PPL Corp 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, PPL Corporation and Subsidiaries (Millions of Dollars, except share data) 2025 2024 2023 Operating Revenues $ 9,042 $ 8,462 $ 8,312 Operating Expenses Operation Fuel 855 783 733 Energy purchases 1,892 1,679 1,841 Other operation and maintenance 2,431 2,607 2,462 Depreciation 1,312 1,279 1,254 Taxes, other than income 423 374 392 Total Operating Expenses 6,913 6,722 6,682 Operating Income 2,129 1,740 1,630 Other Income (Expense) - net (Note 14) 151 114 ( 40 ) Interest Expense 808 738 666 Income Before Income Taxes 1,472 1,116 924 Income Taxes 291 228 184 Net Income $ 1,181 $ 888 $ 740 Earnings Per Share of Common Stock: Net Income Available to PPL Common Shareowners: Basic $ 1.60 $ 1.20 $ 1.00 Diluted $ 1.59 $ 1.20 $ 1.00 Weighted-Average Shares of Common Stock Outstanding (in thousands) Basic 739,406 737,756 737,036 Diluted 743,348 739,853 738,166 The accompanying Notes to Financial Statements are an integral part of the financial statements. 75 Table of Contents CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, PPL Corporation and Subsidiaries (Millions of Dollars) 2025 2024 2023 Net income $ 1,181 $ 888 $ 740 Other comprehensive income (loss): Amounts arising during the period - gains (losses), net of tax (expense) benefit: Qualifying derivatives, net of tax of ($ 1 ), $ 0 , $ 0 1 — — Equity investees' other comprehensive income (loss), net tax of $ 0 , $ 0 , $ 0 ( 1 ) 1 1 Defined benefit plans: Net actuarial gain (loss), net of tax of $ 7 , $ 8 , $ 15 ( 20 ) ( 22 ) ( 41 ) Reclassifications to net income - (gains) losses, net of tax expense (benefit): Qualifying derivatives, net of tax of ($ 1 ), $ 0 , $ 0 2 3 3 Defined benefit plans: Prior service costs, net of tax of $ 0 , $ 0 , ($ 1 ) 1 1 1 Net actuarial (gain) loss, net of tax of $ 1 , $ 0 , $ 0 ( 1 ) ( 4 ) ( 3 ) Total other comprehensive income (loss) ( 18 ) ( 21 ) ( 39 ) Comprehensive income $ 1,163 $ 867 $ 701 The accompanying Notes to Financial Statements are an integral part of the financial statements. 76 Table of Contents CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, PPL Corporation and Subsidiaries (Millions of Dollars) 2025 2024 2023 Cash Flows from Operating Activities Net income $ 1,181 $ 888 $ 740 Adjustments to reconcile net income to net cash provided by operating activities Depreciation 1,312 1,279 1,254 Amortization 104 78 81 Defined benefit plans - income ( 57 ) ( 72 ) ( 73 ) Deferred income taxes and investment tax credits 192 196 322 Stock compensation expense 49 46 33 Equity component of AFUDC ( 81 ) ( 47 ) ( 30 ) Other 8 30 1 Change in current assets and current liabilities Accounts receivable ( 207 ) 254 ( 170 ) Accounts payable ( 12 ) ( 41 ) ( 72 ) Unbilled revenues ( 73 ) ( 57 ) 128 Fuel, materials and supplies ( 28 ) ( 2 ) ( 60 ) Prepayments 43 ( 34 ) 1 Taxes payable 87 ( 27 ) 6 Regulatory assets and liabilities, net 162 ( 68 ) ( 37 ) Accrued interest 38 33 27 Other ( 4 ) ( 65 ) 38 Other operating activities Defined benefit plans - funding ( 12 ) ( 10 ) ( 13 ) Proceeds from transfer of excess benefit plan funds — 13 — Other assets ( 138 ) ( 96 ) ( 69 ) Other liabilities 65 42 ( 349 ) Net cash provided by operating activities 2,629 2,340 1,758 Cash Flows from Investing Activities Expenditures for property, plant and equipment ( 4,030 ) ( 2,805 ) ( 2,390 ) Other investing activities 26 ( 13 ) 7 Net cash used in investing activities ( 4,004 ) ( 2,818 ) ( 2,383 ) Cash Flows from Financing Activities Issuance of long-term debt 3,045 1,894 3,252 Retirement of long-term debt ( 616 ) — ( 1,854 ) Payment of common stock dividends ( 794 ) ( 747 ) ( 704 ) Issuance of treasury stock 401 2 5 Net increase (decrease) in short-term debt 153 ( 689 ) 7 Debt issuance costs ( 41 ) ( 19 ) ( 46 ) Other financing activities ( 26 ) ( 6 ) ( 10 ) Net cash provided by financing activities 2,122 435 650 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 747 ( 43 ) 25 Cash, Cash Equivalents and Restricted Cash at Beginning of Period 339 382 357 Cash, Cash Equivalents and Restricted Cash at End of Period $ 1,086 $ 339 $ 382 Supplemental Disclosures of Cash Flow Information Cash paid (received) during the period for: Interest - net of amount capitalized $ 745 $ 670 $ 604 Income taxes - net $ 93 $ ( 123 ) $ 281 Significant non-cash transactions: Accrued expenditures for property, plant and equipment at December 31, $ 630 $ 358 $ 220 The accompanying Notes to Financial Statements are an integral part of the financial statements. 77 Table of Contents CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, PPL Corporation and Subsidiaries (Millions of Dollars, shares in thousands) 2025 2024 Assets Current Assets Cash and cash equivalents $ 1,071 $ 306 Accounts receivable (less reserve: 2025, $ 133 ; 2024, $ 147 ) Customer 1,108 961 Other 117 76 Unbilled revenues (less reserve: 2025, $ 6 ; 2024, $ 6 ) 558 485 Fuel, materials and supplies 551 511 Prepayments 106 136 Regulatory assets 308 320 Other current assets 112 85 Total Current Assets 3,931 2,880 Property, Plant and Equipment Regulated utility plant 42,953 40,391 Less: accumulated depreciation - regulated utility plant 10,303 9,682 Regulated utility plant, net 32,650 30,709 Non-regulated property, plant and equipment 71 79 Less: accumulated depreciation - non-regulated property, plant and equipment 26 29 Non-regulated property, plant and equipment, net 45 50 Construction work in progress 3,437 2,390 Property, Plant and Equipment, net 36,132 33,149 Other Noncurrent Assets Regulatory assets 2,092 2,060 Goodwill 2,247 2,247 Other intangibles 327 314 Other noncurrent assets (less reserve for accounts receivable: 2025, $ 1 ; 2024, $ 1 ) 515 419 Total Other Noncurrent Assets 5,181 5,040 Total Assets $ 45,244 $ 41,069 The accompanying Notes to Financial Statements are an integral part of the financial statements. 78 Table of Contents CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, PPL Corporation and Subsidiaries (Millions of Dollars, shares in thousands) 2025 2024 Liabilities and Equity Current Liabilities Short-term debt $ 456 $ 303 Long-term debt due within one year 904 551 Accounts payable 1,559 1,196 Taxes 190 103 Interest 195 157 Dividends 198 186 Regulatory liabilities 376 223 Other current liabilities 668 614 Total Current Liabilities 4,546 3,333 Long-term Debt 17,990 15,952 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 3,506 3,356 Investment tax credits 109 111 Accrued pension obligations 281 317 Asset retirement obligations 133 136 Regulatory liabilities 3,318 3,335 Other deferred credits and noncurrent liabilities 480 452 Total Deferred Credits and Other Noncurrent Liabilities 7,827 7,707 Commitments and Contingent Liabilities (Notes 7 and 12) Equity Common stock - $ 0.01 par value (a) 8 8 Additional paid-in capital 12,443 12,346 Treasury stock ( 575 ) ( 928 ) Earnings reinvested 3,207 2,835 Accumulated other comprehensive loss ( 202 ) ( 184 ) Total Equity 14,881 14,077 Total Liabilities and Equity $ 45,244 $ 41,069 (a) 1,560,000 shares authorized; 770,978 shares issued and 751,041 shares outstanding at December 31, 2025. 1,560,000 shares authorized; 770,215 shares issued and 738,033 shares outstanding at December 31, 2024. The accompanying Notes to Financial Statements are an integral part of the financial statements. 79 Table of Contents CONSOLIDATED STATEMENTS OF EQUITY PPL Corporation and Subsidiaries (Millions of Dollars) Common stock shares outstanding (a) Common stock Additional paid-in capital Treasury Stock Earnings reinvested Accumulated other comprehensive loss Noncontrolling interest Total December 31, 2022 736,487 $ 8 $ 12,317 $ ( 967 ) $ 2,681 $ ( 124 ) $ 3 $ 13,918 Treasury stock issued 643 4 19 23 Stock-based compensation 5 5 Net income 740 740 Dividends and dividend equivalents (b) ( 711 ) ( 711 ) Preferred stock ( 3 ) ( 3 ) Other comprehensive income (loss) ( 39 ) ( 39 ) December 31, 2023 737,130 $ 8 $ 12,326 $ ( 948 ) $ 2,710 $ ( 163 ) $ — $ 13,933 Common stock issued 202 — Treasury stock issued 701 7 20 27 Stock-based compensation 13 13 Net income 888 888 Dividends and dividend equivalents (b) ( 763 ) ( 763 ) Other comprehensive income (loss) ( 21 ) ( 21 ) December 31, 2024 738,033 $ 8 $ 12,346 $ ( 928 ) $ 2,835 $ ( 184 ) $ — $ 14,077 Common stock issued 763 26 26 Treasury stock issued 12,245 67 353 420 Stock-based compensation 4 4 Net income 1,181 1,181 Dividends and dividend equivalents (b) ( 809 ) ( 809 ) Other comprehensive income (loss) ( 18 ) ( 18 ) December 31, 2025 751,041 $ 8 $ 12,443 $ ( 575 ) $ 3,207 $ ( 202 ) $ — $ 14,881 (a) Shares in thousands. Each share entitles the holder to one vote on any question presented at any shareowners' meeting. (b) Dividends declared per share of common stock at December 31, 2025, 2024 and 2023 were: $ 1.09 , $ 1.03 and $ 0.96 . The accompanying Notes to Financial Statements are an integral part of the financial statements. 80 Table of Contents (THIS PAGE LEFT BLANK INTENTIONALLY.) 81 Table of Contents CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, PPL Electric Utilities Corporation and Subsidiaries (Millions of Dollars) 2025 2024 2023 Operating Revenues $ 3,113 $ 2,876 $ 3,008 Operating Expenses Operation Energy purchases 876 721 992 Other operation and maintenance 630 705 605 Depreciation 413 401 397 Taxes, other than income 151 131 143 Total Operating Expenses 2,070 1,958 2,137 Operating Income 1,043 918 871 Other Income (Expense) - net (Note 14) 48 45 39 Interest Income from Affiliate 9 33 — Interest Expense 257 246 223 Income Before Income Taxes 843 750 687 Income Taxes 204 176 168 Net Income (a) $ 639 $ 574 $ 519 (a) Net income equals comprehensive income. The accompanying Notes to Financial Statements are an integral part of the financial statements. 82 Table of Contents CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, PPL Electric Utilities Corporation and Subsidiaries (Millions of Dollars) 2025 2024 2023 Cash Flows from Operating Activities Net income $ 639 $ 574 $ 519 Adjustments to reconcile net income to net cash provided by operating activities Depreciation 413 401 397 Amortization 48 45 41 Defined benefit plans - income ( 29 ) ( 39 ) ( 42 ) Deferred income taxes and investment tax credits 24 129 46 Equity component of AFUDC ( 30 ) ( 23 ) ( 16 ) Other 4 24 ( 8 ) Change in current assets and current liabilities Accounts receivable ( 142 ) 89 ( 78 ) Accounts payable 99 64 13 Unbilled revenues ( 50 ) ( 10 ) 75 Materials and supplies ( 40 ) 6 ( 30 ) Prepayments 49 ( 32 ) 2 Regulatory assets and liabilities, net 67 ( 101 ) ( 38 ) Taxes payable 45 ( 49 ) 15 Accrued interest 11 12 8 Other ( 8 ) ( 25 ) 9 Other operating activities Defined benefit plans - funding — — ( 5 ) Other assets ( 50 ) ( 32 ) 3 Other liabilities — 9 1 Net cash provided by operating activities 1,050 1,042 912 Cash Flows from Investing Activities Expenditures for property, plant and equipment ( 1,608 ) ( 1,229 ) ( 956 ) Expenditures for intangible assets ( 12 ) ( 9 ) ( 6 ) Net (increase) decrease in notes receivable from affiliate 79 ( 222 ) — Other investing activities 38 5 4 Net cash used in investing activities ( 1,503 ) ( 1,455 ) ( 958 ) Cash Flows from Financing Activities Issuance of long-term debt 496 649 1,329 Retirement of long-term debt — — ( 1,240 ) Contributions from parent 540 688 206 Payment of common stock dividends to parent ( 401 ) ( 375 ) ( 323 ) Return of capital to parent ( 170 ) ( 60 ) ( 250 ) Net increase (decrease) in short-term debt — ( 509 ) 364 Debt issuance costs ( 6 ) ( 7 ) ( 14 ) Net cash provided by financing activities 459 386 72 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 6 ( 27 ) 26 Cash, Cash Equivalents and Restricted Cash at Beginning of Period 24 51 25 Cash, Cash Equivalents and Restricted Cash at End of Period $ 30 $ 24 $ 51 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest - net of amount capitalized $ 236 $ 224 $ 205 Income taxes - net $ 129 $ 83 $ 92 Significant non-cash transactions: Accrued expenditures for property, plant and equipment at December 31, $ 213 $ 173 $ 122 The accompanying Notes to Financial Statements are an integral part of the financial statements. 83 Table of Contents CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, PPL Electric Utilities Corporation and Subsidiaries (Millions of Dollars, shares in thousands) 2025 2024 Assets Current Assets Cash and cash equivalents $ 30 $ 24 Accounts receivable (less reserve: 2025, $ 34 ; 2024, $ 37 ) Customer 450 353 Other 29 8 Accounts receivable from affiliates 7 10 Notes receivable from affiliate 143 222 Unbilled revenues (less reserve: 2025, $ 4 ; 2024, $ 3 ) 209 159 Materials and supplies 151 104 Prepayments 38 74 Regulatory assets 112 133 Other current assets 46 30 Total Current Assets 1,215 1,117 Property, Plant and Equipment Regulated utility plant 17,476 16,469 Less: accumulated depreciation - regulated utility plant 4,124 4,052 Regulated utility plant, net 13,352 12,417 Construction work in progress 1,216 898 Property, Plant and Equipment, net 14,568 13,315 Other Noncurrent Assets Regulatory assets 725 673 Intangibles 282 274 Other noncurrent assets (less reserve for accounts receivable: 2025, $ 1 ; 2024, $ 1 ) 96 96 Total Other Noncurrent Assets 1,103 1,043 Total Assets $ 16,886 $ 15,475 The accompanying Notes to Financial Statements are an integral part of the financial statements. 84 Table of Contents CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, PPL Electric Utilities Corporation and Subsidiaries (Millions of Dollars, shares in thousands) 2025 2024 Liabilities and Equity Current Liabilities Accounts payable $ 690 $ 565 Accounts payable to affiliates 54 44 Taxes 47 2 Interest 66 55 Customer deposits 92 25 Regulatory liabilities 103 57 Other current liabilities 58 58 Total Current Liabilities 1,110 806 Long-term Debt 5,707 5,214 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 1,781 1,726 Regulatory liabilities 828 839 Other deferred credits and noncurrent liabilities 122 160 Total Deferred Credits and Other Noncurrent Liabilities 2,731 2,725 Commitments and Contingent Liabilities (Notes 7 and 12) Equity Common stock - no par value (a) 364 364 Additional paid-in capital 5,038 4,668 Earnings reinvested 1,936 1,698 Total Equity 7,338 6,730 Total Liabilities and Equity $ 16,886 $ 15,475 (a) 170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2025 and December 31, 2024 . The accompanying Notes to Financial Statements are an integral part of the financial statements. 85 Table of Contents CONSOLIDATED STATEMENTS OF EQUITY PPL Electric Utilities Corporation and Subsidiaries (Millions of Dollars) Common stock shares outstanding (a) Common stock Additional paid-in capital Earnings reinvested Total December 31, 2022 66,368 $ 364 $ 4,084 $ 1,303 $ 5,751 Net income 519 519 Capital contributions from parent 206 206 Return of capital to parent ( 250 ) ( 250 ) Dividends declared ( 323 ) ( 323 ) December 31, 2023 66,368 $ 364 $ 4,040 $ 1,499 $ 5,903 Net income 574 574 Capital contributions from parent 688 688 Return of capital to parent ( 60 ) ( 60 ) Dividends declared ( 375 ) ( 375 ) December 31, 2024 66,368 $ 364 $ 4,668 $ 1,698 $ 6,730 Net income 639 639 Capital contributions from parent 540 540 Return of capital to parent ( 170 ) ( 170 ) Dividends declared ( 401 ) ( 401 ) December 31, 2025 66,368 $ 364 $ 5,038 $ 1,936 $ 7,338 (a) Shares in thousands. All common shares of PPL Electric stock are owned by PPL. The accompanying Notes to Financial Statements are an integral part of the financial statements. 86 Table of Contents (THIS PAGE LEFT BLANK INTENTIONALLY.) 87 Table of Contents STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, Louisville Gas and Electric Company (Millions of Dollars) 2025 2024 2023 Operating Revenues Retail and wholesale $ 1,718 $ 1,617 $ 1,580 Electric revenue from affiliate 30 31 33 Total Operating Revenues 1,748 1,648 1,613 Operating Expenses Operation Fuel 338 308 286 Energy purchases 187 151 168 Energy purchases from affiliate 22 20 12 Other operation and maintenance 364 349 364 Depreciation 307 305 302 Taxes, other than income 51 49 48 Total Operating Expenses 1,269 1,182 1,180 Operating Income 479 466 433 Other Income (Expense) - net (Note 14) 24 12 3 Interest Income from Affiliate — 1 1 Interest Expense 116 105 102 Income Before Income Taxes 387 374 335 Income Taxes 78 77 69 Net Income (a) $ 309 $ 297 $ 266 (a) Net income equals comprehensive income. The accompanying Notes to Financial Statements are an integral part of the financial statements. 88 Table of Contents STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, Louisville Gas and Electric Company (Millions of Dollars) 2025 2024 2023 Cash Flows from Operating Activities Net income $ 309 $ 297 $ 266 Adjustments to reconcile net income to net cash provided by (used in) operating activities Depreciation 307 305 302 Amortization 24 16 14 Equity component of AFUDC ( 16 ) ( 8 ) ( 3 ) Deferred income taxes and investment tax credits ( 9 ) 6 ( 14 ) Other 6 2 ( 4 ) Change in current assets and current liabilities Accounts receivable ( 10 ) ( 25 ) 40 Accounts receivable from affiliates ( 6 ) ( 11 ) 7 Accounts payable 14 12 ( 40 ) Accounts payable to affiliates 6 15 ( 8 ) Unbilled revenues ( 10 ) 1 24 Fuel, materials and supplies ( 2 ) ( 13 ) 24 Regulatory assets and liabilities, net ( 12 ) ( 3 ) 25 Taxes payable 20 ( 1 ) — Accrued interest 13 — 5 Other ( 5 ) — 1 Other operating activities Expenditures for asset retirement obligations ( 9 ) ( 11 ) ( 11 ) Other assets ( 43 ) ( 27 ) ( 21 ) Other liabilities 22 ( 1 ) 2 Net cash provided by operating activities 599 554 609 Cash Flows from Investing Activities Expenditures for property, plant and equipment ( 767 ) ( 444 ) ( 378 ) Notes receivable from affiliates ( 36 ) — — Net cash used in investing activities ( 803 ) ( 444 ) ( 378 ) Cash Flows from Financing Activities Net increase (decrease) in notes payable with affiliates ( 43 ) 43 — Issuance of long-term debt 700 — 464 Retirement of long-term debt ( 300 ) — ( 300 ) Payment of common stock dividends to parent ( 200 ) ( 187 ) ( 166 ) Contributions from parent 281 65 67 Return of capital to parent ( 55 ) ( 76 ) ( 161 ) Debt issuance costs ( 9 ) — ( 5 ) Net increase (decrease) in short-term debt ( 25 ) 25 ( 179 ) Net cash provided by (used in) financing activities 349 ( 130 ) ( 280 ) Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 145 ( 20 ) ( 49 ) Cash, Cash Equivalents and Restricted Cash at Beginning of Period 24 44 93 Cash, Cash Equivalents and Restricted Cash at End of Period $ 169 $ 24 $ 44 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest - net of amount capitalized $ 103 $ 101 $ 93 Income taxes - net $ 81 $ 73 $ 84 Significant non-cash transactions: Accrued expenditures for property, plant and equipment at December 31, $ 142 $ 64 $ 30 The accompanying Notes to Financial Statements are an integral part of the financial statements. 89 Table of Contents BALANCE SHEETS AT DECEMBER 31, Louisville Gas and Electric Company (Millions of Dollars, shares in thousands) 2025 2024 Assets Current Assets Cash and cash equivalents $ 162 $ 8 Accounts receivable (less reserve: 2025, $ 5 ; 2024, $ 3 ) Customer 154 134 Other 26 23 Unbilled revenues (less reserve: 2025, $ 0 ; 2024, $ 0 ) 97 87 Accounts receivable from affiliates 46 40 Notes receivable from affiliates 36 — Fuel, materials and supplies 160 157 Prepayments 11 9 Regulatory assets 19 8 Other current assets 2 2 Total Current Assets 713 468 Property, Plant and Equipment Regulated utility plant 8,270 7,748 Less: accumulated depreciation - regulated utility plant 1,842 1,643 Regulated utility plant, net 6,428 6,105 Construction work in progress 689 443 Property, Plant and Equipment, net 7,117 6,548 Other Noncurrent Assets Regulatory assets 482 491 Goodwill 389 389 Other intangibles 11 12 Other noncurrent assets 106 84 Total Other Noncurrent Assets 988 976 Total Assets $ 8,818 $ 7,992 The accompanying Notes to Financial Statements are an integral part of the financial statements. 90 Table of Contents BALANCE SHEETS AT DECEMBER 31, Louisville Gas and Electric Company (Millions of Dollars, shares in thousands) 2025 2024 Liabilities and Equity Current Liabilities Short-term debt $ — $ 25 Notes payable with affiliates — 43 Long-term debt due within one year 90 300 Accounts payable 262 158 Accounts payable to affiliates 73 64 Customer deposits 37 36 Taxes 60 40 Regulatory liabilities 13 14 Interest 34 21 Asset retirement obligations 2 11 Other current liabilities 54 50 Total Current Liabilities 625 762 Long-term Debt 2,775 2,171 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 819 803 Investment tax credits 29 30 Price risk management liabilities 4 3 Asset retirement obligations 73 73 Regulatory liabilities 809 815 Other deferred credits and noncurrent liabilities 78 64 Total Deferred Credits and Other Noncurrent Liabilities 1,812 1,788 Commitments and Contingent Liabilities (Notes 7 and 12) Equity Common stock - no par value (a) 424 424 Additional paid-in capital 2,208 1,982 Earnings reinvested 974 865 Total Equity 3,606 3,271 Total Liabilities and Equity $ 8,818 $ 7,992 (a) 75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2025 and December 31, 2024. The accompanying Notes to Financial Statements are an integral part of the financial statements. 91 Table of Contents STATEMENTS OF EQUITY Louisville Gas and Electric Company (Millions of Dollars) Common stock shares outstanding (a) Common stock Additional paid-in capital Earnings reinvested Total December 31, 2022 21,294 $ 424 $ 2,087 $ 655 $ 3,166 Net income 266 266 Capital contributions from parent 67 67 Return of capital to parent ( 161 ) ( 161 ) Cash dividends declared ( 166 ) ( 166 ) December 31, 2023 21,294 $ 424 $ 1,993 $ 755 $ 3,172 Net income 297 297 Capital contributions from parent 65 65 Return of capital to parent ( 76 ) ( 76 ) Cash dividends declared ( 187 ) ( 187 ) December 31, 2024 21,294 $ 424 $ 1,982 $ 865 $ 3,271 Net income 309 309 Capital contributions from parent 281 281 Return of capital to parent ( 55 ) ( 55 ) Cash dividends declared ( 200 ) ( 200 ) December 31, 2025 21,294 $ 424 $ 2,208 $ 974 $ 3,606 (a) Shares in thousands. All common shares of LG&E stock are owned by LKE. The accompanying Notes to Financial Statements are an integral part of the financial statements. 92 Table of Contents (THIS PAGE LEFT BLANK INTENTIONALLY.) 93 Table of Contents STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, Kentucky Utilities Company (Millions of Dollars) 2025 2024 2023 Operating Revenues Retail and wholesale $ 2,042 $ 1,944 $ 1,872 Electric revenue from affiliate 22 20 12 Total Operating Revenues 2,064 1,964 1,884 Operating Expenses Operation Fuel 517 476 447 Energy purchases 26 25 24 Energy purchases from affiliate 30 31 33 Other operation and maintenance 416 413 427 Depreciation 408 403 392 Taxes, other than income 51 49 45 Total Operating Expenses 1,448 1,397 1,368 Operating Income 616 567 516 Other Income (Expense) - net (Note 14) 29 15 8 Interest Expense 148 137 134 Interest Expense from Affiliate — — 1 Income Before Income Taxes 497 445 389 Income Taxes 99 89 77 Net Income (a) $ 398 $ 356 $ 312 (a) Net income equals comprehensive income. The accompanying Notes to Financial Statements are an integral part of the financial statements. 94 Table of Contents STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, Kentucky Utilities Company (Millions of Dollars) 2025 2024 2023 Cash Flows from Operating Activities Net income $ 398 $ 356 $ 312 Adjustments to reconcile net income to net cash provided by (used in) operating activities Depreciation 408 403 392 Amortization 21 21 20 Defined benefit plans - income ( 3 ) ( 5 ) ( 5 ) Equity component of AFUDC ( 21 ) ( 9 ) ( 3 ) Deferred income taxes and investment tax credits — ( 15 ) ( 10 ) Other 11 5 1 Change in current assets and current liabilities Accounts receivable ( 2 ) ( 21 ) 16 Accounts payable 1 ( 23 ) ( 26 ) Accounts payable to affiliates 7 29 ( 24 ) Unbilled revenues ( 4 ) ( 5 ) 17 Fuel, materials and supplies ( 8 ) 14 ( 17 ) Regulatory assets and liabilities, net ( 6 ) 23 25 Taxes payable 26 5 5 Accrued interest 14 — 5 Other ( 4 ) ( 5 ) ( 4 ) Other operating activities Expenditures for asset retirement obligations ( 11 ) ( 10 ) ( 28 ) Other assets ( 21 ) ( 41 ) ( 25 ) Other liabilities ( 8 ) 1 ( 4 ) Net cash provided by operating activities 798 723 647 Cash Flows from Investing Activities Expenditures for property, plant and equipment ( 983 ) ( 643 ) ( 572 ) Other investing activities ( 3 ) — 6 Net cash used in investing activities ( 986 ) ( 643 ) ( 566 ) Cash Flows from Financing Activities Net increase (decrease) in notes payable with affiliates ( 37 ) 73 — Issuance of long-term debt 700 — 459 Retirement of long-term debt ( 250 ) — ( 313 ) Payment of common stock dividends to parent ( 249 ) ( 232 ) ( 190 ) Contributions from parent 198 126 76 Return of capital to parent ( 37 ) ( 103 ) ( 84 ) Debt issuance costs ( 9 ) — ( 4 ) Net increase (decrease) in short-term debt ( 140 ) 47 ( 8 ) Net cash provided by (used in) financing activities 176 ( 89 ) ( 64 ) Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash ( 12 ) ( 9 ) 17 Cash, Cash Equivalents and Restricted Cash at Beginning of Period 29 38 21 Cash, Cash Equivalents and Restricted Cash at End of Period $ 17 $ 29 $ 38 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest - net of amount capitalized $ 138 $ 135 $ 125 Income taxes - net $ 94 $ 102 $ 78 Significant non-cash transactions: Accrued expenditures for property, plant and equipment at December 31, $ 101 $ 74 $ 38 The accompanying Notes to Financial Statements are an integral part of the financial statements. 95 Table of Contents BALANCE SHEETS AT DECEMBER 31, Kentucky Utilities Company (Millions of Dollars, shares in thousands) 2025 2024 Assets Current Assets Cash and cash equivalents $ 10 $ 13 Accounts receivable (less reserve: 2025, $ 4 ; 2024, $ 2 ) Customer 171 160 Other 26 22 Unbilled revenues (less reserve: 2025, $ 0 ; 2024, $ 0 ) 106 102 Fuel, materials and supplies 183 173 Prepayments 12 11 Regulatory assets 1 1 Other current assets 16 9 Total Current Assets 525 491 Property, Plant and Equipment Regulated utility plant 10,929 10,419 Less: accumulated depreciation - regulated utility plant 2,934 2,652 Regulated utility plant, net 7,995 7,767 Construction work in progress 952 567 Property, Plant and Equipment, net 8,947 8,334 Other Noncurrent Assets Regulatory assets 467 458 Goodwill 607 607 Other intangibles 34 28 Other noncurrent assets 178 155 Total Other Noncurrent Assets 1,286 1,248 Total Assets $ 10,758 $ 10,073 The accompanying Notes to Financial Statements are an integral part of the financial statements. 96 Table of Contents BALANCE SHEETS AT DECEMBER 31, Kentucky Utilities Company (Millions of Dollars, shares in thousands) 2025 2024 Liabilities and Equity Current Liabilities Short-term debt $ — $ 140 Notes payable with affiliates 36 73 Long-term debt due within one year 164 250 Accounts payable 137 96 Accounts payable to affiliates 106 100 Customer deposits 41 39 Taxes 63 37 Regulatory liabilities 16 22 Interest 38 24 Asset retirement obligations 6 10 Other current liabilities 69 58 Total Current Liabilities 676 849 Long-term Debt 3,346 2,816 Deferred Credits and Other Noncurrent Liabilities Deferred income taxes 956 924 Investment tax credits 79 81 Asset retirement obligations 51 54 Regulatory liabilities 997 1,009 Other deferred credits and noncurrent liabilities 44 41 Total Deferred Credits and Other Noncurrent Liabilities 2,127 2,109 Commitments and Contingent Liabilities (Notes 7 and 12) Equity Common stock - no par value (a) 308 308 Additional paid-in capital 3,217 3,056 Earnings reinvested 1,084 935 Total Equity 4,609 4,299 Total Liabilities and Equity $ 10,758 $ 10,073 (a) 80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2025 and December 31, 2024. The accompanying Notes to Financial Statements are an integral part of the financial statements. 97 Table of Contents STATEMENTS OF EQUITY Kentucky Utilities Company (Millions of Dollars) Common stock shares outstanding (a) Common stock Additional paid-in capital Earnings reinvested Total December 31, 2022 37,818 $ 308 $ 3,041 $ 689 $ 4,038 Net income 312 312 Capital contributions from parent 76 76 Return of capital to parent ( 84 ) ( 84 ) Cash dividends declared ( 190 ) ( 190 ) December 31, 2023 37,818 $ 308 $ 3,033 $ 811 $ 4,152 Net income 356 356 Capital contributions from parent 126 126 Return of capital to parent ( 103 ) ( 103 ) Cash dividends declared ( 232 ) ( 232 ) December 31, 2024 37,818 $ 308 $ 3,056 $ 935 $ 4,299 Net income 398 398 Capital contributions from parent 198 198 Return of capital to parent ( 37 ) ( 37 ) Cash dividends declared ( 249 ) ( 249 ) December 31, 2025 37,818 $ 308 $ 3,217 $ 1,084 $ 4,609 (a) Shares in thousands. All common shares of KU stock are owned by LKE. The accompanying Notes to Financial Statements are an integral part of the financial statements. 98 Table of Contents COMBINED NOTES TO FINANCIAL STATEMENTS Index to Combined Notes to Consolidated Financial Statements The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply: Registrant PPL PPL Electric LG&E KU 1. Summary of Significant Accounting Policies x x x x 2. Segment and Related Information x x x x 3. Revenue from Contracts with Customers x x x x 4. Preferred Securities x x x x 5. Earnings Per Share x 6. Income and Other Taxes x x x x 7. Utility Rate Regulation x x x x 8. Financing Activities x x x x 9. Acquisitions, Development and Divestitures x x x 10. Retirement and Postemployment Benefits x x x x 11. Jointly Owned Facilities x x x 12. Commitments and Contingencies x x x x 13. Related Party Transactions x x x 14. Other Income (Expense) - net x x x x 15. Fair Value Measurements x x x x 16. Derivative Instruments and Hedging Activities x x x x 17. Goodwill and Other Intangible Assets x x x x 18. Asset Retirement Obligations x x x x 19. Accumulated Other Comprehensive Income (Loss) x 20. New Accounting Guidance Pending Adoption x x x x 1. Summary of Significant Accounting Policies (All Registrants) General Capitalized terms and abbreviations appearing in the combined notes to financial statements are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted. The specific Registrant to which disclosures are applicable is identified in parenthetical headings in italics above the applicable disclosure or within the applicable disclosure for each Registrants' related activities and disclosures. Within combined disclosures, amounts are disclosed for any Registrant when significant. Business and Consolidation (PPL) PPL is a utility holding company that, through its regulated subsidiaries, is primarily engaged in: 1) the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas, primarily in Kentucky; 2) the transmission, distribution and sale of electricity in Pennsylvania; and 3) the transmission, distribution and sale of electricity and the distribution and sale of natural gas in Rhode Island. Headquartered in Allentown, PA, PPL's principal subsidiaries are LG&E, KU, RIE and PPL Electric. PPL's corporate level financing subsidiary is PPL Capital Funding. 99 Table of Contents (PPL and PPL Electric) PPL Electric's principal business is the transmission and distribution of electricity to serve retail customers in its franchised territory in eastern and central Pennsylvania and the regulated supply of electricity to retail customers in that territory as a PLR. (PPL, LG&E and KU) LG&E and KU are engaged in the generation, transmission, distribution and sale of electricity. LG&E also engages in the distribution and sale of natural gas. LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name. (All Registrants) The financial statements of the Registrants include each company's own accounts as well as the accounts of all entities in which the company has a controlling financial interest. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for Variable Interest Entities (VIEs). The Registrants consolidate a VIE when they are determined to have a controlling interest in the VIE and, as a result, are the primary beneficiary of the entity. Amounts consolidated under the VIE guidance are not material to the Registrants. All significant intercompany transactions have been eliminated. The financial statements of PPL, LG&E and KU include their share of any undivided interests in jointly owned facilities, as well as their share of the related operating costs of those facilities. See Note 11 for additional information. Regulation (All Registrants) PPL Electric, RIE, LG&E and KU are cost-based rate-regulated utilities for which rates are set by regulators to enable PPL Electric, RIE, LG&E and KU to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. Base rates are generally established based on a future test period. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by GAAP and reflect the effects of regulatory actions. Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover expected future costs, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC or the applicable state regulatory commissions. See Note 7 for additional details regarding regulatory matters. Accounting Records The system of accounts for regulated entities is maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the applicable state regulatory commissions. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Loss Accruals Potential losses are accrued when (1) information is available that indicates it is "probable" that a loss has been incurred, given the likelihood of uncertain future events and (2) the amount of loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." 100 Table of Contents The Registrants continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss accruals for environmental remediation are discounted when appropriate. The accrual of contingencies that might result in gains is not recorded, unless realization is assured. Earnings Per Share (PPL) EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareowners. Share-based payment awards that provide recipients a non-forfeitable right to dividends or dividend equivalents are considered participating securities. The if-converted method, which assumes the securities were converted to common stock at the start of the period (or issuance), is used to determine the dilutive effects of convertible securities. Price Risk Management (All Registrants) Interest rate contracts are used to hedge exposure to changes in the fair value of debt instruments and to hedge exposure to variability in expected cash flows associated with existing floating-rate debt instruments or forecasted fixed-rate issuances of debt. Derivative instruments pursuant to regulator approved plans to manage commodity price risk associated with natural gas purchases to reduce fluctuations in natural gas prices and costs associated with these derivatives instruments are generally recoverable through approved cost recovery mechanism. Similar derivatives may receive different accounting treatment, depending on management's intended use and documentation. Certain contracts may not meet the definition of a derivative because they lack a notional amount or a net settlement provision. In cases where there is no net settlement provision, markets are periodically assessed to determine whether market mechanisms have evolved to facilitate net settlement. Certain derivative contracts may be excluded from the requirements of derivative accounting treatment because NPNS has been elected. These contracts are accounted for using accrual accounting. Contracts that have been classified as derivative contracts are reflected on the balance sheets at fair value. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing activities on the Statements of Cash Flows, depending on the classification of the hedged items. PPL and its subsidiaries have elected not to offset net derivative positions against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements. Derivative transactions may be marked to fair value through regulatory assets/liabilities at PPL Electric, RIE, LG&E and KU, if approved by the appropriate regulatory body. These transactions generally include the effect of interest rate swaps or commodity gas contracts that are included in customer rates. See Notes 15 and 16 for additional information on derivatives. (PPL and PPL Electric) To meet their obligations as last resort providers of electricity supply to their customers, PPL Electric and RIE have entered into certain contracts that meet the definition of a derivative. However, NPNS has been elected for these contracts. Revenue (All Registrants) Operating revenues are primarily recorded based on energy deliveries through the end of each calendar month. Unbilled retail revenues result because customers' bills are rendered throughout the month, rather than at the end of the month. For RIE, LG&E and KU, unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh or Mcf by the estimated average price per kWh or Mcf. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. For PPL Electric, unbilled revenues for a month are calculated by multiplying the actual unbilled volumes by the applicable tariff price. 101 Table of Contents PPL Electric's, RIE's, LG&E's and KU's base rates are determined based on cost of service. Some regulators have also authorized the use of additional alternative revenue programs, which enable PPL Electric, RIE, LG&E and KU to adjust future rates based on past activities or completed events. Revenues from alternative revenue programs are recognized when the specific events permitting future billings have occurred. Revenues from alternative revenue programs are required to be presented separately from revenues from contracts with customers. These amounts are, however, presented as revenues from contracts with customers, with an offsetting adjustment to alternative revenue program revenue, when they are billed to customers in future periods. See Note 3 for additional information. Financing and Other Receivables (All Registrants) Accounts receivable are reported on the Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Financing receivables include accounts receivable, with the exception of those items within accounts receivable that are not subject to the current expected credit loss model. Financing receivable collectability is evaluated using a current expected credit loss model, consisting of a combination of factors, including past due status based on contractual terms, trends in write-offs and the age of the receivable. Specific events, such as bankruptcies, are also considered when applicable. The Registrants also evaluate the impact of observable external factors on the collectability of the financing receivables to determine if adjustments to the allowance for doubtful accounts should be made based on current conditions or reasonable and supportable forecasts. Adjustments to the allowance for doubtful accounts are made based on the results of these analyses. Accounts receivable are written off in the period in which the receivable is deemed uncollectible. PPL Electric, RIE, LG&E and KU have identified one class of financing receivables, "accounts receivable - customer", which includes financing receivables for all billed and unbilled sales with customers. All other financing receivables are classified as other. The changes in the allowance for doubtful accounts are included in the following table. Amounts relate to financing receivables, except as noted. Additions Balance at Beginning of Period Charged to Income Deductions (a) Balance at End of Period PPL 2025 $ 154 $ 84 $ 98 $ 140 (b) 2024 130 109 85 154 (b) 2023 95 87 52 130 (b) PPL Electric 2025 $ 41 $ 33 $ 35 $ 39 (c) 2024 50 56 65 41 (c) 2023 33 52 35 50 (c) LG&E 2025 $ 3 $ 4 $ 2 $ 5 2024 6 4 7 3 2023 4 4 2 6 KU 2025 $ 2 $ 5 $ 3 $ 4 2024 2 4 4 2 2023 3 3 4 2 (a) Primarily related to uncollectible accounts written off. (b) Includes $ 43 million, $ 39 million and $ 41 million related to other accounts receivable at December 31, 2025, 2024 and 2023. (c) Includes $ 2 million, $ 2 million and $ 3 million related to other accounts receivable at December 31, 2025, 2024 and 2023. 102 Table of Contents Cash (All Registrants) Cash Equivalents All highly liquid investments with original maturities of three months or less are considered to be cash equivalents. (PPL, LG&E and KU) Restricted Cash and Cash Equivalents Bank deposits and other cash equivalents that are restricted by agreement or that have been clearly designated for a specific purpose are classified as restricted cash and cash equivalents. On the Balance Sheets, the current portion of restricted cash and cash equivalents is included in "Other current assets," while the noncurrent portion is included in "Other noncurrent assets." See Note 15 for a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the Balance Sheets to the amounts shown on the Statements of Cash Flows. (All Registrants) Fair Value Measurements The Registrants value certain financial and non-financial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to price risk management assets and liabilities, investments in securities in defined benefit plans, and cash and cash equivalents. PPL and its subsidiaries use, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk. The Registrants classify fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows: • Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. • Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability. • Level 3 - unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value. Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, the Registrants' assessment of the significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy. 103 Table of Contents Investments Generally, the original maturity date of an investment and management's intent and ability to sell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for other than current operations or are clearly designated for expenditure in the acquisition or construction of noncurrent assets or for the liquidation of long-term debts, are classified as long-term. Investments in entities in which a company has the ability to exercise significant influence but does not have a controlling financial interest are accounted for under the equity method. All other investments are carried at cost or fair value. These investments are included in "Other noncurrent assets" on the Balance Sheets. Earnings from these investments are recorded in "Other Income (Expense) - net" on the Statements of Income. Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and less than a year, as well as investments with original maturities of greater than a year that management has the ability and intent to sell within a year, are included in "Other current assets" on the Balance Sheets. Long-Lived and Intangible Assets Property, Plant and Equipment PP&E is recorded at original cost, unless impaired. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. PP&E acquired in business combinations is recorded at fair value at the time of acquisition. Original cost for constructed assets includes material, labor, contractor costs, certain overheads and financing costs, where applicable. Included in PP&E are capitalized costs of software projects that were developed or obtained for internal use. The cost of repairs and minor replacements are charged to expense as incurred. The Registrants record costs associated with planned major maintenance projects in the period in which work is performed and costs are incurred. AFUDC is capitalized at PPL Electric and RIE as part of the construction costs for cost-based rate-regulated projects for which a return on such costs is recovered after the project is placed in service. AFUDC is capitalized at LG&E and KU for certain projects as part of the construction cost of approved projects. LG&E and KU are generally provided a return on construction work in progress for other projects. The debt component of AFUDC is credited to "Interest Expense" and the equity component is credited to "Other Income (Expense) - net" on the Statements of Income. The Registrants capitalize interest costs as part of construction costs. Capitalized interest, including the debt component of AFUDC, for the years ended December 31 is as follows: 2025 2024 2023 PPL $ 32 $ 20 $ 12 PPL Electric 13 9 7 LG&E 6 3 1 KU 8 4 1 Depreciation Depreciation is recorded over the estimated useful lives of property using various methods including the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant portion of an operating unit that was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income, unless otherwise required by regulators. RIE, LG&E and KU accrue costs of removal net of estimated salvage value through depreciation, which is included in the calculation of customer rates over the assets' depreciable lives in accordance with regulatory practices. Cost of removal amounts accrued through depreciation rates are accumulated as a regulatory liability until the removal costs are incurred. For LG&E and KU, all ARO depreciation expenses are reclassified to a regulatory asset or regulatory liability. See "Asset Retirement Obligations" below and Note 7 for additional information. PPL Electric records net costs of removal when incurred as a regulatory asset. The regulatory asset is subsequently amortized through depreciation over a five-year period, which is recoverable in customer rates in accordance with regulatory practices. 104 Table of Contents Following are the weighted-average annual rates of depreciation, for regulated utility plant, for the years ended December 31: 2025 2024 2023 PPL 3.06 % 3.20 % 3.26 % PPL Electric 2.46 % 2.52 % 2.62 % LG&E 3.69 % 4.02 % 4.00 % KU 3.68 % 3.86 % 3.95 % Goodwill and Other Intangible Assets Goodwill represents the excess of the purchase price paid over the fair value of the identifiable net assets acquired in a business combination. Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed or otherwise used. Costs incurred to obtain, renew or extend terms of an intangible asset are capitalized. When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, PPL and its subsidiaries consider: • the expected use of the asset; • the expected useful life of other assets to which the useful life of the intangible asset may relate; • legal, regulatory, or contractual provisions that may limit the useful life; • the company's historical experience as evidence of its ability to support renewal or extension; • the effects of obsolescence, demand, competition, and other economic factors; and, • the level of maintenance expenditures required to obtain the expected future cash flows from the asset. Asset Impairment (Excluding Investments) The Registrants review long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or circumstances indicate carrying amounts may not be recoverable. A long-lived asset classified as held and used is impaired when the carrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value. A long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell. PPL, LG&E and KU review goodwill for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the reporting unit's fair value. Additionally, goodwill must be tested for impairment in circumstances when a portion of goodwill has been allocated to a business to be disposed. PPL's, LG&E's and KU's reporting units are primarily at the operating segment level. PPL, for its reporting units, and individually, LG&E and KU, may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a quantitative test. If the qualitative evaluation (referred to as step zero) is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the quantitative impairment test is not necessary. However, the quantitative impairment test is required if management concludes it is more likely than not that the fair value of a reporting unit is less than the carrying amount based on the step zero assessment. If the carrying amount of the reporting unit, including goodwill, exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. As of October 1, 2025, PPL, for its reporting units, and individually, LG&E and KU, elected to perform the qualitative step zero evaluation of goodwill. These evaluations considered the excess of fair value over the carrying value of each reporting unit that was calculated during step one of the quantitative impairment tests performed in the fourth quarter of 2022, and the relevant events and circumstances that occurred since those tests were performed including: • current year financial performance versus the prior year, 105 Table of Contents • changes in planned capital expenditures, • the consistency of forecasted free cash flows, • earnings quality and sustainability, • changes in market participant discount rates, • changes in long-term growth rates, • changes in PPL's market capitalization, and • the overall economic and regulatory environments in which these regulated entities operate. Based on these evaluations, management concluded it was not more likely than not that the fair value of these reporting units was less than their carrying value. As such, the step one quantitative impairment test was not performed and no impairment was recognized. ( PPL, LG&E and KU ) Asset Retirement Obligations PPL and its subsidiaries record liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and offset with an increase in the value of the capitalized asset, which is depreciated over the asset's useful life. Until the obligation is settled, the liability is increased through the recognition of accretion expense classified within "Other operation and maintenance" on the Statements of Income to reflect changes in the obligation due to the passage of time. For LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset. See Note 7 and Note 18 for additional information on AROs. Compensation and Benefits Defined Benefits (All Registrants) Certain PPL subsidiaries sponsor various defined benefit pension and other postretirement plans. An asset or liability is recorded to recognize the funded status of all defined benefit plans with an offsetting entry to AOCI or, for PPL Electric, LG&E, KU and RIE, to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. The expected return on plan assets is determined based on a market-related value of plan assets, which is calculated by rolling forward the prior year market-related value with contributions, disbursements and long-term expected return on investments. One-fifth of the difference between the actual value and the expected value is added (or subtracted if negative) to the expected value to determine the new market-related value. PPL and its subsidiaries, excluding RIE, use an accelerated amortization method for the recognition of gains and losses for its defined benefit pension plans. Under the accelerated method, actuarial gains and losses in excess of 30 % of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the required amortization period. Actuarial gains and losses in excess of 10 % of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30 % of the plan's projected benefit obligation are amortized on a straight-line basis over the full required amortization period. RIE uses the standard amortization method under GAAP for recognition of gains and losses for its defined benefit pension plan. See Note 7 for a discussion of the regulatory treatment of defined benefit costs and Note 10 for a discussion of defined benefits. 106 Table of Contents Stock-Based Compensation (PPL) PPL has several stock-based compensation plans for purposes of granting stock options, restricted stock, restricted stock units and performance units to certain employees as well as stock units and restricted stock units to directors. PPL grants most stock-based compensation awards in the first quarter of each year. PPL recognizes compensation expense for stock-based compensation awards based on the fair value method. Forfeitures of awards are recognized when they occur. All awards are recorded as equity or a liability on the Balance Sheets. Stock-based compensation expense is primarily included in "Other operation and maintenance" on the Statements of Income. Taxes Income Taxes (All Registrants) PPL and its subsidiaries file a consolidated U.S. federal income tax return. Significant management judgment is required in developing the Registrants' provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken on tax returns and valuation allowances on deferred tax assets. The Registrants use a two-step process to evaluate uncertain tax positions. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in its financial statements the amount of the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization upon settlement that exceeds 50 %. Unrecognized tax benefits are classified as current to the extent management expects to settle the uncertain tax position by payment or receipt of cash within one year of the reporting date. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements of the Registrants in future periods. At December 31, 2025, no significant changes in unrecognized tax benefits were projected over the next 12 months. Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, as well as the tax effects of net operating losses and tax credit carryforwards. The Registrants record valuation allowances to reduce deferred income tax assets to the amounts that are more-likely-than-not to be realized. The need for valuation allowances requires significant management judgment. If the Registrants determine that they are able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made. Likewise, if the Registrants determine that they are not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future . The Registrants defer investment tax credits when the credits are generated and amortize the deferred amounts over the average lives of the related assets. With respect to acquired renewable tax credits, pursuant to the IRA, any benefit is recognized in the period the credits can be utilized. The Registrants recognize tax-related interest and penalties in "Income Taxes" on their Statements of Income. The Registrants use the portfolio approach method of accounting for deferred taxes related to pre-tax OCI transactions. The portfolio approach involves a strict period-by-period cumulative incremental allocation of income taxes to the change in income and losses reflected in OCI. Under this approach, the net cumulative tax effect is ignored. The net change in unrealized gains and losses recorded in AOCI under this approach would be eliminated only on the date the investment portfolio is classified as held for sale or is liquidated. See Note 6 for income tax disclosures. 107 Table of Contents The provision for the Registrants' deferred income taxes related to regulatory assets and liabilities is based upon the ratemaking principles reflected in rates established by relevant regulators. The difference in the provision for deferred income taxes for regulatory assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included on the Balance Sheets in noncurrent "Regulatory assets" or "Regulatory liabilities." (PPL Electric, LG&E and KU) The income tax provision for PPL Electric, LG&E and KU is calculated in accordance with an intercompany tax sharing agreement, which provides that taxable income be calculated as if PPL Electric, LG&E, KU and any subsidiaries each filed a separate return. Tax benefits are not shared between companies. The entity that generates a tax benefit is the entity that is entitled to the tax benefit. The effect of PPL filing a consolidated tax return is taken into account in the settlement of current taxes and the recognition of deferred taxes. At December 31, the following intercompany tax payables were recorded: 2025 2024 PPL Electric $ ( 27 ) $ ( 2 ) LG&E ( 7 ) ( 2 ) KU ( 10 ) ( 5 ) Taxes, Other Than Income (All Registrants) The Registrants present sales taxes in "Other current liabilities" on the Balance Sheets. These taxes are not reflected on the Statements of Income. See Note 6 for details of taxes included in "Taxes, other than income" on the Statements of Income. Other (All Registrants) Fuel, Materials and Supplies Fuel, natural gas stored underground and materials and supplies are valued using the average cost method. Fuel costs for electricity generation are charged to expense as used. For RIE, natural gas supply costs are charged to expense when delivered to customers. For LG&E, natural gas supply costs are charged to expense as delivered to the distribution system. See Note 7 for further discussion of the gas supply clause. "Fuel, materials and supplies" on the Balance Sheets consisted of the following at December 31: 2025 PPL PPL Electric LG&E KU Fuel $ 157 $ — $ 58 $ 99 Natural gas stored underground 50 — 33 — Materials and supplies 344 151 69 84 Total $ 551 $ 151 $ 160 $ 183 2024 PPL PPL Electric LG&E KU Fuel $ 153 $ — $ 64 $ 89 Natural gas stored underground 49 — 29 — Materials and supplies 309 104 64 84 Total $ 511 $ 104 $ 157 $ 173 108 Table of Contents (PPL and PPL Electric) Renewable Energy Standard Obligation Purchased Renewable Energy Certificates (RECs) are stated at cost and are used to measure compliance with state renewable energy standards. RECs support new renewable generation standards and are held primarily to be utilized in fulfillment of RIE's and PPL Electric's compliance obligations. (All Registrants) Guarantees Generally, the initial measurement of a guarantee liability is the fair value of the guarantee at its inception. However, there are certain guarantees excluded from the scope of accounting guidance and other guarantees that are not subject to the initial recognition and measurement provisions of accounting guidance that only require disclosure. See Note 12 for further discussion of guarantees. New Accounting Guidance Adopted (All Registrants) Improvements to Income Tax Disclosures Effective December 31, 2025, the Registrants retrospectively adopted accounting guidance to improve income tax disclosures. The guidance requires enhanced disclosures about disaggregated rate reconciliation in eight specific categories, presented in both percentages and currency amounts. Further disaggregation by jurisdiction or nature of the item, or both, is required if over a 5% threshold. The utility industry has specific tax rate impacts due to federal and state rate-making requirements, which frequently exceed the 5% threshold. Accordingly, a ninth category is used to disaggregate the utility rate-making tax adjustments. The guidance also requires disclosure of the amount of income taxes paid disaggregated by federal, state, and foreign. See Note 6 for additional information. 2. Segment and Related Information (PPL) PPL is organized into three segments, broken down by geographic location: Kentucky Regulated, Pennsylvania Regulated, and Rhode Island Regulated. The Kentucky Regulated segment consists primarily of the regulated electricity generation, transmission and distribution operations conducted by LG&E and KU, as well as LG&E's regulated distribution and sale of natural gas. The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric. The Rhode Island Regulated segment includes the regulated electricity transmission and distribution and natural gas distribution operations of RIE. "Corporate and Other" primarily includes corporate level financing costs, certain unallocated corporate costs, and certain non-recoverable costs incurred in conjunction with the acquisition of RIE. "Corporate and Other" is presented to reconcile segment information to PPL's consolidated results and is not a reportable segment. PPL's Chief Operating Decision Maker (CODM) is the CLC. The CLC uses financial metrics including segment net income, earnings from ongoing operations, earnings per share and return on equity, as well as various operational metrics to assess segment performance and make investment and resource decisions. Segment net income is the measure of segment profit or loss that most closely aligns with GAAP and is being presented for disclosure purposes. 109 Table of Contents The tables below provide information about PPL's segments and include a reconciliation of segment net income to consolidated net income for the year ended December 31, 2025: Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Operating Revenues from external customers (a) $ 3,760 $ 3,113 $ 2,168 $ 9,041 Reconciliation of revenue Corporate and other revenues 1 Total consolidated revenues $ 9,042 Less: Fuel 855 — — 855 Energy Purchases 214 876 802 1,892 Operation and maintenance 818 630 851 2,299 Depreciation 717 413 177 1,307 Taxes, other than income 102 151 170 423 Other (income) expense - net ( 53 ) ( 48 ) ( 33 ) ( 134 ) Interest (income) from affiliate — ( 9 ) ( 3 ) ( 12 ) Interest expense 264 257 111 632 Income taxes 169 204 8 381 Segment net income $ 674 $ 639 $ 85 $ 1,398 Reconciliation of segment profit or loss to consolidated net income Corporate and other net loss ( 217 ) Net Income $ 1,181 (a) See Note 1 and Note 3 for additional information on Operating Revenues. Other information for the segments and reconciliation to PPL's Consolidated results for the year ended December 31, 2025 are as follows: Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Segments Corporate and Other Consolidated Total Other Segment Disclosures Amortization (a) $ 43 $ 48 $ 1 $ 92 $ 12 $ 104 Deferred income taxes and investment tax credits (b) ( 9 ) 24 28 43 149 192 Expenditures for long lived assets 1,752 1,620 668 4,040 2 4,042 (a) Represents non-cash expense items that include amortization of operating lease right-of-use assets, regulatory assets and liabilities, debt discounts and premiums and debt issuance costs. (b) Represents a non-cash expense item that is also included in "Income Taxes." The tables below provide information about PPL's segments and include a reconciliation of segment net income to consolidated net income for the year ended December 31, 2024: Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Operating Revenues from external customers (a) $ 3,562 $ 2,876 $ 2,024 $ 8,462 Reconciliation of revenue Corporate and other revenues — Total consolidated revenues $ 8,462 110 Table of Contents Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Less: Fuel 783 — — 783 Energy Purchases 176 721 782 1,679 Operation and maintenance 803 705 731 2,239 Depreciation 710 401 165 1,276 Taxes, other than income 99 131 144 374 Other (income) expense - net ( 29 ) ( 45 ) ( 20 ) ( 94 ) Interest (income) from affiliate — ( 33 ) ( 4 ) ( 37 ) Interest expense 240 246 95 581 Income taxes 160 176 22 358 Segment net income $ 620 $ 574 $ 109 $ 1,303 Reconciliation of segment profit or loss to consolidated net income Corporate and other net loss ( 415 ) Net Income $ 888 (a) See Note 1 and Note 3 for additional information on Operating Revenues. Other information for the segments and reconciliation to PPL's Consolidated results for the year ended December 31, 2024 are as follows: Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Segments Corporate and Other Consolidated Total Other Segment Disclosures Amortization (a) $ 24 $ 45 $ 1 $ 70 $ 8 $ 78 Deferred income taxes and investment tax credits (b) 2 129 38 169 27 196 Expenditures for long lived assets 1,088 1,229 495 2,812 ( 7 ) 2,805 (a) Represents non-cash expense items that include amortization of operating lease right-of-use assets, regulatory assets and liabilities, debt discounts and premiums and debt issuance costs. (b) Represents a non-cash expense item that is also included in "Income Taxes." The tables below provide information about PPL's segments and include a reconciliation of segment net income to consolidated net income for the year ended December 31, 2023: Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Operating Revenues from external customers (a) $ 3,452 $ 3,008 $ 1,851 $ 8,311 Reconciliation of revenue Corporate and other revenues 1 Total consolidated revenues $ 8,312 Less: Fuel 733 — — 733 Energy Purchases 192 992 658 1,842 Operation and maintenance 826 605 705 2,136 Depreciation 696 397 156 1,249 Taxes, other than income 93 143 156 392 Other (income) expense - net ( 12 ) ( 39 ) ( 19 ) ( 70 ) Interest expense 235 223 83 541 Income taxes 137 168 16 321 Segment net income $ 552 $ 519 $ 96 $ 1,167 Reconciliation of segment profit or loss to consolidated net income Corporate and other net loss ( 427 ) Net Income $ 740 (a) See Note 1 and Note 3 for additional information on Operating Revenues. 111 Table of Contents Other information for the segments and reconciliation to PPL's Consolidated results for the year ended December 31, 2023 are as follows: Kentucky Regulated Pennsylvania Regulated Rhode Island Regulated Total Segments Corporate and Other Consolidated Total Other Segment Disclosures Amortization (a) $ 33 $ 41 $ 1 $ 75 $ 6 $ 81 Deferred income taxes and investment tax credits (b) ( 17 ) 46 48 77 245 322 Expenditures for long lived assets 950 956 454 2,360 30 2,390 (a) Represents non-cash expense items that include amortization of operating lease right-of-use assets, regulatory assets and liabilities, debt discounts and premiums and debt issuance costs. (b) Represents a non-cash expense item that is also included in "Income Taxes." The following provides Balance Sheet data for the segments and reconciliation to PPL's consolidated results as of: As of December 31, 2025 2024 Total Assets Kentucky Regulated $ 19,060 $ 17,626 Pennsylvania Regulated 16,886 15,475 Rhode Island Regulated 7,510 7,055 Corporate and Other (a) 1,788 913 Total $ 45,244 $ 41,069 (a) Primarily consists of unallocated items, including cash, PP&E, goodwill, and the elimination of inter-segment transactions. (PPL Electric) PPL Electric has two operating segments, distribution and transmission, which are aggregated into a single reportable segment. PPL Electric's CODM is the President of PPL Electric. The President uses financial metrics including segment net income, earnings from ongoing operations, earnings per share and return on equity, as well as various operational metrics to assess segment performance and make investment and resource decisions. The significant segment expenses of and measure of profit and loss for PPL Electric regularly provided to the President are included on the face of PPL Electric's Statements of Income. The measure of segment assets is reported on PPL Electric's Balance Sheets as total consolidated assets. The measures of significant non-cash segment expenses as well as expenditures for long lived assets are reported on PPL Electric's Statements of Cash Flows. (LG&E and KU) Each of LG&E and KU operates as a single operating and reportable segment, and the CODM for each of LG&E and KU is its President. The President manages LG&E and KU as a single consolidated entity. Financial metrics including net income, earnings from ongoing operations, earnings per share and return on equity, as well as various operational metrics are used to assess segment performance and make investment and resource decisions. The significant segment expenses of and measure of profit and loss for each of LG&E and KU regularly provided to its President are included on the face of the Statements of Income of LG&E and KU. The measures of segment assets are reported on the Balance Sheets of LG&E and KU as total assets. The measures of significant non-cash segment expenses as well as expenditures for long lived assets are reported on the Statements of Cash Flows of LG&E and KU. 112 Table of Contents 3. Revenue from Contracts with Customers (All Registrants) The following is a description of the principal activities from which the Registrants and PPL's segments generate their revenues. (PPL and PPL Electric) Pennsylvania Regulated Segment Revenue The Pennsylvania Regulated segment generates substantially all of its revenues from contracts with customers from PPL Electric's tariff-based distribution and transmission of electricity. Distribution Revenue PPL Electric provides distribution services to residential, commercial, industrial, municipal and governmental end users of energy. PPL Electric satisfies its performance obligation to its distribution customers and revenue is recognized over time as electricity is delivered and simultaneously consumed by the customer. The amount of revenue recognized is the volume of electricity delivered during the period multiplied by the price per tariff, plus a monthly fixed charge and include unbilled amounts, which represent the amounts due from customers as a result of customer's bills being rendered throughout the month, rather than at the end of the month. This method of recognition fairly presents PPL Electric's transfer of electric service to the customer as the calculation is based on volumes delivered, and the price per tariff and the monthly fixed charge are set by the PAPUC. Customers are typically billed monthly and outstanding amounts are normally due within 21 days of the date of the bill. Distribution customers are "at will" customers of PPL Electric with no term contract and no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with PPL Electric's retail account contracts. Certain customers have the option to obtain electricity from other suppliers where PPL Electric facilitates the delivery. In those circumstances, revenue is only recognized for providing delivery of the commodity to the customer. Transmission Revenue PPL Electric generates transmission revenues from a FERC-approved PJM Open Access Transmission Tariff. An annual revenue requirement for PPL Electric to provide transmission services is calculated using a formula-based rate. This revenue requirement is converted into a daily rate (dollars per day). PPL Electric satisfies its performance obligation to provide transmission services and revenue is recognized over time as transmission services are provided and consumed. This method of recognition fairly presents PPL Electric's transfer of transmission services as the daily rate is set by a FERC approved formula-based rate. PJM remits payment on a weekly basis. PPL Electric's agreement to provide transmission services contains no minimum purchase commitment. The performance obligation is limited to the service requested and received to date. Accordingly, PPL Electric has no unsatisfied performance obligations. (PPL) Rhode Island Regulated Segment Revenues The Rhode Island Regulated segment generates substantially all of its revenues from contracts with customers from RIE's regulated tariff-based transmission and distribution of electricity and regulated tariff-based distribution of natural gas. Distribution Revenue Distribution revenues are primarily from the sale of electricity, natural gas, and related services to retail customers. Distribution sales are regulated by the RIPUC, which is responsible for approving the rates and other terms of services as part of the rate making process. Natural gas and electric distribution revenues are derived from the regulated sale and distribution of electricity and natural gas to residential, commercial, and industrial customers within RIE's service territory under the tariff rates. The performance obligation related to distribution sales is to provide electricity and natural gas to customers on demand. 113 Table of Contents The performance obligation is satisfied over time because the customer simultaneously receives and consumes the electricity or natural gas as services are provided. RIE records revenues related to the distribution sales based upon the approved tariff rate and the volume delivered to the customers, which corresponds with the amount RIE has the right to invoice. Customers are typically billed monthly and outstanding amounts are normally due within 21 days of date of the bill. Distribution revenue also includes estimated unbilled amounts, which represent the estimated amounts due from retail customers as a result of customer's bills being rendered throughout the month, rather than at the end of the month. Unbilled revenues are determined based on estimated unbilled sales volumes and then applying tariff rates to those volumes. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. This method of recognition fairly presents RIE's transfer of electricity and natural gas to the customer as the amount recognized is based on actual and estimated volumes delivered and the tariff rate per unit of energy and any applicable fixed charges or regulatory mechanisms as approved by the respective regulatory body. Distribution customers are "at will" customers of RIE with no term contract and no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with RIE's retail account contracts. Certain customers have the option to obtain electricity or natural gas from other suppliers where RIE facilitates the delivery. In those circumstances, revenue is only recognized for providing delivery of the commodity to the customer. Transmission Revenue RIE's transmission services are regulated by the FERC and coordinated with ISO – New England (ISO-NE). As of January 1, 2023, RIE is a transmission operator. These revenues arise under tariff/rate agreements and are collected primarily from RIE's distribution customers. The revenue is recognized over time as transmission services are provided and consumed. This method of recognition fairly presents RIE's transfer of transmission services as the daily rate is set by a FERC-approved formula-based rate. RIE's agreement to provide transmission services contains no minimum purchase commitment. The performance obligation is limited to the service requested and received to date. Accordingly, RIE has no unsatisfied performance obligations. (PPL, LG&E and KU) Kentucky Regulated Segment Revenue The Kentucky Regulated Segment generates substantially all of its revenues from contracts with customers from LG&E's and KU's regulated tariff-based sales of electricity and LG&E's regulated tariff-based sales of natural gas. LG&E and KU are engaged in the generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, Virginia. LG&E also engages in the distribution and sale of natural gas in Kentucky. Revenue from these activities is generated from tariffs approved by applicable regulatory authorities including the FERC, KPSC and VSCC. LG&E and KU satisfy their performance obligations upon LG&E's and KU's delivery of electricity and LG&E's delivery of natural gas to customers. This revenue is recognized over time as the customer simultaneously receives and consumes the benefits provided by LG&E and KU. The amount of revenue recognized is the billed volume of electricity or natural gas delivered multiplied by a tariff rate per-unit of energy, plus any applicable fixed charges or additional regulatory mechanisms. Customers are billed monthly and outstanding amounts are typically due within 22 days of the date of the bill. Additionally, unbilled revenues are recognized as a result of customers' bills being rendered throughout the month, rather than at the end of the month. Unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh or Mcf delivered but not yet billed by the estimated average cents per kWh or Mcf. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. This method of recognition fairly presents LG&E's and KU's transfer of electricity and LG&E's transfer of natural gas to the customer as the amount recognized is based on actual and estimated volumes delivered and the tariff rate per-unit of energy and any applicable fixed charges or regulatory mechanisms as set by the respective regulatory body. LG&E's and KU's customers generally have no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with these customers. 114 Table of Contents (All Registrants) The following table reconciles "Operating Revenues" included in each Registrant's Statement of Income with revenues generated from contracts with customers for the years ended December 31: 2025 PPL PPL Electric LG&E KU Operating Revenues (a)(b) $ 9,042 $ 3,113 $ 1,748 $ 2,064 Revenues derived from: Alternative revenue programs (c) 153 21 ( 2 ) — Other (d) ( 25 ) ( 17 ) ( 4 ) ( 4 ) Revenues from Contracts with Customers $ 9,170 $ 3,117 $ 1,742 $ 2,060 2024 PPL PPL Electric LG&E KU Operating Revenues (a)(b) $ 8,462 $ 2,876 $ 1,648 $ 1,964 Revenues derived from: Alternative revenue programs (c) 5 ( 19 ) 13 16 Other (d) ( 23 ) ( 15 ) ( 4 ) ( 4 ) Revenues from Contracts with Customers $ 8,444 $ 2,842 $ 1,657 $ 1,976 2023 PPL PPL Electric LG&E KU Operating Revenues (a)(b) $ 8,312 $ 3,008 $ 1,613 $ 1,884 Revenues derived from: Alternative revenue programs (c) 1 5 ( 1 ) ( 5 ) Other (d) ( 23 ) ( 15 ) ( 4 ) ( 4 ) Revenues from Contracts with Customers $ 8,290 $ 2,998 $ 1,608 $ 1,875 (a) PPL includes $ 2,168 million, $ 2,024 million and $ 1,851 million for the twelve months ended December 31, 2025, 2024, and 2023 of revenues from external customers reported by the Rhode Island Regulated segment. PPL Electric represents revenues from external customers reported by the Pennsylvania Regulated segment and LG&E and KU, net of intercompany power sales and transmission revenues, represent revenues from external customers reported by the Kentucky Regulated segment. See Note 2 for additional information. (b) PPL's transition services agreement associated with the RIE acquisition ended in the third quarter of 2024. In conjunction with the completion of the agreement, PPL conformed the presentation of RIE's and the Rhode Island Regulated segment's net metering charges with the presentation of the other segments, resulting in an increase in "Operating Revenues" and a corresponding increase in "Energy purchases" beginning on January 1, 2024. For the year ended December 31, 2023, $ 146 million of net metering was presented as a reduction of "Operating Revenues" on PPL's Statement of Income. (c) This line item shows the over/under collection of rate mechanisms deemed alternative revenue programs with over-collections of revenue shown as positive amounts and under collections as negative amounts. (d) Represents additional revenues outside the scope of revenues from contracts with customers such as leases and other miscellaneous revenues. The following table shows revenues from contracts with customers disaggregated by customer class for the years ended December 31: Residential Commercial Industrial Other (a) Wholesale - municipality Wholesale - other (b) Transmission Revenues from Contracts with Customers PPL 2025 PA Regulated $ 1,656 $ 448 $ 56 $ 54 $ — $ — $ 903 $ 3,117 RI Regulated (c) 1,249 671 83 86 — — 213 2,302 KY Regulated 1,616 1,063 627 309 25 111 — 3,751 Total PPL $ 4,521 $ 2,182 $ 766 $ 449 $ 25 $ 111 $ 1,116 $ 9,170 115 Table of Contents Residential Commercial Industrial Other (a) Wholesale - municipality Wholesale - other (b) Transmission Revenues from Contracts with Customers 2024 PA Regulated $ 1,502 $ 418 $ 47 $ 57 $ — $ — $ 818 $ 2,842 RI Regulated (c) 1,150 593 91 10 — — 176 2,020 KY Regulated 1,510 1,028 635 323 23 63 — 3,582 Total PPL $ 4,162 $ 2,039 $ 773 $ 390 $ 23 $ 63 $ 994 $ 8,444 2023 PA Regulated $ 1,649 $ 444 $ 55 $ 54 $ — $ — $ 796 $ 2,998 RI Regulated 640 228 20 793 — — 170 1,851 KY Regulated 1,458 1,001 637 272 22 50 — 3,440 Corp and Other — — — 1 — — — 1 Total PPL $ 3,747 $ 1,673 $ 712 $ 1,120 $ 22 $ 50 $ 966 $ 8,290 PPL Electric 2025 $ 1,656 $ 448 $ 56 $ 54 $ — $ — $ 903 $ 3,117 2024 $ 1,502 $ 418 $ 47 $ 57 $ — $ — $ 818 $ 2,842 2023 $ 1,649 $ 444 $ 55 $ 54 $ — $ — $ 796 $ 2,998 LG&E 2025 $ 809 $ 540 $ 187 $ 139 $ — $ 67 $ — $ 1,742 2024 $ 754 $ 518 $ 188 $ 147 $ — $ 50 $ — $ 1,657 2023 $ 751 $ 517 $ 189 $ 104 $ — $ 47 $ — $ 1,608 KU 2025 $ 807 $ 523 $ 440 $ 169 $ 25 $ 96 $ — $ 2,060 2024 $ 756 $ 510 $ 447 $ 176 $ 23 $ 64 $ — $ 1,976 2023 $ 707 $ 484 $ 448 $ 168 $ 22 $ 46 $ — $ 1,875 (a) Primarily includes revenues from pole attachments, street lighting, other public authorities and other non-core businesses. For the years ended December 31, 2023, the Rhode Island Regulated segment primarily includes open access tariff revenues, which are calculated on combined customer classes. (b) Includes wholesale power and transmission revenues. LG&E and KU amounts include intercompany power sales and transmission revenues, which are eliminated upon consolidation at PPL. (c) PPL's transition services agreement associated with the RIE acquisition ended in the third quarter of 2024. In conjunction with the completion of the agreement, PPL disaggregated the 2024 revenues of the Rhode Island Regulated segment in a manner consistent with that of its other segments. This resulted in certain customer revenues for the Rhode Island Regulated segment, which were previously presented in the "Other" category, being presented in the "Residential", "Commercial" or "Industrial" customer classes beginning on January 1, 2024. Applying the previous methodology to 2025 revenues would result in $ 534 million of Residential, $ 409 million of Commercial and $ 83 million of Industrial for the Rhode Island Regulated segment being presented as "Other" for the year ended December 31, 2025. Applying the previous methodology to 2024 revenues would result in $ 469 million of Residential, $ 372 million of Commercial and $ 88 million of Industrial for the Rhode Island Regulated segment being presented as "Other" for the year ended December 31, 2024. As discussed in Note 2, PPL segments its business by geographic location. Revenues from external customers for each segment/geographic location are reconciled to revenues from contracts with customers in the footnotes to the tables above. PPL Electric's revenues from contracts with customers are further disaggregated by distribution and transmission as indicated in the above tables. Contract receivables from customers are primarily included in "Accounts receivable - Customer" and "Unbilled revenues" on the Balance Sheets. 116 Table of Contents The following table shows the accounts receivable and unbilled revenues balances that were impaired for the year ended December 31: 2025 2024 2023 PPL (a) $ 101 $ 103 $ 79 PPL Electric (a) 32 52 47 LG&E 4 4 4 KU 5 4 2 (a) 2024 and 2023 includes amounts impaired related to PPL Electric's billing issues. See Note 7 in PPL's 2024 Form 10-K for additional information. Contract liabilities result from recording contractual billings in advance for customer attachments to the Registrants' infrastructure and payments received in excess of revenues earned to date. Advanced billings for customer attachments are recognized as revenue ratably over the billing period. Payments received in excess of revenues earned to date are recognized as revenue as services are delivered in subsequent periods. The Registrants' contract liabilities are not material at December 31, 2025, 2024 and 2023. 4. Preferred Securities (PPL) PPL is authorized to issue up to 10 million shares of preferred stock. No PPL preferred stock was issued or outstanding in 2025, 2024 or 2023. (PPL Electric) PPL Electric is authorized to issue up to 20,629,936 shares of preferred stock. No PPL Electric preferred stock was issued or outstanding in 2025, 2024 or 2023. (LG&E) LG&E is authorized to issue up to 1,720,000 shares of preferred stock at a $ 25 par value and 6,750,000 shares of preferred stock without par value. LG&E had no preferred stock issued or outstanding in 2025, 2024 or 2023. (KU) KU is authorized to issue up to 5,300,000 shares of preferred stock and 2,000,000 shares of preference stock. KU had no preferred or preference stock issued or outstanding in 2025, 2024 or 2023. 5. Earnings Per Share (PPL) Basic EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding during the applicable period. Diluted EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding, increased by the number of incremental shares that would be outstanding if potentially dilutive share-based payment awards were converted to common shares as calculated using the Two-Class Method or Treasury Stock Method. The If-Converted Method is applied to the Exchangeable Senior Notes due 2028 and 2030 (Exchangeable Notes) issued in February 2023 and November 2025. Incremental non-participating securities that have a dilutive impact are detailed in the table below. In 2025, these securities include forward sales of PPL common stock issued through an ATM Program and the number of shares needed to settle the conversion premium on the Exchangeable Notes. The forward sale agreements are dilutive under the Treasury Stock Method to the extent the average stock price of PPL's common shares exceeds the forward sale price prescribed in the agreements. See Note 8 for additional information on the ATM Program and the Exchangeable Senior Notes due 2030 and Note 8 in PPL's Annual Report on Form 10-K for the year ended December 31, 2023 for additional information on the Exchangeable Notes due 2028. 117 Table of Contents Reconciliations of the amounts of income and shares of PPL common stock (in thousands) for the periods ended December 31, used in the EPS calculation are: 2025 2024 2023 Income (Numerator) Net income $ 1,181 $ 888 $ 740 Less amounts allocated to participating securities 2 2 1 Net income available to PPL common shareowners - Basic and Diluted $ 1,179 $ 886 $ 739 Shares of Common Stock (Denominator) Weighted-average shares - Basic EPS 739,406 737,756 737,036 Add incremental non-participating securities: Dilutive share-based payment awards (a) 2,724 2,097 1,130 Forward sale agreements 170 — — Exchangeable Notes 1,048 — — Weighted-average shares - Diluted EPS 743,348 739,853 738,166 Basic EPS Net Income available to PPL common shareowners $ 1.60 $ 1.20 $ 1.00 Diluted EPS Net Income available to PPL common shareowners $ 1.59 $ 1.20 $ 1.00 (a) The Treasury Stock Method was applied to non-participating share-based payment awards. For the years ended December 31, PPL issued common stock related to the DRIP as follows (in thousands): 2025 2024 2023 DRIP 762 202 — For the years ended December 31, the following shares (in thousands) were excluded from the computations of diluted EPS because the effect would have been antidilutive: 2025 2024 2023 Stock-based compensation awards 106 — 243 Forward sale agreements 10,040 — — 6. Income and Other Taxes (PPL) Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes and the tax effects of net operating loss and tax credit carryforwards. The provision for PPL's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles of the applicable jurisdiction. See Notes 1 and 7 for additional information. Net deferred tax assets have been recognized based on management's estimates of future taxable income. 118 Table of Contents Significant components of PPL's deferred income tax assets and liabilities were as follows: 2025 2024 Deferred Tax Assets Deferred investment tax credits $ 27 $ 28 Regulatory liabilities 186 133 Income taxes due to customers 397 418 Accrued pension and postretirement costs 99 112 State loss carryforwards 181 224 Federal and state tax credit carryforwards 35 24 Internal Revenue Code Section 197 intangibles 67 72 Contributions in aid of construction 206 163 Bad debt 34 37 Other 130 114 Valuation allowances ( 184 ) ( 224 ) Total deferred tax assets 1,178 1,101 Deferred Tax Liabilities Plant - net 4,105 3,898 Regulatory assets 432 432 Prepayments 49 39 Goodwill 52 38 Other 37 38 Total deferred tax liabilities 4,675 4,445 Net deferred tax liability $ 3,497 $ 3,344 State deferred taxes are determined by entity and by jurisdiction. As a result, $ 9 million and $ 12 million of net deferred tax assets are shown as "Other noncurrent assets" on the Balance Sheets for 2025 and 2024. At December 31, 2025, PPL had the following loss and tax credit carryforwards, related deferred tax assets and valuation allowances recorded against the deferred tax assets: Gross Deferred Tax Asset Valuation Allowance Expiration Loss and other carryforwards State net operating losses $ 4,281 $ 181 $ ( 181 ) 2026-2045 State charitable contributions 1 — — 2026-2030 Foreign capital loss 8 2 ( 2 ) Indefinite Gross Deferred Tax Asset Valuation Allowance Expiration Credit carryforwards Federal investment tax credit $ 26 $ — 2045 Federal - other 2 — 2045 State recycling credit 6 — 2028 State - other 2 — Indefinite Valuation allowances have been established for the amount that, more likely than not, will not be realized. The changes in deferred tax valuation allowances were as follows: Additions Balance at Beginning of Period Charged to Income Charged to Other Accounts Deductions Balance at End of Period 2025 $ 224 $ 4 $ — $ 44 (a) $ 184 2024 245 3 1 25 (b) 224 2023 213 54 (c) — 22 (d) 245 (a) In 2025, PPL recorded a $ 41 million decrease in a valuation allowance on a 2005 state net operating loss carryforward that expired in 2025. (b) In 2024, PPL recorded a $ 23 million decrease in a valuation allowance on a 2004 state net operating loss carryforward that expired in 2024. 119 Table of Contents (c) PPL has a Pennsylvania net operating loss fully offset by a valuation allowance. In 2023, PPL adjusted the net operating loss and related valuation allowance to be recorded at the current estimate of the applicable rate at which each portion of the net operating loss that will expire and be written off as the rate is reduced annually by one half a percentage point until the rate reaches to 4.99% in 2031. (d) In 2023, PPL recorded a $ 22 million decrease in a valuation allowance on a 2003 state net operating loss carryforward that expired in 2023. Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were as follows: 2025 2024 2023 Income Tax Expense (Benefit) Current - Federal (a) $ 46 $ 23 $ ( 175 ) Current - State 53 9 37 Total Current Expense (Benefit) 99 32 ( 138 ) Deferred - Federal (a) 172 137 286 Deferred - State 27 64 48 Total Deferred Expense (Benefit), excluding operating loss carryforwards 199 201 334 Amortization of investment tax credit ( 3 ) ( 3 ) ( 3 ) Tax expense (benefit) of operating loss carryforwards Deferred - Federal 1 1 3 Deferred - State ( 5 ) ( 3 ) ( 12 ) Total Tax Expense (Benefit) of Operating Loss Carryforwards ( 4 ) ( 2 ) ( 9 ) Total income tax expense (benefit) $ 291 $ 228 $ 184 Total income tax expense (benefit) - Federal $ 216 $ 158 $ 111 Total income tax expense (benefit) - State 75 70 73 Total income tax expense (benefit) $ 291 $ 228 $ 184 (a) In 2025, 2024, and 2023, PPL purchased approximately $ 153 million, $ 27 million and $ 300 million of renewable tax credits and recorded a current tax benefit and a deferred tax expense for utilization of approximately $ 138 million, $ 61 million and $ 250 million of the credits, respectively. In the table above, the following income tax expense (benefit) are excluded from income taxes: 2025 2024 2023 Other comprehensive income $ ( 6 ) $ ( 8 ) $ ( 14 ) Valuation allowance recorded to other comprehensive income — — ( 1 ) Total $ ( 6 ) $ ( 8 ) $ ( 15 ) 2025 2024 2023 Amount Percent Amount Percent Amount Percent Reconciliation of Income Tax Expense (Benefit) Federal income tax on Income Before Income Taxes at statutory tax rate $ 309 21.0 % $ 234 21.0 % $ 194 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (a) 75 5.0 % 67 6.1 % 69 7.5 % Tax credits (federal): Investment tax credits ( 17 ) ( 1.1 ) % ( 5 ) ( 0.5 ) % ( 19 ) ( 2.1 ) % Other tax credits ( 1 ) ( 0.1 ) % ( 5 ) ( 0.5 ) % ( 7 ) ( 0.7 ) % Subtotal ( 18 ) ( 1.2 ) % ( 10 ) ( 1.0 ) % ( 26 ) ( 2.8 ) % Utility rate-making tax adjustments (federal and state): Amortization of excess deferred taxes ( 51 ) ( 3.4 ) % ( 46 ) ( 4.1 ) % ( 48 ) ( 5.2 ) % AFUDC Equity ( 20 ) ( 1.3 ) % ( 10 ) ( 0.9 ) % ( 6 ) ( 0.7 ) % Flow-through rate-making (b) ( 10 ) ( 0.6 ) % ( 11 ) ( 1.0 ) % ( 4 ) ( 0.5 ) % Subtotal ( 81 ) ( 5.3 ) % ( 67 ) ( 6.0 ) % ( 58 ) ( 6.4 ) % Other 6 0.3 % 4 0.3 % 5 0.6 % Total increase (decrease) ( 18 ) ( 1.2 ) % ( 6 ) ( 0.6 ) % ( 10 ) ( 1.1 ) % Total income tax expense $ 291 19.8 % $ 228 20.4 % $ 184 19.9 % 120 Table of Contents (a) Jurisdictions that make up the majority of state income taxes, net of federal effect, are Kentucky and Pennsylvania. (b) Flow-through occurs when the regulator excludes deferred tax expense or benefit from recoverable costs when determining income tax expense. Income tax cash payments (refunds) by federal and state jurisdictions: 2025 2024 2023 Federal $ 66 (a) $ ( 149 ) (b) $ 252 (c) Pennsylvania 20 21 24 Kentucky 6 4 4 Other states 1 1 1 Total $ 93 $ ( 123 ) $ 281 (a) Includes purchase price of transferable tax credits of $ 40 million. (b) Includes refund for the carry-back of acquired transferable tax credits applied to the 2021 tax return of $ 200 million and purchase price of transferable tax credits of $ 20 million. (c) Includes refund of $ 55 million and purchase price of transferable tax credits of $ 282 million. 2025 2024 2023 Taxes, other than income State gross earnings and state gross receipts $ 214 $ 167 $ 195 Property and other 209 207 197 Total $ 423 $ 374 $ 392 (PPL Electric) The provision for PPL Electric's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the PAPUC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets. Significant components of PPL Electric's deferred income tax assets and liabilities were as follows: 2025 2024 Deferred Tax Assets Accrued pension and postretirement costs $ 29 $ 36 Contributions in aid of construction 156 120 Regulatory liabilities 57 40 Income taxes due to customers 177 184 Other 25 22 Total deferred tax assets 444 402 Deferred Tax Liabilities Electric utility plant - net 2,028 1,934 Regulatory assets 165 160 Prepayments 30 30 Other 2 4 Total deferred tax liabilities 2,225 2,128 Net deferred tax liability $ 1,781 $ 1,726 PPL Electric expects to have adequate levels of taxable income to realize its recorded deferred income tax assets. Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were as follows: 121 Table of Contents 2025 2024 2023 Income Tax Expense Current - Federal $ 136 $ 44 $ 91 Current - State 44 4 31 Total Current Expense 180 48 122 Deferred - Federal 17 86 28 Deferred - State 7 42 18 Total Deferred Expense, excluding operating loss carryforwards 24 128 46 Total income tax expense $ 204 $ 176 $ 168 Total income tax expense - Federal $ 153 $ 130 $ 119 Total income tax expense - State 51 46 49 Total income tax expense $ 204 $ 176 $ 168 2025 2024 2023 Amount Percent Amount Percent Amount Percent Reconciliation of Income Tax Expense (Benefit) Taxes at statutory tax rate $ 177 21.0 % $ 158 21.0 % $ 144 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (a) 52 6.1 % 47 6.2 % 48 7.1 % Utility rate-making tax adjustments (federal and state): Amortization of excess deferred federal income taxes ( 10 ) ( 1.2 ) % ( 10 ) ( 1.3 ) % ( 11 ) ( 1.6 ) % AFUDC Equity ( 8 ) ( 1.0 ) % ( 6 ) ( 0.7 ) % ( 4 ) ( 0.7 ) % Flow-through rate-making (b) ( 10 ) ( 1.2 ) % ( 11 ) ( 1.5 ) % ( 4 ) ( 0.7 ) % Subtotal ( 28 ) ( 3.4 ) % ( 27 ) ( 3.5 ) % ( 19 ) ( 3.0 ) % Other 3 0.5 % ( 2 ) ( 0.2 ) % ( 5 ) ( 0.6 ) % Total increase (decrease) 27 3.2 % 18 2.5 % 24 3.5 % Total income tax expense $ 204 24.2 % $ 176 23.5 % $ 168 24.5 % (a) The jurisdiction that makes up the majority of state income taxes, net of federal effect, is Pennsylvania. (b) Flow-through occurs when the regulator excludes deferred tax expense or benefit from recoverable costs when determining income tax expense. Income tax cash payments by federal and state jurisdictions: 2025 2024 2023 Federal $ 109 $ 62 $ 68 Pennsylvania 20 21 24 Total $ 129 $ 83 $ 92 2025 2024 2023 Taxes, other than income State gross receipts $ 144 $ 122 $ 136 Property and other 7 9 7 Total $ 151 $ 131 $ 143 (LG&E) The provision for LG&E's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets. Significant components of LG&E's deferred income tax assets and liabilities were as follows: 122 Table of Contents 2025 2024 Deferred Tax Assets Contributions in aid of construction $ 17 $ 18 Regulatory liabilities 18 18 Accrued pension and postretirement costs — 4 Deferred investment tax credits 7 7 Income taxes due to customers 104 110 State tax credit carryforwards 5 6 Lease liabilities 4 4 Other 9 6 Valuation allowances ( 5 ) ( 6 ) Total deferred tax assets 159 167 Deferred Tax Liabilities Plant - net 884 875 Regulatory assets 87 88 Lease right-of-use assets 4 4 Other 3 3 Total deferred tax liabilities 978 970 Net deferred tax liability $ 819 $ 803 At December 31, 2025, LG&E had $ 5 million of state credit carryforwards that expire in 2028 and a $ 5 million valuation allowance related to state credit carryforwards due to insufficient projected Kentucky taxable income. Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were: 2025 2024 2023 Income Tax Expense (Benefit) Current - Federal $ 72 $ 60 $ 70 Current - State 14 11 13 Total Current Expense (Benefit) 86 71 83 Deferred - Federal ( 10 ) 1 ( 15 ) Deferred - State 3 6 2 Total Deferred Expense (Benefit) ( 7 ) 7 ( 13 ) Amortization of investment tax credit - Federal ( 1 ) ( 1 ) ( 1 ) Total income tax expense (benefit) $ 78 $ 77 $ 69 Total income tax expense (benefit) - Federal $ 61 $ 60 $ 54 Total income tax expense (benefit) - State 17 17 15 Total income tax expense (benefit) $ 78 $ 77 $ 69 2025 2024 2023 Amount Percent Amount Percent Amount Percent Reconciliation of Income Tax Expense (Benefit) Taxes at statutory tax rate $ 81 21.0 % $ 79 21.0 % $ 70 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (a) 15 3.8 % 14 3.7 % 13 3.8 % Utility rate-making tax adjustments (federal and state): Amortization of excess deferred taxes ( 14 ) ( 3.5 ) % ( 13 ) ( 3.4 ) % ( 13 ) ( 3.9 ) % AFUDC Equity ( 4 ) ( 1.1 ) % ( 2 ) ( 0.4 ) % ( 1 ) ( 0.3 ) % Subtotal ( 18 ) ( 4.6 ) % ( 15 ) ( 3.8 ) % ( 14 ) ( 4.2 ) % Other — — % ( 1 ) ( 0.3 ) % — — % Total increase (decrease) ( 3 ) ( 0.8 ) % ( 2 ) ( 0.4 ) % ( 1 ) ( 0.4 ) % Total income tax expense $ 78 20.2 % $ 77 20.6 % $ 69 20.6 % (a) The jurisdiction that makes up the majority of state income taxes, net of federal effect, is Kentucky. 123 Table of Contents Income tax cash payments by federal and state jurisdictions: 2025 2024 2023 Federal $ 67 $ 62 $ 71 Kentucky 14 11 13 Total $ 81 $ 73 $ 84 2025 2024 2023 Taxes, other than income Property and other $ 51 $ 49 $ 48 Total $ 51 $ 49 $ 48 (KU) The provision for KU's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC, the VSCC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets. Significant components of KU's deferred income tax assets and liabilities were as follows: 2025 2024 Deferred Tax Assets Contributions in aid of construction $ 17 $ 12 Regulatory liabilities 31 29 Deferred investment tax credits 20 20 Income taxes due to customers 117 124 State tax credit carryforwards 3 4 Lease liabilities 7 6 Other 8 4 Valuation allowances ( 1 ) ( 2 ) Total deferred tax assets 202 197 Deferred Tax Liabilities Plant - net 1,085 1,053 Regulatory assets 56 55 Pension and postretirement costs 8 6 Lease right-of-use assets 7 6 Other 2 1 Total deferred tax liabilities 1,158 1,121 Net deferred tax liability $ 956 $ 924 At December 31, 2025, KU had $ 3 million of state credit carryforwards of which $ 1 million will expire in 2028 and $ 2 million that has an indefinite carryforward period. At December 31, 2025, KU had a $ 1 million valuation allowance related to state credit carryforwards due to insufficient projected Kentucky taxable income. 124 Table of Contents Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, income tax cash payments and refunds by federal and state jurisdictions, and details of "Taxes, other than income" were: 2025 2024 2023 Income Tax Expense (Benefit) Current - Federal $ 83 $ 87 $ 73 Current - State 16 17 13 Total Current Expense (Benefit) 99 104 86 Deferred - Federal ( 4 ) ( 15 ) ( 11 ) Deferred - State 6 2 4 Total Deferred Expense (Benefit) 2 ( 13 ) ( 7 ) Amortization of investment tax credit - Federal ( 2 ) ( 2 ) ( 2 ) Total income tax expense (benefit) $ 99 $ 89 $ 77 Total income tax expense (benefit) - Federal $ 77 $ 70 $ 60 Total income tax expense (benefit) - State 22 19 17 Total income tax expense (benefit) $ 99 $ 89 $ 77 2025 2024 2023 Amount Percent Amount Percent Amount Percent Reconciliation of Income Tax Expense (Benefit) Taxes at statutory tax rate $ 104 21.0 % $ 93 21.0 % $ 82 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (a) 19 3.8 % 16 3.7 % 15 3.8 % Utility rate-making tax adjustment (federal and state): Amortization of excess deferred federal and state income taxes ( 18 ) ( 3.6 ) % ( 17 ) ( 3.7 ) % ( 17 ) ( 4.3 ) % AFUDC Equity ( 5 ) ( 1.0 ) % ( 2 ) ( 0.6 ) % — — % Subtotal ( 23 ) ( 4.6 ) % ( 19 ) ( 4.3 ) % ( 17 ) ( 4.3 ) % Other ( 1 ) ( 0.3 ) % ( 1 ) ( 0.4 ) % ( 3 ) ( 0.7 ) % Total decrease ( 5 ) ( 1.1 ) % ( 4 ) ( 1.0 ) % ( 5 ) ( 1.2 ) % Total income tax expense $ 99 19.9 % $ 89 20.0 % $ 77 19.8 % (a) The jurisdiction that makes up the majority of state income taxes, net of federal effect, is Kentucky. Income tax cash payments by federal and state jurisdictions: 2025 2024 2023 Federal $ 78 $ 85 $ 65 Kentucky 15 16 12 Other 1 1 1 Total $ 94 $ 102 $ 78 2025 2024 2023 Taxes, other than income Property and other $ 51 $ 49 $ 45 Total $ 51 $ 49 $ 45 125 Table of Contents (All Registrants) Unrecognized Tax Benefits PPL or its subsidiaries file tax returns in four major tax jurisdictions. The income tax provisions for PPL Electric, LG&E and KU are calculated in accordance with an intercompany tax sharing agreement, which provides that taxable income be calculated as if each subsidiary filed a separate consolidated return. PPL Electric or its subsidiaries indirectly or directly file tax returns in three major tax jurisdictions, and LG&E and KU indirectly or directly file tax returns in two major tax jurisdictions. With few exceptions, at December 31, 2025, these jurisdictions, as well as the tax years that are no longer subject to examination, were as follows. PPL PPL Electric LG&E KU U.S. (federal) 2020 and prior 2020 and prior 2020 and prior 2020 and prior Pennsylvania (state) 2021 and prior 2021 and prior n/a n/a Kentucky (state) 2020 and prior 2020 and prior 2020 and prior 2020 and prior Other One Big Beautiful Bill Act (All Registrants) On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act. The Registrants are continuing to review the law to assess any material impacts to the financial statements. Additionally, on July 7, 2025, President Trump issued an Executive Order directing the Treasury to take action to strictly enforce the termination of clean electricity tax credits under IRC Sections 45Y and 48E for wind and solar. On August 15, 2025, the IRS issued Notice 2025-42, primarily tightening the rules regarding when a solar project is considered to have commenced construction. In addition, the One Big Beautiful Bill Act included new rules addressing Foreign Entities of Concern (FEOC). These rules are supply‑chain, foreign entity ownership and debt issuance restrictions that may limit eligibility for certain U.S. clean energy tax credits such as those provided for in IRC Sections 45Y and 48E. On February 12, 2026, the Treasury and the IRS issued Notice 2026-15, which provides interim guidance on the FEOC restrictions on certain clean electricity tax credits. Additionally, the IRS is expected to issue further guidance on the tax provisions of the One Big Beautiful Bill Act. The Registrants do not currently anticipate these rules or guidance to result in limitations on its clean energy projects and associated tax credits but will continue to monitor closely. 7. Utility Rate Regulation Regulatory Assets and Liabilities (All Registrants) PPL, PPL Electric, LG&E and KU reflect the effects of regulatory actions in the financial statements for their rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to an item will be recovered or refunded within a year of the balance sheet date. (PPL) RIE is subject to the jurisdiction of the RIPUC, the Rhode Island Division of Public Utilities and Carriers, and the FERC. RIE operates under a FERC-approved open access transmission tariff. RIE's base distribution rates are calculated based on recovery of costs as well as a return on rate base. Certain other recovery mechanisms exist to recover expenses and capital investments with a return on rate base separate from the base distribution rate case process. (PPL, LG&E and KU) LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the VSCC and the FERC. 126 Table of Contents Prior to January 1, 2026, LG&E's and KU's Kentucky base rates were calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. Effective January 1, 2026, pursuant to the KPSC rate case, Kentucky base rates are calculated based on a return on rate base (net utility plant plus certain regulatory assets and working capital less accumulated deferred income taxes and certain regulatory liabilities) and include recovery of applicable operations and maintenance expenses. (PPL and KU) KU's Virginia base rates are calculated based on recovery of costs as well as a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except for regulatory assets and liabilities related to the levelized fuel factor, accumulated deferred income taxes, pension and postretirement benefits, and AROs related to certain CCR impoundments, are excluded from the return on rate base utilized in the calculation of Virginia base rates, no return is earned on the related assets. KU's rates to municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets. (PPL and PPL Electric) PPL Electric is subject to the jurisdiction of the PAPUC and the FERC. PPL Electric's distribution base rates are calculated based on recovery of costs as well as a return on distribution rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions) and an annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets. (All Registrants) The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations at December 31: 127 Table of Contents PPL PPL Electric LG&E KU 2025 2024 2025 2024 2025 2024 2025 2024 Current Regulatory Assets: Gas supply clause $ 10 $ 3 $ — $ — $ 10 $ 3 $ — $ — Rate adjustment mechanisms 86 95 — — — — — — Renewable energy certificates 21 14 — — — — — — Storm damage expense rider 53 68 53 68 — — — — Transmission service charge 61 44 — 27 — — — — ISR deferral 6 22 — — — — — — TCJA 40 21 40 21 — — — — Other 31 53 19 17 9 5 1 1 Total current regulatory assets $ 308 $ 320 $ 112 $ 133 $ 19 $ 8 $ 1 $ 1 Noncurrent Regulatory Assets: Defined benefit plans $ 961 $ 967 $ 477 $ 473 $ 212 $ 226 $ 144 $ 149 Plant outage costs 23 30 — — 5 7 18 23 Net metering 164 147 — — — — — — Environmental cost recovery 102 96 — — — — — — Storm costs 113 113 42 22 24 20 38 29 Unamortized loss on debt 18 20 2 3 8 9 6 6 Terminated interest rate swaps 47 53 — — 28 31 19 22 Accumulated cost of removal of utility plant 184 173 184 173 — — — — AROs 263 280 — — 73 75 190 205 RAR 76 83 — — 76 83 — — Gas line inspections 24 24 — — 22 22 2 2 Advanced metering infrastructure 67 28 — — 28 14 39 14 IT system costs 18 — 18 — — — — — Other 32 46 2 2 6 4 11 8 Total noncurrent regulatory assets $ 2,092 $ 2,060 $ 725 $ 673 $ 482 $ 491 $ 467 $ 458 PPL PPL Electric LG&E KU 2025 2024 2025 2024 2025 2024 2025 2024 Current Regulatory Liabilities: Generation supply charge $ 45 $ 52 $ 45 $ 52 $ — $ — $ — $ — Transmission service charge 17 — 17 — — — — — Universal service rider 17 3 17 3 — — — — Transmission formula rate 62 1 23 — — — — — Rate adjustment mechanisms 124 71 — — — — — — Energy efficiency 26 25 — — — — — — DSM 21 17 — — 8 7 13 10 Environmental cost recovery 6 12 — — 3 6 3 6 Revenue decoupling mechanism 55 10 — — — — — — Other 3 32 1 2 2 1 — 6 Total current regulatory liabilities $ 376 $ 223 $ 103 $ 57 $ 13 $ 14 $ 16 $ 22 Noncurrent Regulatory Liabilities: Accumulated cost of removal of utility plant $ 1,043 $ 1,022 $ — $ — $ 334 $ 314 $ 415 $ 408 Net deferred taxes 1,798 1,899 708 739 415 439 467 498 Defined benefit plans 342 294 120 100 23 24 69 65 Terminated interest rate swaps 52 54 — — 26 27 26 27 Advanced metering infrastructure 30 13 — — 10 4 20 9 Other 53 53 — — 1 7 — 2 Total noncurrent regulatory liabilities $ 3,318 $ 3,335 $ 828 $ 839 $ 809 $ 815 $ 997 $ 1,009 Following is an overview of selected regulatory assets and liabilities presented in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters." 128 Table of Contents Defined Benefit Plans (All Registrants) Defined benefit plan regulatory assets and liabilities represent prior service cost and net actuarial gains and losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices and, generally, are amortized over the average remaining service lives of plan participants. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is remeasured. (PPL, LG&E and KU) As a result of previous rate case settlements and orders, the difference between pension cost calculated in accordance with LG&E's and KU's pension accounting policy and pension cost calculated using a 15 -year amortization period for actuarial gains and losses and settlements are recorded as a regulatory asset. As of December 31, 2025, the balances were $ 72 million for PPL, $ 41 million for LG&E and $ 31 million for KU. As of December 31, 2024, the balances were $ 79 million for PPL, $ 44 million for LG&E and $ 35 million for KU. (PPL) RIE is subject to a pension rate adjustment mechanism whereby the difference in amounts allowed to be recovered in base rates and the actual costs of RIE's pension and other postretirement benefit plans that are to be recovered from or passed back to customers in future periods, are also recorded as regulatory assets and liabilities. (All Registrants) Storm Costs PPL Electric, LG&E and KU have the ability to establish or request regulatory assets for expenses related to specific extraordinary storms from the PAPUC, the KPSC and the VSCC, for regulatory accounting and reporting purposes. Once such authority is granted, LG&E and KU can request recovery of those expenses in a base rate case and begin amortizing the costs when recovery starts. PPL Electric can recover qualifying expenses caused by major storm events, as defined in its retail tariff, over three years through the Storm Damage Expense Rider commencing in the application year after the storm occurred. LG&E's and KU's regulatory assets for storm costs approved for base rate recovery are being amortized through various dates ending in 2031. As provided in the Amended Settlement Agreement (ASA), RIE has the authority from the RIPUC to treat certain incremental O&M expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once all expenses for the extraordinary storm have been finalized, RIE files a final accounting of those storm expenses with the RIPUC that is subject to review by the RIPUC and the Rhode Island Division of Public Utilities and Carriers. Unamortized Loss on Debt Unamortized loss on debt represents losses on long-term debt refinanced, reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2053 for PPL Electric, through 2042 for KU, and through 2044 for LG&E. Accumulated Cost of Removal of Utility Plant RIE, LG&E and KU charge costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five -year period. 129 Table of Contents Net Deferred Taxes Regulatory liabilities associated with net deferred taxes represent the future revenue impact from the adjustment of deferred income taxes required primarily for excess deferred taxes and unamortized investment tax credits, largely a result of the TCJA. (PPL and PPL Electric) Generation Supply Charge (GSC) The GSC is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service. The recovery includes charges for generation supply, as well as administration of the acquisition process. In addition, the GSC contains a reconciliation mechanism whereby any over- or under-recovery from prior periods is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent rate filing period. Transmission Service Charge (TSC) PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PAPUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year. RIE arranges transmission service on behalf of its customers and bills the costs of those services to customers, pursuant to its Transmission Service Cost Adjustment Provision. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year. Transmission Formula Rate PPL Electric's transmission revenues are billed in accordance with a FERC-approved Open Access Transmission Tariff that utilizes a formula-based rate recovery mechanism. Under this formula, rates are put into effect on January 1st of each year based upon actual expenditures from the most recently filed FERC Form 1, forecasted capital additions, and other data based on PPL Electric's books and records. Rates are compared during the year to the estimated annual expenses and capital additions that will be filed in PPL Electric's annual FERC Form 1, filed under the FERC's Uniform System of Accounts. Under the mechanism, any difference between the revenue requirement in effect and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability, and the regulatory asset or regulatory liability is to be recovered from or returned to customers starting one year after the conclusion of the rate year. Storm Damage Expense Rider (SDER) The SDER is a reconcilable automatic adjustment clause under which PPL Electric annually will compare actual storm costs to storm costs allowed in base rates and refund or recover any differences from customers. In the 2015 rate case settlement approved by the PAPUC in November 2015, it was determined that reportable storm damage expenses to be recovered annually through base rates will be set at $ 20 million. The SDER will recover from or refund to customers the applicable expenses from reportable storms as compared to the $ 20 million recovered annually through base rates. Universal Service Rider (USR) The USR provides for recovery of costs associated with universal service programs, OnTrack and Winter Relief Assistance Program (WRAP), provided by PPL Electric to residential customers. OnTrack is a special payment program for low-income households and WRAP provides low-income customers a means to reduce electric bills through energy saving methods. The USR rate is applied to residential customers who receive distribution service. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year. 130 Table of Contents TCJA As a result of the reduced U.S federal corporate income tax rate as enacted by the TCJA, the PAPUC ruled that these tax benefits should be refunded to customers. Timing differences between the recognition of these tax benefits and the refund of the benefit to the customer creates a regulatory liability. PPL Electric's liability is being credited back to distribution customers through a temporary negative surcharge and remains in place until PPL Electric files and the PAPUC approves new base rates. The TCJA is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year. IT System Costs IT system costs represent expenditures incurred associated with implementing strategic information technology investments. As part of the ongoing rate case proceedings, PPL Electric has requested certain of these implementation costs to be treated as capital for ratemaking purposes to be recovered over the useful life of the associated IT asset. Recovery of these costs is subject to approval by the PAPUC, but PPL and PPL Electric believe recovery of these costs is probable. (PPL, LG&E and KU) AROs As discussed in Note 1, for LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal. Terminated Interest Rate Swaps Net realized gains and losses on all interest rate swaps are recovered through regulated rates. As such, any gains and losses on these derivatives are included in regulatory assets or liabilities and are primarily recognized in "Interest Expense" on the Statements of Income over the life of the associated debt. Plant Outage Costs From July 1, 2017 through June 30, 2021, plant outage costs were normalized for ratemaking purposes based on an average level of expenses. Plant outage expenses that were greater or less than the average would be collected from or returned to customers, through future base rates. Effective July 1, 2021, under-recovered plant outage costs are being amortized through 2029 for LG&E and KU. Advanced Metering Infrastructure (AMI) In 2021 base rate case orders from the KPSC, LG&E and KU received approval to record regulatory assets comprised of the operating expenses associated with implementation of the AMI project, the incremental difference between AFUDC accrued at LG&E's and KU's weighted average cost of capital and that calculated using the methodology approved by the FERC, and the remaining net book value of the retired legacy meters replaced by AMI. Additionally, LG&E and KU received approval to record regulatory liabilities comprised of meter reading and field service expense savings since their previous rate case and the cost of capital impact for legacy meters replaced and retired during the AMI implementation. Recovery and/or return of these costs was approved effective January 1, 2026 in the base rate case proceedings. (PPL) Energy Efficiency The energy efficiency mechanism is designed to collect the estimated costs of RIE's energy efficiency plan for the upcoming calendar year. Any differences between revenue billed to customers through RIE's energy efficiency charge and the costs of RIE's energy efficiency programs, as approved by the RIPUC, are recorded as regulatory assets or regulatory liabilities. The final annual over or under collection is reconciled in the next year's energy efficiency plan filing, as part of the reconciliation factor calculation. RIE may file to change the energy efficiency plan charge at any time should significant over-or under-recoveries occur. 131 Table of Contents Net Metering The net metering mechanism provides for recovery of costs associated with customer-installed on-site generation facilities, including the costs of renewable generation credits. Net metering is reconcilable annually, and any over- or under-recovery from customers will be refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year. Rate Adjustment Mechanisms In addition to commodity costs, RIE is subject to a number of additional rate adjustment mechanisms whereby a regulatory asset or regulatory liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the RIPUC. The rate adjustment mechanisms are reconcilable, and any over- or under-recovery from customers are to be refunded or recovered annually in the subsequent year. Renewable Energy Certificates The Renewable Energy Certificates regulatory asset represents deferred costs associated with RIE's compliance obligation with the Rhode Island Renewable Portfolio Standard (RPS). The RPS is legislation established to foster the development of new renewable energy sources. The regulatory asset will be recovered over the next year. Environmental Cost Recovery (PPL, LG&E and KU) Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Clean Air Act and those federal, state or local environmental requirements, which apply to coal combustion wastes and by-products from coal-fired electricity generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the opportunity to roll-in ECR amounts to base rates each two-year period. The KPSC has authorized a return on equity of 9.35 % for existing approved ECR projects. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is typically recovered or refunded within 12 months. (PPL) RIE's rate plans provide for specific rate allowances for RIE's share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated, with variances deferred for future recovery from, or return to, customers. RIE believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. The regulatory asset represents the excess of amounts incurred for RIE's actual site investigation and remediation costs versus amounts received in rates. (PPL and LG&E) Gas Supply Clause LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs and customer usage from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause previously included a separate natural gas procurement incentive mechanism, which allowed LG&E's rates to be adjusted annually to share savings between the actual cost of gas purchases and market indices, with the shareholders and the customers during each performance-based rate year (12 months ending October 31). The operation of this incentive mechanism expired on October 31, 2024, but savings achieved through October 31, 2024 will be included in LG&E's rates through October 31, 2026. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are typically recovered or refunded within 18 months. 132 Table of Contents RAR The RAR rider was established by KPSC orders in 2021 to provide recovery of and return on the retirement costs of certain electric generating units, including the remaining net book value of each unit, materials and supplies that cannot be used at other plants and any associated removal costs, upon their retirement over a ten-year period following retirement. Costs included as of December 31, 2025 represent the remaining retirement costs of Mill Creek Unit 1 to be recovered through April 2034. Regulatory Matters Rhode Island Activities (PPL) Rate Case Proceeding On November 26, 2025, RIE filed a request with the RIPUC for an increase in electric and natural gas base distribution rates, and approval of certain regulatory and accounting treatments. In its application, RIE seeks to implement a two-year rate plan. In the first year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect additional operating revenue of approximately $ 181 million ($ 66 million or 18.2 % in electricity revenues and $ 115 million or 36.4 % in gas revenues). In the second year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect the proposed base distribution rate increases for electric and gas in the first year of the rate plan and additional operating revenues of approximately $ 49 million ($ 17 million or 3.6 % in electricity revenues and $ 32 million or 7.4 % in gas revenues). The application is based on a historical test year of September 1, 2024 through August 31, 2025 and requested an authorized ROE of 10.75 %. Subject to RIPUC approval, new rates are expected to become effective on September 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the RIPUC is anticipated during the third quarter of 2026. PPL cannot predict the outcome of the proceeding. Hold Harmless Implementation Agreement As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers required PPL to hold harmless Rhode Island customers from the impact of future rate increases resulting from changes in Accumulated Deferred Income Taxes as a result of the Acquisition (the Hold Harmless Commitment). On June 13, 2025, an agreement was entered into by and among RIE, PPL, PPL Rhode Island Holdings and the Rhode Island Division of Public Utilities and Carriers Advocacy Section (the Hold Harmless Implementation Agreement) to satisfy the Hold Harmless Commitment by providing approximately $ 155 million in miscellaneous bill credits issued to customers, with approximately $ 74 million to be issued in the first quarter of 2026 and approximately $ 81 million to be issued in the first quarter of 2027. The bill credits would be recorded as a reduction to revenue in the periods in which the credits are applied to customers' bills. On September 10, 2025, the Rhode Island Division of Public Utilities and Carriers issued an order confirming that RIE's provision of proposed miscellaneous bill credits as set forth in the Hold Harmless Implementation Agreement would satisfy the Hold Harmless Commitment. Also on September 10, 2025, the RIPUC opened a docket to evaluate the miscellaneous bill credit proposal set forth in the Hold Harmless Implementation Agreement, including the underlying rate accounting, and required RIE to file a tariff advice with the RIPUC, which RIE filed on October 2, 2025. After responding to discovery in that proceeding and before the evidentiary hearing was held or convened, RIE filed a notice of withdrawal of its tariff advice filing noting that it would hold in abeyance a comprehensive satisfaction of the Hold Harmless Commitment at this time. As a result of RIE's filing the notice of withdrawal, the Commission cancelled the evidentiary hearing. The docket remains open, but there has been no further activity since RIE's withdrawal of the tariff advice and the RIPUC's cancellation of the evidentiary hearing. PPL cannot predict whether there will be any further proceedings on the docket or the outcome of any further proceedings that may occur. 133 Table of Contents Winter Bill Volatility Docket At an Open Meeting on November 24, 2025, the RIPUC approved several measures to help mitigate winter bill increases for electric customers. First, the RIPUC approved miscellaneous bill credits for all residential electric customers of $ 23.54 per month for January, February, and March 2026. Second, the RIPUC paused the Storm Fund Replenishment Factor for usage on and after January 1, 2026, subject to further review through the 2026 Annual Retail Rate Filing. Third, the RIPUC paused the electric Energy Efficiency Charge for usage beginning January 1, 2026 through March 31, 2026. To offset the costs of the miscellaneous bill credits, the RIPUC directed RIE to apply the December 31, 2025 electric Energy Efficiency fund balance, net of any earned incentives, and directed RIE to transfer $ 11 million from the storm fund balance. The RIPUC approved future cost recovery for RIE of any unfunded balance of the miscellaneous bill credits through future identified offsets and/or a reconciling recovery mechanism to be determined in conjunction with the 2026 electric retail rate filing to allow recovery by December 31, 2026. Any remaining unfunded balance shall accrue at RIE's weighted average cost of capital. FY 2026 Gas ISR Plan On March 28, 2025, the RIPUC approved the FY 2026 Gas ISR Plan of $ 165 million, of which $ 147 million is for capital investment spend and $ 18 million is spend for paving costs as operation and maintenance (O&M), plus a potential additional $ 15 million is available if certain regulations are implemented by the PHMSA. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025. FY 2027 Gas ISR Plan On December 22, 2025, RIE filed its FY 2027 Gas ISR Plan with the RIPUC with a budget of $ 184 million that primarily included $ 166 million of capital investment spend and $ 17 million for spending on curb-to-curb paving. A decision from the RIPUC on the Plan is expected by March 31, 2026. RIE cannot predict the outcome of this matter. FY 2026 Electric ISR Plan On March 28, 2025, the RIPUC approved a FY 2026 Electric ISR Plan of $ 219 million for capital investment spend (including $ 88 million for Advanced Metering Functionality), $ 14 million for vegetation operations and maintenance spend and $ 1 million for Other O&M spend. On March 31, 2025, the RIPUC approved RIE's compliance filing for rates effective April 1, 2025. FY 2027 Electric ISR Plan On December 22, 2025, RIE filed its FY 2027 Electric ISR Plan with the RIPUC with a budget that primarily included $ 154 million of capital investment spend (including $ 18 million for Advanced Metering Functionality) and $ 13 million of vegetation operation and maintenance spend. A decision from the RIPUC is expected by March 31, 2026. RIE cannot predict the outcome of this matter. Kentucky Activities (PPL, LG&E and KU) Rate Case Proceedings On May 30, 2025, LG&E and KU filed requests with the KPSC for an increase in annual electricity and gas revenues of approximately $ 391 million ($ 105 million and $ 226 million in electricity revenues at LG&E and KU and $ 60 million in gas revenues at LG&E) and approval of certain regulatory and accounting treatments. The revenue increases would be an increase of 8.3 % and 11.5 % in electricity revenues at LG&E and KU, and an increase of 14.0 % in gas revenues at LG&E. The applications were based on a forecasted test year of January 1, 2026 through December 31, 2026 and requested an authorized ROE of 10.95 %. New interim rates became effective on January 1, 2026, subject to refund pursuant to the KPSC's final order. Certain counterparties have intervened in the proceedings. On October 20, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation (the agreement) regarding a proposed resolution of issues with a majority of the intervenors in the proceedings. Under the agreement, the parties proposed that the KPSC should issue orders granting a revised increase in annual electricity and gas revenues of approximately $ 235 million ($ 58 million and $ 132 million in electricity revenues at LG&E and KU and $ 45 million in gas revenues at LG&E.) The agreement proposed a revised authorized ROE of 9.90 %. 134 Table of Contents The agreement proposed a "stay out" commitment from LG&E and KU to refrain from effective base rate increases before August 1, 2028, subject to certain exceptions. In connection with the stay out period, the agreement also proposed the establishment of two new rate adjustment clause mechanisms, a Generation Cost Recovery Adjustment Clause (GCR) and a Sharing Mechanism Adjustment Clause (SM). The proposed GCR mechanism would provide LG&E and KU recovery of and return on investment of covered costs (excluding fuel amounts, which LG&E and KU can recover via an existing rate mechanism) of relevant new generation and energy storage assets authorized in the 2022 and 2025 CPCN proceedings (excluding the Mill Creek Unit 6 NGCC, see "2025 CPCN" for more information regarding the Mill Creek Unit 6 NGCC) as they are placed in service. The proposed SM mechanism would address any base rate revenue deficiency or surplus during the final thirteen months of the stay out period, July 2027 through July 2028, below or above a suggested ROE band of 9.40 % to 10.15 %. Any such base rate revenue deficiency or surplus would be collected from or returned to customers over a thirteen-month billing period beginning November 2028. Following issuance of the 2025 CPCN Order, LG&E and KU filed supplemental testimony with the KPSC in the rate case proceedings seeking recovery of the Mill Creek Unit 2 stay open costs through a proposed additional rate adjustment clause mechanism. The agreement further proposed that LG&E and KU use regulatory deferral accounting for actual expenses above or below base rate levels for certain expenses including: pension and post-retirement benefits, storm restoration, vegetation management, transmission waivers and credits, and gas line or well activities, with recovery of such deferred asset or liability amounts to be addressed in future rate cases. On February 16, 2026, the KPSC issued orders approving portions of the October 2025 stipulation and recommendation, with modifications. The KPSC orders provide for increases in annual electricity and gas revenues of $ 233 million ($ 59 million and $ 128 million in electricity revenues at LG&E and KU and $ 46 million in gas revenues at LG&E.) The orders include authorized returns on equity of 9.775 % for base rate purposes and 9.675 % for capital rate adjustment mechanisms. The KPSC orders approve LG&E's and KU's requests for establishment of certain new rate adjustment mechanisms or tariffs, with modifications: • a temporary Pilot Generation Recovery Adjustment Clause (PGR) to provide recovery of and return on investment of applicable costs of certain new generation and storage assets being built or anticipated to be built by LG&E and KU as authorized in the 2022 CPCN proceeding; • the inclusion in the PGR of recovery of and return on investment of certain costs associated with a potential extension of the operating life of LG&E's Mill Creek Unit 2 beyond its original 2027 retirement date; and • an Extremely High Load Factor Tariff for future applicable customers, such as data centers, which includes requirements such as long-term contracts, minimum revenue payments and collateral security structures that help protect the interests of LG&E, KU and of other ratepayers. The PGR mechanism is similar to the GCR proposed in the stipulation, but restructured by the KPSC to be a pilot adjustment mechanism with a term until the earlier of ten months following the submission of LG&E's and KU's next base rate proceeding or the effective date of new rates in such proceeding, with the expectation that the mechanism would be reviewed in such proceeding. The pilot mechanism will apply to the planned Mill Creek Unit 5, Brown Battery Energy Storage System, Mercer County Solar and Marion County Solar generation-related projects. The KPSC also included Mill Creek Unit 2's potential stay-open costs in the PGR in lieu of approving the stipulation's request for a stand-alone adjustment mechanism for such costs. Finally, the KPSC excluded from coverage under the PGR costs related to Mill Creek Unit 6 and Brown Unit 12 planned new generation assets due to their anticipated in-service dates falling outside of the estimated pilot mechanism's duration, but without prejudice to LG&E and KU seeking recovery of such costs in future proceedings. The KPSC orders also approved, approved with modifications, or denied in some cases, other requested accounting and rate matters relating to regulatory assets or liabilities, depreciation rates, and other areas. The rate changes have a retroactive effective date as of January 1, 2026. Consistent with authorized rate case procedures, LG&E and KU will refund to customers amounts billed in excess of the final approved rates within sixty days. 135 Table of Contents The KPSC orders did not approve the SM adjustment clause that had been requested in the stipulation and made no modifications to the stay out offer by LG&E and KU to refrain from effective base rate increases prior to August 2028. LG&E and KU and all intervenors have rights to request rehearing or appeal of the orders of the KPSC and because the KPSC orders modified or denied terms of the proposed stipulation, LG&E and KU and all stipulating parties have the right to withdraw from the stipulation. LG&E and KU continue to evaluate the details contained in the orders and related matters as they consider next steps. PPL, LG&E and KU cannot predict the outcome of this matter. 2025 CPCN On February 28, 2025, LG&E and KU filed an application with the KPSC regarding certain future plans for new generation and generation-related construction matters. The proposals included in the application were intended to serve anticipated load growth, including from potential data center demand in LG&E's or KU's service territory. The proposals did not include retirements of coal or other fossil-fueled plants, which would require additional KPSC approval procedures under Kentucky legislation enacted in 2023 and 2024. LG&E and KU submitted a joint application to the KPSC for approval of certain certificates of public convenience and necessity, site compatibility certificates, and accounting treatment, where applicable, relating to a number of generation-related plans or projects that generally are expected to become operational or established within the next six years. The aggregate projected capital expenditures associated with these proposals were expected to be $ 3.7 billion. The application included proposals to build: • a 645 MW NGCC generation unit at KU's E.W. Brown station (Brown Unit 12), • a 645 MW NGCC generation unit at LG&E's Mill Creek station (Mill Creek Unit 6), • a four-hour 400 MW ( 1600 MWh total) battery energy storage system (BESS) at LG&E's Cane Run station, and • a selective catalytic reduction (SCR) environmental facility at KU's Ghent station Unit 2 (Ghent Unit 2). The new NGCC units are anticipated to be wholly owned by LG&E and the BESS unit jointly owned by LG&E ( 32 %) and KU ( 68 %), with actual project costs allocated consistent with LG&E's and KU's ultimate ownership shares and existing shared dispatch, cost allocation, tariff or other frameworks. The proposed Mill Creek Unit 6 NGCC is in addition to a new NGCC unit currently under construction at that location (Mill Creek Unit 5). The filing also noted projected in service dates for the projects, including the Brown Unit 12 NGCC in 2030, the Mill Creek Unit 6 NGCC in 2031, the Cane Run BESS in 2028 and the Ghent Unit 2 SCR in 2028. On July 29, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation regarding a proposed resolution of issues with several of the intervenors in the CPCN proceeding (stipulation). The stipulation recommended to the KPSC the approval of the large majority of LG&E's and KU's requested generation-related projects and associated accounting matters, subject to certain changes. Under the stipulation, the parties agreed the KPSC should issue an order granting a CPCN for the proposed: (a) Brown Unit 12 NGCC; (b) Mill Creek Unit 6 NGCC; and (c) Ghent Unit 2 SCR. In addition, the proposal to build the $ 775 million Cane Run BESS would be withdrawn without prejudice, the relevant costs regarding the proposed $ 1.4 billion Mill Creek Unit 6 NGCC would be recovered through a new rate adjustment clause mechanism, the retirement date for the existing Mill Creek Unit 2 coal unit would be extended from 2027 to the operational date of the proposed Mill Creek Unit 6 NGCC or afterwards, subject to relevant future economic analysis, regulatory or environmental authorizations, and the relevant costs to continue to operate the Mill Creek Unit 2 coal unit would be recovered through a new rate adjustment clause mechanism. The stipulation also contained provisions relating to regulatory asset accounting, proposed data center tariffs, future renewable power requests-for-proposals and other matters. LG&E and KU would retain the right to seek approval of the potentially withdrawn Cane Run BESS or similar substitute project in future regulatory proceedings. On October 28, 2025, the KPSC issued an order approving much of LG&E's and KU's July 2025 stipulation, with certain modifications. The order granted the requested CPCNs and site-related permits to construct the proposed Brown Unit 12 NGCC, Mill Creek Unit 6 NGCC, and Ghent Unit 2 SCR. The order authorized inclusion of relevant costs of the Ghent Unit 2 SCR in KU's existing environmental cost recovery rate mechanism. The order established a separate monitoring case to receive and consider information during the construction of Mill Creek Unit 6 NGCC. 136 Table of Contents The order approved requests regarding regulatory asset deferral accounting treatment for certain AFUDC related amounts and noted the KPSC's expectation that the stipulating parties would follow through with their commitments regarding tariffs and power supply contracts related to potential future data center or high load customers in LG&E's and KU's pending rate proceedings. The order also approved other elements of the stipulation or the originally-filed application, with minor modifications. The KPSC decided not to approve LG&E's and KU's proposed new rate adjustment cost recovery mechanisms for certain costs associated with Mill Creek Unit 6 NGCC and costs associated with operating the Mill Creek Unit 2 coal plant beyond its original retirement date in 2027. However, the denials were without prejudice to resubmission and the KPSC encouraged the parties to provide additional evidence on such matters in separate proceedings. LG&E and KU provided such evidence addressing recovery of the Mill Creek Unit 2 stay open costs in their pending rate case proceedings. Recovery of Mill Creek Unit 6 costs will be addressed in a future proceeding. The KPSC declined to rule on the matter related to the retirement date of Mill Creek Unit 2 coal plant. The KPSC indicated that a request for a new retirement approval proceeding may be required should LG&E elect to operate Mill Creek Unit 2 beyond its existing approved retirement date and seek to later retire the unit. In light of the conditional withdrawal in the stipulation, the order did not include a CPCN for the Cane Run BESS. LG&E and KU retain the right to seek approval of the Cane Run BESS project or similar substitute projects at any time in future regulatory proceedings. Kentucky January 2025 Storm In January 2025, LG&E and KU experienced snow, ice, sleet and freezing rain in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets. On January 31, 2025, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance (O&M) expenses portion of the costs incurred related to the storm. On March 19, 2025, the KPSC issued an order authorizing LG&E and KU to establish, for accounting purposes only, regulatory assets based on the jurisdictional incremental costs of extraordinary O&M expense incurred by LG&E and KU as a result of the 2025 winter storm, with recovery amounts and amortization thereof to be determined in subsequent base rate proceedings. LG&E and KU cannot predict the outcome of these matters. As of December 31, 2025, LG&E and KU had recorded regulatory assets related to the storm of $ 2 million and $ 7 million. Mill Creek Unit 1 and Unit 2 RAR Application (PPL and LG&E) In November 2023, the KPSC issued an order approving, among other items, the requested retirement of Mill Creek Units 1 and 2. On October 4, 2024, LG&E submitted an application related to the retirement of Mill Creek Unit 1, which occurred on December 31, 2024, requesting recovery of associated costs under the RAR. On February 24, 2025, the KPSC issued an order approving LG&E's cost recovery for Mill Creek Unit 1 under the RAR of $ 125 million and related amounts were included in bills beginning in May 2025. LG&E anticipates the recovery of associated costs, including the remaining net book value, for Mill Creek Unit 2 through the RAR. The remaining net book value of Mill Creek Unit 2 was approximately $ 199 million at December 31, 2025 and LG&E is continuing to depreciate using the current approved rates through its retirement date. LG&E expects to reclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period of ten years in accordance with the RAR. There can be no assurance that these costs will be recovered in the amounts or over the time periods that LG&E expects. See the "2025 CPCN" and "Rate Case Proceedings" discussions above for information regarding potential changes in the retirement date of Mill Creek Unit 2. Pennsylvania Activities (PPL and PPL Electric) Rate Case Proceeding On September 30, 2025, PPL Electric filed a request with the PAPUC for an increase in distribution base rates of approximately $ 356 million, more than $ 50 million of which is already included in customer bills through rate recovery mechanisms, and approval of certain regulatory and accounting treatments. The proposed increase in distribution base rates would increase PPL Electric's total annual revenue by approximately 8.6 %. The application is based on a fully projected future test year of July 1, 2026 through June 30, 2027 and requested an authorized ROE of 11.3 %. Subject to PAPUC approval, new rates are expected to become effective on July 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the PAPUC is anticipated during the second quarter of 2026. PPL and PPL Electric cannot predict the outcome of the proceeding. 137 Table of Contents DSIC Petition On April 26, 2024, PPL Electric filed a Petition with the PAPUC requesting that the PAPUC waive PPL Electric's DSIC cap of 5 % of billed revenues and increase the maximum allowable DSIC to 9 % for bills rendered on or after January 1, 2025. On February 28, 2025, the PAPUC issued its written order permitting PPL Electric to increase its DSIC cap from 5 % to 7.5 % for bills rendered on or after March 13, 2025 until the effective date of rates established in PPL Electric's next base rate case or the end of the PPL Electric's 2023-2027 Long-term Infrastructure Improvement Plan, whichever occurs first, at which time it will return to 5 %. Federal Matters FERC Transmission Rate Filing (PPL, LG&E and KU) In 2018, LG&E and KU applied to the FERC requesting elimination of certain on-going waivers and credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the U.S. Court of Appeals - D.C. Circuit (D.C. Circuit Court of Appeals) regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. In August 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. On May 18, 2023, the FERC issued an order on remand reversing its 2019 decision and requiring LG&E and KU to refund credits previously withheld, including under such transition mechanism. LG&E and KU filed a petition for review of the FERC's May 18, 2023 order with the D.C. Circuit Court of Appeals and provided refunds in accordance with the FERC order on December 1, 2023. The FERC issued an order on LG&E's and KU's compliance filing on November 16, 2023, and LG&E and KU filed a petition for review of this November 16, 2023 order on February 14, 2024. The FERC issued the substantive order on rehearing on March 21, 2024, reaffirming its prior decision. On August 8, 2025, the D.C. Circuit Court of Appeals issued a procedural ruling vacating the FERC's prior orders and remanded the matter back to the FERC for further proceedings. LG&E and KU cannot predict the ultimate outcome of the proceedings or any other post decision process but do not expect the annual impact to have a material effect on their operations or financial condition. LG&E and KU currently receive recovery of certain waivers and credits primarily through existing base rate levels. Recovery of Transmission Costs (PPL) NE-ISO allocates RIE's costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT). The ROE for transmission rates under the ISO-NE OATT is the subject of four complaints that are pending before the FERC. On October 16, 2014, the FERC issued an order on the first complaint, Opinion No. 531-A, resetting the base ROE applicable to transmission assets under the ISO-NE OATT from 11.14 % to 10.57 % effective as of October 16, 2014 and establishing a maximum ROE of 11.74 %. On April 14, 2017, this order was vacated and remanded by the D.C. Circuit Court of Appeals (Court of Appeals). After the remand, the FERC issued an order on October 16, 2018 applicable to all four pending cases where it proposed a new base ROE methodology that, with subsequent input and support from the New England Transmission Owners (NETO), yielded a base ROE of 10.41 %. Subsequent to the FERC's October 2018 order in the New England Transmission Owners cases, the FERC further refined its ROE methodology in another proceeding and has applied that refined methodology to transmission owners' ROEs in other jurisdictions, and the NETOs filed further information in the New England matters to distinguish their case. Those determinations in other jurisdictions have been vacated and remanded back to the FERC for further proceedings by the D.C. Circuit Court of Appeals. The proceeding and the final base rate ROE determination in the New England matters remain open, pending a final order from the FERC. PPL cannot predict the outcome of this matter, and an estimate of the impact cannot be determined. 138 Table of Contents Other Purchase of Receivables Program (PPL and PPL Electric) In accordance with RIPUC-approved and PAPUC-approved purchase of accounts receivable programs, RIE and PPL Electric purchase certain accounts receivable from alternative electricity suppliers at a discount, which reflects a provision for uncollectible accounts. The alternative electricity suppliers have no continuing involvement or interest in the purchased accounts receivable. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. During 2025, 2024 and 2023, RIE purchased $ 314 million, $ 299 million and $ 235 million of accounts receivable from alternative suppliers. During 2025, 2024 and 2023, PPL Electric purchased $ 1.6 billion, $ 1.5 billion and $ 1.5 billion of accounts receivable from alternative suppliers. 8. Financing Activities Credit Arrangements and Short-term Debt (All Registrants) The Registrants maintain credit facilities to enhance liquidity, provide credit support and provide a backstop to commercial paper programs. For reporting purposes, on a consolidated basis, the credit facilities and commercial paper programs of PPL Electric, LG&E and KU also apply to PPL. The amounts listed in the borrowed column below are recorded as "Short-term debt" on the Balance Sheets. The following credit facilities were in place at: December 31, 2025 December 31, 2024 Expiration Date Capacity Borrowed Letters of Credit and Commercial Paper Issued (a) Unused Capacity Borrowed Letters of Credit and Commercial Paper Issued (a) PPL PPL Capital Funding (b) Syndicated Credit Facility (c)(d)(e) Dec. 2029 $ 1,500 $ — $ 456 $ 1,044 $ — $ 138 Bilateral Credit Facility (c)(d) Feb. 2026 100 — — 100 — — Bilateral Credit Facility (c)(d) Feb. 2026 100 — 17 83 — 15 Total PPL Capital Funding Credit Facilities $ 1,700 $ — $ 473 $ 1,227 $ — $ 153 PPL Electric Syndicated Credit Facility (c)(d) Dec. 2029 750 — 6 744 — 1 Total PPL Electric Credit Facilities $ 750 $ — $ 6 $ 744 $ — $ 1 LG&E Syndicated Credit Facility (c)(d) Dec. 2029 600 — — 600 — 25 Total LG&E Credit Facilities $ 600 $ — $ — $ 600 $ — $ 25 KU Syndicated Credit Facility (c)(d) Dec. 2029 600 — — 600 — 140 Total KU Credit Facilities $ 600 $ — $ — $ 600 $ — $ 140 (a) Commercial paper issued reflects the undiscounted face value of the issuance. (b) PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL. (c) Each company pays customary fees under its respective facility and borrowings generally bear interest at applicable secured overnight financing rates or base rates, plus an applicable margin. 139 Table of Contents (d) The facilities contain a financial covenant requiring debt to total capitalization not to exceed 70 % for PPL Capital Funding, RIE, PPL Electric, LG&E and KU, as calculated in accordance with the facilities and other customary covenants. Additionally, subject to certain conditions, PPL Capital Funding may request that the capacity of one of its bilateral credit facilities expiring in February 2026 be increased by up to $ 30 million and that the capacity of its syndicated credit facility be increased by up to $ 400 million. PPL Electric, LG&E and KU may each request up to a $ 250 million increase in its syndicated credit facility's capacity, subject to regulatory approval of the increased capacity. Participation in any such increase is at the sole discretion of each lender. (e) Includes a $ 400 million borrowing sublimit for RIE and a $ 1.1 billion sublimit for PPL Capital Funding at December 31, 2025 and a $ 250 million borrowing sublimit for RIE and a $ 1 billion sublimit for PPL Capital Funding at December 31, 2024. At December 31, 2025, PPL Capital Funding had $ 355 million of commercial paper outstanding and RIE had $ 101 million commercial paper outstanding. At December 31, 2024, PPL Capital Funding had $ 138 million of commercial paper outstanding and RIE had no commercial paper outstanding. RIE's obligations under the facility are not guaranteed by PPL. (PPL) In January 2026, PPL Capital Funding amended its existing $ 1.50 billion syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030. (PPL and PPL Electric) In January 2026, PPL Electric amended its existing $ 750 million syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030. (PPL and LG&E) In January 2026, LG&E amended its existing $ 600 million syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030. (PPL and KU) In January 2026, KU amended its existing $ 600 million syndicated credit facility to extend the termination date of certain commitments from December 6, 2029 to December 6, 2030. (All Registrants) The Registrants maintain commercial paper programs to provide an additional financing source to fund short-term liquidity needs. Commercial paper issuances, included in "Short-term debt" on the Balance Sheets, are supported by the respective Registrant's credit facilities. The following commercial paper programs were in place at: December 31, 2025 December 31, 2024 Weighted - Average Interest Rate Capacity Commercial Paper Issuances (a) Unused Capacity Weighted - Average Interest Rate Commercial Paper Issuances (a) PPL Capital Funding (b)(c) 4.16 % $ 1,600 $ 355 $ 1,245 4.76 % $ 138 RIE (c) 4.21 % 400 101 299 — PPL Electric 750 — 750 — LG&E 600 — 600 4.72 % 25 KU 600 — 600 4.71 % 140 Total $ 3,950 $ 456 $ 3,494 $ 303 (a) Commercial paper issued reflects the undiscounted face value of the issuance. (b) PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL. (c) Issuances under the PPL Capital Funding and RIE commercial paper programs are supported by the PPL Capital Funding syndicated credit facility, which at December 31, 2025, had a total capacity of $ 1.50 billion, with a $ 400 million borrowing sublimit for RIE and a $ 1.1 billion sublimit for PPL Capital Funding. At December 31, 2024, the borrowing sublimits were $ 250 million for RIE and $ 1 billion for PPL Capital Funding. RIE's obligations under the facility are not guaranteed by PPL. The sublimits of each borrower may be decreased or increased at the borrowers' option up to a prescribed amount such that all borrowings under the syndicated credit facility cannot exceed the size of the credit facility of $ 1.50 billion. PPL Capital Funding's commercial paper program is also backed by a separate bilateral credit facility for $ 100 million. (PPL Electric, LG&E and KU) See Note 13 for a discussion of intercompany borrowings. 140 Table of Contents Long-term Debt (All Registrants) December 31, Weighted-Average Rate (d) Maturities (d) 2025 2024 PPL Senior Unsecured Notes 4.34 % 2026 - 2047 $ 4,316 $ 4,316 Senior Secured Notes/First Mortgage Bonds (a)(b)(c) 4.64 % 2026 - 2055 12,227 10,878 Exchangeable Senior Unsecured Notes 2.94 % 2028 - 2030 2,150 1,000 Junior Subordinated Notes 6.61 % 2067 480 480 Total Long-term Debt before adjustments 19,173 16,674 Long-term Debt, repurchased affiliate bonds ( 84 ) — Unamortized premium and (discount), net ( 58 ) ( 57 ) Unamortized debt issuance costs ( 137 ) ( 114 ) Total Long-term Debt 18,894 16,503 Less current portion of Long-term Debt 904 551 Total Long-term Debt, noncurrent $ 17,990 $ 15,952 PPL Electric Senior Secured Notes/First Mortgage Bonds (a)(b) 4.72 % 2027 - 2055 $ 5,799 $ 5,299 Total Long-term Debt Before Adjustments 5,799 5,299 Unamortized discount ( 45 ) ( 42 ) Unamortized debt issuance costs ( 47 ) ( 43 ) Total Long-term Debt 5,707 5,214 Less current portion of Long-term Debt — — Total Long-term Debt, noncurrent $ 5,707 $ 5,214 LG&E Senior Secured Notes/First Mortgage Bonds (a)(c) 4.52 % 2026 - 2055 $ 2,889 $ 2,489 Total Long-term Debt Before Adjustments 2,889 2,489 Unamortized discount ( 4 ) ( 4 ) Unamortized debt issuance costs ( 20 ) ( 14 ) Total Long-term Debt 2,865 2,471 Less current portion of Long-term Debt 90 300 Total Long-term Debt, noncurrent $ 2,775 $ 2,171 KU Senior Secured Notes/First Mortgage Bonds (a)(c) 4.60 % 2026 - 2055 $ 3,539 $ 3,089 Total Long-term Debt Before Adjustments 3,539 3,089 Unamortized premium 4 4 Unamortized discount ( 8 ) ( 8 ) Unamortized debt issuance costs ( 25 ) ( 19 ) Total Long-term Debt 3,510 3,066 Less current portion of Long-term Debt 164 250 Total Long-term Debt, noncurrent $ 3,346 $ 2,816 (a) Includes PPL Electric's senior secured and first mortgage bonds that are secured by the lien of PPL Electric's 2001 Mortgage Indenture, which covers substantially all of PPL Electric's tangible distribution properties and certain of its tangible transmission properties located in Pennsylvania, subject to certain exceptions and exclusions. The carrying value of PPL Electric's property, plant and equipment was approximately $ 14.6 billion and $ 13.3 billion at December 31, 2025 and 2024. 141 Table of Contents Includes LG&E's first mortgage bonds that are secured by the lien of the LG&E 2010 Mortgage Indenture which creates a lien, subject to certain exceptions and exclusions, on substantially all of LG&E's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage and distribution of natural gas. The aggregate carrying value of the property subject to the lien was $ 6.4 billion and $ 6.0 billion at December 31, 2025 and 2024. Includes KU's first mortgage bonds that are secured by the lien of the KU 2010 Mortgage Indenture which creates a lien, subject to certain exceptions and exclusions, on substantially all of KU's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity. The aggregate carrying value of the property subject to the lien was $ 8.0 billion and $ 7.5 billion at December 31, 2025 and 2024. (b) Includes PPL Electric's series of senior secured bonds that secure its obligations to make payments with respect to each series of Pollution Control Bonds that were issued by the LCIDA on behalf of PPL Electric. These senior secured bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such Pollution Control Bonds. These senior secured bonds were issued under PPL Electric's 2001 Mortgage Indenture and are secured as noted in (a) above. The tax-exempt revenue bonds are subject to mandatory redemption upon determination that the interest rate on the bonds would be included in the holders' gross income for federal tax purposes. (c) Includes LG&E's and KU's series of first mortgage bonds that were issued to the respective trustees of tax-exempt revenue bonds to secure its respective obligations to make payments with respect to each series of bonds. The first mortgage bonds were issued in the same principal amounts, contain payment and redemption provisions that correspond to and bear the same interest rate as such tax-exempt revenue bonds. These first mortgage bonds were issued under the LG&E 2010 Mortgage Indenture and the KU 2010 Mortgage Indenture and are secured as noted in (a) above. The related tax-exempt revenue bonds were issued by various governmental entities, principally counties in Kentucky, on behalf of LG&E and KU. The related revenue bond documents allow LG&E and KU to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, term rate of at least one year or, in some cases, an auction rate or a SOFR index rate. At December 31, 2025, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a term rate mode totaled $ 894 million for PPL, comprised of $ 538 million and $ 356 million for LG&E and KU. At December 31, 2025, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a variable rate mode totaled $ 66 million and $ 33 million for LG&E and KU. These variable rate tax-exempt revenue bonds are subject to tender for purchase by LG&E and KU at the option of the holder and to mandatory tender for purchase by LG&E and KU upon the occurrence of certain events. (d) The table reflects principal maturities only, based on stated maturities, sinking fund requirements, or earlier put dates, and the weighted-average rates as of December 31, 2025. The aggregate maturities of long-term debt, based on sinking fund requirements, stated maturities or earlier put dates, for the periods 2026 through 2030 and thereafter are as follows: PPL (a) PPL Electric LG&E KU 2026 $ 904 $ — $ 90 $ 164 2027 428 108 260 60 2028 1,350 — — — 2029 116 116 — — 2030 2,181 — — — Thereafter 14,110 5,575 2,539 3,315 Total $ 19,089 $ 5,799 $ 2,889 $ 3,539 (a) Reduced by $ 84 million of repurchased affiliate bonds as of December 31, 2025. See "Open Market Repurchase Program" below for additional information. Exchangeable Notes (PPL) In November 2025, PPL Capital Funding issued $ 1.15 billion of 3.000 % Exchangeable Senior Notes due 2030 (the Notes). PPL Capital Funding received proceeds of $ 1.14 billion, net of underwriting fees, which were used to repay short-term debt and for general corporate purposes. The Notes are senior unsecured obligations of PPL Capital Funding, fully and unconditionally guaranteed on a senior unsecured basis by PPL. The Notes are scheduled to mature on December 1, 2030, unless earlier exchanged, redeemed or repurchased. The Notes are exchangeable at an initial exchange rate of approximately 23.44 shares of PPL's common stock per $1,000 principal amount (equivalent to an initial exchange price of approximately $ 42.66 per share of common stock). The initial exchange rate is subject to adjustment, as provided in the indenture for anti-dilutive events and fundamental change and redemption provisions. Upon exchange of the Notes, PPL Capital Funding expects to redeem the aggregate principal amount of the Notes in cash. PPL Capital Funding will pay cash, deliver shares of common stock or a combination of cash and shares of common stock, at PPL Capital Funding's election, in respect of the remainder, if any, of its exchange obligation in excess of the aggregate principal amount of the Notes being exchanged. Prior to the close of business on the business day immediately preceding September 1, 2030, the Notes will be exchangeable at the option of the noteholders only upon the satisfaction of specified conditions and during certain periods described in the indenture pursuant to which the Notes were issued. On or after the close of business on the business day immediately preceding September 1, 2030 until the maturity date, the Notes will be exchangeable at the option of the noteholders at any time regardless of these conditions or periods. 142 Table of Contents PPL Capital Funding may not redeem the Notes prior to December 5, 2028. PPL Capital Funding may redeem for cash all or any portion of the Notes, at its option, on or after December 5, 2028, if the last reported sale price of the common stock has been at least 130% of the exchange price then in effect for at least 20 trading days (whether or not consecutive), during any 30 consecutive trading day period, at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus any accrued and unpaid interest to, but excluding, the redemption date. No sinking fund is provided for the Notes. Subject to certain conditions, holders of the Notes will have the right to require PPL Capital Funding to repurchase all or a portion of their Notes upon the occurrence of a fundamental change, as defined in the indenture pursuant to which the Notes were issued at a repurchase price of 100% of their principal amount plus any accrued and unpaid interest. In connection with certain corporate events or if PPL Capital Funding calls any Notes for redemption, PPL Capital Funding will, under certain circumstances, increase the exchange rate for noteholders who elect to exchange their Notes in connection with any such corporate event or exchange their Notes called for redemption. Open Market Repurchase Program In the fourth quarter of 2025, PPL repurchased $ 84 million of affiliate bonds that included $ 36 million of PPL Electric bonds, $ 8 million of LG&E bonds and $ 40 million of KU bonds. On a consolidated basis, PPL's repurchases have been accounted for as debt extinguishments and resulted in a pre-tax gain of $ 18 million, net of unamortized debt issuance fees and discounts, which has been recorded as a reduction of Interest Expense on PPL's Consolidated Statements of Income. Intercompany interest expense related to the repurchased bonds was immaterial for the year ended December 31, 2025. First Mortgage Bond Issuances (PPL and PPL Electric) In August 2025, PPL Electric issued $ 500 million of 5.55 % First Mortgage Bonds due 2055. PPL Electric received proceeds of $ 491 million, net of discounts and underwriting fees, to be used to repay short-term debt and for other general corporate purposes. (PPL and LG&E) In August 2025, LG&E issued $ 700 million of 5.85 % First Mortgage Bonds due 2055. LG&E received proceeds of $ 694 million, net of discounts and underwriting fees, to be used to repay short-term debt, the current portion of certain long-term debt and for other general corporate purposes. (PPL and KU) In August 2025, KU issued $ 700 million of 5.85 % First Mortgage Bonds due 2055. KU received proceeds of $ 694 million, net of discounts and underwriting fees, to be used to repay short-term debt, the current portion of certain long-term debt and for other general corporate purposes. (PPL Electric, LG&E and KU) See Note 13 for additional information related to intercompany borrowings. Legal Separateness (All Registrants) The subsidiaries of PPL are separate legal entities. PPL's subsidiaries are not liable for the debts of PPL. Accordingly, creditors of PPL may not satisfy their debts from the assets of PPL's subsidiaries absent a specific contractual undertaking by a subsidiary to pay PPL's creditors or as required by applicable law or regulation. Similarly, other than PPL's guarantee of PPL Capital Funding's obligations, PPL is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of PPL's subsidiaries may not satisfy their debts from the assets of PPL or its other subsidiaries absent a specific contractual undertaking by PPL or its other subsidiaries to pay the creditors or as required by applicable law or regulation. 143 Table of Contents Similarly, the subsidiaries of PPL Electric are each separate legal entities. These subsidiaries are not liable for the debts of PPL Electric. Accordingly, creditors of PPL Electric may not satisfy its debts from the assets of its subsidiaries absent a specific contractual undertaking by a subsidiary to pay the creditors or as required by applicable law or regulation. Similarly, PPL Electric is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of these subsidiaries may not satisfy their debts from the assets of PPL Electric (or its other subsidiaries) absent a specific contractual undertaking by PPL Electric or any such other subsidiary to pay such creditors or as required by applicable law or regulation. (PPL) Equity Securities ATM Program In February 2025, PPL entered into an equity distribution agreement, pursuant to which PPL may sell, from time to time, up to an aggregate of $ 2 billion of its common stock through an ATM Program, which may utilize an optional forward sales component. Each forward contract under the agreement must be settled within 24 months. The compensation paid to the selling agents by PPL may be up to 2 % of the gross offering proceeds of the shares. As of December 31, 2025, PPL had entered into forward contracts to sell approximately 38.7 million shares of its common stock at a blended initial forward price of approximately $ 35.62 per share. The forward sale price may be adjusted based on changes in daily interest rates, for certain stock loan fees as determined by a third-party agent, and will be subject to predetermined reductions based on expected dividends. Each outstanding forward contract must be settled on or before dates ranging from December 30, 2025 to August 11, 2027. PPL may elect, at its discretion, to physically settle, net share settle or net cash settle the forward contracts. On December 29, 2025, PPL settled forward sale contracts with physical delivery of approximately 11.3 million shares of common stock for proceeds of approximately $ 394 million, net of issuance fees. At December 31, 2025, PPL could have settled the remaining forward sale contracts with physical delivery of approximately 27.4 million shares of common stock for proceeds of approximately $ 981 million. The forward contracts under the ATM program are classified as equity transactions. Distributions and Related Restrictions In November 2025, PPL declared its quarterly common stock dividend, payable January 2, 2026, at 27.25 cents per share (equivalent to $ 1.09 per annum). On February 20, 2026, PPL announced a quarterly common stock dividend of 28.50 cents per share, payable April 1, 2026, to shareowners of record as of March 10, 2026. Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other factors. Neither PPL Capital Funding nor PPL may declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067. At December 31, 2025, no interest payments were deferred. 9. Acquisitions, Development and Divestitures (PPL) Acquisitions Acquisition of Narragansett Electric On May 25, 2022, PPL Rhode Island Holdings acquired 100% of the outstanding shares of common stock of Narragansett Electric from National Grid U.S., a subsidiary of National Grid plc (the Acquisition). Narragansett Electric, whose service area covers substantially all of Rhode Island, is primarily engaged in the transmission and distribution of electricity and distribution of natural gas. In connection with the Acquisition, National Grid USA Service Company, Inc., National Grid U.S. and Narragansett Electric entered into a transition services agreement (TSA), pursuant to which the National Grid entities agreed to provide certain transition services to Narragansett Electric to facilitate the transition of the operation of Narragansett Electric to PPL following the Acquisition, as agreed upon in the Narragansett share purchase agreement. The TSA was for an initial two-year term and was completed in the third quarter of 2024. TSA costs of $ 137 million and $ 228 million were incurred for the years ended December 31, 2024 and 2023. RIE will not seek to recover in rates any markup charged by National Grid U.S. and/or its affiliates under the TSA which were $ 10 million, and $ 7 million for the years ended December 31, 2024 and 2023. 144 Table of Contents As a condition to the Acquisition, RIE will forgo potential recovery of any and all transition costs, which includes (1) the installation of certain information technology systems; (2) modification and enhancements to physical facilities in Rhode Island; and (3) severance payments, communications and branding changes, and other transition related costs. These costs, which are being expensed as incurred, were $ 71 million, $ 307 million, and $ 262 million for the years ended December 31, 2025, 2024, and 2023. Developments (PPL, LG&E and KU) Mill Creek Unit 5 Construction In December 2022, LG&E and KU filed a CPCN with the KPSC requesting approval to construct a 645 MW net summer rating Natural Gas Combined Cycle (NGCC) combustion turbine at LG&E's Mill Creek Generating Station. In November 2023, the KPSC issued an order approving the request as well as the requested AFUDC accounting treatment for associated financing costs relating to the NGCC. The new NGCC facility will be jointly owned by LG&E ( 31 %) and KU ( 69 %). In February 2024, LG&E and KU entered into agreements to begin construction of Mill Creek Unit 5. Total project costs are estimated at approximately $ 1.0 billion, including AFUDC. Commercial operation of the facility is anticipated to begin in mid-2027. 10. Retirement and Postemployment Benefits (All Registrants) Defined Benefits Certain employees of PPL's subsidiaries are eligible for pension benefits under non-contributory defined benefit pension plans with benefits based on length of service and final average pay, as defined by the plans. Effective January 1, 2012, PPL's primary defined benefit pension plan was closed to all newly hired salaried employees. Effective July 1, 2014, PPL's primary defined benefit pension plan was closed to all newly hired bargaining unit employees. Newly hired employees are eligible to participate in the PPL Retirement Savings Plan, a 401(k) savings plan with enhanced employer contributions. The defined benefit pension plans of LKE and its subsidiaries were closed to new salaried and bargaining unit employees hired after December 31, 2005. Employees hired after December 31, 2005 receive additional company contributions above the standard matching contributions to their savings plans. The pension plans sponsored by LKE and LG&E were merged effective January 1, 2020 into the LG&E and KU Pension Plan. The merged plan is sponsored by LKE. LG&E and KU participate in this plan. The RIE defined benefit plans were closed to new salaried employees in 2012 and bargaining unit employees in 2013. Employees hired after the defined benefit plans were closed receive additional company contributions above the standard matching contributions to their savings plans. PPL and certain of its subsidiaries also provide supplemental retirement benefits to executives and other key management employees through unfunded nonqualified retirement plans. Certain employees of PPL's subsidiaries are eligible for certain health care and life insurance benefits upon retirement through contributory plans. Effective January 1, 2014, the PPL Postretirement Medical Plan was closed to all newly hired salaried employees. Effective July 1, 2014, the PPL Postretirement Medical Plan was closed to all newly hired bargaining unit employees. Effective January 1, 2024, newly hired salaried employees and certain bargaining unit employees of LKE will no longer be eligible for postretirement medical benefits under the LKE Postretirement Plan. Postretirement health benefits may be paid from 401(h) accounts established as part of the PPL Retirement Plan and the LG&E and KU Pension Plan within the PPL Services Corporation Master Trust, funded VEBA trusts and company funds. The Rhode Island postretirement benefit plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage. 145 Table of Contents (PPL) The following table provides the components of net periodic defined benefit costs (credits) for PPL's pension and other postretirement benefit plans for the years ended December 31. Pension Benefits Other Postretirement Benefits 2025 2024 2023 2025 2024 2023 Net periodic defined benefit costs (credits): Service cost $ 31 $ 35 $ 34 $ 6 $ 6 $ 6 Interest cost 185 183 188 30 29 30 Expected return on plan assets ( 287 ) ( 299 ) ( 309 ) ( 30 ) ( 30 ) ( 30 ) Amortization of: Prior service cost (credit) — 3 6 2 1 1 Actuarial (gain) loss 18 10 2 ( 4 ) ( 5 ) ( 5 ) Net periodic defined benefit costs (credits) $ ( 53 ) $ ( 68 ) $ ( 79 ) $ 4 $ 1 $ 2 Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets/Liabilities - Gross: Net (gain) loss $ 27 $ 134 $ 193 $ — $ 1 $ ( 6 ) Prior service cost (credit) ( 5 ) ( 13 ) 2 2 — — Amortization of: Prior service (cost) credit — ( 3 ) ( 6 ) ( 2 ) ( 1 ) ( 1 ) Actuarial gain (loss) ( 18 ) ( 10 ) ( 2 ) 4 5 5 Total recognized in OCI and regulatory assets/liabilities 4 108 187 4 5 ( 2 ) Total recognized in net periodic defined benefit costs, OCI and regulatory assets/liabilities $ ( 49 ) $ 40 $ 108 $ 8 $ 6 $ — For PPL's pension and postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities for the years ended December 31 were as follows: Pension Benefits Other Postretirement Benefits 2025 2024 2023 2025 2024 2023 OCI $ 21 $ 25 $ 52 $ 2 $ 2 $ — Regulatory assets/liabilities ( 17 ) 83 135 2 3 ( 2 ) Total recognized in OCI and regulatory assets/liabilities $ 4 $ 108 $ 187 $ 4 $ 5 $ ( 2 ) (PPL) PPL uses base mortality tables issued by the Society of Actuaries for all defined benefit pension and other postretirement benefit plans. The Pri-2012 base table and the MP-2020 projection scale with varying adjustment factors based on the underlying demographic and geographic differences and experience of the plan participants was used for all periods. The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31. Pension Benefits Other Postretirement Benefits 2025 2024 2025 2024 PPL Discount rate 5.72 % 5.93 % 5.74 % 5.91 % Rate of compensation increase 3.43 % 3.43 % 3.43 % 3.44 % 146 Table of Contents The following weighted-average assumptions were used to determine the net periodic defined benefit costs for the years ended December 31. Pension Benefits Other Postretirement Benefits 2025 2024 2023 2025 2024 2023 PPL Discount rate 5.93 % 5.52 % 5.52 % 5.91 % 5.54 % 5.54 % Rate of compensation increase 3.43 % 3.43 % 3.43 % 3.44 % 3.43 % 3.43 % Expected return on plan assets (a) 8.25 % 8.25 % 8.25 % 7.27 % 7.28 % 7.38 % (a) The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption. The following table provides the assumed health care cost trend rates for the years ended December 31: 2025 2024 2023 PPL Health care cost trend rate assumed for next year – obligations 7.50 % 7.00 % 6.25 % – cost 7.00 % 6.25 % 6.50 % Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) – obligations 4.50 % 5.00 % 5.00 % – cost 5.00 % 5.00 % 5.00 % Year that the rate reaches the ultimate trend rate – obligations 2038 2033 2029 – cost 2033 2029 2029 147 Table of Contents The funded status of PPL's plans at December 31 was as follows: Pension Benefits Other Postretirement Benefits 2025 2024 2025 2024 Change in Benefit Obligation Benefit Obligation, beginning of period $ 3,244 $ 3,454 $ 523 $ 538 Service cost 31 35 6 6 Interest cost 185 183 30 29 Participant contributions — — 8 8 Plan amendments ( 5 ) ( 13 ) 1 — Actuarial (gain) loss 77 ( 131 ) 20 ( 4 ) Gross benefits paid ( 297 ) ( 284 ) ( 51 ) ( 56 ) Federal subsidy — — — 2 Benefit Obligation, end of period 3,235 3,244 537 523 Change in Plan Assets Plan assets at fair value, beginning of period 2,936 3,176 417 438 Actual return on plan assets 338 34 51 25 Employer contributions 10 10 11 14 Participant contributions — — 7 7 Transfer out (a) — — — ( 13 ) Gross benefits paid ( 297 ) ( 284 ) ( 54 ) ( 54 ) Plan assets at fair value, end of period 2,987 2,936 432 417 Funded Status, end of period $ ( 248 ) $ ( 308 ) $ ( 105 ) $ ( 106 ) Amounts recognized in the Balance Sheets consist of: Noncurrent asset $ 44 $ 19 $ 9 $ 8 Current liability ( 11 ) ( 10 ) ( 10 ) ( 13 ) Noncurrent liability ( 281 ) ( 317 ) ( 104 ) ( 101 ) Net amount recognized, end of period $ ( 248 ) $ ( 308 ) $ ( 105 ) $ ( 106 ) Amounts recognized in AOCI and regulatory assets/liabilities (pre-tax) consist of: Prior service cost (credit) $ ( 11 ) $ ( 6 ) $ 8 $ 9 Net actuarial (gain) loss 1,173 1,164 ( 86 ) ( 90 ) Total $ 1,162 $ 1,158 $ ( 78 ) $ ( 81 ) Total accumulated benefit obligation for defined benefit pension plans $ 3,105 $ 3,116 (a) Transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to be used to pay medical claims of active bargaining unit employees. For PPL's pension and other postretirement benefit plans, the amounts recognized in AOCI and regulatory assets/liabilities at December 31 were as follows: Pension Benefits Other Postretirement Benefits 2025 2024 2025 2024 AOCI $ 304 $ 283 $ 18 $ 16 Regulatory assets/liabilities 858 875 ( 96 ) ( 97 ) Total $ 1,162 $ 1,158 $ ( 78 ) $ ( 81 ) The actuarial loss for pension plans in 2025 was primarily related to a change in the discount rate used to measure the benefit obligations of those plans. The actuarial gain for pension plans in 2024 was related to a change in the discount rate used to measure the benefit obligations of those plans. 148 Table of Contents The following tables provide information on pension plans where the projected benefit obligation (PBO) or accumulated benefit obligation (ABO) exceed the fair value of plan assets: PBO in excess of plan assets 2025 2024 Projected benefit obligation $ 2,704 $ 2,719 Fair value of plan assets 2,412 2,392 ABO in excess of plan assets 2025 2024 Accumulated benefit obligation $ 2,600 $ 2,618 Fair value of plan assets 2,412 2,392 (PPL Electric) Although PPL Electric does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by PPL Services based on its participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retirees are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to PPL Electric resulted in assets/(liabilities) at December 31 as follows: 2025 2024 Pension $ ( 62 ) $ ( 83 ) Other postretirement benefits ( 53 ) ( 60 ) (LG&E) Although LG&E does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE. LG&E is also allocated costs of defined benefits plans from LKS for defined benefit plans sponsored by LKE. See Note 13 for additional information on costs allocated to LG&E from LKS. These allocations are based on LG&E's participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of LG&E are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to LG&E resulted in assets/(liabilities) at December 31 as follows: 2025 2024 Pension $ 46 $ 29 Other postretirement benefits ( 46 ) ( 44 ) (KU) Although KU does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE. KU is also allocated costs of defined benefit plans from LKS for defined benefit plans sponsored by LKE. See Note 13 for additional information on costs allocated to KU from LKS. These allocations are based on KU's participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of KU are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to KU resulted in assets/(liabilities) at December 31 as follows. 2025 2024 Pension $ 56 $ 46 Other postretirement benefits ( 10 ) ( 8 ) 149 Table of Contents Plan Assets - Pension Plans (PPL) All of PPL's qualified pension plans are invested in the PPL Services Corporation Master Trust (the Master Trust) that also includes 401(h) accounts that are restricted for certain other postretirement benefit obligations of PPL, RIE and LKE. The investment strategy for the Master Trust is to achieve a risk-adjusted return on a mix of assets that, in combination with PPL's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments, while also managing the duration of the assets to complement the duration of the liabilities. The Master Trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore has no significant concentration of risk. The investment policy of the Master Trust outlines investment objectives and defines the responsibilities of the EBPB, external investment managers, investment advisor and trustee and custodian. The investment policy is reviewed annually by PPL's Board of Directors. The EBPB created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios: growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return at a reasonable risk, including equity securities, certain debt securities and alternative investments. The immunizing portfolio consists of debt securities, generally with long durations, and derivative positions. The immunizing portfolio is designed to offset a portion of the change in the pension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of cash and cash equivalents. Target allocation ranges have been developed for each portfolio based on input from external consultants with a goal of limiting funded status volatility. The EBPB monitors the investments in each portfolio and seeks to obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the EBPB establishes revised guidelines from time to time. EBPB investment guidelines as of the end of 2025 are presented below. The asset allocation for the trust and the target allocation by portfolio at December 31 are as follows: Percentage of trust assets 2025 2025 2024 Target Asset Allocation Growth Portfolio 55 % 55 % 55 % Equity securities 30 % 30 % Debt securities (a) 13 % 13 % Alternative investments 12 % 12 % Immunizing Portfolio 43 % 43 % 43 % Debt securities (a) 31 % 35 % Derivatives (b) 12 % 8 % Liquidity Portfolio 2 % 2 % 2 % Total 100 % 100 % 100 % (a) Includes commingled debt funds, which PPL treats as debt securities for asset allocation purposes. (b) Includes posted collateral to support derivative instruments subject to counterparty risk. 150 Table of Contents (PPL) The fair value of net assets in the Master Trust by asset class and level within the fair value hierarchy was: December 31, 2025 December 31, 2024 Fair Value Measurements Using Fair Value Measurements Using Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 PPL Services Corporation Master Trust Cash and cash equivalents $ 239 $ 239 $ — $ — $ 212 $ 212 $ — $ — Equity securities: U.S. Equity 69 69 — — 63 63 — — U.S. Equity fund measured at NAV (a) 469 — — — 461 — — — International equity fund measured at NAV (a) 375 — — — 376 — — — Commingled debt measured at NAV (a) 464 — — — 461 — — — Debt securities: U.S. Treasury and U.S. government sponsored agency 273 273 — — 150 149 1 — Corporate 753 — 742 11 867 — 848 19 Other 7 — 7 — 13 — 13 — Alternative investments: Real estate measured at NAV (a) 71 — — — 72 — — — Private equity measured at NAV (a) 122 — — — 114 — — — Private credit partnerships measured at NAV (a) 20 — — — 16 — — — Hedge funds measured at NAV (a) 179 — — — 181 — — — Derivatives ( 7 ) — ( 7 ) — ( 38 ) — ( 38 ) — PPL Services Corporation Master Trust assets, at fair value 3,034 $ 581 $ 742 $ 11 2,948 $ 424 $ 824 $ 19 Receivables and payables, net (b) 69 102 401(h) accounts restricted for other postretirement benefit obligations ( 116 ) ( 114 ) Total PPL Services Corporation Master Trust pension assets $ 2,987 $ 2,936 (a) In accordance with accounting guidance, certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position. (b) Receivables and payables, net represents amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received. A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2025 is as follows: Corporate debt Balance at beginning of period $ 19 Actual return on plan assets: Relating to assets sold during the period ( 1 ) Purchases, sales and settlements ( 7 ) Balance at end of period $ 11 A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2024 is as follows: Corporate debt Balance at beginning of period $ 10 Actual return on plan assets: Relating to assets still held at the reporting date ( 2 ) Relating to assets sold during the period 7 Purchases, sales and settlements 4 Balance at end of period $ 19 151 Table of Contents Cash and cash equivalents include deposits in banks, collateral accounts with brokers, and short-term investment funds, for which the carrying amounts disclosed approximate fair value based on their short-term nature. The market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and passively managed investments that are managed against various equity indices. Investments in commingled equity and debt funds are categorized as equity securities within the fair value hierarchy, however, the debt funds are treated as fixed income for asset allocation and target allocation purposes. Investments in commingled equity funds include funds that invest in U.S. and international equity securities. Investments in commingled debt funds include funds that invest in a diversified portfolio of emerging market debt obligations, as well as funds that invest in investment grade long-duration fixed-income securities. The fair value measurements of debt securities are generally based on evaluations that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. The fair value of debt securities is generally measured using a market approach, including the use of pricing models, which incorporate observable inputs. Common inputs include benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as payment data, future predicted cash flows, collateral performance and new issue data. For the Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by residential mortgages, auto loans, credit cards and other pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries; investments in debt securities issued by foreign governments and corporations. Investments in real estate represent an investment in a partnership whose purpose is to manage investments in U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value. Investments in private equity represent interests in partnerships in multiple early-stage venture capital funds and private equity fund of funds that use a number of diverse investment strategies. The partnerships have limited lives of at least 10 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed. Investments in private credit represent pools of actively managed loans that span capital structure and borrower type. Strategies carry different types and levels of risk. Returns from those strategies will vary in terms of yield, fees generated, loan loss rates and the pace of principal repayment. Investments have limited lives of approximately 2-8 years. The investment cannot be redeemed with the general partner; however, the interest may be sold to other parties, subject to the general partner's approval. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed. At December 31, 2025, the Master Trust had unfunded commitments of $ 49 million that may be required during the lives of the real estate, private equity and private credit partnerships. Investments in hedge funds represent investments in a fund of hedge funds. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under most market conditions. Major investment strategies for the fund of hedge funds include long/short equity, tactical trading, event driven, and relative value. Shares may be redeemed with 45 days prior written notice. The fund is subject to short term lockups and other restrictions. The fair value for the fund has been estimated using the net asset value per share. The fair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard option valuation models and standard industry models. These securities primarily represent investments in treasury futures, total return swaps, interest rate swaps and swaptions (the option to enter into an interest rate swap), which are valued based on quoted prices, changes in the value of the underlying exposure or on the swap details, such as swap curves, notional amount, index and term of index, reset frequency, volatility and payer/receiver credit ratings. 152 Table of Contents Plan Assets - Other Postretirement Benefit Plans The investment strategy with respect to other postretirement benefit obligations is to fund VEBA trusts and/or 401(h) accounts with voluntary contributions and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the Master Trust, other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers and, therefore, have no significant concentration of risk. Equity securities include investments in a large-cap commingled fund and a global equity exchange-traded fund. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities within the fair value hierarchy, but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes. The asset allocation for the PPL VEBA trusts and the target allocation, by asset class, at December 31 are detailed below. Percentage of plan assets Target Asset Allocation 2025 2024 2025 Asset Class Equity securities 46 % 45 % 45 % Debt securities (a) 48 % 49 % 49 % Cash and cash equivalents (b) 6 % 6 % 6 % Total 100 % 100 % 100 % (a) Includes commingled debt funds and debt securities. (b) Includes money market funds. The fair value of assets in the other postretirement benefit plans by asset class and level within the fair value hierarchy was: December 31, 2025 December 31, 2024 Fair Value Measurement Using Fair Value Measurement Using Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Money market funds $ 19 $ 19 $ — $ — $ 19 $ 19 $ — $ — Equity securities: Large-cap equity fund measure at NAV (a) 75 — — — 71 — — — Commingled debt fund measured at NAV (a) 82 — — — 78 — — — Global equity exchange-traded fund 74 74 — — 70 70 — — Long-term bond exchange-traded fund 75 75 — — 74 74 — — Total VEBA trust assets, at fair value 325 $ 168 $ — $ — 312 $ 163 $ — $ — Receivables and payables, net (b) ( 9 ) ( 9 ) 401(h) account assets 116 114 Total other postretirement benefit plan assets $ 432 $ 417 (a) In accordance with accounting guidance certain investments that are measured at fair value using the net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position. (b) Receivables and payables represent amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received. Investments in money market funds represent investments in funds that invest primarily in a diversified portfolio of investment grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The primary objective of the fund is a level of current income consistent with stability of principal and liquidity. Redemptions can be made daily on this fund. Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Fair value measurements are not obtained from a quoted price in an active market but are based on firm quotes of net asset values per share as provided by the trustee of the fund. Redemptions can be made daily on this fund. 153 Table of Contents Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade long-duration fixed income securities. Redemptions can be made daily on these funds. Investments in global equity exchange-traded fund represents a passively-managed pooled investment vehicle that invests in developed market equities and is designed to track the performance of the MSCI World Index. Fair value measurements can be obtained from a quoted price on the exchange. Redemptions can be made daily on this fund. Investments in long-term bond exchange-traded fund represents a passively-managed pooled investment vehicle that is designed to track the performance of the Bloomberg U.S. Long Government/Credit Float Adjusted Index, which includes all medium and larger issues of U.S. Government, investment-grade corporate and investment-grade international dollar-denominated bonds that have maturities of greater than 10 years. Fair value measurements can be obtained from a quoted price on the exchange. Redemptions can be made daily on this fund. Expected Cash Flows - Defined Benefit Plans (PPL) PPL does not plan to contribute to its pension plans in 2026, as PPL's defined benefit pension plans have the option to utilize available prior year credit balances to meet current and future contribution requirements. PPL sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. PPL expects to make approximately $ 11 million of benefit payments under these plans in 2026. PPL is not required to make contributions to its other postretirement benefit plans that are funded through VEBA trusts and 401(h) accounts. However, postretirement benefits for certain non-union employees are not funded in such trusts. PPL pays for these benefits from its general assets and expects to make $ 10 million of postretirement benefit plan payments for these employees in 2025. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the plans and the following federal subsidy payments are expected to be received by PPL. Other Postretirement Pension Benefit Payment Expected Federal Subsidy 2026 $ 307 $ 50 $ — 2027 294 49 — 2028 287 49 — 2029 279 48 — 2030 272 48 — 2031-2035 1,271 224 — Savings Plans (All Registrants) Substantially all employees of PPL's subsidiaries are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were: 2025 2024 2023 PPL $ 60 $ 53 $ 48 PPL Electric 10 9 8 LG&E 10 8 8 KU 8 6 6 154 Table of Contents 11. Jointly Owned Facilities (PPL, LG&E and KU) At December 31, 2025 and 2024, the Balance Sheets reflect the owned interests in the generating plants listed below. Ownership Interest Electric Plant Accumulated Depreciation Construction Work in Progress PPL December 31, 2025 Trimble County Unit 1 75.00 % $ 464 $ 141 $ 20 Trimble County Unit 2 75.00 % 1,543 344 20 December 31, 2024 Trimble County Unit 1 75.00 % $ 462 $ 124 $ 1 Trimble County Unit 2 75.00 % 1,549 323 10 LG&E December 31, 2025 E.W. Brown Units 6-7 38.00 % $ 53 $ 31 $ — Paddy's Run Unit 13 & E.W. Brown Unit 5 53.00 % 52 32 — Trimble County Unit 1 75.00 % 464 141 20 Trimble County Unit 2 14.25 % 474 88 9 Trimble County Units 5-6 29.00 % 37 20 — Trimble County Units 7-10 37.00 % 82 44 2 Cane Run Unit 7 22.00 % 137 31 2 E.W. Brown Solar Unit 39.00 % 10 4 — Solar Share 44.00 % 3 1 — Mercer Solar 37.00 % 7 — 14 Mill Creek Unit 5 31.00 % 1 — 219 Brown Wind 36.00 % — — — December 31, 2024 E.W. Brown Units 6-7 38.00 % $ 53 $ 29 $ — Paddy's Run Unit 13 & E.W. Brown Unit 5 53.00 % 52 30 — Trimble County Unit 1 75.00 % 462 124 1 Trimble County Unit 2 14.25 % 472 79 5 Trimble County Units 5-6 29.00 % 37 19 — Trimble County Units 7-10 37.00 % 82 41 1 Cane Run Unit 7 22.00 % 137 27 — E.W. Brown Solar Unit 39.00 % 10 4 — Solar Share 44.00 % 3 — — Mercer Solar 37.00 % 10 — 1 Mill Creek Unit 5 31.00 % — — 74 Brown Wind 36.00 % — — — 155 Table of Contents Ownership Interest Electric Plant Accumulated Depreciation Construction Work in Progress KU December 31, 2025 E.W. Brown Units 6-7 62.00 % $ 88 $ 51 $ — Paddy's Run Unit 13 & E.W. Brown Unit 5 47.00 % 47 28 — Trimble County Unit 2 60.75 % 1,069 256 12 Trimble County Units 5-6 71.00 % 87 47 — Trimble County Units 7-10 63.00 % 136 74 3 Cane Run Unit 7 78.00 % 486 109 6 E.W. Brown Solar Unit 61.00 % 16 7 — Solar Share 56.00 % 4 1 — Mercer Solar 63.00 % 13 — 23 Mill Creek Unit 5 69.00 % 1 — 486 Brown Wind 64.00 % 1 — — December 31, 2024 E.W. Brown Units 6-7 62.00 % $ 87 $ 48 $ — Paddy's Run Unit 13 & E.W. Brown Unit 5 47.00 % 46 26 — Trimble County Unit 2 60.75 % 1,077 224 5 Trimble County Units 5-6 71.00 % 87 44 — Trimble County Units 7-10 63.00 % 136 69 1 Cane Run Unit 7 78.00 % 485 95 1 E.W. Brown Solar Unit 61.00 % 16 6 — Solar Share 56.00 % 4 1 — Mercer Solar 63.00 % 16 — 2 Mill Creek Unit 5 69.00 % — — 164 Brown Wind 64.00 % 1 — — Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs associated with the plants is included in the corresponding operating expenses on the Statements of Income. 12. Commitments and Contingencies Energy Purchase Commitments (PPL, LG&E and KU) LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's retail natural gas supply operations. These contracts include the following commitments: Contract Type Maximum Maturity Date Natural Gas Fuel 2027 Natural Gas Retail Supply 2026 Coal 2030 Coal Transportation and Fleeting Services 2033 Natural Gas Transportation 2055 156 Table of Contents LG&E and KU have a PPA with OVEC expiring in June 2040. See footnote (d) to the table in "Guarantees and Other Assurances" below for information on the OVEC power purchase contract. Future obligations for power purchases from OVEC are demand payments, comprised of debt-service payments and contractually-required reimbursements of plant operating, maintenance and other expenses, and are projected as follows: LG&E KU Total 2026 $ 19 $ 8 $ 27 2027 24 10 34 2028 24 11 35 2029 25 11 36 2030 23 10 33 Thereafter 184 83 267 Total $ 299 $ 133 $ 432 LG&E and KU had total energy purchases under the OVEC PPA for the years ended December 31 as follows: 2025 2024 2023 LG&E $ 26 $ 21 $ 20 KU 11 9 9 Total $ 37 $ 30 $ 29 (PPL) RIE enters into purchase contracts to supply electricity for electricity distribution operations and for the delivery, storage and supply of natural gas for RIE's retail natural gas operations. These contracts include the following commitments: Contract Type Maximum Maturity Date Electric power 2027 Gas-related 2043 RIE's commitments under these long-term contracts subsequent to December 31, 2025 are summarized in the table below. Total 2026 2027-2028 2029-2030 Thereafter Energy Purchase Obligations $ 939 $ 268 $ 199 $ 126 $ 346 Long-term Contracts for Renewable Energy (PPL) Several of the obligations included in the table above relate to certain long-term contracts for renewable energy, including: • the Deepwater Wind PPA, a small-scale renewable energy generation project of up to eight offshore wind turbines with an aggregate nameplate capacity of up to 30 MW to benefit the Town of New Shoreham and an underwater cable to Block Island, placed into service in 2016; • the Three-State Procurement, involving six clean energy long-term contracts pursuant to the Rhode Island Long-Term Contracting Standard (LTCS) of which approximately 36 MW is currently operational and with respect to which RIE collects 2.75% remunerations in the annual payments pursuant to the LTCS; and • the Offshore Wind Energy Procurement, pursuant to a 20-year PPA with Deep Water Wind Rev I, LLC (Revolution Wind), with an expected nameplate capacity of 407 MW and is expected to be operational in 2026; this contract was approved without remuneration but allows RIE to seek costs incurred under the agreement. 157 Table of Contents In addition, RIE is obligated under the LTCS (as amended in 2014) to annually solicit for renewable projects until 90 MW of renewable contracting capacity has been secured. The RIPUC-approved solicitations currently in service include: (i) a 15-year PPA with Orbit Energy Rhode Island, LLC for a 3.2 MW nameplate anaerobic digester biogas project located in Johnston, Rhode Island, placed in service in 2017, (ii) a 15-year PPA with Black Bear Development Holdings, LLC for a 3.9 MW nameplate run-of-river hydroelectric plant located in Orono, Maine, placed in service in 2013, (iii) a 15-year PPA with Copenhagen Wind Farm, LLC for an 80 MW nameplate land-based wind project located in Denmark, New York, placed in service in 2018, and (iv) a 15-year PPA with Rhode Island LFG Genco, LLC for a 32.1 MW nameplate combined cycle combustion turbine generating facility fueled by a landfill gas project located in Johnston, Rhode Island, placed in service in 2013 . On December 23, 2025, the RIPUC approved the RFP for soliciting renewable energy under LTCS. Under the approved schedule, the RFP will be released, and the solicitation will commence on May 13, 2026 with the deadline for the submission of bids proposals on August 12, 2026. In addition to the LTCS, on December 19, 2025, RIE along with state agencies and utilities in Maine, Massachusetts, Connecticut and Vermont, released a multi-state RFP to identify competitive proposals for renewable energy and associated transmission infrastructure in Northern Maine under the Affordable Clean Energy Security Act (ACES), as amended in 2022. Bids are due at the end of February 2026 and the selection process will conclude in the third quarter of 2026. As approved by the RIPUC, RIE is allowed to pass through commodity-related/purchased power costs to customers and collect remuneration equal to 2.75% for long-term contracts approved prior to January 1, 2022, pursuant to LTCS as amended in 2022, and that have achieved commercial operation. For long-term contracts approved pursuant to LTCS or ACES, both as amended, on or after January 1, 2022, RIE is entitled to financial remuneration equal to 1.0% through December 31, 2026, for those projects that are commercially operating. For long-term contracts approved pursuant to LTCS or ACES on or after January 1, 2027, RIE is not entitled to any financial remuneration, unless otherwise granted by the RIPUC. Also, the 2022 amendments to LTCS and ACES added a provision, which provides that for any calendar year in which RIE's actual return on equity exceeds the return on equity allowed by the RIPUC in the last general rate case, the RIPUC may adjust any or all remuneration to assure that such remuneration does not result in or contribute toward RIE earning above its allowed return for such calendar year. Legal Matters (All Registrants) PPL and its subsidiaries are involved in legal proceedings, claims and litigation in the ordinary course of business. PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted. Narragansett Electric Litigation (PPL) Energy Efficiency Programs Investigation Narragansett Electric, while under the ownership of National Grid, performed an internal investigation into conduct associated with its energy efficiency programs. On June 27, 2022, the RIPUC opened a new docket (RIPUC Docket No. 22-05-EE) to investigate RIE's actions and the actions of employees of National Grid USA and affiliates during the time RIE was a National Grid USA affiliate being provided services by National Grid USA Service Company, Inc. relating to the manipulation of the reporting of invoices affecting the calculation of past energy efficiency shareholder incentives and the resulting impact on customers. The Rhode Island Attorney General and National Grid USA intervened in the docket and the Rhode Island Division of Public Utilities and Carriers (the Division) is an automatic party in the docket. On February 21, 2025, the Division filed testimony confirming its initial testimony that $ 12 million is the appropriate amount to be refunded to the energy efficiency program. On March 4, 2025, a Settlement Agreement between RIE, the Division, and the Rhode Island Attorney General was filed with the RIPUC requiring refunds of $ 10 million. Of this amount, $ 2 million has already been refunded through the energy efficiency mechanism with the remaining $ 8 million to reduce the storm cost regulatory asset recorded on PPL's balance sheet. The settlement also included reimbursement of minor consulting fees and various other compliance actions. On March 5, 2025, the RIPUC approved the Settlement Agreement. 158 Table of Contents E.W. Brown Environmental Assessment ( PPL and KU) KU is undertaking extensive remedial measures at the E.W. Brown plant including closure of the former ash pond, implementation of a groundwater remedial action plan and performance of a corrective action plan including aquatic study of adjacent surface waters and risk assessment. The aquatic study and risk assessment are being undertaken pursuant to a 2017 Agreed Order with the Kentucky Energy and Environment Cabinet (KEEC). KU conducted sampling of Herrington Lake in 2017 and 2018. In June 2019, KU submitted to the KEEC the required aquatic study and risk assessment, conducted by an independent third-party consultant, finding that discharges from the E.W. Brown plant have not had any significant impact on Herrington Lake and that the water in the lake is safe for recreational use and meets safe drinking water standards. On May 31, 2021, the KEEC approved the report and released a response to public comments. On August 6, 2021, KU submitted a Supplemental Remedial Alternatives Analysis report to the KEEC that outlines proposed additional fish, water, and sediment testing. On February 18, 2022, the KEEC provided approval to KU to proceed with the proposed sampling, which commenced in the spring of 2022. On November 17, 2022, KU submitted a Supplemental Performance Monitoring Report to the KEEC finding that there are no significant unaddressed risks to human health or the environment at the plant. KU revised the Supplemental Performance Monitoring Report on June 8, 2023, in response to KEEC comments from April 24, 2023. On September 1, 2023, the KEEC requested KU to propose additional monitoring or remedial measures. KU submitted a revised Supplemental Performance Monitoring and Corrective Action Completion on December 28, 2023. In August 2024, KU submitted a proposed environmental covenant to the KEEC specifying certain site restrictions. Discussions between KU and the KEEC are ongoing, but KU cannot predict the outcome of this matter. (PPL, LG&E and KU) EPA Deregulatory Initiative On March 12, 2025, the EPA announced a plan to reconsider 31 environmental rules including the Section 111 performance standards and emissions limits for greenhouse gases, the endangerment finding for greenhouse gases, the Good Neighbor Plan, the Mercury and Air Toxics Standards, revisions to the fine particulate matter standard, the ELGs, and the CCRs Rule. Supplementing previous Executive Orders directing various regulatory changes, on April 9, 2025, President Trump issued an Executive Order and Presidential Memorandum directing review of existing rules, repeal of unlawful rules, and initiation of a zero-based budgeting process by which certain rules would automatically expire unless extended. While the current Presidential administration may seek to implement some regulatory changes outside of the rulemaking process, changes to existing rules are generally expected to require formal rulemaking proceedings. Any final EPA actions repealing or revising current rules will likely result in legal challenges. PPL, LG&E, and KU are unable to predict future regulatory changes, if any, that may result from the EPA's deregulatory plan or the outcome of any associated legal challenges. PPL, LG&E, and KU are closely monitoring the ongoing EPA initiative and any related litigation for the impact to our business including planned capital expenditures to comply with the EPA rules. 159 Table of Contents Water/Waste ELGs In 2015, the EPA finalized ELGs for wastewater discharge permits for new and existing steam electricity generating facilities. These guidelines require deployment of additional control technologies providing physical, chemical and biological treatment and mandate operational changes including "zero discharge" requirements for certain wastewaters. The implementation date for individual generating stations was to be determined by the states on a case-by-case basis according to criteria provided by the EPA. In September 2017, the EPA issued a rule to postpone the compliance date for certain requirements. In October 2020, the EPA issued revisions to its best available technology standards for certain wastewaters and potential extensions to compliance dates (the Reconsideration Rule). On May 9, 2024, the EPA issued a final rule modifying the 2020 ELG revisions. The rule increases the stringency of previous control technology and zero discharge requirements, revises certain exemptions for generating units planned for retirement, and requires case-by-case limitations for legacy wastewaters based on the best professional judgment of the state regulators. Legal challenges to the final rule have been consolidated before the U.S. Court of Appeals for the Eighth Circuit. The final rule could potentially result in significant operational changes and additional controls for LG&E and KU plants, but in March 2025 the EPA announced its plan to reconsider the rule. The ELGs are expected to be implemented by the states or applicable permitting authorities in the course of their normal permitting activities. Certain costs are included in the Registrants' capital plans and expected to be recovered from customers through rate recovery mechanisms, but additional costs and recovery will depend on further regulatory developments at the state level. On December 31, 2025, the EPA issued a final rule extending the retirement exemption category application deadline an additional six years, from December 2025 to December 2031 and a five-year extension to the zero liquid discharge deadlines, from December 2029 to December 2034. The EPA announced that it will conduct a technology review of the zero liquid discharge technology in a future rulemaking. CCRs In 2015, the EPA issued a final rule governing management of CCRs, which include fly ash, bottom ash and sulfur dioxide scrubber wastes (2015 CCR Rule). The 2015 CCR Rule imposed extensive new requirements for certain CCR impoundments and landfills, including public notifications, location restrictions, design and operating standards, groundwater monitoring and corrective action requirements, and closure and post-closure care requirements, and specifies restrictions relating to the beneficial use of CCRs. In January 2022, the EPA issued several proposed regulatory determinations, facility notifications, and public announcements which indicate increased scrutiny by the EPA to determine the adequacy of measures taken by facility owners and operators to achieve closure of CCR surface impoundments and landfills. In particular, the agency indicated that it will focus on certain practices which it views as posing a threat of continuing groundwater contamination. On May 8, 2024, the EPA issued a final rule (2024 CCR Rule) establishing regulatory requirements for inactive surface impoundments at inactive electricity generation facilities (legacy impoundments). The 2024 CCR Rule also establishes identification, groundwater monitoring, corrective action, closure, and post-closure care requirements for all CCR management units, as defined in the rule, at regulated CCR facilities regardless of how or when the CCR was placed. The rule also requires LG&E and KU to complete applicability determinations, implement site security measures, initiate weekly inspections and monthly monitoring of the impoundment, create a website, and complete hazard assessments and reports for its legacy impoundments. Additionally, the rule could potentially subject CCR management units that have previously completed remedial action and closure and certain beneficial use projects to additional federal regulatory requirements. Legal challenges to the rule have been filed in the D.C. Circuit Court. In March 2025, the EPA announced its plan to update the rule. On July 22, 2025, the EPA published a proposed rule to extend the deadline for select CCR management units for the Facility Evaluation Report Part 1 and Part 2 by one year to February 2027 and February 2028, respectively. The proposed rule would also extend the groundwater monitoring deadline to August 8, 2030, with the initial groundwater monitoring report extended to January 31, 2031. In connection with the 2015 CCR Rule, LG&E and KU recorded adjustments to existing AROs beginning in 2015. In connection with the 2024 CCR Rule, in the second quarter of 2024, LG&E and KU recognized ARO obligations related to preliminary risk assessments, facility evaluations, feasibility studies and sampling. See Note 18 for additional information. The results of those evaluations, as well as future guidance, regulatory determinations, rulemakings, implementation determinations and other developments could potentially require revisions to current LG&E and KU compliance plans including additional monitoring and remediation at surface impoundments and landfills, the cost of which could be material. PPL, LG&E and KU are unable to predict the outcome of the ongoing litigation, rulemaking, and regulatory determinations or potential impacts on current LG&E and KU compliance plans. PPL, LG&E and KU are currently finalizing or revising closure plans and schedules in accordance with applicable regulations and further material changes to AROs, current capital plans or operating costs may be required as estimates are refined based on closure developments, groundwater monitoring results, and regulatory or legal proceedings. Costs relating to this rule are expected to be subject to rate recovery. 160 Table of Contents LG&E and KU received KPSC approval for a compliance plan associated with the 2015 CCR Rule providing for the closure of impoundments at the Mill Creek, Trimble County, E.W. Brown, and Ghent stations, and construction of process water management facilities at those plants. In addition to the foregoing measures required for compliance with the federal CCR Rule, KU also received KPSC approval for its plans to close impoundments at the retired Green River, Pineville and Tyrone plants to comply with applicable state law. LG&E and KU have completed planned closure measures at most of the subject impoundments and have commenced post closure groundwater monitoring as required at those facilities. Associated costs are subject to rate recovery through the Companies' ECR adjustment clause. Superfund and Other Remediation (All Registrants) The Registrants are potentially responsible for investigating and remediating contamination under the federal Superfund program and similar state programs. Actions are under way at certain sites including former manufactured gas plants in Pennsylvania, Rhode Island and Kentucky previously owned or operated by, or currently owned by predecessors or affiliates of, PPL subsidiaries. Depending on the outcome of investigations at identified sites where investigations have not begun or been completed, or developments at sites for which information is incomplete, additional costs of remediation could be incurred. PPL, PPL Electric, LG&E and KU lack sufficient information about such additional sites to estimate any potential liability or range of reasonably possible losses, if any, related to these sites. Such costs, however, are not currently expected to be significant. The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of manufactured gas plant operations. As a result, individual states may establish stricter standards for water quality and soil cleanup, that could require several PPL subsidiaries to take more extensive assessment and remedial actions at former manufactured gas plants. The Registrants cannot reasonably estimate a range of possible losses, if any, related to these matters. (PPL and PPL Electric) PPL Electric is a potentially responsible party for a share of clean-up costs at certain sites. Cleanup actions have been or are being undertaken at these sites as requested by governmental agencies, the costs of which have not been and are not expected to be significant to PPL Electric. At December 31, 2025 and December 31, 2024, PPL Electric had a recorded liability of $ 8 million and $ 8 million, representing its best estimate of the probable loss incurred to remediate these sites. (PPL) RIE is a potentially responsible party for a share of clean-up costs at certain sites including former manufactured gas plant facilities formerly owned by the Blackstone Valley Gas and Electric Company and the Rhode Island gas distribution assets of the New England Gas division of Southern Union Company and electric operations at certain RIE facilities. RIE is currently investigating and remediating, as necessary, those sites and certain other properties under agreements with governmental agencies, the costs of which have not been and are not expected to be significant to PPL. At December 31, 2025 and December 31, 2024, RIE had a recorded liability of $ 98 million and $ 98 million, representing its best estimate of the remaining costs of environmental remediation activities. These undiscounted costs are expected to be incurred over approximately 30 years and to be subject to rate recovery. However, remediation costs for each site may be materially higher than estimated, depending on changing technologies and regulatory standards, selected end uses for each site, and actual environmental conditions encountered. RIE has recovered amounts from certain insurers and potentially responsible parties, and, where appropriate, may seek additional recovery from other insurers and potentially responsible parties, but it is uncertain whether, and to what extent, such efforts will be successful. 161 Table of Contents The RIPUC has approved two settlement agreements that provide for rate recovery of qualified remediation costs of certain contaminated sites located in Rhode Island and Massachusetts. Rate-recoverable contributions for electric operations of approximately $ 3 million are added annually to RIE's Environmental Response Fund, established with RIPUC approval in March 2000 to address such costs, along with interest and any recoveries from insurance carriers and other third-parties. In addition, RIE recovers approximately $ 1 million annually for gas operations under a distribution adjustment charge in which the qualified remediation costs are amortized over 10 years. See Note 7 for additional information on RIE's recorded environmental regulatory assets and liabilities. Regulatory Issues See Note 7 for information on regulatory matters related to utility rate regulation. Electricity - Reliability Standards The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk electric system in North America. The FERC oversees this process and independently enforces the Reliability Standards. The Reliability Standards have the force and effect of law and apply to certain users of the bulk electric system, including electric utility companies, generators and marketers. Under the Federal Power Act, the FERC may assess civil penalties for certain violations. PPL Electric, LG&E, KU and RIE monitor their compliance with the Reliability Standards and self-report or self-log potential violations of applicable reliability requirements whenever identified, and submit accompanying mitigation plans, as required. The resolution of a small number of potential violations is pending. Penalties incurred to date have not been significant. Any Regional Reliability Entity determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC. In the course of implementing their programs to ensure compliance with the Reliability Standards by those PPL affiliates subject to the standards, certain other instances of potential non-compliance may be identified from time to time. The Registrants cannot predict the outcome of these matters, and an estimate or range of possible losses cannot be determined. Gas - Security Directives (PPL and LG&E) In May and July of 2021, the Department of Homeland Security's (DHS) Transportation Security Administration issued two security directives applicable to certain notified owners and operators of natural gas pipeline facilities (including local distribution companies) that the Transportation Security Administration has determined to be critical. Both security directives have been updated and extended multiple times. The Transportation Security Administration has determined that LG&E is within the scope of the directives, while RIE has not been notified of this distinction. The first directive, most recently updated and now effective through January 2027, requires notified owners/operators to report specified cybersecurity incidents to the DHS, designate a cybersecurity coordinator, and perform a gap assessment of current entity cybersecurity practices against certain voluntary Transportation Security Administration security guidelines and report results and proposed mitigation to the DHS. The second security directive, updated and effective through May 2026, requires refinement of a Transportation Security Administration-approved Cybersecurity Implementation Plan (CIP) and the Cybersecurity Assessment Plan (CAP). The Transportation Security Administration has transitioned to a performance‑based regulatory model, requiring operators to meet defined cybersecurity outcomes rather than implement prescriptive controls. Key requirements now include: maintaining a Transportation Security Administration‑approved CIP; reporting significant cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (CISA) within 24 hours; completing annual CAPs with all CIP measures assessed on a three‑year cycle; conducting annual testing of at least two Cybersecurity Incident Response Plan (CIRP) objectives; meeting new 2026 vetting requirements for non‑U.S. citizen cybersecurity coordinators (who must participate in a trusted traveler program); and complying with clarified rules governing shared responsibilities when third parties support pipeline operations. LG&E does not believe these security directives or their updates have had, or are expected to have, a material impact on its operations or financial condition. 162 Table of Contents Other Guarantees and Other Assurances (All Registrants) In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. Examples of such agreements include: guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage. (PPL) PPL fully and unconditionally guarantees all of the debt securities and loan obligations of PPL Capital Funding. (All Registrants) The table below details guarantees provided as of December 31, 2025. "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee. The Registrants believe the probability of expected payment/performance under each of these guarantees is remote, except for the guarantee related to the payment obligations of Safari under certain sale/leaseback financing transactions and PPL's agreement to fund any increases in the fair value of those obligations, which PPL believes are reasonably possible of occurring. For reporting purposes, on a consolidated basis, the guarantees of PPL include the guarantees of its subsidiary Registrants. Exposure at December 31, 2025 Expiration Date PPL Indemnifications related to certain tax liabilities related to the sale of the U.K. utility business £ 50 (a) 2028 PPL guarantees related to certain sale/leaseback financing transactions related to the sale of Safari Holdings $ 71 (b) 2028 Indemnifications for losses suffered related to items not covered by Aspen Power's representation and warranty insurance associated with the sale of Safari Holdings 140 (c) 2028 LG&E and KU LG&E and KU obligation of shortfall related to OVEC (d) (a) PPL WPD Limited entered into a Tax Deed dated June 9, 2021 in which it agreed to a tax indemnity regarding certain potential tax liabilities of the entities sold with respect to periods prior to the completion of the sale, subject to customary exclusions and limitations. Because National Grid Holdings One plc, the buyer, agreed to purchase indemnity insurance, the amount of the cap on the indemnity for these liabilities is £1, except with respect to certain surrenders of tax losses, for which the amount of the cap on the indemnity is £ 50 million. In June 2025, the indemnifications were novated to PPL Energy Holdings. (b) PPL guaranteed the payment obligations of Safari under certain sale/leaseback financing transactions executed by Safari. These guarantees will remain in place until Safari exercises its option to buy-out the projects under the sale/leaseback financings by the year 2028. Safari will indemnify PPL for any payments made by PPL or claims against PPL under the sale/leaseback transaction guarantees up to $ 25 million. Separately, PPL has agreed to fund incremental payment obligations under the buy-outs resulting from increases in the fair market value of the projects from the initial fair market value determined at the time of PPL's sale of Safari Holdings to the time the buy-out options are exercised by Safari. As of December 31, 2025, PPL cannot reasonably estimate its payment obligations related to the remaining buy-out options. (c) Aspen Power has obtained representation and warranty insurance, therefore, PPL generally has no liability for its representations and warranties under the agreement except for losses suffered related to items not covered. Expiration of these indemnifications range from 18 months to 6 years from the date of the closing of the transaction, and PPL's aggregate liability for these claims will not exceed $ 140 million subject to certain adjustments. (d) Pursuant to the OVEC power purchase contract, LG&E and KU are obligated to pay for their share of OVEC's excess debt service, post-retirement and decommissioning costs, as well as any shortfall from amounts included within a demand charge designed and expected to cover these costs over the term of the contract. PPL's proportionate share of OVEC's outstanding debt was $ 71 million at December 31, 2025, consisting of LG&E's share of $ 49 million and KU's share of $ 22 million. The maximum exposure and the expiration date of these potential obligations are not presently determinable. See "Energy Purchase Commitments" above for additional information on the OVEC power purchase contract. The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business. These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration. The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is remote. 163 Table of Contents PPL, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage. The coverage provides maximum aggregate coverage of $ 231 million for non-wildfire liability losses and maximum aggregate coverage of $ 181 million for wildfire liability losses. This insurance may be applicable to obligations under certain of these contractual arrangements. 13. Related Party Transactions Wholesale Sales and Purchases (LG&E and KU) LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail customers. When LG&E has excess generation capacity after serving its own retail customers and its generation cost is lower than that of KU, KU purchases electricity from LG&E and vice versa. These transactions are reflected in the Statements of Income as "Electric revenue from affiliate" and "Energy purchases from affiliate" and are recorded at a price equal to the seller's fuel cost plus any split savings. Savings realized from such intercompany transactions are shared equally between both companies. The volume of energy each company has to sell to the other is dependent on its retail customers' needs and its available generation. Support Costs (PPL Electric, LG&E and KU) PPL Services and LKS provide the Registrants, their respective subsidiaries and each other with administrative, management and support services. For all services companies, the costs of directly assignable and attributable services are charged to the respective recipients as direct support costs. General costs that cannot be directly attributed to a specific entity are allocated and charged to the respective recipients as indirect support costs. PPL Services and LKS use a three-factor methodology that includes the applicable recipients' invested capital, operation and maintenance expenses and number of employees to allocate indirect costs. PPL Services may also use a ratio of overall direct and indirect costs or a weighted average cost ratio. PPL Services and LKS charged the following amounts for the years ended December 31, including amounts applied to accounts that are further distributed between capital and expense on the books of the recipients, based on methods that are believed to be reasonable. 2025 2024 2023 PPL Electric from PPL Services $ 261 $ 227 $ 222 LG&E from LKS 113 105 115 LG&E from PPL Services 135 66 42 KU from LKS 141 130 150 KU from PPL Services 131 65 48 In addition to the charges for services noted above, LKS makes payments on behalf of LG&E and KU for fuel purchases and other costs for products or services provided by third parties. LG&E and KU also provide services to each other and to LKS. Billings between LG&E and KU relate to labor and overheads associated with union and hourly employees performing work for the other company, charges related to jointly-owned generating units and other miscellaneous charges. Tax settlements between PPL and LG&E and KU are reimbursed through LKS. Intercompany Borrowings (PPL Electric) CEP Reserves maintains a $ 800 million revolving line of credit with a PPL Electric subsidiary. At December 31, 2025, CEP Reserves had $ 143 million of borrowings outstanding. At December 31, 2024, CEP Reserves had $ 222 million borrowings outstanding. The interest rates on borrowings are equal to one-month SOFR plus a spread. Interest income is reflected in "Interest Income from Affiliate" on the Income Statements. (LG&E and KU) LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to the difference between LG&E's FERC borrowing limit and LG&E's commercial paper limit at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on SOFR. At December 31, 2025, LG&E's money pool unused capacity was $ 750 million. At December 31, 2025 LG&E had no borrowings from KU and/or LKE. At December 31, 2024, LG&E's borrowings outstanding from KU and/or LKE were $ 43 million. 164 Table of Contents KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to the difference between KU's FERC borrowing limit and KU's commercial paper limit at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on SOFR. At December 31, 2025, KU's money pool unused capacity was $ 614 million. At December 31, 2025 KU had borrowings outstanding of $ 36 million from LG&E and/or LKE. At December 31, 2024, KU's borrowings outstanding from LG&E and/or LKE were $ 73 million. VEBA Funds Receivable (PPL Electric) In 2018, PPL received a favorable private letter ruling from the IRS permitting a transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to a new subaccount within the VEBA, to be used to pay medical claims of active bargaining unit employees. In October 2024, additional excess funds were removed from the PPL Bargaining Unit Retiree Health Plan VEBA and deposited into the existing subaccount within the VEBA to be used to pay medical claims of active bargaining unit employees. Based on PPL Electric's participation in PPL's Other Postretirement Benefit plan, PPL Electric was allocated a portion of the excess funds from PPL Services. These funds have been recorded as an intercompany receivable on PPL Electric's balance sheets. The receivable balance decreases as PPL Electric pays incurred medical claims and is reimbursed by PPL Services. There was no intercompany receivable balance associated with these funds at December 31, 2025, as PPL Electric's allocation of excess funds was depleted. The intercompany receivable balance associated with these funds was $ 7 million at December 31, 2024, of which $ 4 million was reflected in "Accounts receivable from affiliates" and $ 3 million was reflected in "Other noncurrent assets" on PPL Electric's balance sheets. Other (PPL Electric, LG&E and KU) See Note 1 for discussions regarding the intercompany tax sharing agreement (for PPL Electric, LG&E and KU) and intercompany allocations of stock-based compensation expense (for PPL Electric). For PPL Electric, LG&E and KU, see Note 10 for discussions regarding intercompany allocations associated with defined benefits. 14. Other Income (Expense) - net (PPL) The components of "Other Income (Expense) - net" for the years ended December 31, were: 2025 2024 2023 Defined benefit plans - non-service credits (Note 10) $ 59 $ 42 $ 40 Interest income 20 33 32 AFUDC - equity component 81 47 30 Talen litigation (a) — ( 2 ) ( 124 ) Miscellaneous ( 9 ) ( 6 ) ( 18 ) Other Income (Expense) - net $ 151 $ 114 $ ( 40 ) (a) PPL incurred legal expenses related to litigation associated with its former affiliate, Talen Montana, LLC, and certain affiliated entities (collectively, Talen), which was settled in December 2023. (PPL Electric) The components of "Other Income (Expense) - net" for the years ended December 31, were: 2025 2024 2023 Defined benefit plans - non-service credits (Note 10) $ 14 $ 17 $ 20 Interest income 8 8 8 AFUDC - equity component 30 23 16 Miscellaneous ( 4 ) ( 3 ) ( 5 ) Other Income (Expense) - net $ 48 $ 45 $ 39 165 Table of Contents (LG&E) The components of "Other Income (Expense) - net" for the years ended December 31, were: 2025 2024 2023 Defined benefit plans - non-service credits (Note 10) $ 3 $ 3 $ — AFUDC - equity component 16 8 3 Miscellaneous 5 1 — Other Income (Expense) - net $ 24 $ 12 $ 3 (KU) The components of "Other Income (Expense) - net" for the years ended December 31, were: 2025 2024 2023 Defined benefit plans - non-service credits (Note 10) $ 7 $ 8 $ 6 AFUDC - equity component 21 9 3 Miscellaneous 1 ( 2 ) ( 1 ) Other Income (Expense) - net $ 29 $ 15 $ 8 15. Fair Value Measurements (All Registrants) Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). A market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models), and/or a cost approach (generally, replacement cost) are used to measure the fair value of an asset or liability, as appropriate. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk. The fair value of a group of financial assets and liabilities is measured on a net basis. See Note 1 for information on the levels in the fair value hierarchy. Recurring Fair Value Measurements The assets and liabilities measured at fair value were: December 31, 2025 December 31, 2024 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 PPL Assets Cash and cash equivalents $ 1,071 $ 1,071 $ — $ — $ 306 $ 306 $ — $ — Restricted cash and cash equivalents (a) 15 15 — — 33 33 — — Total Cash, Cash Equivalents and Restricted Cash (b) 1,086 1,086 — — 339 339 — — Special use funds (a): Money market fund 1 1 — — 1 1 — — Commingled debt fund measured at NAV (c) 5 — — — 10 — — — Commingled equity fund measured at NAV (c) 5 — — — 8 — — — Total special use funds 11 1 — — 19 1 — — 166 Table of Contents December 31, 2025 December 31, 2024 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Price risk management assets (d): Gas contracts 6 — 2 4 9 — 4 5 Total assets $ 1,103 $ 1,087 $ 2 $ 4 $ 367 $ 340 $ 4 $ 5 Liabilities Price risk management liabilities (d): Interest rate derivatives $ 5 $ — $ 5 $ — $ 3 $ — $ 3 $ — Gas contracts 10 — 6 4 13 — 10 3 Total price risk management liabilities $ 15 $ — $ 11 $ 4 $ 16 $ — $ 13 $ 3 PPL Electric Assets Cash and cash equivalents $ 30 $ 30 $ — $ — $ 24 $ 24 $ — $ — Total assets $ 30 $ 30 $ — $ — $ 24 $ 24 $ — $ — LG&E Assets Cash and cash equivalents $ 162 $ 162 $ — $ — $ 8 $ 8 $ — $ — Restricted cash and cash equivalents (a) 7 7 — — 16 16 — — Total Cash, Cash Equivalents and Restricted Cash (b) 169 169 — — 24 24 — — Total assets $ 169 $ 169 $ — $ — $ 24 $ 24 $ — $ — Liabilities Price risk management liabilities (e): Interest rate derivatives $ 5 $ — $ 5 $ — $ 3 $ — $ 3 $ — Total price risk management liabilities $ 5 $ — $ 5 $ — $ 3 $ — $ 3 $ — KU Assets Cash and cash equivalents $ 10 $ 10 $ — $ — $ 13 $ 13 $ — $ — Restricted cash and cash equivalents (a) 7 7 — — 16 16 — — Total Cash, Cash Equivalents and Restricted Cash (b) 17 17 — — 29 29 — — Total assets $ 17 $ 17 $ — $ — $ 29 $ 29 $ — $ — (a) Current portion is included in "Other current assets" and noncurrent portion is included in "Other noncurrent assets" on the Balance Sheets. (b) Total Cash, Cash Equivalents and Restricted Cash provides a reconciliation of these items reported within the Balance Sheets to the sum shown on the Statements of Cash Flows. (c) In accordance with accounting guidance, certain investments that are measured at fair value using net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position. (d) Current portion is included in "Other current assets" and "Other current liabilities" and noncurrent portion is included in "Other noncurrent assets" "Other deferred credits and noncurrent liabilities" on the Balance Sheets. (e) Current portion is included in "Other current liabilities" on the Balance Sheets. A reconciliation of net assets classified as Level 3 for the year ended December 31 is as follows: Gas Contracts 2025 Balance at beginning of period $ 2 Total unrealized gains (losses) recognized as Regulatory Assets/Regulatory Liabilities ( 2 ) Balance at end of period $ — 167 Table of Contents 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. 168 Table of Contents Financial Instruments Not Recorded at Fair Value (All Registrants) The carrying amounts of long-term debt on the Balance Sheets and their estimated fair values are set forth below. Long-term debt is classified as Level 2. The effect of third-party credit enhancements is not included in the fair value measurement. December 31, 2025 December 31, 2024 Carrying Amount (a) Fair Value Carrying Amount (a) Fair Value PPL $ 18,894 $ 18,488 $ 16,503 $ 15,562 PPL Electric 5,707 5,473 5,214 4,862 LG&E 2,865 2,784 2,471 2,295 KU 3,510 3,304 3,066 2,750 (a) Amounts are net of debt issuance costs. The carrying amounts of other current financial instruments (except for long-term debt due within one year) approximate their fair values because of their short-term nature. 16. Derivative Instruments and Hedging Activities (All Registrants) Risk Management Objectives PPL has a risk management policy approved by the Board of Directors to manage market risk associated with commodities, interest rates on debt issuances (including price, liquidity and volumetric risk) and credit risk (including non-performance risk and payment default risk). The Risk Management Committee, comprised of senior management and chaired by the Vice President-Financial Strategy and Chief Risk Officer, oversees the risk management function. Key risk control activities designed to ensure compliance with the risk policy and detailed programs include, but are not limited to, credit review and approval, validation of transactions, verification of risk and transaction limits, value-at-risk analyses (VaR, a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level) and the coordination and reporting of the Enterprise Risk Management program. Market Risk Market risk includes the potential loss that may be incurred as a result of price changes associated with a particular financial or commodity instrument as well as market liquidity and volumetric risks. Forward contracts, futures contracts, options, swaps and structured transactions are utilized as part of risk management strategies to minimize unanticipated fluctuations in earnings caused by changes in commodity prices and interest rates. Many of these contracts meet the definition of a derivative. All derivatives are recognized on the Balance Sheets at their fair value, unless NPNS is elected. The following summarizes the market risks that affect PPL and its subsidiaries. Interest Rate Risk • PPL and its subsidiaries are exposed to interest rate risk associated with forecasted fixed-rate and existing floating-rate debt issuances. PPL and LG&E utilize over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt. PPL, LG&E and KU utilize hedging instruments to limit exposure to fluctuations in benchmark interest rates, when appropriate, in connection with future debt issuance. • PPL and its subsidiaries are exposed to interest rate risk associated with debt securities and derivatives held by defined benefit plans. This risk is significantly mitigated to the extent that the plans are sponsored at, or sponsored on behalf of, the regulated utilities due to the recovery methods in place. 169 Table of Contents 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. 170 Table of Contents PPL, LG&E and KU had no obligation to return or post cash collateral under master netting arrangements at December 31, 2025 and 2024. See "Offsetting Derivative Instruments" below for a summary of derivative positions presented in the balance sheets where a right of setoff exists under these arrangements. Interest Rate Risk (All Registrants) PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. A variety of financial derivative instruments are utilized to adjust the mix of fixed and floating interest rates in their debt portfolios, adjust the duration of the debt portfolios and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under PPL's risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of the debt portfolio due to changes in benchmark interest rates. In addition, the interest rate risk of certain subsidiaries is potentially mitigated as a result of the existing regulatory framework or the timing of rate cases. Cash Flow Hedges (PPL) Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. Financial interest rate derivatives that qualify as cash flow hedges may be entered into to hedge floating interest rate risk associated with both existing and anticipated debt issuances. As of December 31, 2025, PPL held an aggregate notional value in interest rate derivatives of $ 20 million that mature on June 15, 2026. Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time period and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedged transaction is not probable of occurring. For 2025, 2024 and 2023, PPL had no cash flow hedges reclassified into earnings associated with discontinued cash flow hedges. At December 31, 2025, the amount of accumulated net unrecognized after-tax gains (losses) on qualifying derivatives expected to be reclassified into earnings during the next 12 months is insignificant. Amounts are reclassified as the hedged interest expense is recorded. Economic Activity (PPL and LG&E) LG&E enters into interest rate swap contracts that economically hedge interest payments. Because realized gains and losses from the swaps, including terminated swap contracts, are recoverable through regulated rates, any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities until they are realized as interest expense. Realized gains and losses are recognized in "Interest Expense" on the Statements of Income at the time the underlying hedged interest expense is recorded. At December 31, 2025, LG&E held contracts with a notional amount of $ 64 million that mature in 2033. Commodity Price Risk (PPL) Economic Activity RIE enters into derivative contracts that economically hedge natural gas purchases. Realized gains and losses from the derivatives are recoverable through regulated rates, therefore subsequent changes in fair value are included in regulatory assets or liabilities until they are realized as purchased gas. Realized gains and losses are recognized in "Energy Purchases" on the Statements of Income upon settlement of the contracts. See Note 7 for amounts recorded in regulatory assets and regulatory liabilities at December 31, 2025. At December 31, 2025, RIE held contracts with notional volumes of 48 Bcf that range in maturity from 2026 through 2029. 171 Table of Contents Accounting and Reporting (All Registrants) All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless the NPNS is elected. NPNS contracts include certain full-requirement purchase contracts and other physical purchase contracts. Changes in the fair value of derivatives not designated as NPNS are recognized in earnings unless specific hedge accounting criteria are met and designated as such, except for the changes in fair values of LG&E's interest rate swaps that are recognized as regulatory assets or regulatory liabilities. See Note 7 for amounts recorded in regulatory assets and regulatory liabilities at December 31, 2025 and 2024. See Note 1 for additional information on accounting policies related to derivative instruments. (PPL) The following table presents the fair value and location of derivatives not designated as hedging instruments recorded on the Balance Sheets: December 31, 2025 December 31, 2024 Assets Liabilities Assets Liabilities Current: Price Risk Management Assets/Liabilities (a): Interest rate derivatives (b) $ — $ 1 $ — $ — Gas contracts 6 5 7 10 Total current 6 6 7 10 Noncurrent: Price Risk Management Assets/Liabilities (a): Interest rate derivatives (b) — 4 — 3 Gas contracts — 5 2 3 Total noncurrent — 9 2 6 Total derivatives $ 6 $ 15 $ 9 $ 16 (a) Current portion is included in "Other current assets" and "Other current liabilities" and noncurrent portion is included in "Other noncurrent assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets. (b) Excludes accrued interest, if applicable. The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets and regulatory liabilities: Derivative Relationships Derivative Gain (Loss) Recognized in OCI Location of Gain (Loss) Recognized in Income on Derivative Gain (Loss) Reclassified from AOCI into Income 2025 Cash Flow Hedges: Interest rate derivatives $ 2 Interest Expense $ ( 3 ) Total $ 2 $ ( 3 ) 2024 Cash Flow Hedges: Interest rate derivatives $ — Interest Expense $ ( 3 ) Total $ — $ ( 3 ) 2023 Cash Flow Hedges: Interest rate derivatives $ — Interest Expense $ ( 3 ) Total $ — $ ( 3 ) 172 Table of Contents Derivatives Not Designated as Hedging Instruments Location of Gain (Loss) Recognized in Income on Derivative 2025 2024 2023 Gas contracts Energy Purchases $ ( 9 ) $ ( 40 ) $ ( 19 ) Other income (expense) - net ( 1 ) — ( 1 ) Total $ ( 10 ) $ ( 40 ) $ ( 20 ) Derivatives Not Designated as Hedging Instruments Location of Gain (Loss) Recognized as Regulatory Liabilities/Assets 2025 2024 2023 Gas contracts Regulatory assets - current $ 3 $ 48 $ 9 Regulatory assets - noncurrent ( 2 ) 7 ( 8 ) Interest rate derivatives Regulatory assets - noncurrent — 4 — Total $ 1 $ 59 $ 1 The following table presents the effect of cash flow hedge activity on the Statement of Income for the year ended December 31, 2025: Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships Interest Expense Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded $ 808 The effects of cash flow hedges: Gain (Loss) on cash flow hedging relationships: Interest rate derivatives: Amount of gain (loss) reclassified from AOCI to income ( 3 ) The following table presents the effect of cash flow hedge activity on the Statement of Income for the year ended December 31, 2024: Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships Interest Expense Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded $ 738 The effects of cash flow hedges: Gain (Loss) on cash flow hedging relationships: Interest rate derivatives: Amount of gain (loss) reclassified from AOCI to income ( 3 ) The following table presents the effect of cash flow hedge activity on the Statement of Income for the year ended December 31, 2023: Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships Interest Expense Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded $ 666 The effects of cash flow hedges: Gain (Loss) on cash flow hedging relationships: Interest rate derivatives: Amount of gain (loss) reclassified from AOCI to income ( 3 ) 173 Table of Contents (LG&E) The following table presents the fair value and the location on the Balance Sheets of derivatives not designated as hedging instruments: December 31, 2025 December 31, 2024 Assets Liabilities Assets Liabilities Current: Price Risk Management Assets/Liabilities: Interest rate derivatives (a) $ — $ 1 $ — $ — Total current — 1 — — Noncurrent: Price Risk Management Assets/Liabilities: Interest rate derivatives $ — $ 4 $ — $ 3 Total noncurrent — 4 — 3 Total derivatives $ — $ 5 $ — $ 3 (a) Current portion is included in "Other current liabilities" on the Balance Sheets. The following table presents the pre-tax effect of derivatives not designated as cash flow hedges that are recognized in income or regulatory assets: Derivative Instruments Location of Gain (Loss) 2025 2024 2023 Interest rate derivatives Regulatory assets - noncurrent $ ( 2 ) $ 4 $ — (PPL, LG&E and KU) Offsetting Derivative Instruments PPL, LG&E and KU or certain of their subsidiaries have master netting arrangements in place and also enter into agreements pursuant to which they purchase or sell certain energy and other products. Under the agreements, upon termination of the agreement as a result of a default or other termination event, the non-defaulting party typically would have a right to set off amounts owed under the agreement against any other obligations arising between the two parties (whether under the agreement or not), whether matured or contingent and irrespective of the currency, place of payment or place of booking of the obligation. PPL, LG&E and KU have elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivatives agreements. The table below summarizes the derivative positions presented in the balance sheets where a right of setoff exists under these arrangements and related cash collateral received or pledged. Assets Liabilities Eligible for Offset Eligible for Offset Gross Derivative Instruments Cash Collateral Received Net Gross Derivative Instruments Cash Collateral Pledged Net December 31, 2025 Derivatives PPL $ 6 $ 3 $ — $ 3 $ 10 $ 3 $ — $ 7 LG&E — — — — 5 — — 5 December 31, 2024 Derivatives PPL $ 9 $ 5 $ — $ 4 $ 16 $ 5 $ — $ 11 LG&E — — — — 3 — — 3 174 Table of Contents Credit Risk-Related Contingent Features Certain derivative contracts contain credit risk-related contingent features which, when in a net liability position, would permit the counterparties to require the transfer of additional collateral upon a decrease in the credit ratings of PPL, LG&E and KU or certain of their subsidiaries. Most of these features would require the transfer of additional collateral or permit the counterparty to terminate the contract if the applicable credit rating were to fall below investment grade. Some of these features also would allow the counterparty to require additional collateral upon each downgrade in credit rating at levels that remain above investment grade. In either case, if the applicable credit rating were to fall below investment grade, and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent features require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization on derivative instruments in net liability positions. Additionally, certain derivative contracts contain credit risk-related contingent features that require adequate assurance of performance be provided if the other party has reasonable concerns regarding the performance of PPL's, LG&E's and KU's obligations under the contracts. A counterparty demanding adequate assurance could require a transfer of additional collateral or other security, including letters of credit, cash and guarantees from a creditworthy entity. This would typically involve negotiations among the parties. However, amounts disclosed below would represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" features. (PPL) At December 31, 2025, derivative contracts in a net liability position that contain credit risk-related contingent features was $ 5 million. The aggregate fair value of additional collateral requirements in the event of a credit downgrade below investment grade was $ 5 million. 17. Goodwill and Other Intangible Assets Goodwill (PPL) Goodwill at PPL totaled $ 2,247 million at December 31, 2025 and 2024, consisting of $ 662 million for the Kentucky Regulated segment, $ 725 million for the Rhode Island Regulated segment and $ 860 million for Corporate and Other. There were no accumulated impairment losses related to goodwill. Other Intangible Assets (PPL) The gross carrying amount and the accumulated amortization of other intangible assets were: December 31, 2025 December 31, 2024 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Subject to amortization: Contracts (a) $ 125 $ 124 $ 125 $ 116 Renewable Energy Credits 24 — 20 — Land rights and easements 445 139 432 147 Licenses and other 2 — 2 — Total subject to amortization 596 263 579 263 Not subject to amortization due to indefinite life: Land rights and easements 18 — 18 — Total not subject to amortization due to indefinite life 18 — 18 — Total $ 614 $ 263 $ 597 $ 263 (a) Gross carrying amount includes the fair value at the acquisition date of the OVEC power purchase contract with terms favorable to market recognized as a result of the 2010 acquisition of LKE by PPL. 175 Table of Contents Current intangible assets are included in "Other current assets" and long-term intangible assets are included in "Other intangibles" on the Balance Sheets. Amortization expense was as follows: 2025 2024 2023 Intangible assets with no regulatory offset $ 5 $ 5 $ 5 Intangible assets with regulatory offset 8 8 9 Total $ 13 $ 13 $ 14 Amortization expense for each of the next five years is estimated to be: 2026 2027 2028 2029 2030 Intangible assets with no regulatory offset $ 5 $ 5 $ 5 $ 5 $ 5 Intangible assets with regulatory offset 1 — — — — Total $ 6 $ 5 $ 5 $ 5 $ 5 (PPL Electric) The gross carrying amount and the accumulated amortization of other intangible assets were: December 31, 2025 December 31, 2024 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Subject to amortization: Land rights and easements $ 408 $ 145 $ 396 $ 141 Licenses and other 2 1 2 1 Total subject to amortization 410 146 398 142 Not subject to amortization due to indefinite life: Land rights and easements 18 — 18 — Total $ 428 $ 146 $ 416 $ 142 Intangible assets are shown as "Intangibles" on the Balance Sheets. Amortization expense was as follows: 2025 2024 2023 Intangible assets with no regulatory offset $ 4 $ 4 $ 4 Amortization expense for each of the next five years is estimated to be: 2026 2027 2028 2029 2030 Intangible assets with no regulatory offset $ 4 $ 4 $ 4 $ 4 $ 4 (LG&E) The gross carrying amount and the accumulated amortization of other intangible assets were: December 31, 2025 December 31, 2024 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Subject to amortization: Land rights and easements (a) $ 8 $ ( 2 ) $ 7 $ 2 OVEC power purchase agreement (b) 86 85 86 79 Total subject to amortization $ 94 $ 83 $ 93 $ 81 (a) December 31, 2025 accumulated amortization includes salvage proceeds related to a land sale in excess of the related accumulated amortization. 176 Table of Contents (b) Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 7 for additional information. Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets. Amortization expense was as follows: 2025 2024 2023 Intangible assets with regulatory offset $ 6 $ 6 $ 6 Amortization expense for each of the next five years is immaterial. (KU) The gross carrying amount and the accumulated amortization of other intangible assets were: December 31, 2025 December 31, 2024 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Subject to amortization: Land rights and easements (a) $ 30 $ ( 3 ) $ 29 $ 4 OVEC power purchase agreement (b) 39 38 39 36 Total subject to amortization $ 69 $ 35 $ 68 $ 40 (a) December 31, 2025 accumulated amortization includes salvage proceeds related to a land sale in excess of the related accumulated amortization. (b) Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 7 for additional information. Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets. Amortization expense was as follows: 2025 2024 2023 Intangible assets with regulatory offset $ 2 $ 2 $ 3 Amortization expense for each of the next five years is estimated to be immaterial. 18. Asset Retirement Obligations (PPL and PPL Electric) PPL Electric has identified legal retirement obligations for the retirement of certain transmission assets that could not be reasonably estimated due to indeterminable settlement dates. These assets are located on rights-of-way that allow the grantor to require PPL Electric to relocate or remove the assets. Since this option is at the discretion of the grantor of the right-of-way, PPL Electric is unable to determine when these events may occur. (PPL, LG&E and KU) PPL's, LG&E's and KU's ARO liabilities are primarily related to CCR closure costs. See Note 12 for information on the CCR rule. LG&E and RIE also have AROs related to natural gas mains and wells. LG&E's and KU's transmission and distribution lines largely operate under perpetual property easement agreements, which do not generally require restoration upon removal of the property. Therefore, no material AROs are recorded for transmission and distribution assets. For LG&E, KU, and RIE, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal. 177 Table of Contents The changes in the carrying amounts of AROs were as follows: PPL LG&E KU 2025 2024 2025 2024 2025 2024 ARO at beginning of period $ 157 $ 158 $ 84 $ 85 $ 64 $ 66 Accretion 8 8 4 4 4 4 Obligations incurred — 9 — 3 — 6 Changes in estimated timing or cost 2 4 — 3 2 1 Obligations settled ( 26 ) ( 24 ) ( 13 ) ( 11 ) ( 13 ) ( 13 ) Other ( 1 ) 2 — — — — ARO at end of period $ 140 $ 157 $ 75 $ 84 $ 57 $ 64 19. Accumulated Other Comprehensive Income (Loss) (PPL) The after-tax changes in AOCI by component for the years ended December 31 were as follows: Unrealized gains (losses) on qualifying derivatives Defined benefit plans Equity investees' AOCI Prior service costs Actuarial gain (loss) Total PPL December 31, 2022 $ 3 $ 2 $ ( 5 ) $ ( 124 ) $ ( 124 ) Amounts arising during the year — 1 — ( 41 ) ( 40 ) Reclassifications from AOCI 3 — 1 ( 3 ) 1 Net OCI during the year 3 1 1 ( 44 ) ( 39 ) December 31, 2023 $ 6 $ 3 $ ( 4 ) $ ( 168 ) $ ( 163 ) Amounts arising during the year — 1 — ( 22 ) ( 21 ) Reclassifications from AOCI 3 — 1 ( 4 ) — Net OCI during the year 3 1 1 ( 26 ) ( 21 ) December 31, 2024 $ 9 $ 4 $ ( 3 ) $ ( 194 ) $ ( 184 ) Amounts arising during the year 1 ( 1 ) — ( 20 ) ( 20 ) Reclassifications from AOCI 2 — 1 ( 1 ) 2 Net OCI during the year 3 ( 1 ) 1 ( 21 ) ( 18 ) December 31, 2025 $ 12 $ 3 $ ( 2 ) $ ( 215 ) $ ( 202 ) The following table presents PPL's gains (losses) and related income taxes for reclassifications from AOCI for the years ended December 31, 2025, 2024 and 2023. The defined benefit plan components of AOCI are not reflected in their entirety in the statement of income; rather, they are included in the computation of net periodic defined benefit costs (credits) and subject to capitalization. See Note 10 for additional information. PPL Details about AOCI 2025 2024 2023 Affected Line Item on the Statements of Income Qualifying derivatives Interest rate derivatives $ ( 3 ) $ ( 3 ) $ ( 3 ) Interest Expense Total Pre-tax ( 3 ) ( 3 ) ( 3 ) Income Taxes 1 — — Total After-tax ( 2 ) ( 3 ) ( 3 ) Defined benefit plans Prior service costs ( 1 ) ( 1 ) ( 2 ) Net actuarial loss 2 4 3 Total Pre-tax 1 3 1 Income Taxes ( 1 ) — 1 Total After-tax — 3 2 Total reclassifications during the year $ ( 2 ) $ — $ ( 1 ) 178 Table of Contents 20. New Accounting Guidance Pending Adoption (All Registrants) Disaggregation of Income Statement Expenses In November 2024, the FASB issued guidance which requires public business entities to provide in the notes to financial statements specified information about certain costs and expenses. This includes the disclosure of amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, and (e) depreciation, depletion, and amortization recognized as part of oil and gas-producing activities included in each relevant income statement expense caption. A relevant expense caption is an expense caption included on the face of the income statement within continuing operations that contains any of the specified expense categories (a)-(e). A qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated must also be disclosed. Additionally, public business entities must disclose the total amount of selling expenses and, in annual reporting periods, the entity's definition of selling expenses. For public business entities, this guidance will be applied on a prospective basis. Retrospective application is permitted. This guidance will be effective for annual periods beginning after December 15, 2026, and interim periods reporting periods beginning after December 15, 2027. Early adoption is permitted. Adoption of this guidance will result in additional disclosures. The Registrants plan to adopt the standard retrospectively effective for the year ending December 31, 2027. Accounting for Internal-Use Software In September 2025, the FASB issued guidance to clarify and modernize the accounting for costs related to internal-use software. This includes 1) eliminating the traditional stage-based model and requiring entities to start capitalizing software costs when (a) management has authorized/committed to funding the software project and (b) it is probable that the project will be completed and the software will be used to perform the function intended ("probable-to-complete recognition threshold"), 2) requiring entities to consider whether there is significant uncertainty associated with the development activities of the software when evaluating the probable-to-complete recognition threshold, and 3) clarifying disclosure requirements. This guidance can be applied on either a prospective, modified, or retrospective basis and will be effective for annual periods beginning after December 15, 2027 and interim reporting periods within those annual reporting periods. Early adoption is permitted. The Registrants are currently assessing the impact of adopting this guidance. 179 Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company None.