the Statements of Income at the time the underlying hedged interest expense is recorded. At December 31, 2025, LG&E held contracts with a notional amount of $64 million that mature in 2033.
Commodity Price Risk (PPL)
Economic Activity
RIE enters into derivative contracts that economically hedge natural gas purchases. Realized gains and losses from the derivatives are recoverable through regulated rates, therefore subsequent changes in fair value are included in regulatory assets or liabilities until they are realized as purchased gas. Realized gains and losses are recognized in "Energy Purchases" on the Statements of Income upon settlement of the contracts. See Note 7 for amounts recorded in regulatory assets and regulatory liabilities at December 31, 2025. At December 31, 2025, RIE held contracts with notional volumes of 48 Bcf that range in maturity from 2026 through 2029.
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Accounting and Reporting
(All Registrants)
All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless the NPNS is elected. NPNS contracts include certain full-requirement purchase contracts and other physical purchase contracts. Changes in the fair value of derivatives not designated as NPNS are recognized in earnings unless specific hedge accounting criteria are met and designated as such, except for the changes in fair values of LG&E's interest rate swaps that are recognized as regulatory assets or regulatory liabilities. See Note 7 for amounts recorded in regulatory assets and regulatory liabilities at December 31, 2025 and 2024.
See Note 1 for additional information on accounting policies related to derivative instruments.
(PPL)
The following table presents the fair value and location of derivatives not designated as hedging instruments recorded on the Balance Sheets:

|  |  |  |  | December 31, 2025 |  |  |  |  |  | December 31, 2024
|  |  |  |  | Assets |  | Liabilities |  |  |  |  |  | Assets |  | Liabilities
Current: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price Risk Management |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets/Liabilities (a): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (b) |  |  |  |  | $ | — |  |  | $ | 1 |  |  |  |  |  |  | $ | — |  |  | $ | — |
Gas contracts |  |  |  |  | 6 |  |  | 5 |  |  |  |  |  |  | 7 |  |  | 10 |
Total current |  |  |  |  | 6 |  |  | 6 |  |  |  |  |  |  | 7 |  |  | 10 |
Noncurrent: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price Risk Management |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets/Liabilities (a): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (b) |  |  |  |  | — |  |  | 4 |  |  |  |  |  |  | — |  |  | 3 |
Gas contracts |  |  |  |  | — |  |  | 5 |  |  |  |  |  |  | 2 |  |  | 3 |
Total noncurrent |  |  |  |  | — |  |  | 9 |  |  |  |  |  |  | 2 |  |  | 6 |
Total derivatives |  |  |  |  | $ | 6 |  |  | $ | 15 |  |  |  |  |  |  | $ | 9 |  |  | $ | 16 |

(a)Current portion is included in "Other current assets" and "Other current liabilities" and noncurrent portion is included in "Other noncurrent assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
(b)Excludes accrued interest, if applicable.
The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets and regulatory liabilities:

Derivative Relationships |  | Derivative Gain (Loss) Recognized in OCI |  | Location of Gain (Loss) Recognized in Income on Derivative |  | Gain (Loss) Reclassified from AOCI into Income
2025 |  |  |  |  |  |
Cash Flow Hedges: |  |  |  |  |  |
Interest rate derivatives |  | $ | 2 |  |  | Interest Expense |  | $ | (3) |
Total |  | $ | 2 |  |  |  |  | $ | (3) |
2024 |  |  |  |  |  |
Cash Flow Hedges: |  |  |  |  |  |
Interest rate derivatives |  | $ | — |  |  | Interest Expense |  | $ | (3) |
Total |  | $ | — |  |  |  |  | $ | (3) |
2023 |  |  |  |  |  |
Cash Flow Hedges: |  |  |  |  |  |
Interest rate derivatives |  | $ | — |  |  | Interest Expense |  | $ | (3) |
Total |  | $ | — |  |  |  |  | $ | (3) |

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Derivatives Not Designated as Hedging Instruments |  | Location of Gain (Loss) Recognized in Income on Derivative |  | 2025 |  | 2024 |  | 2023
Gas contracts |  | Energy Purchases |  | $ | (9) |  |  | $ | (40) |  |  | $ | (19) |
|  | Other income (expense) - net |  | (1) |  |  | — |  |  | (1) |
|  | Total |  | $ | (10) |  |  | $ | (40) |  |  | $ | (20) |

Derivatives Not Designated as Hedging Instruments |  | Location of Gain (Loss) Recognized as Regulatory Liabilities/Assets |  | 2025 |  | 2024 |  | 2023
Gas contracts |  | Regulatory assets - current |  | $ | 3 |  |  | $ | 48 |  |  | $ | 9 |
|  | Regulatory assets - noncurrent |  | (2) |  |  | 7 |  |  | (8) |
Interest rate derivatives |  | Regulatory assets - noncurrent |  | — |  |  | 4 |  |  | — |
|  | Total |  | $ | 1 |  |  | $ | 59 |  |  | $ | 1 |

The following table presents the effect of cash flow hedge activity on the Statement of Income for the year ended December 31, 2025:

| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships
| Interest Expense |  |
Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 808 |  |  |
The effects of cash flow hedges: |  |  |
Gain (Loss) on cash flow hedging relationships: |  |  |
Interest rate derivatives: |  |  |
Amount of gain (loss) reclassified from AOCI to income | (3) |  |  |

The following table presents the effect of cash flow hedge activity on the Statement of Income for the year ended December 31, 2024:

| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships
| Interest Expense |  |
Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 738 |  |  |
The effects of cash flow hedges: |  |  |
Gain (Loss) on cash flow hedging relationships: |  |  |
Interest rate derivatives: |  |  |
Amount of gain (loss) reclassified from AOCI to income | (3) |  |  |

The following table presents the effect of cash flow hedge activity on the Statement of Income for the year ended December 31, 2023:

| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships
| Interest Expense
Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 666 |
The effects of cash flow hedges: |
Gain (Loss) on cash flow hedging relationships: |
Interest rate derivatives: |
Amount of gain (loss) reclassified from AOCI to income | (3) |

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(LG&E)
The following table presents the fair value and the location on the Balance Sheets of derivatives not designated as hedging instruments:

|  | December 31, 2025 |  | December 31, 2024 |  |  |  |  |  |  |  |  |  |
|  | Assets |  | Liabilities |  | Assets |  | Liabilities |  |  |  |  |  |  |  |  |  |
Current: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price Risk Management |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets/Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |  |  |  |  |
Total current |  | — |  |  | 1 |  |  | — |  |  | — |  |  |  |  |  |  |  |  |  |  |
Noncurrent: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price Risk Management |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets/Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives |  | $ | — |  |  | $ | 4 |  |  | $ | — |  |  | $ | 3 |  |  |  |  |  |  |  |  |  |  |
Total noncurrent |  | — |  |  | 4 |  |  | — |  |  | 3 |  |  |  |  |  |  |  |  |  |  |
Total derivatives |  | $ | — |  |  | $ | 5 |  |  | $ | — |  |  | $ | 3 |  |  |  |  |  |  |  |  |  |  |

(a)Current portion is included in "Other current liabilities" on the Balance Sheets.
The following table presents the pre-tax effect of derivatives not designated as cash flow hedges that are recognized in income or regulatory assets:

Derivative Instruments |  | Location of Gain (Loss) |  | 2025 |  | 2024 |  | 2023
Interest rate derivatives |  | Regulatory assets - noncurrent |  | $ | (2) |  |  | $ | 4 |  |  | $ | — |

(PPL, LG&E and KU)
Offsetting Derivative Instruments
PPL, LG&E and KU or certain of their subsidiaries have master netting arrangements in place and also enter into agreements pursuant to which they purchase or sell certain energy and other products. Under the agreements, upon termination of the agreement as a result of a default or other termination event, the non-defaulting party typically would have a right to set off amounts owed under the agreement against any other obligations arising between the two parties (whether under the agreement or not), whether matured or contingent and irrespective of the currency, place of payment or place of booking of the obligation.
PPL, LG&E and KU have elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivatives agreements. The table below summarizes the derivative positions presented in the balance sheets where a right of setoff exists under these arrangements and related cash collateral received or pledged.

|  | Assets |  | Liabilities
|  |  |  | Eligible for Offset |  |  |  |  |  | Eligible for Offset |  |
|  | Gross |  | Derivative Instruments |  | Cash Collateral Received |  | Net |  | Gross |  | Derivative Instruments |  | Cash Collateral Pledged |  | Net
December 31, 2025 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PPL |  | $ | 6 |  |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |  |  | $ | 10 |  |  | $ | 3 |  |  | $ | — |  |  | $ | 7 |
LG&E |  | — |  |  | — |  |  | — |  |  | — |  |  | 5 |  |  | — |  |  | — |  |  | 5 |
December 31, 2024 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
PPL |  | $ | 9 |  |  | $ | 5 |  |  | $ | — |  |  | $ | 4 |  |  | $ | 16 |  |  | $ | 5 |  |  | $ | — |  |  | $ | 11 |
LG&E |  | — |  |  | — |  |  | — |  |  | — |  |  | 3 |  |  | — |  |  | — |  |  | 3 |

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Credit Risk-Related Contingent Features
Certain derivative contracts contain credit risk-related contingent features which, when in a net liability position, would permit the counterparties to require the transfer of additional collateral upon a decrease in the credit ratings of PPL, LG&E and KU or certain of their subsidiaries. Most of these features would require the transfer of additional collateral or permit the counterparty to terminate the contract if the applicable credit rating were to fall below investment grade. Some of these features also would allow the counterparty to require additional collateral upon each downgrade in credit rating at levels that remain above investment grade. In either case, if the applicable credit rating were to fall below investment grade, and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent features require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization on derivative instruments in net liability positions.
Additionally, certain derivative contracts contain credit risk-related contingent features that require adequate assurance of performance be provided if the other party has reasonable concerns regarding the performance of PPL's, LG&E's and KU's obligations under the contracts. A counterparty demanding adequate assurance could require a transfer of additional collateral or other security, including letters of credit, cash and guarantees from a creditworthy entity. This would typically involve negotiations among the parties. However, amounts disclosed below would represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" features.
(PPL)
At December 31, 2025, derivative contracts in a net liability position that contain credit risk-related contingent features was $5 million. The aggregate fair value of additional collateral requirements in the event of a credit downgrade below investment grade was $5 million.
17. Goodwill and Other Intangible Assets
Goodwill
(PPL)
Goodwill at PPL totaled $2,247 million at December 31, 2025 and 2024, consisting of $662 million for the Kentucky Regulated segment, $725 million for the Rhode Island Regulated segment and $860 million for Corporate and Other. There were no accumulated impairment losses related to goodwill.
Other Intangible Assets
(PPL)
The gross carrying amount and the accumulated amortization of other intangible assets were:

| December 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Gross Carrying Amount |  | Accumulated Amortization
Subject to amortization: |  |  |  |  |  |  |
Contracts (a) | $ | 125 |  |  | $ | 124 |  |  | $ | 125 |  |  | $ | 116 |
Renewable Energy Credits | 24 |  |  | — |  |  | 20 |  |  | — |
Land rights and easements | 445 |  |  | 139 |  |  | 432 |  |  | 147 |
Licenses and other | 2 |  |  | — |  |  | 2 |  |  | — |
Total subject to amortization | 596 |  |  | 263 |  |  | 579 |  |  | 263 |
Not subject to amortization due to indefinite life: |  |  |  |  |  |  |
Land rights and easements | 18 |  |  | — |  |  | 18 |  |  | — |
Total not subject to amortization due to indefinite life | 18 |  |  | — |  |  | 18 |  |  | — |
Total | $ | 614 |  |  | $ | 263 |  |  | $ | 597 |  |  | $ | 263 |

(a)Gross carrying amount includes the fair value at the acquisition date of the OVEC power purchase contract with terms favorable to market recognized as a result of the 2010 acquisition of LKE by PPL.
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Current intangible assets are included in "Other current assets" and long-term intangible assets are included in "Other intangibles" on the Balance Sheets.

Amortization expense was as follows: |  |  |  |  |
| 2025 |  | 2024 |  | 2023
Intangible assets with no regulatory offset | $ | 5 |  |  | $ | 5 |  |  | $ | 5 |
Intangible assets with regulatory offset | 8 |  |  | 8 |  |  | 9 |
Total | $ | 13 |  |  | $ | 13 |  |  | $ | 14 |

Amortization expense for each of the next five years is estimated to be:

| 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030
Intangible assets with no regulatory offset | $ | 5 |  |  | $ | 5 |  |  | $ | 5 |  |  | $ | 5 |  |  | $ | 5 |
Intangible assets with regulatory offset | 1 |  |  | — |  |  | — |  |  | — |  |  | — |
Total | $ | 6 |  |  | $ | 5 |  |  | $ | 5 |  |  | $ | 5 |  |  | $ | 5 |

(PPL Electric)
The gross carrying amount and the accumulated amortization of other intangible assets were:

| December 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Gross Carrying Amount |  | Accumulated Amortization
Subject to amortization: |  |  |  |  |  |  |
Land rights and easements | $ | 408 |  |  | $ | 145 |  |  | $ | 396 |  |  | $ | 141 |
Licenses and other | 2 |  |  | 1 |  |  | 2 |  |  | 1 |
Total subject to amortization | 410 |  |  | 146 |  |  | 398 |  |  | 142 |
Not subject to amortization due to indefinite life: |  |  |  |  |  |  |
Land rights and easements | 18 |  |  | — |  |  | 18 |  |  | — |
Total | $ | 428 |  |  | $ | 146 |  |  | $ | 416 |  |  | $ | 142 |

Intangible assets are shown as "Intangibles" on the Balance Sheets.
Amortization expense was as follows:

| 2025 |  | 2024 |  | 2023
Intangible assets with no regulatory offset | $ | 4 |  |  | $ | 4 |  |  | $ | 4 |

Amortization expense for each of the next five years is estimated to be:

| 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030
Intangible assets with no regulatory offset | $ | 4 |  |  | $ | 4 |  |  | $ | 4 |  |  | $ | 4 |  |  | $ | 4 |

(LG&E)
The gross carrying amount and the accumulated amortization of other intangible assets were:

| December 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Gross Carrying Amount |  | Accumulated Amortization
Subject to amortization: |  |  |  |  |  |  |
Land rights and easements (a) | $ | 8 |  |  | $ | (2) |  |  | $ | 7 |  |  | $ | 2 |
OVEC power purchase agreement (b) | 86 |  |  | 85 |  |  | 86 |  |  | 79 |
Total subject to amortization | $ | 94 |  |  | $ | 83 |  |  | $ | 93 |  |  | $ | 81 |

(a) December 31, 2025 accumulated amortization includes salvage proceeds related to a land sale in excess of the related accumulated amortization.
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(b) Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 7 for additional information.
Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
Amortization expense was as follows:

| 2025 |  | 2024 |  | 2023
Intangible assets with regulatory offset | $ | 6 |  |  | $ | 6 |  |  | $ | 6 |

Amortization expense for each of the next five years is immaterial.
(KU)
The gross carrying amount and the accumulated amortization of other intangible assets were:

| December 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Gross Carrying Amount |  | Accumulated Amortization
Subject to amortization: |  |  |  |  |  |  |
Land rights and easements (a) | $ | 30 |  |  | $ | (3) |  |  | $ | 29 |  |  | $ | 4 |
OVEC power purchase agreement (b) | 39 |  |  | 38 |  |  | 39 |  |  | 36 |
Total subject to amortization | $ | 69 |  |  | $ | 35 |  |  | $ | 68 |  |  | $ | 40 |

(a) December 31, 2025 accumulated amortization includes salvage proceeds related to a land sale in excess of the related accumulated amortization.
(b) Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 7 for additional information.
Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
Amortization expense was as follows:

| 2025 |  | 2024 |  | 2023
Intangible assets with regulatory offset | $ | 2 |  |  | $ | 2 |  |  | $ | 3 |

Amortization expense for each of the next five years is estimated to be immaterial.
18. Asset Retirement Obligations
(PPL and PPL Electric)
PPL Electric has identified legal retirement obligations for the retirement of certain transmission assets that could not be reasonably estimated due to indeterminable settlement dates. These assets are located on rights-of-way that allow the grantor to require PPL Electric to relocate or remove the assets. Since this option is at the discretion of the grantor of the right-of-way, PPL Electric is unable to determine when these events may occur.
(PPL, LG&E and KU)
PPL's, LG&E's and KU's ARO liabilities are primarily related to CCR closure costs. See Note 12 for information on the CCR rule. LG&E and RIE also have AROs related to natural gas mains and wells. LG&E's and KU's transmission and distribution lines largely operate under perpetual property easement agreements, which do not generally require restoration upon removal of the property. Therefore, no material AROs are recorded for transmission and distribution assets. For LG&E, KU, and RIE, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal.
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The changes in the carrying amounts of AROs were as follows:

| PPL |  | LG&E |  | KU
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
ARO at beginning of period | $ | 157 |  |  | $ | 158 |  |  | $ | 84 |  |  | $ | 85 |  |  | $ | 64 |  |  | $ | 66 |
Accretion | 8 |  |  | 8 |  |  | 4 |  |  | 4 |  |  | 4 |  |  | 4 |
Obligations incurred | — |  |  | 9 |  |  | — |  |  | 3 |  |  | — |  |  | 6 |
Changes in estimated timing or cost | 2 |  |  | 4 |  |  | — |  |  | 3 |  |  | 2 |  |  | 1 |
Obligations settled | (26) |  |  | (24) |  |  | (13) |  |  | (11) |  |  | (13) |  |  | (13) |
Other | (1) |  |  | 2 |  |  | — |  |  | — |  |  | — |  |  | — |
ARO at end of period | $ | 140 |  |  | $ | 157 |  |  | $ | 75 |  |  | $ | 84 |  |  | $ | 57 |  |  | $ | 64 |

19. Accumulated Other Comprehensive Income (Loss)
(PPL)
The after-tax changes in AOCI by component for the years ended December 31 were as follows:

|  |  |  |  | Unrealized gains (losses) on qualifying derivatives |  |  |  | Defined benefit plans |  |
|  |  |  |  |  | Equity investees' AOCI |  | Prior service costs |  | Actuarial gain (loss) |  | Total
PPL |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2022 |  |  |  |  | $ | 3 |  |  | $ | 2 |  |  | $ | (5) |  |  | $ | (124) |  |  | $ | (124) |
Amounts arising during the year |  |  |  |  | — |  |  | 1 |  |  | — |  |  | (41) |  |  | (40) |
Reclassifications from AOCI |  |  |  |  | 3 |  |  | — |  |  | 1 |  |  | (3) |  |  | 1 |
Net OCI during the year |  |  |  |  | 3 |  |  | 1 |  |  | 1 |  |  | (44) |  |  | (39) |
December 31, 2023 |  |  |  |  | $ | 6 |  |  | $ | 3 |  |  | $ | (4) |  |  | $ | (168) |  |  | $ | (163) |
Amounts arising during the year |  |  |  |  | — |  |  | 1 |  |  | — |  |  | (22) |  |  | (21) |
Reclassifications from AOCI |  |  |  |  | 3 |  |  | — |  |  | 1 |  |  | (4) |  |  | — |
Net OCI during the year |  |  |  |  | 3 |  |  | 1 |  |  | 1 |  |  | (26) |  |  | (21) |
December 31, 2024 |  |  |  |  | $ | 9 |  |  | $ | 4 |  |  | $ | (3) |  |  | $ | (194) |  |  | $ | (184) |
Amounts arising during the year |  |  |  |  | 1 |  |  | (1) |  |  | — |  |  | (20) |  |  | (20) |
Reclassifications from AOCI |  |  |  |  | 2 |  |  | — |  |  | 1 |  |  | (1) |  |  | 2 |
Net OCI during the year |  |  |  |  | 3 |  |  | (1) |  |  | 1 |  |  | (21) |  |  | (18) |
December 31, 2025 |  |  |  |  | $ | 12 |  |  | $ | 3 |  |  | $ | (2) |  |  | $ | (215) |  |  | $ | (202) |

The following table presents PPL's gains (losses) and related income taxes for reclassifications from AOCI for the years ended December 31, 2025, 2024 and 2023. The defined benefit plan components of AOCI are not reflected in their entirety in the statement of income; rather, they are included in the computation of net periodic defined benefit costs (credits) and subject to capitalization. See Note 10 for additional information.

|  | PPL |  |
Details about AOCI |  | 2025 |  | 2024 |  | 2023 |  | Affected Line Item on the Statements of Income
Qualifying derivatives |  |  |  |  |  |  |  |
Interest rate derivatives |  | $ | (3) |  |  | $ | (3) |  |  | $ | (3) |  |  | Interest Expense
Total Pre-tax |  | (3) |  |  | (3) |  |  | (3) |  |  |
Income Taxes |  | 1 |  |  | — |  |  | — |  |  |
Total After-tax |  | (2) |  |  | (3) |  |  | (3) |  |  |
Defined benefit plans |  |  |  |  |  |  |  |
Prior service costs |  | (1) |  |  | (1) |  |  | (2) |  |  |
Net actuarial loss |  | 2 |  |  | 4 |  |  | 3 |  |  |
Total Pre-tax |  | 1 |  |  | 3 |  |  | 1 |  |  |
Income Taxes |  | (1) |  |  | — |  |  | 1 |  |  |
Total After-tax |  | — |  |  | 3 |  |  | 2 |  |  |
Total reclassifications during the year |  | $ | (2) |  |  | $ | — |  |  | $ | (1) |  |  |

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20. New Accounting Guidance Pending Adoption
(All Registrants)
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued guidance which requires public business entities to provide in the notes to financial statements specified information about certain costs and expenses. This includes the disclosure of amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, and (e) depreciation, depletion, and amortization recognized as part of oil and gas-producing activities included in each relevant income statement expense caption. A relevant expense caption is an expense caption included on the face of the income statement within continuing operations that contains any of the specified expense categories (a)-(e). A qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated must also be disclosed. Additionally, public business entities must disclose the total amount of selling expenses and, in annual reporting periods, the entity's definition of selling expenses.
For public business entities, this guidance will be applied on a prospective basis. Retrospective application is permitted. This guidance will be effective for annual periods beginning after December 15, 2026, and interim periods reporting periods beginning after December 15, 2027. Early adoption is permitted.
Adoption of this guidance will result in additional disclosures. The Registrants plan to adopt the standard retrospectively effective for the year ending December 31, 2027.
Accounting for Internal-Use Software
In September 2025, the FASB issued guidance to clarify and modernize the accounting for costs related to internal-use software. This includes 1) eliminating the traditional stage-based model and requiring entities to start capitalizing software costs when (a) management has authorized/committed to funding the software project and (b) it is probable that the project will be completed and the software will be used to perform the function intended ("probable-to-complete recognition threshold"), 2) requiring entities to consider whether there is significant uncertainty associated with the development activities of the software when evaluating the probable-to-complete recognition threshold, and 3) clarifying disclosure requirements.
This guidance can be applied on either a prospective, modified, or retrospective basis and will be effective for annual periods beginning after December 15, 2027 and interim reporting periods within those annual reporting periods. Early adoption is permitted.
The Registrants are currently assessing the impact of adopting this guidance.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a)Evaluation of disclosure controls and procedures.
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
The Registrants' principal executive officers and principal financial officers, based on their evaluation of the Registrants' disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of December 31, 2025, the Registrants' disclosure controls and procedures are effective to ensure that material information relating to the Registrants and their consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, particularly during the period for which this annual report has been prepared. The aforementioned principal officers have concluded that the disclosure controls and procedures are also effective to ensure that information required to be disclosed in reports filed under the Exchange Act is accumulated and communicated to management, including the principal executive officers and principal financial officers, to allow for timely decisions regarding required disclosure.
(b)Changes in internal control over financial reporting.
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company, and Kentucky Utilities Company
The Registrants' principal executive officers and principal financial officers have concluded that there were no changes in the Registrants' internal control over financial reporting during the Registrants' fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Registrants' internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
PPL Corporation
PPL's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). PPL's internal control over financial reporting is a process designed to provide reasonable assurance to PPL's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in "Internal Control - Integrated Framework" (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2025. The effectiveness of our internal control over financial reporting has been audited by Deloitte & Touche LLP, an independent registered public accounting firm.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Management of PPL's non-accelerated filer companies, PPL Electric, LG&E and KU, are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Each of the aforementioned companies' internal control over financial reporting is a process designed to provide reasonable assurance to management and Board of Directors of these companies regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
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Under the supervision and with the participation of our management, including the principal executive officers and principal financial officers of the companies listed above, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in "Internal Control - Integrated Framework" (2013), management of these companies concluded that our internal control over financial reporting was effective as of December 31, 2025. This annual report does not include an attestation report of Deloitte & Touche LLP, the companies' independent registered public accounting firm regarding internal control over financial reporting for these non-accelerated filer companies. The effectiveness of internal control over financial reporting for the aforementioned companies was not subject to attestation by the companies' registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit these companies to provide only management's report in this annual report.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareowners and the Board of Directors of PPL Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of PPL Corporation and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report dated February 20, 2026, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Morristown, New Jersey
February 20, 2026
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ITEM 9B. OTHER INFORMATION
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
(a) None.
(b) Securities Trading Plans of Directors and Executive Officers
During the three months ended December 31, 2025, none of our directors or executive officers adopted, terminated or modified any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as such terms are defined in Item 408 of Regulation S-K.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Not applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PPL Corporation
Additional information required by this Item is incorporated by reference to, and will be contained in, our definitive proxy statement in the sections entitled: "Proposal 1: Election of Directors," "Governance of the Company – Board of Directors," "Governance of the Company – Board Committees," "Delinquent Section 16(a) Reports," and "Governance Policies Underpinning Our Compensation Framework – Insider Trading Policy." The proxy statement will be filed within 120 days after December 31, 2025; accordingly, we have omitted the information from this Item pursuant to General Instruction G(3) of Form 10-K.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 10 is omitted as PPL Electric, LG&E and KU meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K.
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EXECUTIVE OFFICERS OF THE REGISTRANTS
Officers of the Registrants are elected annually by their Boards of Directors to serve at the pleasure of the respective Boards. There are no family relationships among any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.
Listed below are the executive officers at December 31, 2025.
PPL Corporation

Name |  | Age |  | Positions Held During the Past Five Years |  | Dates
Vincent Sorgi |  | 54 |  | President and Chief Executive Officer |  | June 2020 - Present
Joseph P. Bergstein, Jr. |  | 55 |  | Executive Vice President and Chief Financial Officer |  | April 2021 - Present
|  |  |  | Senior Vice President and Chief Financial Officer |  | July 2019 - April 2021
Wendy E. Stark |  | 53 |  | Executive Vice President-Utilities and Chief Legal Officer |  | November 2024 - Present
|  |  |  | Executive Vice President-Utilities, Chief Legal Officer and Corporate Secretary |  | March 2024 - November 2024
|  |  |  | Executive Vice President, Chief Legal Officer and Corporate Secretary |  | January 2023 - March 2024
|  |  |  | Senior Vice President, General Counsel, Corporate Secretary and Chief Legal Officer |  | January 2022 - December 2022
|  |  |  | Senior Vice President, General Counsel and Corporate Secretary |  | April 2021 - December 2021
|  |  |  | Senior Vice President, Legal and Regulatory Strategy and General Counsel (led the legal and regulatory affairs departments, overseeing all legal matters and regulatory strategy for several electric and gas utilities in multiple jurisdictions) at Pepco Holdings, LLC (a subsidiary of Exelon) |  | December 2018 - April 2021
Angela K. Gosman |  | 57 |  | Executive Vice President and Chief Human Resources Officer |  | January 2023 - Present
|  |  |  | Senior Vice President and Chief Human Resources Officer |  | January 2022 - December 2022
|  |  |  | Vice President and Chief Human Resources Officer-PPL Services |  | August 2021 - December 2021
|  |  |  | Vice President - Human Resources-PPL EU Services |  | May 2020 - July 2021
Dean A. Del Vecchio |  | 59 |  | Executive Vice President and Chief Technology & Innovation Officer |  | February 2024 - Present
|  |  |  | Executive Vice President, Chief Information and Operations Officer (with responsibility for implementing a strategic technology vision, leading enterprise customer service and operations, shared services organization in India, real estate and facilities, physical security, office services, source-to-pay process for procurement efficiency, and enterprise imaging) at The Guardian Life Insurance Company of America |  | August 2013 - February 2024

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Name |  | Age |  | Positions Held During the Past Five Years |  | Dates
Lonnie E. Bellar |  | 61 |  | Executive Vice President-Engineering, Construction and Generation |  | March 2025 - Present
|  |  |  | Senior Vice President-Engineering & Construction- PPL Services |  | March 2024 – March 2025
|  |  |  | Chief Operating Officer-LKE |  | March 2018 - March 2024
David J. Bonenberger |  | 64 |  | Executive Vice President and Chief Operating Officer-Utilities |  | March 2025 - Present
|  |  |  | Senior Vice President and Chief Operating Officer-Utilities-PPL Services |  | March 2024 - March 2025
|  |  |  | President-RIE |  | May 2022 - March 2024
|  |  |  | Vice President-Operations Integration-PPL Services |  | April 2021 - present
|  |  |  | Vice President-Transmission and Substations-PPL Electric |  | January 2018 - April 2021
|  |  |  | Vice President-Distribution Operations-PPL Electric |  | December 2017 - July 2021
J. Gregory Cornett (a) |  | 55 |  | President-RIE |  | March 2024 - Present
|  |  |  | Vice President and Deputy General Counsel-Litigation-PPL Services |  | December 2021 - March 2024
|  |  |  | Associate General Counsel and Director of Legal Services-PPL Services |  | May 2018 - December 2021
John R. Crockett III (a) |  | 61 |  | President-LKE |  | October 2021 - Present
|  |  |  | General Counsel, Chief Compliance Officer and Corporate Secretary - LKE |  | January 2018 - September 2021
Christine M. Martin (a) |  | 53 |  | President-PPL Electric |  | September 2023 - Present
|  |  |  | Senior Vice President-Public Affairs and Chief Sustainability Officer-PPL Services |  | January 2023 - August 2023
|  |  |  | Vice President-Public Affairs and Chief Sustainability Officer-PPL Services |  | April 2022 - January 2023
|  |  |  | Vice President-Public Affairs and Sustainability-PPL Services |  | August 2018 - April 2022
Tadd J. Henninger |  | 50 |  | Senior Vice President-Finance and Treasurer |  | January 2023 - Present
|  |  |  | Vice President-Finance and Treasurer |  | July 2019 - January 2023
Marlene C. Beers |  | 54 |  | Vice President and Controller |  | March 2019 - Present

(a)Designated an executive officer of PPL by virtue of their respective positions at a PPL subsidiary.
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ITEM 11. EXECUTIVE COMPENSATION
PPL Corporation
The information required by this Item is incorporated by reference to, and will be contained in, our definitive proxy statement in the sections entitled: "Governance of the Company – Compensation of Directors," "Executive Compensation – People and Compensation Committee Report" "Executive Compensation – Compensation Discussion and Analysis," "Executive Compensation - Executive Compensation Tables," and "Executive Compensation – CEO Pay Ratio." The proxy statement w ill be filed within 120 days after December 31, 2025; accordingly, we have omitted the information from this Item pursuant to General Instruction G(3) of Form 10-K.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 11 is omitted as PPL Electric, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
PPL Corporation
Additional information required by this Item is incorporated by reference to, and will be contained in, our definitive proxy statement in the section entitled: "Stock Ownership." The proxy statement will be filed within 120 days after December 31, 2025; accordingly, we have omitted the information from this Item pursuant to General Instruction G(3) of Form 10-K. In addition, provided below in tabular format is information as of December 31, 2025, with respect to compensation plans (including individual compensation arrangements) under which equity securities of PPL are authorized for issuance.
Equity Compensation Plan Information

| Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (3) (4)
Equity compensation |  |  |  |  | 1,010,182 |  | – DDCP
plans approved by |  |  |  |  | 5,556,839 |  | – SIP
security holders (1) |  |  |  |  | 559,780 |  | – ICPKE
|  |  |  |  | 7,126,801 |  | – Total
Equity compensation |  |  |  |  |  |
plans not approved by |  |  |  |  |  |
security holders (2) |  |  |  |  |  |

(1)Includes (a) the ICPKE, under which restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based compensation awards may be awarded to non-executive key employees of PPL and its subsidiaries; (b) the SIP approved by shareowners in 2017 under which restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based compensation awards may be awarded to executive officers of PPL and its subsidiaries; and (c) the DDCP, under which stock units may be awarded to directors of PPL.
(2)All of PPL's current compensation plans under which equity securities of PPL are authorized for issuance have been approved by PPL's shareowners.
(3)As of December 31, 2025, there were 4,189,745 stock awards outstanding under the plans. The following stock awards are outstanding under the SIP, ICPKE and DDCP: 1,354,533 restricted stock units, 983,384 TSR performance awards, 510,343 EG performance awards and 510,343 LTS performance awards under the SIP; 768 restricted stock units under the ICPKE; and 830,374 stock units under the DDCP.
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(4)Based upon the following aggregate award limitations under the SIP, ICPKE and DDCP: (a) under the SIP, 15,000,000 awards; (b) under the ICPKE, 16,573,608 awards (i.e., 5% of the total PPL common stock outstanding as of January 1, 2003) granted after April 25, 2003, reduced by outstanding awards for which common stock was not yet issued as of such date of 2,373,812 resulting in a limit of 14,199,796; and (c) under the DDCP, the number of stock units available for issuance was reduced to 2,000,000 stock units in March 2012. In addition, the ICPKE includes an annual award limitation of 2% of total PPL common stock outstanding as of January 1 of each year.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 12 is omitted as PPL Electric, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
PPL Corporation
The information require d by this Item is incorporated by reference to, and will be contained in, our definitive proxy statement in the sections entitled: "Governance of the Company – Board of Directors" and "Transactions with Related Persons." The proxy statement will be fi led within 120 days after December 31, 2025; a ccordingly, we have omitted the information from this Item pursuant to General Instruction G(3) of Form 10-K.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 13 is omitted as PPL Electric, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PPL Corporation
The information required by this Item is incorporated by reference to, and will be contained in, our definitive proxy statement in the section entitled: "Proposal 3: Ratification of the Appointment of Independent Registered Public Accounting Firm -- Fees to Independent Auditor for 2025 and 2024." The proxy statement will be filed within 120 days after December 31, 2025; accordingly, we have omitted the information from this Item pursuant to General Instruction G(3) of Form 10-K.
PPL Electric Utilities Corporation
For the fiscal years ended 2025 and 2024, Deloitte & Touche LLP (Deloitte) served as PPL Electric's independent auditor. The following table presents an allocation of fees billed, including expenses, by the independent auditor to PPL Electric, for professional services rendered for the audits of PPL Electric's annual financial statements and for fees billed for other services rendered by Deloitte.

| 2025 |  | 2024
| (in thousands)
Audit fees (a) | $ | 1,412 |  |  | $ | 1,302 |
Audit-related fees (b) | 21 |  |  | 21 |

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in PPL Electric's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
(b)Fees for agreed-upon procedures related to annual EPA filings.
Louisville Gas and Electric Company
For the fiscal years ended 2025 and 2024, Deloitte served as LG&E's independent auditor. The following table presents an allocation of fees billed, including expenses, by the independent auditor to LG&E, for professional services rendered for the audits of LG&E's annual financial statements and for fees billed for other services rendered by Deloitte.

| 2025 |  | 2024
| (in thousands)
Audit fees (a) | $ | 943 |  |  | $ | 903 |

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in LG&E's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
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Kentucky Utilities Company
For the fiscal years ended 2025 and 2024, Deloitte served as KU's independent auditor. The following table presents an allocation of fees billed, including expenses, by the independent auditor to KU, for professional services rendered for the audits of KU's annual financial statements and for fees billed for other services rendered by Deloitte.

|  | 2025 |  | 2024
|  | (in thousands)
Audit fees (a) |  | $ | 1,181 |  |  | $ | 1,053 |

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in KU's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Approval of Fees. The Audit Committee of PPL has procedures for pre-approving audit and non-audit services to be provided by the independent auditor. These procedures are designed to ensure the continued independence of the independent auditor. More specifically, the use of the independent auditor to perform either audit or non-audit services is prohibited unless specifically approved in advance by the Audit Committee of PPL. As a result of this approval process, the Audit Committee of PPL has pre-approved specific categories of services and authorization levels. All services outside of the specified categories and all amounts exceeding the authorization levels are approved by the Chair of the Audit Committee of PPL, who serves as the Committee designee to review and approve audit and non-audit related services during the year. A listing of the approved audit and non-audit services is reviewed with the full Audit Committee of PPL no later than its next meeting.
The Audit Committee of PPL approved 100% of the 2025 and 2024 services provided by Deloitte.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
(a) The following documents are filed as part of this report:
1.Financial Statements - Refer to the "Table of Contents" for an index of the financial statements included in this report.
2.Supplementary Data and Supplemental Financial Statement Schedule - included in response to Item 8.
All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.
3.Exhibits
See Exhibit Index immediately following "Shareowner and Investor Information."
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SHAREOWNER AND INVESTOR INFORMATION
Annual Meeting: The 2026 annual meeting of shareowners of PPL will be held on Wednesday, May 13, 2026 in a virtual meeting format.
Proxy Statement Material: A proxy statement and notice of PPL's annual meeting will be provided to all shareowners who are holders of record as of March 4, 2026. The latest proxy statement can be accessed at www.pplweb.com/PPLCorpProxy.
PPL Annual Report: The report will be published in the beginning of April and will be provided to all shareowners who are holders of record as of March 4, 2026. The latest annual report can be accessed at www.pplweb.com/PPLCorpProxy.
Dividends: Subject to the declaration of dividends on PPL common stock by the PPL Board of Directors or its Executive Committee, dividends are paid on the first business day of April, July, October and January. The 2026 record dates for dividends are expected to be March 10, June 10, September 10 and December 10.
PPL's Website (www.pplweb.com): Shareowners can access PPL publications such as annual and quarterly reports to the Securities and Exchange Commission (SEC Forms 10-K and 10-Q), other PPL filings, corporate governance materials, news releases, stock quotes and historical performance. Visitors to our website can subscribe to receive automated email alerts for SEC filings, earnings releases, daily stock prices or other financial news.
Financial reports which are available at www.pplweb.com will be mailed without charge upon request.
By mail:
PPL Treasury Dept.
645 Hamilton Street
Allentown, PA 18101
By email: invserv@pplweb.com
By telephone:
610-774-5151 or Toll-free at 1-800-345-3085
Online Account Access: Registered shareowners can activate their account for online access by visiting shareowneronline.com.
Direct Stock Purchase and Dividend Reinvestment Plans (Plan): PPL offers investors the opportunity to acquire shares of PPL common stock through its Plan. Through the Plan, participants are eligible to invest up to $25,000 per calendar month in PPL common stock. Shareowners may choose to have dividends on their PPL common stock fully or partially reinvested in PPL common stock or can receive full payment of cash dividends by check or electronic funds transfer. Participants in the Plan may choose to have their common stock certificates deposited into their Plan account.
Direct Registration System: PPL participates in the Direct Registration System (DRS). Shareowners may choose to have their common stock certificates converted to book entry form within the DRS by submitting their certificates to PPL's transfer agent.
Listed Securities:
New York Stock Exchange
PPL Corporation:
Common Stock (Code: PPL)
PPL Capital Funding, Inc.:
2007 Series A Junior Subordinated Notes due 2067 (Code: PPL/67)
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Fiscal Agents:
Transfer Agent and Registrar; Dividend Disbursing Agent; Plan Administrator
Equiniti Trust Company
Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Toll Free: 1-800-345-3085
Outside U.S.: 651-450-4064
Website: shareowneronline.com
Indenture Trustee
The Bank of New York Mellon
Corporate Trust Administration
500 Ross Street
Pittsburgh, PA 15262
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EXHIBIT INDEX
The following Exhibits indicated by an asterisk preceding the Exhibit number are filed herewith. The balance of the Exhibits has heretofore been filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein by reference. Exhibits indicated by a [_] are filed or listed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

1(a) | - | Securities Purchase and Registration Rights Agreement, dated March 5, 2014, among PPL Capital Funding, Inc., PPL Corporation, and the several purchasers named in Schedule B thereto (Exhibit 1.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 10, 2014)
2(a) | - | Separation Agreement among PPL Corporation, Talen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Raven Power Holdings LLC, C/R Energy Jade, LLC and Sapphire Power Holdings LLC., dated as of June 9, 2014 (Exhibit 2.1 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated June 12, 2014)
2(b) | - | Transaction Agreement among PPL Corporation, Talen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Talen Energy Merger Sub, Inc., C/R Energy Jade, LLC, Sapphire Power Holdings LLC. and Raven Power Holdings LLC, dated as of June 9, 2014 (Exhibit 2.2 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated June 12, 2014)
2(c) | - | Share Purchase Agreement, dated as of March 17, 2021, by and among PPL WPD Limited, National Grid Holdings One plc and National Grid plc. (Exhibit 2.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 18, 2021)
2(d)-1 | - | Share Purchase Agreement, dated as of March 17, 2021, by and among PPL Energy Holdings, LLC, PPL Corporation (solely as guarantor), and National Grid USA (Exhibit 2.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 18, 2021)
2(d)-2 | - | Assignment and Assumption Agreement, dated as of May 3, 2021, by and among PPL Energy Holdings, LLC, PPL Corporation, National Grid USA and PPL Rhode Island Holdings, LLC (Exhibit 2(b)-2 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2021)
2(e) | - | Tax Deed, dated as of June 9, 2021, by and among PPL WPD Limited, National Grid Holdings One plc (Exhibit 2.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 14, 2021)
3(a) | - | Amended and Restated Articles of Incorporation of PPL Corporation, effective as of May 25, 2016 (Exhibit 3(i) to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 26, 2016)
3(a)-1 | - | Certificate of Change: an amendment, effective as of July 31, 2024, to the Amended and Restated Articles of Incorporation of PPL Corporation, effective as of May 25, 2016 (Exhibit 3(a).1 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2024)
3(b) | - | Bylaws of PPL Corporation, effective as of December 16, 2022 (Exhibit 3(ii) to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 19, 2022)
3(c) | - | Amended and Restated Articles of Incorporation of PPL Electric Utilities Corporation, effective as of October 31, 2013 (Exhibit 3(a) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended September 30, 2013)
3(c)-1 | - | Certificate of Change: an amendment, effective as of July 31, 2024, to the Amended and Restated Articles of Incorporation of PPL Electric Utilities Corporation, effective as of October 31, 2013 (Exhibit 3(b).1 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2024)
3(d) | - | Bylaws of PPL Electric Utilities Corporation, effective as of October 27, 2015 (Exhibit 3(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2015)
3(g)-1 | - | Amended and Restated Articles of Incorporation of Louisville Gas and Electric Company, effective as of November 6, 1996 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173676))

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3(g)-2 | - | Articles of Amendment to Articles of Incorporation of Louisville Gas and Electric Company, effective as of April 6, 2004 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173676))
3(g)-3 | - | Statement of Change of Principal Office Address: an amendment, dated March 28, 2025, to the Amended and Restated Articles of Incorporation of Louisville Gas and Electric Company, effective November 6, 1996, as amended, effective April 6, 2004 (Exhibit 3(g)-3 to PPL Corporation Form 10-Q Report (File No11459) for the quarter ended March 31, 2025)
3(h) | - | Bylaws of Louisville Gas and Electric Company, effective as of December 16, 2003 (Exhibit 3(c) to Registration Statement filed on Form S-4 (File No. 333-173676))
3(i)-1 | - | Amended and Restated Articles of Incorporation of Kentucky Utilities Company, effective as of December 14, 1993 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173675))
3(i)-2 | - | Articles of Amendment to Articles of Incorporation of Kentucky Utilities Company, effective as of April 8, 2004 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173675))
3(j) | - | Bylaws of Kentucky Utilities Company, effective as of December 16, 2003 (Exhibit 3(c) to Registration Statement filed on Form S-4 (File No. 333-173675))
4(a)-1 | - | Amended and Restated Employee Stock Ownership Plan, dated December 1, 2016 (Exhibit 4(a) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2016)
4(a)-2 | - | Amendment No. 1 to PPL Employee Stock Ownership Plan, dated October 2, 2017 (Exhibit 4(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2017)
4(a)-3 | - | Amendment No. 2 to PPL Employee Stock Ownership Plan, dated December 1, 2018 (Exhibit 4(a)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2018)
4(a)-4 | - | Amendment No. 3 to PPL Employee Stock Ownership Plan, dated January 1, 2019 (Exhibit 4(a)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2018)
4(b)-1 | - | Indenture, dated as of November 1, 1997, among PPL Corporation, PPL Capital Funding, Inc. and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 12, 1997)
4(b)-2 | - | Supplemental Indenture No. 12, dated as of May 24, 2013, to said Indenture (Exhibit 4.4 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 24, 2013)
4(b)-3 | - | Supplemental Indenture No. 13, dated as of March 10, 2014, to said Indenture (Exhibit 4.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 10, 2014)
4(b)-4 | - | Supplemental Indenture No. 14, dated as of March 10, 2014, to said Indenture (Exhibit 4.3 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 10, 2014)
4(b)-5 | - | Supplemental Indenture No. 15, dated as of May 17, 2016, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 17, 2016)
4(b)-6 | - | Supplemental Indenture No. 16, dated as of September 8, 2017, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated September 6, 2017)
4(b)-7 | - | Supplemental Indenture No. 17, dated as of April 1, 2020, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 3, 2020)

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4(b)-8 | - | Supplemental Indenture No. 18, dated as of August 9, 2024, to said Indenture (Exhibit 4(b) to PPL Corporation 8-K Report (File No. 1-11459) dated August 9, 2024)
4(c)-1 | - | Indenture, dated as of August 1, 2001, by PPL Electric Utilities Corporation and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 21, 2001)
4(c)-2 | - | Supplemental Indenture No. 7, dated as of August 1, 2007, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 14, 2007)
4(c)-3 | - | Supplemental Indenture No. 9, dated as of October 1, 2008, to said Indenture (Exhibit 4(c) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 31, 2008)
4(c)-4 | - | Supplemental Indenture No. 10, dated as of May 1, 2009, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated May 22, 2009)
4(c)-5 | - | Supplemental Indenture No. 11, dated as of July 1, 2011, to said Indenture (Exhibit 4.1 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 13, 2011)
4(c)-6 | - | Supplemental Indenture No. 12, dated as of July 1, 2011, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 18, 2011)
4(c)-7 | - | Supplemental Indenture No. 13, dated as of August 1, 2011, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 23, 2011)
4(c)-8 | - | Supplemental Indenture No. 14, dated as of August 1, 2012, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 24, 2012)
4(c)-9 | - | Supplemental Indenture No. 15, dated as of July 1, 2013, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 11, 2013)
4(c)-10 | - | Supplemental Indenture No. 16, dated as of June 1, 2014, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated June 5, 2014)
4(c)-1 1 | - | Supplemental Indenture No. 17, dated as of October 1, 2015, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 1, 2015)
4(c)-12 | - | Supplemental Indenture No. 18, dated as of March 1, 2016, to said Indenture (Exhibit 4(c) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 10, 2016)
4(c)-13 | - | Supplemental Indenture No. 19, dated as of May 1, 2017, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated May 11, 2017)
4(c)-14 | - | Supplemental Indenture No. 20, dated as of June 1, 2018, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 14, 2018)
4(c)-15 | - | Supplemental Indenture No. 21, dated as of September 1, 2019, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated September 6, 2019)
4(c)-16 | - | Supplemental Indenture No. 23, dated as of June 15, 2020, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 24, 2021)
4(c)-17 | - | Supplemental Indenture No. 24, dated as of March 1, 2023, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 2, 2023)

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4(c)-18 | - | Supplemental Indenture No. 25, dated as of January 1, 2024, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated January 5, 2024)
4(c)-19 |  | Supplemental Indenture No. 26, dated as of August 1, 2025 to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated August 6, 2025)
4(c)-20 |  | Supplemental Indenture No. 27, dated as of September 15, 2025 to said Indenture (Exhibit 4(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2025)
4(d)-1 | - | Pollution Control Facilities Loan Agreement, dated as of October 1, 2008, between Pennsylvania Economic Development Financing Authority and PPL Electric Utilities Corporation (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 31, 2008)
4(d)-2 | - | Pollution Control Facilities Loan Agreement, dated as of March 1, 2016, between PPL Electric Utilities Corporation and the Lehigh County Industrial Development Authority (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 10, 2016)
4(d)-3 | - | Pollution Control Facilities Loan Agreement, dated as of March 1, 2016, between PPL Electric Utilities Corporation and the Lehigh County Industrial Development Authority (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 10, 2016)
4(e)-1 | - | Subordinated Indenture, dated as of March 1, 2007, between PPL Capital Funding, Inc., PPL Corporation and The Bank of New York, as Trustee (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2007)
4(e)-2 | - | Supplemental Indenture No. 1, dated as of March 1, 2007, to said Subordinated Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2007)
4(e)-3 | - | Supplemental Indenture No. 4, dated as of March 15, 2013, to said Subordinated Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 15, 2013)
4(f)-1 | - | Indenture, dated as of October 1, 2010, between Kentucky Utilities Company and The Bank of New York Mellon, as Trustee (Exhibit 4(q)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(f)-2 | - | Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(f)-3 | - | Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(q)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(f)-4 | - | Supplemental Indenture No. 3, dated as of November 1, 2013, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 13, 2013)
4(f)-5 | - | Supplemental Indenture No. 4, dated as of September 1, 2015, to said Indenture (Exhibit 4(b) to Kentucky Utilities Company Form 8-K Report (File No. 1-3464) dated September 28, 2015)
4(f)-6 | - | Supplemental Indenture No. 5, dated as of August 1, 2016, to said Indenture (Exhibit 4(b) to Kentucky Utilities Company Form 8-K Report (File No. 1-3464) dated August 26, 2016)
4(f)-7 | - | Supplemental Indenture No. 6, dated as of August 1, 2018, to said Indenture (Exhibit 4(a) to PPL Corporation 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2018)
4(f)-8 | - | Supplemental Indenture No. 7, dated as of March 1, 2019, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 1, 2019)

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4(f)-9 | - | Supplemental Indenture No. 8, dated as of May 15, 2020, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 3, 2020)
4(f)-10 | - | Supplemental Indenture No. 9, dated as of March 1, 2023, to said Indenture (Exhibit 4(c) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2023)
4(f)-11 | - | Supplemental Indenture No. 10, dated as of November 1, 2023, to said Indenture (Exhibit 4(e) to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2023)
4(f)-12 |  | Supplemental Indenture No. 11 dated as of August 1, 2025, to said Indenture (Exhibit 4(c) to PPL Corporation Form 8-K Report (File No. 1-11459) dated August 13, 2025)
4(g)-1 | - | Indenture, dated as of October 1, 2010, between Louisville Gas and Electric Company and The Bank of New York Mellon, as Trustee (Exhibit 4(r)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(g)-2 | - | Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(r)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(g)-3 | - | Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(r)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(g)-4 | - | Supplemental Indenture No. 3, dated as of November 1, 2013, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 13, 2013)
4(g)-5 | - | Supplemental Indenture No. 4, dated as of September 1, 2015, to said Indenture (Exhibit 4(a) to Louisville Gas and Electric Company Form 8-K Report (File No. 1-2893) dated September 28, 2015)
4(g)-6 | - | Supplemental Indenture No. 5, dated as of September 1, 2016, to said Indenture (Exhibit 4(b) to Louisville Gas and Electric Company Form 8-K (File No. 1-2893) dated September 15, 2016)
4(g)-7 | - | Supplemental Indenture No. 6, dated as of May 15, 2017, to said Indenture (Exhibit 4(b) to Louisville Gas and Electric Company Form 8-K Report (File No. 1-2893) dated June 1, 2017)
4(g)-8 | - | Supplemental Indenture No. 7, dated as of March 1, 2019, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 1, 2019)
4(g)-9 | - | Supplemental Indenture No. 8, dated as of March 1, 2023, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2023)
4(g)-10 | - | Supplemental Indenture No. 9, dated as of November 1, 2023, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2023)
4(g)-11 |  | Supplemental Indenture No. 10, dated as of August 1, 2025, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated August 13, 2025)
4(h)-1 | - | 2002 Series A Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(h)-2 | - | Amendment No. 1 dated as of September 1, 2010 to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)

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4(i)-1 | - | 2002 Series B Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(i)-2 | - | Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(j)-1 | - | 2004 Series A Carroll County Loan Agreement, dated October 1, 2004 and amended and restated as of September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(j)-2 | - | Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(k)-1 | - | 2006 Series B Carroll County Loan Agreement, dated October 1, 2006 and amended and restated September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(k)-2 | - | Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(l)-1 | - | 2008 Series A Carroll County Loan Agreement, dated August 1, 2008 by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(l)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(m) | - | 2016 Series A Carroll County Loan Agreement dated as of August 1, 2016 between Kentucky Utilities Company and the County of Carroll, Kentucky (Exhibit 4(a) to Kentucky Utilities Company Form 8-K Report (File No. 1-3464) dated August 26, 2016)
4(n)-1 | - | 2002 Series A Mercer County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(n)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(o)-1 | - | 2002 Series A Muhlenberg County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(o)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(p) | - | 2018 Series A Carroll County Loan Agreement, dated as of August 1, 2018, by and between Kentucky Utilities Company and County of Carroll, Kentucky (Exhibit 4(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2018)

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4(q) | - | 2023 Series A Trimble County Loan Agreement, dated November 1, 2023 by and between Kentucky Utilities Company and County of Trimble, Kentucky (Exhibit 4(d) to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2023)
4(r)-1 | - | 2001 Series A Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(r)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(s)-1 | - | 2001 Series B Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(s)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(t)-1 | - | 2003 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated October 1, 2003, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(t)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(u)-1 | - | 2005 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated February 1, 2005 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(u)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(v)-1 | - | 2007 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated as of March 1, 2007 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(v)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(w) | - | 2007 Series B Louisville/Jefferson County Metro Government Amended and Restated Loan Agreement, dated November 1, 2010, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(oo) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(x)-1 | - | 2001 Series A Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(qq)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(x)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(qq)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)

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4(y) | - | 2017 Series A Trimble County Loan Agreement, dated as of June 1, 2017, by and between Louisville Gas and Electric Company and County of Trimble, Kentucky (Exhibit 4(a) to Louisville Gas and Electric Company Form 8-K Report (File No. 1-2893) dated June 1, 2017)
4(z)-1 | - | 2001 Series B Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(z)-2 | - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(aa) | - | 2016 Series A Trimble County Loan Agreement dated as of September 1, 2016 by and between Louisville Gas and Electric Company and County of Trimble, Kentucky (Exhibit 4(a) to Louisville Gas and Electric Company Form 8-K (File No. 1-2893) dated September 15, 2016)
4(bb) | - | 2023 Series A Trimble County Loan Agreement dated as of November 1, 2023 by and between Louisville Gas and Electric Company and County of Trimble, Kentucky (Exhibit 4(a) to PPL Corporation Form 8-K (File No. 1-11459) dated December 6, 2023)
4(cc) | - | Description of PPL Corporation's common stock, par value $0.01 per share, as revised in February 2023 (Exhibit 4(bb) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022)
4(dd) | - | Description of PPL Capital Funding, Inc.'s Junior Subordinated Notes 2007 Series A due 2067, as guaranteed by PPL Corporation (Exhibit 4(rr) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2019)
4(ee) | - | Description of PPL Electric Utilities Corporation's common stock, no par value per share (Exhibit 4(tt) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2019)
4(ff)-1 | - | Indenture, dated as of March 22, 2010, by The Narragansett Electric Company and The Bank of New York Mellon as Trustee (Exhibit 4(a)-1 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
4(ff)-2 | - | First Supplemental Indenture, dated as of March 22, 2010, to said Indenture (Exhibit 4(a)-2 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
4(ff)-3 | - | Second Supplemental Indenture, dated as of March 22, 2010, to said Indenture (Exhibit 4(a)-3 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
4(ff)-4 | - | Third Supplemental Indenture, dated as of December 10, 2012, to said Indenture (Exhibit 4(a)-4 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
4(ff)-5 | - | Fourth Supplemental Indenture, dated as of July 27, 2018, to said Indenture (Exhibit 4(a)-5 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
4(ff)-6 | - | Fifth Supplemental Indenture, dated as of April 9, 2020, to said Indenture (Exhibit 4(a)-6 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
4(ff)-7 | - | Sixth Supplemental Indenture, dated as of March 25, 2024, to said Indenture (Exhibit 4.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 25, 2024)

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4(gg) | - | Indenture, dated as of February 24, 2023, by PPL Capital Funding, Inc., as Issuer, PPL Corporation, as Guarantor, and The Bank of New York Mellon, as Trustee (Exhibit 4.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 24, 2023)
4(hh) |  | Indenture, dated as of November 24, 2025, by PPL Capital Funding, Inc., as Issuer, PPL Corporation, as Guarantor, and The Bank of New York Mellon, as Trustee (Exhibit 4.1 to PPL Corporation Form 8-KÐeport (File No. 1-11459) dated November 19, 2025)
10(a) | - | Employee Matters Agreement, among PPL Corporation, Talen Energy Corporation, C/R Energy Jade, LLC, Sapphire Power Holdings LLC. and Raven Power Holdings LLC, dated as of June 9, 2014 (Exhibit 10.1 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated June 12, 2014)
10(b) | - | Amendment No. 4 to Amended and Restated Revolving Credit Agreement, dated as of January 29, 2026, amending the Amended and Restated Revolving Credit Agreement, dated as of December 6, 2021, among PPL Capital Funding, Inc., as Borrower, The Narragansett Electric Company, as Designated Borrower, PPL Corporation, as Guarantor, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated January 30, 2026)
10(c) | - | Amendment No. 4 to Amended and Restated Revolving Credit Agreement, dated as of January 29, 2026, amending the Amended and Restated Revolving Credit Agreement, dated as of December 6, 2021, among PPL Electric Utilities Corporation, as Borrower, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated January 30, 2026)
10(d) | - | Amendment No. 4 to Amended and Restated Revolving Credit Agreement, dated as of January 29, 2026, amending the Amended and Restated Revolving Credit Agreement, dated as of December 6, 2021, among Louisville Gas and Electric Company, as Borrower, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.3 to PPL Corporation Form 8-K Report (File No. 1-11459) dated January 30, 2026)
10(e) | - | Amendment No. 4 to Amended and Restated Revolving Credit Agreement, dated as of January 29, 2026, amending the Amended and Restated Revolving Credit Agreement, dated as of December 6, 2021, among Kentucky Utilities Company, as Borrower, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.4 to PPL Corporation Form 8-K Report (File No. 1-11459) dated January 30, 2026)
10(f) | - | Transition Services Agreement, dated as of May 25, 2022, by and among National Grid USA Service Company, Inc., National Grid USA (solely with respect to Section 4.6) and The Narragansett Electric Company (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 25, 2022)
10(g) | - | $250,000,000 Term Loan Credit Agreement dated as of September 16, 2022 among PPL Electric Utilities Corporation, as Borrower, the Lenders party thereto and U.S. Bank National Association, as Administrative Agent (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated September 19, 2022)
[_]10(h)-1 | - | Amended and Restated Directors Deferred Compensation Plan, dated June 12, 2000 (Exhibit 10(h) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2000)
[_]10(h)-2 | - | Amendment No. 1 to said Directors Deferred Compensation Plan, dated December 18, 2002 (Exhibit 10(m)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002)
[_]10(h)-3 | - | Amendment No. 2 to said Directors Deferred Compensation Plan, dated December 4, 2003 (Exhibit 10(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003)

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[_]10(h)-4 | - | Amendment No. 3 to said Directors Deferred Compensation Plan, dated as of January 1, 2005 (Exhibit 10(cc)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2005)
[_]10(h)-5 | - | Amendment No. 4 to said Directors Deferred Compensation Plan, dated as of May 1, 2008 (Exhibit 10(x)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008)
[_]10(h)-6 | - | Amendment No. 5 to said Directors Deferred Compensation Plan, dated May 28, 2010 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2010)
[_]10(h)-7 | - | Amendment No. 6 to said Directors Deferred Compensation Plan, dated as of April 15, 2015 (Exhibit 10(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2015)
[_]10(i)-1 | - | PPL Corporation Directors Deferred Compensation Plan Trust Agreement, dated as of April 1, 2001, between PPL Corporation and Wachovia Bank, N.A. (as successor to First Union National Bank), as Trustee (Exhibit 10(hh)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012)
[_]10(i)-2 | - | PPL Officers Deferred Compensation Plan, PPL Supplemental Executive Retirement Plan and PPL Supplemental Compensation Pension Plan Trust Agreement, dated as of April 1, 2001, between PPL Corporation and Wachovia Bank, N.A. (as successor to First Union National Bank), as Trustee (Exhibit 10(hh)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012)
[_]10(i)-3 | - | PPL Revocable Employee Nonqualified Plans Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(i)-4 | - | PPL Employee Change in Control Agreements Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(i)-5 | - | PPL Revocable Director Nonqualified Plans Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(e) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
*[_]10(j) | - | Amended and Restated PPL Executive Deferred Compensation Plan, effective as of January 1, 2025
[_]10(k)-1 | - | Amended and Restated Supplemental Executive Retirement Plan, dated December 8, 2003 (Exhibit 10(s) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003)
[_]10(k)-2 | - | Amendment No. 1 to said Supplemental Executive Retirement Plan, dated December 16, 2004 (Exhibit 99.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 17, 2004)
[_]10(k)-3 | - | Amendment No. 2 to said Supplemental Executive Retirement Plan, dated as of January 1, 2005 (Exhibit 10(ff)-3 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2005)
[_]10(k)-4 | - | Amendment No. 3 to said Supplemental Executive Retirement Plan, dated as of January 22, 2007 (Exhibit 10(cc)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
[_]10(k)-5 | - | Amendment No. 4 to said Supplemental Executive Retirement Plan, dated as of December 9, 2008 (Exhibit 10(aa)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008)

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[_]10(k)-6 | - | Amendment No. 5 to said Supplemental Executive Retirement Plan, dated as of February 15, 2012 (Exhibit 10(gg)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2011)
[_]10(k)-7 | - | Amendment No. 6 to the Amended and Restated Supplemental Executive Retirement Plan, dated March 23, 2018 (Exhibit 10(g) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2018)
[_]10(l)-1 | - | Amended and Restated Incentive Compensation Plan, effective January 1, 2003 (Exhibit 10(p) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002)
[_]10(l)-2 | - | Amendment No. 1 to said Incentive Compensation Plan, dated as of January 1, 2005 (Exhibit 10(gg)-2 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2005)
[_]10(l)-3 | - | Amendment No. 2 to said Incentive Compensation Plan, dated as of January 26, 2007 (Exhibit 10(dd)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
[_]10(l)-4 | - | Amendment No. 3 to said Incentive Compensation Plan, dated as of March 21, 2007 (Exhibit 10(f) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(l)-5 | - | Amendment No. 4 to said Incentive Compensation Plan, effective December 1, 2007 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2008)
[_]10(l)-6 | - | Amendment No. 5 to said Incentive Compensation Plan, dated as of December 16, 2008 (Exhibit 10(bb)-6 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2008)
[_]10(l)-7 | - | Form of Stock Option Agreement for stock option awards under the Incentive Compensation Plan (Exhibit 10(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated February 1, 2006)
[_]10(l)-8 | - | Form of Performance Unit Agreement for performance unit awards under the Incentive Compensation Plan (Exhibit 10(ss) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2007)
[_]10(m) | - | Amended and Restated Incentive Compensation Plan for Key Employees, effective October 25, 2018 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2018)
[_]10(n) | - | Short-term Incentive Plan (Annex B to Proxy Statement of PPL Corporation, dated April 12, 2016)
[_]10(o) | - | Form of Change in Control Severance Protection Agreement entered into between PPL Corporation and Lonnie E. Bellar, Joseph P. Bergstein, Jr., David J. Bonenberger, John Gregory Cornett, John R. Crockett III, Dean A. Del Vecchio, Angela K. Gosman, Christine M. Martin, Stephanie R. Raymond, Vincent Sorgi, Francis X. Sullivan, and Wendy E. Stark
[_]10(p)-1 | - | PPL Corporation Amended and Restated 2012 Stock Incentive Plan, effective October 25, 2018 (Exhibit 10(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2018)
[_]10(p)-2 | - | Form of Performance Unit Agreement for performance unit awards under the Stock Incentive Plan (Exhibit 10(tt)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012)
[_]10(p)-3 | - | Form of Performance Contingent Restricted Stock Unit Agreement for restricted stock unit awards under the Stock Incentive Plan (Exhibit 10(tt)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012)

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[_]10(p)-4 | - | Form of Nonqualified Stock Option Agreement for stock option awards under the Stock Incentive Plan (Exhibit 10(tt)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012)
[_]10(p)-5 | - | Form of Return on Equity Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan (Exhibit 10(dd)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2017)
[_]10(p)-6 | - | Form of Restricted Stock Unit Agreement under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022)
[_]10(p)-7 | - | Form of Total Shareholder Return Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-7 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022)
[_]10(p)-8 | - | Form of Earnings Growth Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-8 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022)
[_]10(p)-9 | - | Form of Environmental, Social and Governance Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-9 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022)
*[_]10(p)-10 | - | Form of Total Shareholder Return Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 29, 2026
*[_]10(p)-11 | - | Form of Earnings Growth Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 29, 2026
*[_]10(p)-12 | - | Form of Long-Term Sustainability Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 29, 2026
[_]10(q) | - | PPL Corporation Executive Severance Plan, effective as of July 26, 2012 (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2012)
[_]10(r) | - | Form of Grant Letter dated May 29, 2015 (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 1, 2015)
[_]10(s) | - | Transition and Retirement Agreement dated August 12, 2021, by and among Paul W. Thompson, LG&E and KU Services Company, and PPL Corporation (Exhibit [_]10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2021)
[_]10(t) | - | Offer Letter dated March 6, 2021, between PPL Corporation and Wendy E. Stark (Exhibit [_]10(gg) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2021)
[_]10(u) | - | Rhode Island Energy Executive Supplemental Retirement Plan, effective February 24, 2022 (Exhibit [_]10(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022)
[_]10(v) | - | Separation Agreement between Stephanie R. Raymond, PPL Electric Utilities Corporation, and PPL Corporation dated October 9, 2023 (Exhibit [_]10(aa) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2023)

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[_]10(w) | - | Separation Agreement between Francis X. Sullivan and PPL Corporation dated January 14, 2025 (Exhibit 10.5[_] to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2025)
19 | - | PPL Insider Trading Policy (Exhibit 19 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2024)
*21 | - | Subsidiaries of PPL Corporation
*23(a) | - | Consent of Deloitte & Touche LLP - PPL Corporation
*23(b) | - | Consent of Deloitte & Touche LLP - PPL Electric Utilities Corporation
*23(c) | - | Consent of Deloitte & Touche LLP - Louisville Gas and Electric Company
*23(d) | - | Consent of Deloitte & Touche LLP - Kentucky Utilities Company
*24 | - | Power of Attorney
*31(a) | - | Certificate of PPL's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(b) | - | Certificate of PPL's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(c) | - | Certificate of PPL Electric's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(d) | - | Certificate of PPL Electric's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(e) | - | Certificate of LG&E's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(f) | - | Certificate of LG&E's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(g) | - | Certificate of KU's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(h) | - | Certificate of KU's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32(a) | - | Certificate of PPL's principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32(b) | - | Certificate of PPL Electric's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32(c) | - | Certificate of LG&E's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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*32(d) | - | Certificate of KU's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
97 | - | PPL Corporation Compensation Recoupment Policy, effective October 2, 2023 (Exhibit 97 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2023)
*99(a) | - | PPL Corporation and Subsidiaries Long-term Debt Schedule
101.INS | - | XBRL Instance Document for PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH | - | XBRL Taxonomy Extension Schema for PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
101.CAL | - | XBRL Taxonomy Extension Calculation Linkbase for PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
101.DEF | - | XBRL Taxonomy Extension Definition Linkbase for PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
101.LAB | - | XBRL Taxonomy Extension Label Linkbase for PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
101.PRE | - | XBRL Taxonomy Extension Presentation Linkbase for PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
104 |  | The Cover Page Interactive Data File is formatted as Inline XBRL and contained in Exhibits 101.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PPL Corporation
(Registrant)

By /s/ Vincent Sorgi |  |  |  |
Vincent Sorgi - |  |  |  |
President and Chief Executive Officer |  |  |  |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Vincent Sorgi |  |  |  |
Vincent Sorgi - |  |  |  |
President and Chief Executive Officer |  |  |  |
and Director |  |  |  |
(Principal Executive Officer) |  |  |  |
/s/ Joseph P. Bergstein, Jr. |  |  |  |
Joseph P. Bergstein, Jr. - |  |  |  |
Executive Vice President and |  |  |  |
Chief Financial Officer |  |  |  |
(Principal Financial Officer) |  |  |  |
/s/ Marlene C. Beers |  |  |  |
Marlene C. Beers - |  |  |  |
Vice President and Controller |  |  |  |
(Principal Accounting Officer) |  |  |  |
Directors: |  |  |  |
Arthur P. Beattie |  | Natica von Althann |  |
Venkata Rajamannar Madabhushi |  | Keith H. Williamson |  |
Heather B. Redman |  | Phoebe A. Wood |  |
Craig A. Rogerson |  | Armando Zagalo de Lima |  |
Linda G. Sullivan |  |  |  |
/s/ Vincent Sorgi |  |  |  |
Vincent Sorgi, Attorney-in-fact |  | February 20, 2026 |  |

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PPL Electric Utilities Corporation
(Registrant)

By /s/ Christine M. Martin |  |  |  |
Christine M. Martin - |  |  |  |
President |  |  |  |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Christine M. Martin |  |  |  |
Christine M. Martin - |  |  |  |
President |  |  |  |
(Principal Executive Officer) |  |  |  |
/s/ Marlene C. Beers |  |  |  |
Marlene C. Beers - |  |  |  |
Vice President and Controller (Principal Financial Officer and Principal Accounting Officer) |  |  |  |
Directors: |  |  |  |
/s/ Joseph P. Bergstein, Jr. |  | /s/ Vincent Sorgi |  |
Joseph P. Bergstein, Jr. |  | Vincent Sorgi |  |
/s/ Christine M. Martin |  | /s/ Wendy E. Stark |  |
Christine M. Martin |  | Wendy E. Stark |  |
Date: February 20, 2026 |  |  |  |

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Louisville Gas and Electric Company
(Registrant)

By /s/ John R. Crockett III |  |  |  |
John R. Crockett III - |  |  |  |
President |  |  |  |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ John R. Crockett III |  |  |  |
John R. Crockett III - |  |  |  |
President |  |  |  |
(Principal Executive Officer) |  |  |  |
/s/ Christopher M. Garrett |  |  |  |
Christopher M. Garrett - |  |  |  |
Vice President-Finance and Accounting (Principal Financial Officer and Principal Accounting Officer) |  |  |  |
Directors: |  |  |  |
/s/ Joseph P. Bergstein, Jr. |  | /s/ Vincent Sorgi |  |
Joseph P. Bergstein, Jr. |  | Vincent Sorgi |  |
/s/ John R. Crockett III |  | /s/ Wendy E. Stark |  |
John R. Crockett III |  | Wendy E. Stark |  |
Date: February 20, 2026 |  |  |  |

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Kentucky Utilities Company
(Registrant)

By /s/ John R. Crockett III |  |  |  |
John R. Crockett III - |  |  |  |
President |  |  |  |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ John R. Crockett III |  |  |  |
John R. Crockett III - |  |  |  |
President |  |  |  |
(Principal Executive Officer) |  |  |  |
/s/ Christopher M. Garrett |  |  |  |
Christopher M. Garrett - |  |  |  |
Vice President-Finance and Accounting (Principal Financial Officer and Principal Accounting Officer) |  |  |  |
Directors: |  |  |  |
/s/ Joseph P. Bergstein, Jr. |  | /s/ Vincent Sorgi |  |
Joseph P. Bergstein, Jr. |  | Vincent Sorgi |  |
/s/ John R. Crockett III |  | /s/ Wendy E. Stark |  |
John R. Crockett III |  | Wendy E. Stark |  |
Date: February 20, 2026 |  |  |  |

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