Combined Notes to Condensed Financial Statements (Unaudited)
Index to Combined Notes to Condensed Financial Statements
The notes to the condensed financial statements that follow are a combined presentation. The following list indicates the Registrants to which the notes apply:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Registrant |
| | PPL | | PPL Electric | | LG&E | | KU |
| 1. Interim Financial Statements | | x | | x | | x | | x |
| | | | | | | | |
| 2. Segment and Related Information | | x | | x | | x | | x |
| 3. Revenue from Contracts with Customers | | x | | x | | x | | x |
| 4. Earnings Per Share | | x | | | | | | |
| 5. Income Taxes | | x | | x | | x | | x |
| 6. Utility Rate Regulation | | x | | x | | x | | x |
| 7. Financing Activities | | x | | x | | x | | x |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| 8. Defined Benefits | | x | | x | | x | | x |
| 9. Commitments and Contingencies | | x | | x | | x | | x |
| 10. Related Party Transactions | | | | x | | x | | x |
| 11. Other Income (Expense) - net | | x | | x | | | | |
| 12. Fair Value Measurements | | x | | x | | x | | x |
| 13. Derivative Instruments and Hedging Activities | | x | | x | | x | | x |
| 14. Asset Retirement Obligations | | x | | | | x | | x |
| 15. Accumulated Other Comprehensive Income (Loss) | | x | | | | | | |
| 16. New Accounting Guidance Pending Adoption | | x | | x | | x | | x |
1. Interim Financial Statements
(All Registrants)
Capitalized terms and abbreviations appearing in the unaudited combined notes to condensed 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 Registrant's related activities and disclosures. Within combined disclosures, amounts are disclosed for any Registrant when significant.
The accompanying unaudited condensed financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and, therefore, do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation in accordance with GAAP are reflected in the condensed financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed. Each Registrant's Balance Sheet at December 31, 2025 is derived from that Registrant's 2025 audited Balance Sheet. The financial statements and notes thereto should be read in conjunction with the financial statements and notes contained in each Registrant's 2025 Form 10-K. The results of operations for the three months ended March 31, 2026 are not necessarily indicative of the results to be expected for the full year ending December 31, 2026 or other future periods, because results for interim periods can be disproportionately influenced by various factors, developments and seasonal variations.
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 transmission, 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" consists primarily of corporate level financing costs, certain unallocated costs and certain non-recoverable costs incurred prior to 2026 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.
The table below provides information about PPL's segments and includes a reconciliation of segment net income to consolidated net income for the three months ended March 31, 2026:
| | | | | | | | | | | | | | | | | | | | | | | |
| Kentucky Regulated | | Pennsylvania Regulated | | Rhode Island Regulated | | Total |
| Operating Revenues from external customers (a) | $ | 1,207 | | | $ | 971 | | | $ | 595 | | | $ | 2,773 | |
| Reconciliation of revenue | | | | | | | |
| Corporate and Other revenues | | | | | | | 1 | |
| Total consolidated revenues | | | | | | | $ | 2,774 | |
| | | | | | | |
| Less: | | | | | | | |
| Fuel | 274 | | | — | | | — | | | 274 | |
| Energy purchases | 126 | | | 331 | | | 247 | | | 704 | |
| Other operation and maintenance | 193 | | | 190 | | | 191 | | | 574 | |
| Depreciation | 192 | | | 108 | | | 47 | | | 347 | |
| Taxes, other than income | 27 | | | 48 | | | 46 | | | 121 | |
| Other (income) expense - net | (11) | | | (12) | | | (10) | | | (33) | |
| Interest (income) from affiliate | — | | | (1) | | | — | | | (1) | |
| Interest expense | 71 | | | 67 | | | 33 | | | 171 | |
| Income taxes | 65 | | | 56 | | | 5 | | | 126 | |
| Segment net income | $ | 270 | | | $ | 184 | | | $ | 36 | | | $ | 490 | |
| | | | | | | |
| Reconciliation of segment profit or loss to consolidated net income | | | | | | | |
| Corporate and Other net loss | | | | | | | (38) | |
| Net Income | | | | | | | $ | 452 | |
(a)See Note 3 for additional information on Operating Revenues.
Other information for the segments and reconciliation to PPL's Consolidated results for the three months ended March 31, 2026 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Kentucky Regulated | | Pennsylvania Regulated | | Rhode Island Regulated | | Total Segments | | Corporate and Other | | Consolidated Total |
| Other Segment Disclosures | | | | | | | | | | | |
| Amortization (a) | $ | 14 | | | $ | 17 | | | $ | — | | | $ | 31 | | | $ | 7 | | | $ | 38 | |
| Deferred income taxes and investment tax credits (b) | 6 | | | 37 | | | 22 | | | 65 | | | 29 | | | 94 | |
| Expenditures for long lived assets | 465 | | | 337 | | | 250 | | | 1,052 | | | 9 | | | 1,061 | |
(a)Represents non-cash expense items that include amortization of 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 table below provides information about PPL's segments and includes a reconciliation of segment net income to consolidated net income for the three months ended March 31, 2025:
| | | | | | | | | | | | | | | | | | | | | | | |
| Kentucky Regulated | | Pennsylvania Regulated | | Rhode Island Regulated | | Total |
| Operating Revenues from external customers (a) | $ | 1,059 | | | $ | 819 | | | $ | 626 | | | $ | 2,504 | |
| Reconciliation of revenue | | | | | | | |
| Corporate and Other revenues | | | | | | | — | |
| Total consolidated revenues | | | | | | | $ | 2,504 | |
| | | | | | | |
| Less: | | | | | | | |
| Fuel | 234 | | | — | | | — | | | 234 | |
| Energy purchases | 96 | | | 229 | | | 235 | | | 560 | |
| Other operation and maintenance | 200 | | | 162 | | | 200 | | | 562 | |
| Depreciation | 176 | | | 102 | | | 42 | | | 320 | |
| Taxes, other than income | 25 | | | 41 | | | 47 | | | 113 | |
| Other (income) expense - net | (8) | | | (11) | | | (7) | | | (26) | |
| Interest (income) from affiliate | — | | | (2) | | | (2) | | | (4) | |
| Interest expense | 60 | | | 60 | | | 23 | | | 143 | |
| Income taxes | 53 | | | 54 | | | 18 | | | 125 | |
| Segment net income | $ | 223 | | | $ | 184 | | | $ | 70 | | | $ | 477 | |
| | | | | | | |
| Reconciliation of segment profit or loss to consolidated net income | | | | | | | |
| Corporate and Other net loss | | | | | | | (63) | |
| Net Income | | | | | | | $ | 414 | |
(a)See Note 3 for additional information on Operating Revenues.
Other information for the segments and reconciliation to PPL's Consolidated results for the three months ended March 31, 2025 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Kentucky Regulated | | Pennsylvania Regulated | | Rhode Island Regulated | | Total Segments | | Corporate and Other | | Consolidated Total |
| Other Segment Disclosures | | | | | | | | | | | |
| Amortization (a) | $ | 5 | | | $ | 11 | | | $ | — | | | $ | 16 | | | $ | 4 | | | $ | 20 | |
| Deferred income taxes and investment tax credits (b) | 8 | | | 20 | | | (7) | | | 21 | | | 17 | | | 38 | |
| Expenditures for long lived assets | 290 | | | 328 | | | 172 | | | 790 | | | 3 | | | 793 | |
(a)Represents non-cash expense items that include amortization of 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 Balance Sheets as of:
| | | | | | | | | | | |
| March 31,
2026 | | December 31,
2025 |
| Total Assets | | | |
| Kentucky Regulated | $ | 19,231 | | | $ | 19,060 | |
| Pennsylvania Regulated | 17,216 | | | 16,886 | |
| Rhode Island Regulated | 7,636 | | | 7,510 | |
| Corporate and Other (a) | 2,221 | | | 1,788 | |
| Total | $ | 46,304 | | | $ | 45,244 | |
(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.
The measure of segment assets is reported on PPL Electric's Balance Sheets as total consolidated assets. The measures of significant segment expenses are reported on PPL Electric's Statements of Income. 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.
The measures of segment assets are reported on the Balance Sheets of LG&E and KU as total assets. The measures of significant segment expenses are reported on the Statements of Income of LG&E and KU. 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.
3. Revenue from Contracts with Customers
(All Registrants)
See Note 3 in the Registrants' 2025 Form 10-K for a discussion of the principal activities from which PPL Electric, LG&E and KU and PPL's Pennsylvania Regulated, Rhode Island Regulated and Kentucky Regulated segments generate their revenues. The following tables reconcile "Operating Revenues" included in each Registrant's Statement of Income with revenues generated from contracts with customers for the periods ended March 31.
| | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| 2026 Three Months |
| PPL | | PPL Electric | | LG&E | | KU |
| Operating Revenues (a) | $ | 2,774 | | | $ | 971 | | | $ | 597 | | | $ | 625 | |
| Revenues derived from: | | | | | | | |
| Alternative revenue programs (b) | 20 | | | 2 | | | (3) | | | 1 | |
| Other (c) | (9) | | | (6) | | | (2) | | | (2) | |
| Revenues from Contracts with Customers | $ | 2,785 | | | $ | 967 | | | $ | 592 | | | $ | 624 | |
| | | | | | | |
| 2025 Three Months |
| PPL | | PPL Electric | | LG&E | | KU |
| Operating Revenues (a) | $ | 2,504 | | | $ | 819 | | | $ | 505 | | | $ | 564 | |
| Revenues derived from: | | | | | | | |
| Alternative revenue programs (b) | 50 | | | (2) | | | 2 | | | 4 | |
| Other (c) | (9) | | | (5) | | | (1) | | | (2) | |
| Revenues from Contracts with Customers | $ | 2,545 | | | $ | 812 | | | $ | 506 | | | $ | 566 | |
(a)PPL includes $595 million for the three months ended March 31, 2026 and $626 million for the three months ended March 31, 2025 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)This line item shows the over/under collection of rate mechanisms deemed alternative revenue programs with over-collections of revenue shown as positive amounts in the table above and under-collections shown as negative amounts.
(c)Represents additional revenues outside the scope of revenues from contracts with customers, such as lease and other miscellaneous revenues.
The following tables show revenues from contracts with customers disaggregated by customer class for the periods ended March 31.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Three Months |
| Residential | | Commercial | | Industrial | | Other (a) | | Wholesale - municipality | | Wholesale - other (b) | | Transmission | | Revenues from Contracts with Customers |
| PPL | | | | | | | | | | | | | | | |
| 2026 | | | | | | | | | | | | | | | |
| PA Regulated | $ | 562 | | | $ | 130 | | | $ | 16 | | | $ | 12 | | | $ | — | | | $ | — | | | $ | 247 | | | $ | 967 | |
| KY Regulated | 553 | | | 313 | | | 171 | | | 112 | | | 7 | | | 45 | | | — | | | 1,201 | |
| RI Regulated | 362 | | | 189 | | | 19 | | | (9) | | | — | | | — | | | 55 | | | 616 | |
| Corp and Other | — | | | — | | | — | | | 1 | | | — | | | — | | | — | | | 1 | |
| Total PPL | $ | 1,477 | | | $ | 632 | | | $ | 206 | | | $ | 116 | | | $ | 7 | | | $ | 45 | | | $ | 302 | | | $ | 2,785 | |
| | | | | | | | | | | | | | | |
| 2025 | | | | | | | | | | | | | | | |
| PA Regulated | $ | 457 | | | $ | 106 | | | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 223 | | | $ | 812 | |
| KY Regulated | 487 | | | 280 | | | 154 | | | 96 | | | 7 | | | 38 | | | — | | | 1,062 | |
| RI Regulated | 441 | | | 197 | | | 18 | | | (35) | | | — | | | — | | | 50 | | | 671 | |
| | | | | | | | | | | | | | | |
| Total PPL | $ | 1,385 | | | $ | 583 | | | $ | 185 | | | $ | 74 | | | $ | 7 | | | $ | 38 | | | $ | 273 | | | $ | 2,545 | |
| | | | | | | | | | | | | | | |
| PPL Electric | | | | | | | | | | | | | | | |
| 2026 | $ | 562 | | | $ | 130 | | | $ | 16 | | | $ | 12 | | | $ | — | | | $ | — | | | $ | 247 | | | $ | 967 | |
| 2025 | $ | 457 | | | $ | 106 | | | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 223 | | | $ | 812 | |
| | | | | | | | | | | | | | | |
| LG&E | | | | | | | | | | | | | | | |
| 2026 | $ | 276 | | | $ | 165 | | | $ | 50 | | | $ | 69 | | | $ | — | | | $ | 32 | | | $ | — | | | $ | 592 | |
| 2025 | $ | 239 | | | $ | 147 | | | $ | 46 | | | $ | 54 | | | $ | — | | | $ | 20 | | | $ | — | | | $ | 506 | |
| | | | | | | | | | | | | | | |
| KU | | | | | | | | | | | | | | | |
| 2026 | $ | 277 | | | $ | 148 | | | $ | 121 | | | $ | 43 | | | $ | 7 | | | $ | 28 | | | $ | — | | | $ | 624 | |
| 2025 | $ | 248 | | | $ | 133 | | | $ | 108 | | | $ | 42 | | | $ | 7 | | | $ | 28 | | | $ | — | | | $ | 566 | |
(a)Primarily includes revenues from pole attachments, street lighting, other public authorities and other non-core businesses, and for Rhode Island Regulated Segment certain regulatory deferral mechanisms which could result in a reduction in revenues from over collections. 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 the Kentucky Regulated segment.
As discussed in Note 2, PPL segments its business by geographic location. Revenues from external customers for each segment are reconciled to revenues from contracts with customers in the footnotes to the tables above.
Contract receivables from customers are primarily included in "Accounts receivable - Customer", "Unbilled revenues", and "Other noncurrent assets" on the Balance Sheets.
The following table shows the accounts receivable and unbilled revenues balances that were impaired for the periods ended March 31.
| | | | | | | | | | | | | | | |
| | | Three Months |
| | | | | 2026 | | 2025 |
| PPL | | | | | $ | 36 | | | $ | 25 | |
| PPL Electric | | | | | 8 | | | 7 | |
| LG&E | | | | | 1 | | | 2 | |
| KU | | | | | 4 | | | 1 | |
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 generally recognized as revenue ratably over the quarterly 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 were not material at March 31, 2026 and 2025.
4. 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. 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 2023 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 7 for additional information on the ATM Program.
The 2023 Exchangeable Notes are dilutive under the If-Converted Method as PPL's quarterly average common stock price exceeds the conversion price prescribed in the indenture governing the 2023 Exchangeable Notes. The 2025 Exchangeable Notes are excluded from the diluted EPS calculation as PPL's quarterly average common stock price has not exceeded the conversion price prescribed in the indenture governing the 2025 Exchangeable Notes. See Note 8 in PPL's Form 10-K for the year ended December 31, 2025 for additional information on the 2025 Exchangeable Notes due 2030 and Note 8 in PPL's Form 10-K for the year ended December 31, 2023 for additional information on the 2023 Exchangeable Notes due 2028.
The Purchase Contracts associated with the Corporate Units issued in February 2026 are excluded from the dilutive EPS calculation under the Treasury Stock Method as the average of the volume-weighted average price of PPL's common stock has not exceeded the price prescribed in the agreement governing the Purchase Contracts. See Note 7 for additional information on the Purchase Contracts.
Reconciliations of the amounts of income and shares of PPL common stock (in thousands) for the periods ended March 31 used in the EPS calculation are:
| | | | | | | | | | | | | | | | | |
| | | | Three Months |
| | | | | | 2026 | | 2025 |
| Income (Numerator) | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net income attributable to PPL | | | | | $ | 452 | | | $ | 414 | |
| Less amounts allocated to participating securities | | | | | 1 | | | 1 | |
| Net income available to PPL common shareowners - Basic and Diluted | | | | | $ | 451 | | | $ | 413 | |
| | | | | | | |
| Shares of Common Stock (Denominator) | | | | | | | |
| Weighted-average shares - Basic EPS | | | | | 751,764 | | | 738,691 | |
| | | | | | | |
| Add: Dilutive share-based payment awards (a) | | | | | 2,297 | | | 2,709 | |
| Add: Forward sale agreements | | | | | 644 | | | — | |
| Add: Exchangeable Notes | | | | | 2,453 | | | — | |
| Weighted-average shares - Diluted EPS | | | | | 757,158 | | | 741,400 | |
| | | | | | | |
| Basic and Diluted EPS | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net Income available to PPL common shareowners | | | | | $ | 0.60 | | | $ | 0.56 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
(a) The Treasury Stock Method was applied to non-participating share-based payment awards.
For the periods ended March 31, PPL issued common stock related to the DRIP as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | |
| | | | Three Months |
| | | | | | 2026 | | 2025 |
| | | | | | | |
| DRIP | | | | | 185 | | | 200 | |
For the periods ended March 31, the following shares (in thousands) were excluded from the computations of diluted EPS because the effect would have been antidilutive.
| | | | | | | | | | | | | | | | | |
| | | | Three Months |
| | | | | 2026 | | 2025 |
| Stock-based compensation awards | | | | | 191 | | | 175 | |
| Forward sale agreements | | | | | — | | | 2,033 | |
5. Income Taxes
Reconciliations of income tax expense (benefit) for the periods ended March 31 are as follows.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (PPL) | | | | | | | | | | | |
| | | Three Months |
| | | | | 2026 | | 2025 |
| | | | | Amount | | Percent | | Amount | | Percent |
| Federal income tax on Income Before Income Taxes at statutory tax rate | | | | | $ | 118 | | | 21.0 | % | | $ | 108 | | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | |
| State income taxes, net of federal income tax benefit (a) | | | | | 24 | | | 4.3 | % | | 23 | | | 4.4 | % |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Utility rate-making tax adjustments (federal and state): | | | | | | | | | | | |
| Amortization of excess deferred income taxes | | | | | (14) | | | (2.6) | % | | (16) | | | (3.1) | % |
| AFUDC Equity | | | | | (7) | | | (1.3) | % | | (5) | | | (1.0) | % |
| Flow-through rate-making (b) | | | | | (6) | | | (1.0) | % | | (6) | | | (1.2) | % |
| Subtotal | | | | | (27) | | | (4.9) | % | | (27) | | | (5.3) | % |
| Other | | | | | (7) | | | (1.1) | % | | (2) | | | (0.3) | % |
| Total increase (decrease) | | | | | (10) | | | (1.7) | % | | (6) | | | (1.2) | % |
| Total income tax expense | | | | | $ | 108 | | | 19.3 | % | | $ | 102 | | | 19.8 | % |
(a) Jurisdictions that comprise 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (PPL Electric) | | | | | | | | | | | |
| | | Three Months |
| | | | | 2026 | | 2025 |
| | | | | Amount | | Percent | | Amount | | Percent |
| Taxes at statutory tax rate | | | | | $ | 50 | | | 21.0 | % | | $ | 50 | | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | |
| State income taxes, net of federal income tax benefit (a) | | | | | 14 | | | 5.8 | % | | 14 | | | 6.0 | % |
| Utility rate-making tax adjustments (federal and state): | | | | | | | | | |
| Amortization of excess deferred income taxes | | | | | (2) | | | (0.7) | % | | (3) | | | (1.1) | % |
| AFUDC Equity | | | | | (2) | | | (0.8) | % | | (1) | | | (0.7) | % |
| Flow-through rate-making (b) | | | | | (3) | | | (1.5) | % | | (5) | | | (2.1) | % |
| Subtotal | | | | | (7) | | | (3.0) | % | | (9) | | | (3.9) | % |
| Other | | | | | (1) | | | (0.5) | % | | (1) | | | (0.4) | % |
| Total increase (decrease) | | | | | 6 | | | 2.3 | % | | 4 | | | 1.7 | % |
| Total income tax expense | | | | | $ | 56 | | | 23.3 | % | | $ | 54 | | | 22.7 | % |
(a) The jurisdiction that comprises 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (LG&E) | | | | | | | | | | | |
| | | | Three Months |
| | | | | | 2026 | | 2025 |
| | | | | Amount | | Percent | | Amount | | Percent |
| Taxes at statutory tax rate | | | | | $ | 35 | | | 21.0 | % | | $ | 27 | | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | |
| State income taxes, net of federal income tax benefit (a) | | | | | 6 | | | 3.7 | % | | 5 | | | 3.9 | % |
| Utility rate-making tax adjustments (federal and state): | | | | | | | | | | | |
| Amortization of excess deferred income taxes | | | | | (6) | | | (3.6) | % | | (5) | | | (4.0) | % |
| AFUDC Equity | | | | | (2) | | | (1.1) | % | | (1) | | | (1.1) | % |
| Subtotal | | | | | (8) | | | (4.7) | % | | (6) | | | (5.1) | % |
| | | | | | | | | | | |
| Total increase (decrease) | | | | | (2) | | | (1.0) | % | | (1) | | | (1.2) | % |
| Total income tax expense | | | | | $ | 33 | | | 20.0 | % | | $ | 26 | | | 19.8 | % |
(a) The jurisdiction that comprises the majority of state income taxes, net of federal effect, is Kentucky.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (KU) | | | | | | | | | | | |
| | | | Three Months |
| | | | | | 2026 | | 2025 |
| | | | | Amount | | Percent | | Amount | | Percent |
| Taxes at statutory tax rate | | | | | $ | 38 | | | 21.0 | % | | $ | 33 | | | 21.0 | % |
| Increase (decrease) due to: | | | | | | | | | | | |
| State income taxes, net of federal income tax benefit (a) | | | | | 7 | | | 3.9 | % | | 6 | | | 3.7 | % |
| Utility rate-making tax adjustments (federal and state): | | | | | | | | | | | |
| Amortization of excess deferred income taxes | | | | | (6) | | | (3.3) | % | | (6) | | | (3.9) | % |
| AFUDC Equity | | | | | (2) | | | (1.1) | % | | (1) | | | (0.8) | % |
| Subtotal | | | | | (8) | | | (4.4) | % | | (7) | | | (4.7) | % |
| Other | | | | | (1) | | | (0.5) | % | | (1) | | | (0.1) | % |
| Total increase (decrease) | | | | | (2) | | | (1.0) | % | | (2) | | | (1.1) | % |
| Total income tax expense | | | | | $ | 36 | | | 20.0 | % | | $ | 31 | | | 19.9 | % |
(a) The jurisdiction that comprises the majority of state income taxes, net of federal effect, is Kentucky.
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 and applicable guidance from the IRS 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 energy tax credits under Internal Revenue Code (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 energy 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 material limitations on its clean energy projects and associated tax credits but will continue to monitor closely.
6. Utility Rate Regulation
(All Registrants)
The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| PPL | | PPL Electric | | LG&E | | KU |
| March 31,
2026 | | December 31,
2025 | | March 31,
2026 | | December 31,
2025 | | March 31,
2026 | | December 31,
2025 | | March 31,
2026 | | December 31,
2025 |
| Current Regulatory Assets: | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Rate adjustment mechanisms | $ | 95 | | | $ | 86 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| Renewable energy certificates | 27 | | | 21 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Storm damage expense rider | 50 | | | 53 | | | 50 | | | 53 | | | — | | | — | | | — | | | — | |
| Gas supply clause | 46 | | | 10 | | | — | | | — | | | 46 | | | 10 | | | — | | | — | |
| Fuel adjustment clause | 14 | | | 4 | | | — | | | — | | | 7 | | | 3 | | | 7 | | | 1 | |
| Transmission service charge | 66 | | | 61 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| TCJA | 39 | | | 40 | | | 39 | | | 40 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other | 38 | | | 33 | | | 14 | | | 19 | | | 8 | | | 6 | | | 1 | | | — | |
| Total current regulatory assets | $ | 375 | | | $ | 308 | | | $ | 103 | | | $ | 112 | | | $ | 61 | | | $ | 19 | | | $ | 8 | | | $ | 1 | |
| | | | | | | | | | | | | | | |
| Noncurrent Regulatory Assets: | | | | | | | | | | | | | | | |
| Defined benefit plans | $ | 952 | | | $ | 961 | | | $ | 474 | | | $ | 477 | | | $ | 209 | | | $ | 212 | | | $ | 143 | | | $ | 144 | |
| Plant outage costs | 21 | | | 23 | | | — | | | — | | | 4 | | | 5 | | | 17 | | | 18 | |
| Net metering | 151 | | | 164 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Environmental cost recovery | 100 | | | 102 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Storm costs | 111 | | | 113 | | | 39 | | | 42 | | | 23 | | | 24 | | | 36 | | | 38 | |
| Unamortized loss on debt | 18 | | | 18 | | | 2 | | | 2 | | | 8 | | | 8 | | | 6 | | | 6 | |
| | | | | | | | | | | | | | | |
| Terminated interest rate swaps | 46 | | | 47 | | | — | | | — | | | 27 | | | 28 | | | 19 | | | 19 | |
| Accumulated cost of removal of utility plant | 195 | | | 184 | | | 195 | | | 184 | | | — | | | — | | | — | | | — | |
| AROs | 259 | | | 263 | | | — | | | — | | | 72 | | | 73 | | | 187 | | | 190 | |
| | | | | | | | | | | | | | | |
| RAR | 74 | | | 76 | | | — | | | — | | | 74 | | | 76 | | | — | | | — | |
| | | | | | | | | | | | | | | |
| Gas line inspections | 24 | | | 24 | | | — | | | — | | | 22 | | | 22 | | | 2 | | | 2 | |
| Advanced metering infrastructure | 66 | | | 67 | | | — | | | — | | | 28 | | | 28 | | | 38 | | | 39 | |
| IT system costs | 49 | | | 18 | | | 23 | | | 18 | | | 13 | | | — | | | 13 | | | — | |
| Other | 34 | | | 32 | | | 3 | | | 2 | | | 6 | | | 6 | | | 9 | | | 11 | |
| Total noncurrent regulatory assets | $ | 2,100 | | | $ | 2,092 | | | $ | 736 | | | $ | 725 | | | $ | 486 | | | $ | 482 | | | $ | 470 | | | $ | 467 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| PPL | | PPL Electric | | LG&E | | KU |
| March 31,
2026 | | December 31,
2025 | | March 31,
2026 | | December 31,
2025 | | March 31,
2026 | | December 31,
2025 | | March 31,
2026 | | December 31,
2025 |
| Current Regulatory Liabilities: | | | | | | | | | | | | | | | |
| Generation supply charge | $ | 38 | | | $ | 45 | | | $ | 38 | | | $ | 45 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Transmission service charge | 36 | | | 17 | | | 36 | | | 17 | | | — | | | — | | | — | | | — | |
| Universal service rider | 3 | | | 17 | | | 3 | | | 17 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Transmission formula rate | 76 | | | 62 | | | 25 | | | 23 | | | — | | | — | | | — | | | — | |
| Rate adjustment mechanisms | 121 | | | 124 | | | — | | | — | | | — | | | — | | | — | | | — | |
| Energy efficiency | 26 | | | 26 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| DSM | 21 | | | 21 | | | — | | | — | | | 8 | | | 8 | | | 13 | | | 13 | |
| | | | | | | | | | | | | | | |
| Revenue decoupling mechanism | 50 | | | 55 | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Other | 18 | | | 9 | | | 9 | | | 1 | | | 5 | | | 5 | | | 4 | | | 3 | |
| Total current regulatory liabilities | $ | 389 | | | $ | 376 | | | $ | 111 | | | $ | 103 | | | $ | 13 | | | $ | 13 | | | $ | 17 | | | $ | 16 | |
| | | | | | | | | | | | | | | |
| Noncurrent Regulatory Liabilities: | | | | | | | | | | | | | | | |
| Accumulated cost of removal of utility plant | $ | 1,047 | | | $ | 1,043 | | | $ | — | | | $ | — | | | $ | 338 | | | $ | 334 | | | $ | 415 | | | $ | 415 | |
| | | | | | | | | | | | | | | |
| Net deferred taxes | 1,769 | | | 1,798 | | | 697 | | | 708 | | | 409 | | | 415 | | | 459 | | | 467 | |
| Defined benefit plans | 334 | | | 342 | | | 119 | | | 120 | | | 23 | | | 23 | | | 69 | | | 69 | |
| Terminated interest rate swaps | 50 | | | 52 | | | — | | | — | | | 25 | | | 26 | | | 25 | | | 26 | |
| | | | | | | | | | | | | | | |
| Advanced metering infrastructure | 30 | | | 30 | | | — | | | — | | | 10 | | | 10 | | | 20 | | | 20 | |
| Other | 53 | | | 53 | | | — | | | — | | | 1 | | | 1 | | | — | | | — | |
| Total noncurrent regulatory liabilities | $ | 3,283 | | | $ | 3,318 | | | $ | 816 | | | $ | 828 | | | $ | 806 | | | $ | 809 | | | $ | 988 | | | $ | 997 | |
Below is an overview of selected regulatory assets and liabilities presented in the preceding tables. This overview has been updated from Note 7 in the Registrants' 2025 Form 10-K to include the results of the 2025 Kentucky base rate case proceedings. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."
(All Registrants)
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. As a result of the 2025 Kentucky Rate Case, LG&E and KU agreed to remove from depreciation expense the terminal net salvage component for thermal units. These costs will be recovered when spent upon retirement of the associated generating unit.
IT System Costs
IT system costs represent expenditures incurred associated with implementing strategic information technology investments. The KPSC approved recovery of these costs in the 2025 Kentucky base rate case proceedings. Costs will be amortized over a period consistent with the depreciable life of the associated IT system.
Advanced Metering Infrastructure (AMI) (PPL, LG&E and KU)
In the 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 AFUDC as 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 the 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. AMI regulatory assets approved for base rate recovery are being amortized through 2040 and AMI regulatory liabilities approved for base rate return are being amortized through 2030.
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, and on April 16, 2026, submitted testimony. A ruling from the RIPUC is anticipated during the third quarter of 2026. PPL cannot predict the outcome of the proceeding.
Hold Harmless Commitment
As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers (the Division) 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 Division's Advocacy Section (the Hold Harmless Implementation Agreement) to satisfy the Hold Harmless Commitment by providing approximately $155 million in miscellaneous bill credits. On September 10, 2025, the Division 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. RIE subsequently 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.
During the first quarter of 2026, RIE re-engaged in discussions with the Division regarding a proposal to satisfy the Hold Harmless Commitment. On April 16, 2026, RIE filed a motion with the RIPUC to reopen the previous docket concerning the Hold Harmless Commitment along with an updated tariff advice which reflects a methodology consistent with the previously proposed miscellaneous bill credits and two potential, alternative methods of allocating the bill credits among customers. The actual amount of miscellaneous bill credits to be issued will vary depending upon the agreed upon cost of capital, timing of the issuance of the credits, and the outcome of the pending distribution rate case proceedings. As proposed, the bill credits would be issued and recorded as a reduction to revenue in the first quarters of 2027 and 2028. On April 17, 2026, the RIPUC approved the motion and consolidated the tariff advice docket with the pending base distribution rate proceeding. PPL cannot predict the outcome of these proceedings.
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 will be recovered through the Storm Fund Replenishment factor.
FY 2027 Gas ISR Plan
On March 27, 2026, the RIPUC approved a capital budget of $161 million. In addition, the RIPUC approved an O&M budget of $17 million for curb-to-curb paving. On March 31, 2026, the RIPUC approved RIE's compliance filing for rates effective April 1, 2026.
FY 2027 Electric ISR Plan
On March 27, 2026, the RIPUC approved a capital budget of $141 million (including $18 million for Advanced Metering Functionality). In addition, the RIPUC approved an O&M budget of $14 million, primarily for vegetation management. On March 31, 2026, the RIPUC approved RIE's compliance filing for rates effective April 1, 2026.
Kentucky Activities
(PPL, LG&E and KU)
Rate Case Proceedings
On February 16, 2026, the KPSC issued orders approving portions of LG&E's and KU's October 2025 stipulation and recommendation, with modifications. See "Regulatory Matters - Kentucky Activities – Rate Case Proceedings" in Note 7 in PPL's, LG&E's and KU's 2025 Form 10-K for additional information on the filings made by LG&E and KU with the KPSC in 2025.
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 Generation Cost Recovery Adjustment Clause 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. LG&E and KU applied refunds to customer accounts for amounts billed in excess of the rates approved by the KPSC.
The KPSC orders did not approve the Sharing Mechanism 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 filed a request for rehearing on several issues contained in the orders from the KPSC on March 11, 2026, along with a Notice of their Withdrawal from the stipulation. On March 27, 2026, the KPSC issued orders correcting tariff appendices, denying two intervenor rehearing requests, and reopening the dockets to consider LG&E's and KU's request for rehearing. The KPSC has established a procedural schedule with two additional rounds of discovery beginning on April 10, 2026.
PPL, LG&E and KU cannot predict the outcome of this matter.
Potential Legal Merger of LG&E and KU
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 and KU filed a joint update in the rate case proceedings stating that they expected to file necessary applications for merger approval in mid-2026 with the KPSC. On March 31, 2026, LG&E and KU filed an application with the KPSC for approval of the merger and associated accounting, financing and rate mechanism matters. On April 17, 2026, LG&E and KU filed an application with the VSCC for approval of the merger and certain associated matters. LG&E and KU anticipate filing a related application with the VSCC for approval of financing and affiliate transactions in connection with the proposed merger by mid-May 2026. LG&E and KU anticipate filing an application with the FERC for approval of the merger in the second quarter of 2026. Ultimately, any merger would require formal approval from the KPSC, VSCC and FERC, as well as the boards and sole shareholder of both companies.
PPL, LG&E and KU cannot predict the outcome of this matter, including the regulatory proceedings.
Mill Creek Unit 2 RAR Application (PPL and LG&E)
In 2023, the KPSC issued an order approving, among other items, the requested retirement of Mill Creek Unit 2.
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 $194 million at March 31, 2026 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 "Rate Case Proceedings" discussion above for information regarding potential changes in the retirement date of Mill Creek Unit 2.
Virginia Activities
See "Kentucky Activities - Potential Legal Merger of LG&E and KU" above with respect to filing an application with VSCC for approval of a merger between LG&E and KU.
Rate Case Proceeding (PPL and KU)
On April 30, 2026, KU filed a request with the VSCC for an increase in Virginia annual base electricity rates of approximately $19 million. KU's request is based on an authorized 10.95% ROE. Subject to regulatory review and approval, new rates would become effective February 1, 2027. PPL and KU cannot predict the outcome of this matter.
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 distribution base rates are expected to become effective on July 1, 2026.
On March 5, 2026, PPL Electric reached a non‑unanimous settlement in principle (the settlement) in its distribution rate case. On March 13, 2026, PPL Electric submitted a joint petition with the PAPUC reflecting the settlement to resolve all issues in PPL Electric's base rate proceeding.
The settlement proposed an annual electric base distribution revenue increase of approximately $275 million and does not stipulate a return on equity or capital structure. As part of the settlement, PPL Electric will not increase distribution base rates for two years from the effective date of the new rates. Additionally, the settlement:
•provides for DSIC eligible capital investment (and associated depreciation and tax effects) to be rolled into base rates, and for the DSIC to be reset to zero, capped at 5.0% of annual distribution revenues, upon implementation of new base rates.
•sets the expense from reportable storms recovered through base rates for the Storm Damage Expense Rider (SDER) at $32 million annually beginning July 1, 2026. To the extent eligible reportable storm expenses are above or below this level, over or under collections would be addressed through the SDER during the applicable recovery period.
•supports capitalization of Information Technology (IT) upgrades for planned system implementations and infrastructure costs for shared IT platforms. The total projected cost of these projects is expected to be $54 million, inclusive of AFUDC, through June 30, 2027.
•supports adoption of a new tariff schedule governing service to certain large load customers (including data centers). This new rate class would provide $11 million in support for PPL Electric's residential low-income program.
•provides for enhancements to Customer Assistance Program processes and customer notifications, an increase to the Low-Income Usage Reduction Program annual budget beginning January 1, 2027 of $1.5 million (to a total of $13.5 million) with a rollover mechanism for unspent amounts, and a waiver of reconnection fees for low-income customers beginning July 1, 2027.
The settlement also contains agreed positions regarding certain other tariff, rate, regulatory accounting and other issues raised in the proceedings, as well as recommending approval of all remaining matters as requested by PPL Electric's rate request.
On April 17, 2026, the Administrative Law Judges presiding over the case recommended the settlement be approved without modification. A ruling from the PAPUC is anticipated during the second quarter of 2026. PPL and PPL Electric cannot predict the outcome of the proceeding.
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, which are underway. 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.
ISO-NE ROE Complaints (PPL)
Transmission rates for utilities in ISO-NE are subject to a common ROE shared among the New England transmission owners (NETOs). This ROE has been set at 11.14% since 2005. In 2011 through 2016, transmission customer representatives filed four complaints at the FERC seeking to lower it, arguing that an 11.14% ROE was unjust and unreasonable under the Federal Power Act Section 206.
In 2014, the FERC issued Opinion No. 531 that changed the methodology the FERC uses for determining transmission ROEs. It set the ROE at 10.57% with a maximum ROE including incentives of 11.74%. Two additional FERC orders followed: Opinion No. 531-A (2014) and Opinion No. 531-B (2015). Each maintained the 10.57% ROE. Both the NETOs and customers appealed.
In 2017, the Circuit Court for the District of Columbia issued an order vacating Opinions Nos. 531, 531-A, and 531-B, and remanding to the FERC for further proceedings. The court found that the FERC had not properly followed Section 206, which required a specific finding that the existing 11.14% ROE was unjust and unreasonable before it could order a new 10.57% ROE. In 2018, the FERC issued an additional order on remand applicable to all four pending complaints, seeking additional briefing.
On March 19, 2026, the FERC issued Opinion No. 594, addressing the outstanding NETO complaint dockets. The FERC ordered NETOs' base ROE be set at 9.57%, with a total or maximum ROE including incentives not to exceed 12.09%, with an effective date of October 16, 2014.
As a result of the order, RIE recorded a liability of $26 million in the first quarter of 2026 for the estimated amounts to be refunded.
The FERC initially ordered refunds with interest at the FERC rate to be paid within thirty days. On April 2, 2026, RIE and the other NETOs filed for an extension of the refund period. On April 14, 2026, the FERC issued an order extending the refund period through May 20, 2027.
On April 20, 2026, RIE and the other NETOs filed a request for rehearing of Opinion No. 594, which is a necessary prerequisite to appeal the order. On April 30, 2026, RIE and the other NETOs filed a Section 205 docket requesting a new base ROE of 11.39% going forward. PPL and RIE cannot predict the outcome of these matters.
Other
Purchase of Receivables Programs
(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 the three months ended March 31, 2026 and 2025, RIE purchased $95 million and $87 million of accounts receivable from alternative suppliers.
During the three months ended March 31, 2026 and 2025, PPL Electric purchased $552 million and $466 million of accounts receivable from alternative suppliers.
7. 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 are attributable 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2026 | | December 31, 2025 |
| | 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) | Dec. 2030 | | $ | 1,500 | | | $ | — | | | $ | — | | | $ | 1,500 | | | $ | — | | | $ | 456 | |
| | | | | | | | | | | | | |
| Bilateral Credit Facility | Feb. 2027 | | 100 | | | — | | | — | | | 100 | | | — | | | — | |
| Bilateral Credit Facility | Feb. 2027 | | 100 | | | — | | | 14 | | | 86 | | | — | | | 17 | |
| Total PPL Capital Funding Credit Facilities | | | $ | 1,700 | | | $ | — | | | $ | 14 | | | $ | 1,686 | | | $ | — | | | $ | 473 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| PPL Electric | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2030 | | $ | 750 | | | $ | — | | | $ | 226 | | | $ | 524 | | | $ | — | | | $ | 6 | |
| | | | | | | | | | | | | |
| Total PPL Electric Credit Facilities | | | $ | 750 | | | $ | — | | | $ | 226 | | | $ | 524 | | | $ | — | | | $ | 6 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| LG&E | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2030 | | $ | 600 | | | $ | — | | | $ | — | | | $ | 600 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
| Total LG&E Credit Facilities | | | $ | 600 | | | $ | — | | | $ | — | | | $ | 600 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
| KU | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2030 | | $ | 600 | | | $ | — | | | $ | — | | | $ | 600 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
| Total KU Credit Facilities | | | $ | 600 | | | $ | — | | | $ | — | | | $ | 600 | | | $ | — | | | $ | — | |
(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)At March 31, 2026 and December 31, 2025 the facility included 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 available under the facility allocated to PPL Capital Funding. At March 31, 2026, PPL Capital Funding and RIE had no commercial paper outstanding. At December 31, 2025, PPL Capital Funding had $355 million of commercial paper outstanding and RIE had $101 million of 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 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2026 | | December 31, 2025 |
| Weighted -
Average
Interest Rate | | Capacity | | Commercial
Paper
Issuances (a) | | Unused
Capacity | | Weighted -
Average
Interest Rate | | Commercial
Paper
Issuances (a) |
| PPL Capital Funding (b)(c) | | | $ | 1,600 | | | $ | — | | | $ | 1,600 | | | 4.16% | | $ | 355 | |
| RIE (c) | | | 400 | | | — | | | 400 | | | 4.21% | | 101 | |
PPL Electric | 4.01% | | 750 | | | 220 | | | 530 | | | | | — | |
| LG&E | | | 600 | | | — | | | 600 | | | | | — | |
| KU | | | 600 | | | — | | | 600 | | | | | — | |
| Total | | | $ | 3,950 | | | $ | 220 | | | $ | 3,730 | | | | | $ | 456 | |
(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. At March 31, 2026 and December 31, 2025, the borrowing sublimits were $400 million for RIE and $1.1 billion for PPL Capital Funding. 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 10 for discussion of intercompany borrowings.
Long-term Debt and Equity Securities
(PPL)
Corporate Units
In February 2026, PPL issued 23 million equity units (the Equity Units), initially in the form of corporate units (the Corporate Units), for total gross proceeds of $1.15 billion. The issuance included the underwriters' full exercise of their option to purchase up to an additional 3 million Corporate Units to cover over‑allotments. PPL received proceeds of approximately $1.13 billion, net of underwriting discounts and commissions. Proceeds were used to repay short-term debt and for general corporate purposes.
Each Corporate Unit has a stated amount of $50 and is comprised of (i) a purchase contract (each, a Purchase Contract) obligating the holder to purchase no later than February 15, 2029 (the Purchase Contract Settlement Date), a certain number of shares of PPL's common stock (Common Stock), for $50 in cash and (ii) a 1/40 undivided beneficial ownership interest in (a) $1,000 principal amount of PPL Capital Funding's 4.02% Remarketable Senior Notes due 2034 and (b) $1,000 principal amount of PPL Capital Funding's 4.02% Remarketable Senior Notes due 2039 (together the RSNs). The Corporate Units carry an annual distribution rate of 7.00% of the stated amount, which is comprised of a quarterly interest payment on the RSNs of 4.02% per year and a quarterly contract adjustment payment of 2.98% per year.
The holder's ownership interests in the RSNs are pledged to PPL to secure the holder's obligations under the related Purchase Contract. PPL expects that the RSNs will be remarketed prior to the Purchase Contract Settlement Date. Following a successful remarketing, the interest rates on the RSNs will reset to market rates at that time, interest will be payable on a semi-annual basis and PPL Capital Funding will cease to have the ability to redeem the RSNs at its option. If the remarketing is unsuccessful, the holders will have the right to put the RSNs to PPL Capital Funding at par.
The RSNs are unsecured and unsubordinated obligations of PPL Capital Funding and are fully and unconditionally guaranteed by PPL.
The number of shares to be delivered under the Purchase Contracts will be determined based on the applicable market value of PPL's Common Stock, which is the average of the volume-weighted average price on each trading day during the 20 consecutive scheduled trading day period ending on, and including, the third scheduled trading day prior to the Purchase Contract Settlement Date, subject to anti‑dilution adjustments, as follows:
•If the applicable market value is greater than or equal to $46.58, the holder will receive 1.0735 shares (a minimum of 24.7 million shares).
•If the applicable market value is greater than $37.26 but less than $46.58, the holder will receive a number of shares equal to $50 divided by the applicable market value.
•If the applicable market value is less than or equal to $37.26, the holder will receive 1.3419 shares (a maximum of 30.9 million shares).
Each Purchase Contract requires PPL to make quarterly contract adjustment payments at a rate of 2.98% per year on the $50 stated amount of the Equity Unit. PPL has the option to defer these contract adjustment payments until the Purchase Contract Settlement Date. Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate of 7.00% per year until paid. Until any deferred contract adjustment payments have been paid, PPL may not (1) declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, (2) make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of our debt securities that rank on parity with, or junior to, the contract adjustment payments, or (3) make any guarantee payments under any guarantee by PPL of securities of any of our subsidiaries if the guarantee ranks on parity with, or junior to, the contract adjustment payments.
The proceeds from the sale of the Equity Units were allocated to the RSNs and the Purchase Contracts, including the obligation to make contract adjustment payments, based on the underlying fair value of each instrument at the time of issuance. As a result, the RSNs were recorded at $1.15 billion, which approximated fair value, as long-term debt. At the time of issuance, the present value of the contract adjustment payments of $95 million was recorded to other long-term liabilities, representing the fair value of the obligation to make contract adjustment payments, with an offsetting reduction to capital in excess of par value for the issuance of the Purchase Contracts. The contract adjustment payment liability is being accreted through interest expense over the three-year term of the Purchase Contracts. The initial valuation of the contract adjustment payments is considered a non-cash transaction that is excluded from the Statement of Cash Flows. To settle the Purchase Contracts, PPL will be required to issue a maximum of approximately 30.9 million shares of Common Stock under the standard provisions of the Purchase Contracts and 42.9 million shares of common stock that could be issued under make-whole provisions in the event of early settlement upon a fundamental change. See Note 4 for EPS considerations related to the Purchase Contracts.
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. At March 31, 2026, PPL had outstanding forward contracts to sell approximately 27.4 million shares of its common stock at a blended initial forward price of approximately $35.90 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, 2026 to August 11, 2027. PPL may elect, at its discretion, to physically settle, net share settle or net cash settle the forward contracts. At March 31, 2026, PPL could have settled the outstanding forward sale contracts with physical delivery of approximately 27.4 million shares of common stock for proceeds of approximately $980 million. The forward contracts under the ATM program are classified as equity transactions.
Dividends
In February 2026, PPL declared a quarterly cash dividend on its common stock, payable April 1, 2026, of 28.50 cents per share (equivalent to $1.14 per annum).
8. Defined Benefits
(PPL)
Certain net periodic defined benefit costs are applied to accounts that are further distributed among capital, expense, regulatory assets and regulatory liabilities, including certain costs allocated to applicable subsidiaries for plans sponsored by PPL Services and LKE. Following are the net periodic defined benefit costs (credits) of the plans sponsored by PPL and its subsidiaries for the periods ended March 31:
| | | | | | | | | | | | | | | |
| | | | | Pension Benefits |
| | | | Three Months |
| | | | | | 2026 | | 2025 |
| | | | | | | |
| Service cost | | | | | $ | 7 | | | $ | 8 | |
| Interest cost | | | | | 44 | | | 45 | |
| Expected return on plan assets | | | | | (60) | | | (72) | |
| Amortization of: | | | | | | | |
| | | | | | | |
| Actuarial loss | | | | | 10 | | | 5 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net periodic defined benefit costs (credits) | | | | | $ | 1 | | | $ | (14) | |
| | | | | | | | | | | | | | | |
| | | | | | Other Postretirement Benefits |
| | | | Three Months |
| | | | | | 2026 | | 2025 |
| | | | | | | |
| Service cost | | | | | $ | 2 | | | $ | 2 | |
| Interest cost | | | | | 7 | | | 7 | |
| Expected return on plan assets | | | | | (7) | | | (8) | |
| Amortization of: | | | | | | | |
| | | | | | | |
| Actuarial gain | | | | | (1) | | | (1) | |
| Net periodic defined benefit costs (credits) | | | | | $ | 1 | | | $ | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
(All Registrants)
The non-service cost components of net periodic defined benefit costs (credits) (interest cost, expected return on plan assets, amortization of prior service cost and amortization of actuarial gain and loss) are presented in "Other Income (Expense) - net" on the Statements of Income. See Note 11 for additional information.
9. Commitments and Contingencies
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.
E.W. Brown Environmental Assessment (PPL and KU)
KU has undertaken 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. Additionally, KU has performed an aquatic study of adjacent surface waters and risk assessment pursuant to a 2017 Agreed Order with the Kentucky Energy and Environment Cabinet (KEEC). In 2021, the KEEC approved a report, prepared by KU's 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. The KEEC subsequently approved KU's supplemental report finding that there are no significant unaddressed risks to human health or the environment at the plant. At the request of the KEEC in 2024, KU submitted a proposed environmental covenant specifying certain site restrictions. Discussions between KU and the KEEC are ongoing, and 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.
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. In February 2026, the EPA published a final 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 rule extended the groundwater monitoring deadline to February 10, 2031, with the initial groundwater monitoring report extended to January 31, 2032.
On April 9, 2026, the EPA published a proposed rule to amend the 2024 CCR Rule. The rule proposes to allow certification of closure of legacy surface impoundments by removal for projects completed by November 8, 2024 under regulatory oversight. The rule also proposes to defer compliance of Legacy Surface Impoundments closed prior to November 8, 2024 with the CCR closure standards until site-specific decisions are made by permit authorities. The EPA proposes to rescind all CCR management unit requirements. The EPA proposes to allow alternative compliance pathway for CCR units for groundwater monitoring, corrective action, and closure requirements under federal or approved-state CCR permits that would allow risk-based closure. In addition, the EPA proposes to expand the definition of beneficial use and eliminate the cap for unencapsulated CCR on land.
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 14 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.
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. As of March 31, 2026 and December 31, 2025, PPL Electric had a recorded liability of $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.
As of March 31, 2026 and December 31, 2025, RIE had a recorded liability of $97 million and $98 million, representing its best estimate at each such time of the remaining costs of RIE's environmental remediation activities. These undiscounted costs are expected to be incurred over approximately 30 years and generally 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.
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. See Note 6 for additional information on RIE's recorded environmental regulatory assets and liabilities.
Regulatory Issues
(All Registrants)
See Note 6 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.
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 March 31, 2026. "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 March 31, 2026 | | | 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 | $ | 67 | | (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 March 31, 2026, 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 $73 million at March 31, 2026, consisting of LG&E's share of $51 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" in Note 12 in PPL's, LG&E's and KU's 2025 Form 10-K 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 generally remote.
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 insurance provides maximum aggregate coverage of $231 million for non-wildfire liability losses and maximum aggregate coverage of $196 million for wildfire liability losses. This insurance may be applicable to obligations under certain of these contractual arrangements.
10. Related Party Transactions
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 and LKS charged the following amounts for the periods ended March 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.
| | | | | | | | | | | | | | | |
| | | Three Months |
| | | | | 2026 | | 2025 |
| PPL Electric from PPL Services | | | | | $ | 74 | | | $ | 64 | |
| LG&E from LKS | | | | | 35 | | | 30 | |
| LG&E from PPL Services | | | | | 47 | | | 20 | |
| KU from LKS | | | | | 42 | | | 38 | |
| KU from PPL Services | | | | | 49 | | | 19 | |
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 an $800 million revolving line of credit with a PPL Electric subsidiary. At March 31, 2026, CEP Reserves had borrowings outstanding of $4 million. At December 31, 2025, CEP Reserves had borrowings outstanding of $143 million. The interest rates on borrowings are equal to an adjusted one-month SOFR plus a spread. Interest income is reflected in "Interest Income from Affiliate" on the PPL Electric 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 issued 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 March 31, 2026, LG&E's money pool unused capacity was $750 million. At March 31, 2026 and December 31, 2025, LG&E had no borrowings outstanding from KU and/or LKE.
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 issued 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 March 31, 2026, KU's money pool unused capacity was $612 million. At March 31, 2026, KU had borrowings outstanding of $38 million from LG&E and/or LKE. At December 31, 2025, KU had borrowings outstanding of $36 million from LG&E and/or LKE. These balances are reflected in "Notes payable to affiliates" on the KU Balance Sheets.
11. Other Income (Expense) - net
(PPL)
The details of "Other Income (Expense) - net" for the periods ended March 31 were:
| | | | | | | | | | | | | | | |
| | | | Three Months |
| | | | | 2026 | | 2025 |
| | | | | | | |
Defined benefit plans - non-service credits (Note 8) | | | | | $ | 6 | | | $ | 8 | |
| Interest income | | | | | 9 | | | 5 | |
| AFUDC - equity component | | | | | 24 | | | 16 | |
| | | | | | | |
| | | | | | | |
| Miscellaneous | | | | | — | | | (1) | |
| Other Income (Expense) - net | | | | | $ | 39 | | | $ | 28 | |
(PPL Electric)
The details of "Other Income (Expense) - net" for the periods ended March 31 were:
| | | | | | | | | | | | | | | |
| | | | Three Months |
| | | | | 2026 | | 2025 |
| | | | | | | |
Defined benefit plans - non-service credits (Note 8) | | | | | $ | 1 | | | $ | 3 | |
| Interest income | | | | | 2 | | | 2 | |
| AFUDC - equity component | | | | | 9 | | | 7 | |
| | | | | | | |
| Miscellaneous | | | | | — | | | (1) | |
| | | | | | | |
| Other Income (Expense) - net | | | | | $ | 12 | | | $ | 11 | |
12. 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 in each Registrant's 2025 Form 10-K for information on the levels in the fair value hierarchy.
Recurring Fair Value Measurements
The assets and liabilities measured at fair value were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2026 | | December 31, 2025 |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 |
| PPL | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 1,241 | | | $ | 1,241 | | | $ | — | | | $ | — | | | $ | 1,071 | | | $ | 1,071 | | | $ | — | | | $ | — | |
| Restricted cash and cash equivalents (a) | 10 | | | 10 | | | — | | | — | | | 15 | | | 15 | | | — | | | — | |
| Total Cash, Cash Equivalents and Restricted Cash (b) | 1,251 | | | 1,251 | | | — | | | — | | | 1,086 | | | 1,086 | | | — | | | — | |
| Special use funds (a): | | | | | | | | | | | | | | | |
| Money market fund | 1 | | | 1 | | | — | | | — | | | 1 | | | 1 | | | — | | | — | |
| Commingled debt fund measured at NAV (c) | 4 | | | — | | | — | | | — | | | 5 | | | — | | | — | | | — | |
| Commingled equity fund measured at NAV (c) | 4 | | | — | | | — | | | — | | | 5 | | | — | | | — | | | — | |
| Total special use funds | 9 | | | 1 | | | — | | | — | | | 11 | | | 1 | | | — | | | — | |
| Price risk management assets (d): | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Gas contracts | 5 | | | — | | | 2 | | | 3 | | | 6 | | | — | | | 2 | | | 4 | |
| Total assets | $ | 1,265 | | | $ | 1,252 | | | $ | 2 | | | $ | 3 | | | $ | 1,103 | | | $ | 1,087 | | | $ | 2 | | | $ | 4 | |
| | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | |
| Price risk management liabilities (d): | | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | |
| Gas contracts | 10 | | | — | | | 7 | | | 3 | | | 10 | | | — | | | 6 | | | 4 | |
| Total price risk management liabilities | $ | 15 | | | $ | — | | | $ | 12 | | | $ | 3 | | | $ | 15 | | | $ | — | | | $ | 11 | | | $ | 4 | |
| | | | | | | | | | | | | | | |
| PPL Electric | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 19 | | | $ | 19 | | | $ | — | | | $ | — | | | $ | 30 | | | $ | 30 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| Total assets | $ | 19 | | | $ | 19 | | | $ | — | | | $ | — | | | $ | 30 | | | $ | 30 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| LG&E | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 49 | | | $ | 49 | | | $ | — | | | $ | — | | | $ | 162 | | | $ | 162 | | | $ | — | | | $ | — | |
| Restricted cash and cash equivalents (a) | 4 | | | 4 | | | — | | | — | | | 7 | | | 7 | | | — | | | — | |
| Total Cash, Cash Equivalents and Restricted Cash (b) | 53 | | | 53 | | | — | | | — | | | 169 | | | 169 | | | — | | | — | |
| | | | | | | | | | | | | | | |
| Total assets | $ | 53 | | | $ | 53 | | | $ | — | | | $ | — | | | $ | 169 | | | $ | 169 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | |
| Price risk management liabilities | | | | | | | | | | | | | | | |
| Interest rate derivatives | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | |
| Total price risk management liabilities | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | |
| | | | | | | | | | | | | | | |
| KU | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 14 | | | $ | 14 | | | $ | — | | | $ | — | | | $ | 10 | | | $ | 10 | | | $ | — | | | $ | — | |
| Restricted cash and cash equivalents (a) | 4 | | | 4 | | | — | | | — | | | 7 | | | 7 | | | — | | | — | |
| Total Cash, Cash Equivalents and Restricted Cash (b) | 18 | | | 18 | | | — | | | — | | | 17 | | | 17 | | | — | | | — | |
| Total assets | $ | 18 | | | $ | 18 | | | $ | — | | | $ | — | | | $ | 17 | | | $ | 17 | | | $ | — | | | $ | — | |
(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 Balance Sheets.
(d)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.
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.
Financial Instruments Not Recorded at Fair Value (All Registrants)
Long-term debt is classified as Level 2. The effect of third-party credit enhancements is not included in the fair value measurement. The carrying amounts of contract adjustment payments related to the Purchase Contract component of the Equity Units and long-term debt on the Balance Sheets and their estimated fair values are set forth below.
| | | | | | | | | | | | | | | | | | | | | | | |
| | March 31, 2026 | | December 31, 2025 |
| Carrying
Amount (a) | | Fair Value | | Carrying
Amount (a) | | Fair Value |
| PPL | | | | | | | |
| Contract adjustment payments (b) | $ | 95 | | | $ | 95 | | | $ | — | | | $ | — | |
| Long-term debt | 20,018 | | | 19,435 | | | 18,894 | | | 18,488 | |
| PPL Electric | | | | | | | |
| Long-term debt | 5,708 | | | 5,348 | | | 5,707 | | | 5,473 | |
| LG&E | | | | | | | |
| Long-term debt | 2,865 | | | 2,734 | | | 2,865 | | | 2,784 | |
| KU | | | | | | | |
| Long-term debt | 3,492 | | | 3,224 | | | 3,510 | | | 3,304 | |
(a)Long-term debt amounts are net of issuance costs.
(b)Current portion is included in "Other current liabilities" and noncurrent portion is included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
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.
13. 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 due to the recovery methods in place.
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.
PPL, LG&E and KU had no obligation to return or post cash collateral under master netting arrangements at March 31, 2026 and December 31, 2025.
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 March 31, 2026, 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 the three months ended March 31, 2026 and 2025, PPL had no cash flow hedges reclassified into earnings associated with discontinued cash flow hedges.
At March 31, 2026, 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 March 31, 2026, 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. At March 31, 2026, RIE held contracts with notional volumes of 39 Bcf that range in maturity from 2026 through 2029.
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 and RIE's gas derivative contracts that are recognized as regulatory assets or regulatory liabilities. See Note 6 for amounts recorded in regulatory assets and regulatory liabilities at March 31, 2026 and December 31, 2025.
See Note 1 in each Registrant's 2025 Form 10-K for additional information on accounting policies related to derivative instruments.
(PPL)
The following table presents the fair value and the location of derivatives not designated as hedging instruments on the Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | March 31, 2026 | | | | | | December 31, 2025 |
| | | | | | | |
| | | | | Assets | | Liabilities | | | | | | Assets | | Liabilities |
| Current: | | | | | | | | | | | | | | | |
| Price Risk Management | | | | | | | | | | | | | | | |
| Assets/Liabilities (a): | | | | | | | | | | | | | | | |
| Interest rate derivatives (b) | | | | | $ | — | | | $ | 1 | | | | | | | $ | — | | | $ | 1 | |
| Gas contracts | | | | | 4 | | | 6 | | | | | | | 6 | | | 5 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Total current | | | | | 4 | | | 7 | | | | | | | 6 | | | 6 | |
| Noncurrent: | | | | | | | | | | | | | | | |
| Price Risk Management | | | | | | | | | | | | | | | |
| Assets/Liabilities (a): | | | | | | | | | | | | | | | |
| Interest rate derivatives (b) | | | | | — | | | 4 | | | | | | | — | | | 4 | |
| Gas contracts | | | | | 1 | | | 4 | | | | | | | — | | | 5 | |
| | | | | | | | | | | | | | | |
| Total noncurrent | | | | | 1 | | | 8 | | | | | | | — | | | 9 | |
| Total derivatives | | | | | $ | 5 | | | $ | 15 | | | | | | | $ | 6 | | | $ | 15 | |
(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 for the period ended March 31, 2026.
| | | | | | | | | | | | | | | | | | | | |
| | | | Three Months | | | | | | Three Months |
Derivative
Relationships | | | | Derivative Gain
(Loss) Recognized in
OCI | | Location of Gain (Loss)
Recognized in Income
on Derivative | | | | Gain (Loss)
Reclassified
from AOCI
into Income |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest rate derivatives | | | | $ | — | | | Interest Expense | | | | $ | (1) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized in
Income on Derivative | | | | Three Months |
| Gas contracts | | Energy purchases | | | | $ | 8 | |
| | Operating revenues | | | | (1) | |
| | Total | | | | $ | 7 | |
| | | | | | |
| | | | | | |
| | | | | | | | | | | | | | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized as
Regulatory Liabilities/Assets | | | | Three Months |
| | | | | | |
| | | | | | |
| | | | | | |
| Gas Contracts | | Regulatory assets - noncurrent | | | | $ | (1) | |
| | | | | | |
| | Total | | | | $ | (1) | |
The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets and regulatory liabilities for the period ended March 31, 2025.
| | | | | | | | | | | | | | | | | | | | |
| | | | | Three Months | | | | | | Three Months |
Derivative
Relationships | | | | Derivative Gain
(Loss) Recognized in
OCI | | Location of Gain (Loss)
Recognized in Income
on Derivative | | | | Gain (Loss)
Reclassified
from AOCI
into Income |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest rate derivatives | | | | $ | — | | | Interest Expense | | | | $ | (1) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | | | | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized in
Income on Derivative | | | | Three Months |
| Gas contracts | | Energy Purchases | | | | $ | (5) | |
| | | | | | |
| | Total | | | | $ | (5) | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized as
Regulatory Liabilities/Assets | | | | Three Months |
| Interest rate derivatives | | Regulatory assets - noncurrent | | | | $ | (1) | |
| | | | | | |
| Gas contracts | | Regulatory liabilities - current | | | | 18 | |
| | | | | | |
| | Regulatory liabilities - noncurrent | | | | 1 | |
| | Total | | | | $ | 18 | |
| | | | | | |
| | | | | | |
| | | | | | |
The following table presents the amount of gain (loss) reclassified from accumulated other comprehensive income into interest expense as a result of cash flow hedging activity for the period ended March 31, 2026.
| | | | | | | | | | | | |
| | | Three Months |
| | | | | Interest Expense |
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | | | | | $ | 224 | | | | |
| Amount of gain (loss) reclassified from AOCI to income | | | | | (1) | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
The following table presents the amount of gain (loss) reclassified from accumulated other comprehensive income into interest expense as a result of cash flow hedging activity for the period ended March 31, 2025.
| | | | | | | | | | | | | |
| | | Three Months | |
| | | | | Interest Expense | | | | |
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | | | | | $ | 190 | | | | | |
| Amount of gain (loss) reclassified from AOCI to income | | | | | (1) | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
(LG&E)
The following table presents the fair value and the location on the Balance Sheets of derivatives not designated as hedging instruments.
| | | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2026 | | December 31, 2025 | |
| | Assets | | Liabilities | | Assets | | Liabilities | |
| Current: | | | | | | | | |
| Price Risk Management | | | | | | | | |
| Assets/Liabilities: | | | | | | | | |
| Interest rate derivatives | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Total current | — | | | 1 | | | — | | | 1 | | |
| Noncurrent: | | | | | | | | |
| Price Risk Management | | | | | | | | |
| Assets/Liabilities: | | | | | | | | |
| Interest rate derivatives | — | | | 4 | | | — | | | 4 | | |
| Total noncurrent | — | | | 4 | | | — | | | 4 | | |
| Total derivatives | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | |
There was no effect of derivatives not designated as cash flow hedges recognized in income or regulatory assets for the period ended March 31, 2026.
The following tables present the pre-tax effect of derivatives not designated as cash flow hedges that are recognized in income or regulatory assets for the period ended March 31, 2025.
| | | | | | | | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | Location of Gain (Loss) Recognized in | | | | |
| Derivative Instruments | | Regulatory Assets | | | | Three Months |
| Interest rate derivatives | | Regulatory assets - noncurrent | | | | $ | (1) | |
(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 |
| March 31, 2026 | | | | | | | | | | | | | | | |
| Derivatives | | | | | | | | | | | | | | | |
| PPL | $ | 5 | | | $ | 4 | | | $ | — | | | $ | 1 | | | $ | 15 | | | $ | 4 | | | $ | — | | | $ | 11 | |
| LG&E | — | | | — | | | — | | | — | | | 5 | | | — | | | — | | | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | |
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 represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" features.
(PPL)
At March 31, 2026, derivative contracts in a net liability position that contain credit risk-related contingent features were $5 million. The aggregate fair value of additional collateral requirements in the event of a credit downgrade below investment grade was $5 million.
14. Asset Retirement Obligations
(PPL, LG&E and KU)
PPL's, LG&E's and KU's ARO liabilities are primarily related to CCR closure costs. See Note 9 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.
The changes in the carrying amounts of AROs were as follows.
| | | | | | | | | | | | | | | | | |
| PPL | | LG&E | | KU |
| Balance at December 31, 2025 | $ | 140 | | | $ | 75 | | | $ | 57 | |
| Accretion | 2 | | | 1 | | | 1 | |
| | | | | |
| Changes in estimated timing or cost | (11) | | | (11) | | | — | |
| Obligations settled | (8) | | | (3) | | | (5) | |
| Other | 1 | | | — | | | — | |
| Balance at March 31, 2026 | $ | 124 | | | $ | 62 | | | $ | 53 | |
15. Accumulated Other Comprehensive Income (Loss)
(PPL)
The after-tax changes in AOCI by component for the periods ended March 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, 2025 | | | | | | | $ | 12 | | | $ | 3 | | | $ | (2) | | | $ | (215) | | | $ | (202) | |
| Amounts arising during the period | | | | | | | — | | | 1 | | | — | | | — | | | 1 | |
| Reclassifications from AOCI | | | | | | | 1 | | | — | | | — | | | — | | | 1 | |
| Net OCI during the period | | | | | | | 1 | | | 1 | | | — | | | — | | | 2 | |
| March 31, 2026 | | | | | | | $ | 13 | | | $ | 4 | | | $ | (2) | | | $ | (215) | | | $ | (200) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| December 31, 2024 | | | | | | | $ | 9 | | | $ | 4 | | | $ | (3) | | | $ | (194) | | | $ | (184) | |
| | | | | | | | | | | | | | | |
| Reclassifications from AOCI | | | | | | | 1 | | | — | | | — | | | (1) | | | — | |
| Net OCI during the period | | | | | | | 1 | | | — | | | — | | | (1) | | | — | |
| March 31, 2025 | | | | | | | $ | 10 | | | $ | 4 | | | $ | (3) | | | $ | (195) | | | $ | (184) | |
16. 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 prospectively 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.