Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31,

PPL Corporation and Subsidiaries

(Millions of Dollars, except share data)


	2024		2023		2022
Operating Revenues	$	8,462	$	8,312	$	7,902

Operating Expenses
Operation
Fuel	783		733		931
Energy purchases	1,679		1,841		1,686
Other operation and maintenance	2,607		2,462		2,398
Depreciation	1,279		1,254		1,181
Taxes, other than income	374		392		332
Total Operating Expenses	6,722		6,682		6,528

Operating Income	1,740		1,630		1,374

Other Income (Expense) - net (Note 14)	114		(40)		54

Interest Expense	738		666		513

Income from Continuing Operations Before Income Taxes	1,116		924		915

Income Taxes	228		184		201

Income from Continuing Operations After Income Taxes	888		740		714

Income from Discontinued Operations (net of income taxes) (Note 9)	—		—		42

Net Income	$	888	$	740	$	756

Earnings Per Share of Common Stock:
Basic
Income from Continuing Operations After Income Taxes	$	1.20	$	1.00	$	0.97
Income from Discontinued Operations (net of income taxes)	—		—		0.06
Net Income Available to PPL Common Shareowners	$	1.20	$	1.00	$	1.03

Diluted
Income from Continuing Operations After Income Taxes	$	1.20	$	1.00	$	0.96
Income from Discontinued Operations (net of income taxes)	—		—		0.06
Net Income Available to PPL Common Shareowners	$	1.20	$	1.00	$	1.02

Weighted-Average Shares of Common Stock Outstanding (in thousands)
Basic	737,756		737,036		736,027
Diluted	739,853		738,166		736,902

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

FOR THE YEARS ENDED DECEMBER 31,

PPL Corporation and Subsidiaries

(Millions of Dollars)


	2024		2023		2022
Net income	$	888	$	740	$	756

Other comprehensive income (loss):
Amounts arising during the period - gains (losses), net of tax (expense) benefit:



Equity investees' other comprehensive income (loss), net tax of $0, $0, $0	1		1		2
Defined benefit plans:
Prior service costs, net of tax of $0, $0, $0	—		—		(1)
Net actuarial gain (loss), net of tax of $8, $15, ($2)	(22)		(41)		11
Reclassifications from AOCI - (gains) losses, net of tax expense (benefit):

Qualifying derivatives, net of tax of $0, $0, ($1)	3		3		2

Defined benefit plans:
Prior service costs, net of tax of $0, ($1), ($1)	1		1		2
Net actuarial (gain) loss, net of tax of $0, $0, ($7)	(4)		(3)		17






Total other comprehensive income (loss)	(21)		(39)		33

Comprehensive income	$	867	$	701	$	789

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,

PPL Corporation and Subsidiaries

(Millions of Dollars)


	2024		2023		2022
Cash Flows from Operating Activities
Net income	$	888	$	740	$	756
Income from discontinued operations (net of income taxes)	—		—		(42)
Income from continuing operations (net of income taxes)	888		740		714
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation	1,279		1,254		1,181
Amortization	78		81		52
Defined benefit plans - expense (income)	(72)		(73)		(16)
Deferred income taxes and investment tax credits	196		322		179

Stock compensation expense	46		33		37
Loss on sale of Safari Holdings	—		—		60


Other	(17)		(29)		14
Change in current assets and current liabilities
Accounts receivable	254		(170)		(176)
Accounts payable	(41)		(72)		358
Unbilled revenues	(57)		128		(197)
Fuel, materials and supplies	(2)		(60)		(90)
Prepayments	(34)		1		(13)



Taxes payable	(27)		6		(80)


Regulatory assets and liabilities, net	(68)		(37)		(119)
Accrued interest	33		27		1
Other	(65)		38		(76)
Other operating activities
Defined benefit plans - funding	(10)		(13)		(12)

Proceeds from transfer of excess benefit plan funds	13		—		—
Other assets	(96)		(69)		(126)
Other liabilities	42		(349)		39


Net cash provided by operating activities	2,340		1,758		1,730
Cash Flows from Investing Activities
Expenditures for property, plant and equipment	(2,805)		(2,390)		(2,155)



Proceeds from sale of Safari Holdings, net of cash divested	—		—		146

Acquisition of Narragansett Electric, net of cash acquired	—		—		(3,660)
Other investing activities	(13)		7		15


Net cash used in investing activities	(2,818)		(2,383)		(5,654)
Cash Flows from Financing Activities
Issuance of long-term debt	1,894		3,252		850
Retirement of long-term debt	—		(1,854)		(264)




Payment of common stock dividends	(747)		(704)		(787)





Net increase (decrease) in short-term debt	(689)		7		916
Other financing activities	(23)		(51)		(6)



Net cash provided by financing activities	435		650		709


Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(43)		25		(3,215)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	382		357		3,572
Cash, Cash Equivalents and Restricted Cash at End of Period	$	339	$	382	$	357

Supplemental Disclosures of Cash Flow Information
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	670	$	604	$	462
Income taxes - net	$	(123)	$	281	$	163
Significant non-cash transactions:
Accrued expenditures for property, plant and equipment at December 31,	$	358	$	220	$	269

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,

PPL Corporation and Subsidiaries

(Millions of Dollars, shares in thousands)


	2024		2023
Assets
Current Assets
Cash and cash equivalents	$	306	$	331
Accounts receivable (less reserve: 2024, $147; 2023, $123)
Customer	961		950
Other	76		271
Unbilled revenues (less reserve: 2024, $6; 2023, $4)	485		428
Fuel, materials and supplies	511		505
Prepayments	136		103
Regulatory assets	320		293
Other current assets	85		51

Total Current Assets	2,880		2,932

Property, Plant and Equipment
Regulated utility plant	40,391		38,608
Less: accumulated depreciation - regulated utility plant	9,682		9,156
Regulated utility plant, net	30,709		29,452
Non-regulated property, plant and equipment	79		72
Less: accumulated depreciation - non-regulated property, plant and equipment	29		23
Non-regulated property, plant and equipment, net	50		49
Construction work in progress	2,390		1,917
Property, Plant and Equipment, net	33,149		31,418

Other Noncurrent Assets
Regulatory assets	2,060		1,874
Goodwill	2,247		2,247
Other intangibles	314		306
Other noncurrent assets (less reserve for accounts receivable: 2024, $1; 2023, $2)	419		459
Total Other Noncurrent Assets	5,040		4,886

Total Assets	$	41,069	$	39,236

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,

PPL Corporation and Subsidiaries

(Millions of Dollars, shares in thousands)


	2024		2023
Liabilities and Equity
Current Liabilities
Short-term debt	$	303	$	992
Long-term debt due within one year	551		1
Accounts payable	1,196		1,104
Taxes	103		130
Interest	157		124
Dividends	186		173
Regulatory liabilities	223		225
Other current liabilities	614		591

Total Current Liabilities	3,333		3,340

Long-term Debt	15,952		14,611

Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes	3,356		3,105
Investment tax credits	111		114
Accrued pension obligations	317		275
Asset retirement obligations	136		133
Regulatory liabilities	3,335		3,340
Other deferred credits and noncurrent liabilities	452		385
Total Deferred Credits and Other Noncurrent Liabilities	7,707		7,352

Commitments and Contingent Liabilities (Notes 7 and 12)

Equity
Common stock - $0.01 par value (a)	8		8
Additional paid-in capital	12,346		12,326
Treasury stock	(928)		(948)
Earnings reinvested	2,835		2,710
Accumulated other comprehensive loss	(184)		(163)


Total Equity	14,077		13,933

Total Liabilities and Equity	$	41,069	$	39,236

(a)1,560,000 shares authorized; 770,215 shares issued and 738,033 shares outstanding at December 31, 2024. 1,560,000 shares authorized; 770,013 shares issued and 737,130 shares outstanding at December 31, 2023.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

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, 2021	735,112	$	8	$	12,303	$	(1,003)	$	2,572	$	(157)	$	—	$	13,723
Common stock issued	123			5										5
Treasury stock issued	1,252					36								36

Stock-based compensation				9										9
Net income								756						756
Dividends and dividend equivalents (b)								(647)						(647)
Preferred stock												3		3
Other comprehensive income (loss)										33				33

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

(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, 2024, 2023 and 2022 were: $1.03, $0.960 and $0.875.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

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CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,

PPL Electric Utilities Corporation and Subsidiaries

(Millions of Dollars)


	2024		2023		2022
Operating Revenues	$	2,876	$	3,008	$	3,030

Operating Expenses
Operation
Energy purchases	721		992		1,048

Other operation and maintenance	705		605		605
Depreciation	401		397		393
Taxes, other than income	131		143		149
Total Operating Expenses	1,958		2,137		2,195

Operating Income	918		871		835

Other Income (Expense) - net (Note 14)	45		39		30

Interest Income from Affiliate	33		—		5

Interest Expense	246		223		171

Income Before Income Taxes	750		687		699

Income Taxes	176		168		174

Net Income (a)	$	574	$	519	$	525

(a)Net income equals comprehensive income.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,

PPL Electric Utilities Corporation and Subsidiaries

(Millions of Dollars)


	2024		2023		2022
Cash Flows from Operating Activities
Net income	$	574	$	519	$	525
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation	401		397		393
Amortization	45		41		22
Defined benefit plans expense (income)	(39)		(42)		(23)
Deferred income taxes and investment tax credits	129		46		91
Other	1		(24)		(11)
Change in current assets and current liabilities
Accounts receivable	89		(78)		(47)
Accounts payable	64		13		46
Unbilled revenues	(10)		75		(95)
Materials and supplies	6		(30)		(11)
Prepayments	(32)		2		(2)
Regulatory assets and liabilities, net	(101)		(38)		(59)
Taxes payable	(49)		15		5
Accrued interest	12		8		—
Other	(25)		9		(19)
Other operating activities
Defined benefit plans - funding	—		(5)		—
Other assets	(32)		3		(47)
Other liabilities	9		1		(11)
Net cash provided by operating activities	1,042		912		757

Cash Flows from Investing Activities
Expenditures for property, plant and equipment	(1,229)		(956)		(886)
Expenditures for intangible assets	(9)		(6)		(2)
Net (increase) decrease in notes receivable from affiliate	(222)		—		499
Other investing activities	5		4		2
Net cash used in investing activities	(1,455)		(958)		(387)

Cash Flows from Financing Activities
Issuance of long-term debt	649		1,329		250
Retirement of long-term debt	—		(1,240)		(250)
Contributions from parent	688		206		—
Payment of common stock dividends to parent	(375)		(323)		(340)
Return of capital to parent	(60)		(250)		(170)
Net increase (decrease) in short-term debt	(509)		364		145
Debt issuance costs	(7)		(14)		—
Other financing activities	—		—		(1)
Net cash provided by (used in) financing activities	386		72		(366)

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(27)		26		4
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	51		25		21
Cash, Cash Equivalents and Restricted Cash at End of Period	$	24	$	51	$	25

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest - net of amount capitalized	$	224	$	205	$	164
Income taxes - net	$	83	$	92	$	111
Significant non-cash transactions:
Accrued expenditures for property, plant and equipment at December 31,	$	173	$	122	$	133

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,

PPL Electric Utilities Corporation and Subsidiaries

(Millions of Dollars, shares in thousands)


	2024		2023
Assets
Current Assets
Cash and cash equivalents	$	24	$	51
Accounts receivable (less reserve: 2024, $37; 2023, $46)
Customer	353		434
Other	8		8
Accounts receivable from affiliates	10		10
Notes receivable from affiliate	222		—
Unbilled revenues (less reserve: 2024, $3; 2023, $2)	159		149
Materials and supplies	104		99
Prepayments	74		44
Regulatory assets	133		57
Other current assets	30		17
Total Current Assets	1,117		869

Property, Plant and Equipment
Regulated utility plant	16,469		15,575
Less: accumulated depreciation - regulated utility plant	4,052		3,822
Regulated utility plant, net	12,417		11,753
Construction work in progress	898		680
Property, Plant and Equipment, net	13,315		12,433

Other Noncurrent Assets
Regulatory assets	673		598
Intangibles	274		269

Other noncurrent assets (less reserve for accounts receivable: 2024, $1; 2023, $2)	96		125
Total Other Noncurrent Assets	1,043		992

Total Assets	$	15,475	$	14,294

The accompanying Notes to Financial Statements are an integral part of the financial statements.

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,

PPL Electric Utilities Corporation and Subsidiaries

(Millions of Dollars, shares in thousands)


	2024		2023
Liabilities and Equity
Current Liabilities
Short-term debt	$	—	$	509

Accounts payable	565		454
Accounts payable to affiliates	44		44
Taxes	2		51
Interest	55		43

Regulatory liabilities	57		91
Other current liabilities	83		100
Total Current Liabilities	806		1,292

Long-term Debt	5,214		4,567

Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes	1,726		1,573

Regulatory liabilities	839		836
Other deferred credits and noncurrent liabilities	160		123
Total Deferred Credits and Other Noncurrent Liabilities	2,725		2,532

Commitments and Contingent Liabilities (Notes 7 and 12)

Equity
Common stock - no par value (a)	364		364
Additional paid-in capital	4,668		4,040
Earnings reinvested	1,698		1,499
Total Equity	6,730		5,903

Total Liabilities and Equity	$	15,475	$	14,294

(a)170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2024 and December 31, 2023.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

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, 2021	66,368	$	364	$	4,254	$	1,118	$	5,736
Net income						525		525

Return of capital to parent				(170)				(170)
Dividends declared on common stock						(340)		(340)
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 on common stock						(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 on common stock						(375)		(375)
December 31, 2024	66,368	$	364	$	4,668	$	1,698	$	6,730

(a)Shares in thousands. All common shares of PPL Electric stock are owned by PPL.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

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STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,

Louisville Gas and Electric Company

(Millions of Dollars)


	2024		2023		2022
Operating Revenues
Retail and wholesale	$	1,617	$	1,580	$	1,762
Electric revenue from affiliate	31		33		36
Total Operating Revenues	1,648		1,613		1,798

Operating Expenses
Operation
Fuel	308		286		346
Energy purchases	151		168		245
Energy purchases from affiliate	20		12		25
Other operation and maintenance	349		364		416
Depreciation	305		302		298
Taxes, other than income	49		48		48
Total Operating Expenses	1,182		1,180		1,378

Operating Income	466		433		420

Other Income (Expense) - net (Note 14)	12		3		4

Interest Income from Affiliates	1		1		—

Interest Expense	105		102		89

Income Before Income Taxes	374		335		335

Income Taxes	77		69		63

Net Income (a)	$	297	$	266	$	272

(a)Net income equals comprehensive income.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,

Louisville Gas and Electric Company

(Millions of Dollars)


	2024		2023		2022
Cash Flows from Operating Activities
Net income	$	297	$	266	$	272
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation	305		302		298
Amortization	16		14		5

Deferred income taxes and investment tax credits	6		(14)		(6)
Other	(6)		(7)		4
Change in current assets and current liabilities
Accounts receivable	(25)		40		(19)
Accounts receivable from affiliates	(11)		7		(5)
Accounts payable	12		(40)		22
Accounts payable to affiliates	15		(8)		30
Unbilled revenues	1		24		(32)
Fuel, materials and supplies	(13)		24		(28)
Regulatory assets and liabilities, net	(3)		25		17

Taxes payable	(1)		—		7
Accrued interest	—		5		—
Other	—		1		5
Other operating activities
Defined benefit plans - funding	—		1		(2)

Expenditures for asset retirement obligations	(11)		(11)		(13)
Other assets	(27)		(21)		(8)
Other liabilities	(1)		1		(4)
Net cash provided by operating activities	554		609		543
Cash Flows from Investing Activities
Expenditures for property, plant and equipment	(444)		(378)		(371)
Other investing activities	—		—		11
Net cash used in investing activities	(444)		(378)		(360)
Cash Flows from Financing Activities
Net increase (decrease) in notes payable with affiliates	43		—		(324)
Issuance of long-term debt	—		464		300
Retirement of long-term debt	—		(300)		—


Payment of common stock dividends to parent	(187)		(166)		(275)
Contributions from parent	65		67		90
Return of capital to parent	(76)		(161)		—


Net increase (decrease) in short-term debt	25		(179)		110
Other financing activities	—		(5)		—
Net cash used in financing activities	(130)		(280)		(99)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(20)		(49)		84
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	44		93		9
Cash, Cash Equivalents and Restricted Cash at End of Period	$	24	$	44	$	93

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest - net of amount capitalized	$	101	$	93	$	83
Income taxes - net	$	73	$	84	$	57
Significant non-cash transactions:
Accrued expenditures for property, plant and equipment at December 31,	$	64	$	30	$	43

The accompanying Notes to Financial Statements are an integral part of the financial statements.

BALANCE SHEETS AT DECEMBER 31,

Louisville Gas and Electric Company

(Millions of Dollars, shares in thousands)


	2024		2023
Assets
Current Assets
Cash and cash equivalents	$	8	$	18
Accounts receivable (less reserve: 2024, $3; 2023, $6)
Customer	134		116
Other	23		17
Unbilled revenues (less reserve: 2024, $0; 2023, $0)	87		88
Accounts receivable from affiliates	40		29
Fuel, materials and supplies	157		143
Prepayments	9		11

Regulatory assets	8		7
Other current assets	2		—

Total Current Assets	468		429

Property, Plant and Equipment
Regulated utility plant	7,748		7,669
Less: accumulated depreciation - regulated utility plant	1,643		1,549
Regulated utility plant, net	6,105		6,120
Construction work in progress	443		312
Property, Plant and Equipment, net	6,548		6,432

Other Noncurrent Assets
Regulatory assets	491		395
Goodwill	389		389
Other intangibles	12		18
Other noncurrent assets	84		90
Total Other Noncurrent Assets	976		892

Total Assets	$	7,992	$	7,753

The accompanying Notes to Financial Statements are an integral part of the financial statements.

BALANCE SHEETS AT DECEMBER 31,

Louisville Gas and Electric Company

(Millions of Dollars, shares in thousands)


	2024		2023
Liabilities and Equity
Current Liabilities
Short-term debt	$	25	$	—
Notes payable with affiliates	43		—
Long-term debt due within one year	300		—
Accounts payable	158		115
Accounts payable to affiliates	64		49
Customer deposits	36		34
Taxes	40		41

Regulatory liabilities	14		16
Interest	21		21
Asset retirement obligations	11		13
Other current liabilities	50		48
Total Current Liabilities	762		337

Long-term Debt	2,171		2,469

Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes	803		776
Investment tax credits	30		31
Price risk management liabilities	3		6

Asset retirement obligations	73		72
Regulatory liabilities	815		827
Other deferred credits and noncurrent liabilities	64		63
Total Deferred Credits and Other Noncurrent Liabilities	1,788		1,775

Commitments and Contingent Liabilities (Notes 7 and 12)

Equity
Common stock - no par value (a)	424		424
Additional paid-in capital	1,982		1,993
Earnings reinvested	865		755
Total Equity	3,271		3,172

Total Liabilities and Equity	$	7,992	$	7,753

(a)75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2024 and December 31, 2023.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

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, 2021	21,294	$	424	$	1,997	$	658	$	3,079
Net income						272		272
Capital contributions from parent				90				90
Cash dividends declared on common stock						(275)		(275)
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 on common stock						(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 on common stock						(187)		(187)
December 31, 2024	21,294	$	424	$	1,982	$	865	$	3,271

(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.

(THIS PAGE LEFT BLANK INTENTIONALLY.)

STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,

Kentucky Utilities Company

(Millions of Dollars)


	2024		2023		2022
Operating Revenues
Retail and wholesale	$	1,944	$	1,872	$	2,049
Electric revenue from affiliate	20		12		25
Total Operating Revenues	1,964		1,884		2,074

Operating Expenses
Operation
Fuel	476		447		585
Energy purchases	25		24		28
Energy purchases from affiliate	31		33		36
Other operation and maintenance	413		427		487
Depreciation	403		392		386
Taxes, other than income	49		45		45
Total Operating Expenses	1,397		1,368		1,567

Operating Income	567		516		507

Other Income (Expense) - net (Note 14)	15		8		8

Interest Expense	137		134		117

Interest Expense from Affiliate	—		1		—

Income Before Income Taxes	445		389		398

Income Taxes	89		77		76

Net Income (a)	$	356	$	312	$	322

(a)Net income equals comprehensive income.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,

Kentucky Utilities Company

(Millions of Dollars)


	2024		2023		2022
Cash Flows from Operating Activities
Net income	$	356	$	312	$	322
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation	403		392		386
Amortization	21		20		18
Defined benefit plans - expense (income)	(5)		(5)		(4)
Deferred income taxes and investment tax credits	(15)		(10)		2
Other	(4)		(2)		3
Change in current assets and current liabilities
Accounts receivable	(21)		16		(16)

Accounts payable	(23)		(26)		26
Accounts payable to affiliates	29		(24)		37
Unbilled revenues	(5)		17		(23)
Fuel, materials and supplies	14		(17)		(41)
Regulatory assets and liabilities, net	23		25		(19)

Taxes payable	5		5		7
Accrued interest	—		5		1
Other	(5)		(4)		(3)
Other operating activities
Defined benefit plans - funding	—		—		(1)

Expenditures for asset retirement obligations	(10)		(28)		(29)
Other assets	(41)		(25)		(1)
Other liabilities	1		(4)		(4)
Net cash provided by operating activities	723		647		661
Cash Flows from Investing Activities
Expenditures for property, plant and equipment	(643)		(572)		(547)
Other investing activities	—		6		—
Net cash used in investing activities	(643)		(566)		(547)
Cash Flows from Financing Activities
Net increase (decrease) in notes payable with affiliates	73		—		(294)
Issuance of long-term debt	—		459		300
Retirement of long-term debt	—		(313)		—
Payment of common stock dividends to parent	(232)		(190)		(296)
Contributions from parent	126		76		84
Return of capital to parent	(103)		(84)		—


Net increase (decrease) in short-term debt	47		(8)		101
Other financing activities	—		(4)		(1)
Net cash used in financing activities	(89)		(64)		(106)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(9)		17		8
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	38		21		13
Cash, Cash Equivalents and Restricted Cash at End of Period	$	29	$	38	$	21

Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest - net of amount capitalized	$	135	$	125	$	112
Income taxes - net	$	102	$	78	$	78
Significant non-cash transactions:
Accrued expenditures for property, plant and equipment at December 31,	$	74	$	38	$	56

The accompanying Notes to Financial Statements are an integral part of the financial statements.

BALANCE SHEETS AT DECEMBER 31,

Kentucky Utilities Company

(Millions of Dollars, shares in thousands)


	2024		2023
Assets
Current Assets
Cash and cash equivalents	$	13	$	14
Accounts receivable (less reserve: 2024, $2; 2023, $2)
Customer	160		143
Other	22		12
Unbilled revenues (less reserve: 2024, $0; 2023, $0)	102		97

Fuel, materials and supplies	173		185
Prepayments	11		13

Regulatory assets	1		3
Other current assets	9		1

Total Current Assets	491		468

Property, Plant and Equipment
Regulated utility plant	10,419		9,896
Less: accumulated depreciation - regulated utility plant	2,652		2,476
Regulated utility plant, net	7,767		7,420
Construction work in progress	567		604
Property, Plant and Equipment, net	8,334		8,024

Other Noncurrent Assets
Regulatory assets	458		439
Goodwill	607		607
Other intangibles	28		19
Other noncurrent assets	155		157
Total Other Noncurrent Assets	1,248		1,222

Total Assets	$	10,073	$	9,714

The accompanying Notes to Financial Statements are an integral part of the financial statements.

BALANCE SHEETS AT DECEMBER 31,

Kentucky Utilities Company

(Millions of Dollars, shares in thousands)


	2024		2023
Liabilities and Equity
Current Liabilities
Short-term debt	$	140	$	93
Notes payable with affiliates	73		—
Long-term debt due within one year	250		—
Accounts payable	96		80
Accounts payable to affiliates	100		72
Customer deposits	39		35
Taxes	37		32

Regulatory liabilities	22		1
Interest	24		24
Asset retirement obligations	10		13
Other current liabilities	58		52
Total Current Liabilities	849		402

Long-term Debt	2,816		3,064

Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes	924		912
Investment tax credits	81		83

Asset retirement obligations	54		53
Regulatory liabilities	1,009		1,018
Other deferred credits and noncurrent liabilities	41		30
Total Deferred Credits and Other Noncurrent Liabilities	2,109		2,096

Commitments and Contingent Liabilities (Notes 7 and 12)

Equity
Common stock - no par value (a)	308		308
Additional paid-in capital	3,056		3,033

Earnings reinvested	935		811
Total Equity	4,299		4,152

Total Liabilities and Equity	$	10,073	$	9,714

(a) 80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2024 and December 31, 2023.

The accompanying Notes to Financial Statements are an integral part of the financial statements.

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, 2021	37,818	$	308	$	2,957	$	663	$	3,928
Net income						322		322
Capital contributions from parent				84				84
Cash dividends declared on common stock						(296)		(296)

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 on common stock						(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 on common stock						(232)		(232)

December 31, 2024	37,818	$	308	$	3,056	$	935	$	4,299

(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.

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.

On March 17, 2021, PPL WPD Limited entered into a share purchase agreement to sell PPL's U.K. utility business, which prior to its sale substantially represented PPL's U.K. Regulated segment, to a subsidiary of National Grid plc. The sale was completed on June 14, 2021. The results of operations of the U.K. utility business are classified as Discontinued Operations on PPL's Statements of Income for 2022. PPL has elected to separately report the cash flows of continuing and discontinued operations on the Statements of Cash Flows for 2022. Unless otherwise noted, the notes to these financial statements exclude amounts related to discontinued operations. See Note 9 for additional information.

On May 25, 2022, PPL Rhode Island Holdings, a wholly-owned subsidiary of PPL, acquired 100% of the outstanding shares of common stock of Narragansett Electric from National Grid U.S., a subsidiary of National Grid plc. Narragansett Electric, whose service area covers substantially all of Rhode Island, is primarily engaged in the transmission, distribution and sale of electricity and the distribution and sale of natural gas. The results of Narragansett Electric are included in the consolidated results of PPL from the date of the acquisition. Following the closing of the acquisition, Narragansett Electric provides services doing business under the name Rhode Island Energy (RIE). See Note 9 for additional information.

(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." 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.

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.

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
2024	$	130	$	109	$	85	$	154	(c)
2023	95		87		52		130		(c)
2022	69		78		52		95		(c)

PPL Electric
2024	$	50	$	56	$	65	$	41	(b)
2023	33		52		35		50		(b)
2022	35		27		29		33		(b)

LG&E
2024	$	6	$	4	$	7	$	3
2023	4		4		2		6
2022	3		6		5		4


			Additions
	Balance at Beginning of Period		Charged to Income		Deductions (a)		Balance at End of Period
KU
2024	$	2	$	4	$	4	$	2
2023	3		3		4		2
2022	3		6		6		3

(a)Primarily related to uncollectible accounts written off.

(b)Includes $2 million, $3 million and $3 million related to other accounts receivable at December 31, 2024, 2023 and 2022.

(c)Includes $39 million, $41 million and $36 million related to other accounts receivable at December 31, 2024, 2023 and 2022.

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 nonfinancial 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.

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:


	2024		2023		2022
PPL	$	20	$	12	$	7
PPL Electric	9		7		5
LG&E	3		1		—
KU	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.

Following are the weighted-average annual rates of depreciation, for regulated utility plant, for the years ended December 31:


	2024		2023		2022
PPL	3.20	%	3.26	%	3.21	%
PPL Electric	2.52	%	2.62	%	2.75	%
LG&E	4.02	%	4.00	%	4.16	%
KU	3.86	%	3.95	%	4.01	%

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 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.

Goodwill recognized upon the acquisition of Narragansett Electric was assigned for impairment testing by PPL to its reporting units expected to benefit from the acquisition, which were the Rhode Island Regulated reporting unit, the Pennsylvania Regulated reporting unit and the Kentucky Regulated reporting unit. See Note 9 for additional information regarding the acquisition.

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, 2024, PPL, for its reporting units, and individually, LG&E and KU, elected to perform the qualitative step zero evaluation of goodwill. These evaluations considered the excess of fair value over the carrying value of each reporting unit that was calculated during step one of the quantitative impairment tests performed in the fourth quarter of 2022, and the relevant events and circumstances that occurred since those tests were performed including:

current year financial performance versus the prior year,
changes in planned capital expenditures,
the consistency of forecasted free cash flows,
earnings quality and sustainability,
changes in market participant discount rates,
changes in long-term growth rates,
changes in PPL's market capitalization, and
the overall economic and regulatory environments in which these regulated entities operate.

Based on these evaluations, management concluded it was not more likely than not that the fair value of these reporting units was less than their carrying value. As such, the step one quantitative impairment test was not performed and no impairment was recognized.

(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 LG&E, KU, RIE and PPL Electric, 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.

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 domestic 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, 2024, 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 to the Financial Statements for income tax disclosures.

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 domestic 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 receivables (payables) were recorded:


	2024		2023
PPL Electric	$	(2)	$	(21)
LG&E	(2)		(5)
KU	(5)		(3)

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 fuel adjustment clauses and gas supply clause.

"Fuel, materials and supplies" on the Balance Sheets consisted of the following at December 31:


	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


	2023
	PPL		PPL Electric		LG&E		KU
Fuel	$	144	$	—	$	50	$	94
Natural gas stored underground	58		—		34		—
Materials and supplies	303		99		59		91
Total	$	505	$	99	$	143	$	185

(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 Reportable Segment Disclosures

Effective December 31, 2024, the Registrants retrospectively adopted accounting guidance to improve segment disclosures. The guidance requires enhanced disclosures about significant segment expenses. The standard also requires public entities to disclose the title and position of the Chief Operating Decision Maker (CODM) and explain how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Certain segment-related disclosures that previously were required only on an annual basis will be required to be disclosed in interim periods. In addition, public entities that have a single reportable segment are now required to provide segment disclosures.

The adoption of this guidance resulted in the Registrants including the required additional disclosures within the notes to the financial statements. See Note 2 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 transmission, distribution and sale of natural gas.

The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric.

The Rhode Island Regulated segment includes the regulated electricity transmission and distribution and natural gas distribution operations of RIE, which was acquired in May of 2022.

"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 Rhode Island Energy and the financial results of Safari Energy, prior to its sale on November 1, 2022. "Corporate and Other" is presented to reconcile segment information to PPL's consolidated results and is not a reportable segment.

PPL's CODM is the Corporate Leadership Council (CLC), which is a management committee that is comprised of the Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Chief Technology Officer, Chief Human Resources Officer and Chief Legal Officer.

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.

The tables below provide information about PPL’s segments and include the reconciliation 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

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)		(78)		(24)		(131)
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 the reconciliation 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


	Kentucky Regulated		Pennsylvania Regulated		Rhode Island Regulated		Total
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.

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 tables below provide information about PPL’s segments and include the reconciliation to consolidated net income for the year ended December 31, 2022:


	Kentucky Regulated		Pennsylvania Regulated		Rhode Island Regulated		Total
Operating Revenues from external customers (a)	$	3,811	$	3,030	$	1,038	$	7,879
Reconciliation of revenue
Corporate and other revenues							23
Total consolidated revenues							$	7,902

Less:
Fuel	931		—		—		931
Energy Purchases	273		1,048		365		1,686
Operation and maintenance	959		605		531		2,095
Depreciation	685		393		92		1,170
Taxes, other than income	92		149		92		333
Other (income) expense - net	(12)		(35)		(23)		(70)
Interest expense	205		171		39		415
Income taxes	129		174		(14)		289
Segment net income	$	549	$	525	$	(44)	$	1,030

Reconciliation of segment profit or loss to consolidated net income
Corporate and other net loss							(316)
Income from discontinued operations (Note 9)							42
Net Income							$	756

(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, 2022 are as follows:


	Kentucky Regulated		Pennsylvania Regulated		Rhode Island Regulated		Total Segments		Corporate and Other		Consolidated Total
Other Segment Disclosures
Amortization (a)	$	23	$	22	$	2	$	47	$	5	$	52
Deferred income taxes and investment tax credits (b)	6		91		39		136		43		179
Expenditures for long lived assets	917		889		268		2,074		84		2,158

(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,
	2024		2023
Total Assets
Kentucky Regulated	$	17,626	$	17,029
Pennsylvania Regulated	15,475		14,294
Rhode Island Regulated	7,055		6,515
Corporate and Other (a)	913		1,398
Total	$	41,069	$	39,236

(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.

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. 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. 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 rendered throughout the month, rather than bills being rendered 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 rendered throughout the month, rather than bills being rendered 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.

(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:


	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


	2022
	PPL		PPL Electric		LG&E		KU
Operating Revenues (a)(b)	$	7,902	$	3,030	$	1,798	$	2,074
Revenues derived from:
Alternative revenue programs (c)	(92)		(56)		9		5
Other (d)	(24)		(14)		(6)		(4)
Revenues from Contracts with Customers	$	7,786	$	2,960	$	1,801	$	2,075

(a)PPL includes $2,024 million, $1,851 million and $1,038 million for the twelve months ended December 31, 2024, 2023, and 2022 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, 2024, net metering of $175 million was included in Energy purchases on PPL's Statement of Income. For the years ended December 31, 2023 and 2022, $146 million and $79 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 in the table above 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
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



	Residential		Commercial		Industrial		Other (a)		Wholesale - municipality		Wholesale - other (b)		Transmission		Revenues from Contracts with Customers
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

2022
PA Regulated	$	1,647	$	491	$	85	$	54	$	—	$	—	$	683	$	2,960
RI Regulated	299		101		9		478		—		—		101		988
KY Regulated	1,637		1,068		662		323		28		97		—		3,815
Corp and Other	—		—		—		23		—		—		—		23
Total PPL	$	3,583	$	1,660	$	756	$	878	$	28	$	97	$	784	$	7,786

PPL Electric
2024	$	1,502	$	418	$	47	$	57	$	—	$	—	$	818	$	2,842
2023	$	1,649	$	444	$	55	$	54	$	—	$	—	$	796	$	2,998
2022	$	1,647	$	491	$	85	$	54	$	—	$	—	$	683	$	2,960

LG&E
2024	$	754	$	518	$	188	$	147	$	—	$	50	$	—	$	1,657
2023	$	751	$	517	$	189	$	104	$	—	$	47	$	—	$	1,608
2022	$	835	$	551	$	199	$	141	$	—	$	75	$	—	$	1,801

KU
2024	$	756	$	510	$	447	$	176	$	23	$	64	$	—	$	1,976
2023	$	707	$	484	$	448	$	168	$	22	$	46	$	—	$	1,875
2022	$	802	$	517	$	463	$	182	$	28	$	83	$	—	$	2,075

(a)Primarily includes revenues from pole attachments, street lighting, other public authorities and other non-core businesses. For the years ended December 31, 2023 and 2022, 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 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.

The following table shows the accounts receivable and unbilled revenues balances that were impaired for the year ended December 31:


	2024		2023		2022
PPL(a)	$	103	$	79	$	70
PPL Electric	52		47		21
LG&E	4		4		6
KU	4		2		6

(a)Includes $23 million for the twelve months ended December 31, 2022 related to the commitment to forgive customer arrearages for low-income and protected residential customers at RIE. See Note 9 for additional information.

The following table shows the balances and certain activity of contract liabilities resulting from contracts with customers:


	PPL		PPL Electric		LG&E		KU
Contract liabilities as of December 31, 2024	$	39	$	28	$	5	$	6
Contract liabilities as of December 31, 2023	43		29		6		7
Revenue recognized during the year ended December 31, 2024 that was included in the contract liability balance at December 31, 2023	26		12		6		7

Contract liabilities as of December 31, 2023	$	43	$	29	$	6	$	7
Contract liabilities as of December 31, 2022	34		23		5		6
Revenue recognized during the year ended December 31, 2023 that was included in the contract liability balance at December 31, 2022	21		10		5		6

Contract liabilities as of December 31, 2022	$	34	$	23	$	5	$	6
Contract liabilities as of December 31, 2021	42		25		6		6
Revenue recognized during the year ended December 31, 2022 that was included in the contract liability balance at December 31, 2021	25		12		6		6

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.

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 2024, 2023 or 2022.

(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 2024, 2023 or 2022.

(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 2024, 2023 or 2022.

(KU)

KU is authorized to issue up to 5,300,000 shares of preferred stock and 2,000,000 shares of preference stock without par value. KU had no preferred or preference stock issued or outstanding in 2024, 2023 or 2022.

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. Incremental non-participating securities that have a dilutive impact are detailed in the table below.

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:


	2024		2023		2022
Income (Numerator)
Income from continuing operations after income taxes	$	888	$	740	$	714
Less amounts allocated to participating securities	2		1		1
Income from continuing operations after income taxes available to PPL common shareowners - Basic and Diluted	$	886	$	739	$	713

Income from discontinued operations (net of income taxes) available to PPL common shareowners - Basic and Diluted	$	—	$	—	$	42

Net income attributable to PPL	$	888	$	740	756
Less amounts allocated to participating securities	2		1		1
Net income available to PPL common shareowners - Basic and Diluted	$	886	$	739	$	755

Shares of Common Stock (Denominator)
Weighted-average shares - Basic EPS	737,756		737,036		736,027

Add: Dilutive share-based payment awards (a)	2,097		1,130		875

Weighted-average shares - Diluted EPS	739,853		738,166		736,902

Basic EPS
Available to PPL common shareowners:
Income from continuing operations after income taxes	$	1.20	$	1.00	$	0.97
Income from discontinued operations (net of income taxes)	—		—		0.06
Net Income available to PPL common shareowners	$	1.20	$	1.00	$	1.03

Diluted EPS
Available to PPL common shareowners:
Income from continuing operations after income taxes	$	1.20	$	1.00	$	0.96
Income from discontinued operations (net of income taxes)	—		—		0.06
Net Income available to PPL common shareowners	$	1.20	$	1.00	$	1.02

(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 stock-based compensation plans as follows (in thousands):


	2024	2023

DRIP	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:


			2024						2023						2022
Stock-based compensation awards			—						243						93

6. Income and Other Taxes

(PPL)

"Income from Continuing Operations Before Income Taxes" is from domestic operations.

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.

Significant components of PPL's deferred income tax assets and liabilities were as follows:


	2024		2023
Deferred Tax Assets

Deferred investment tax credits	28		28
Regulatory liabilities	133		123
Income taxes due to customers	418		436
Accrued pension and postretirement costs	112		101


State loss carryforwards	224		253

Federal and state tax credit carryforwards	24		67
Internal Revenue Code Section 197 intangibles	72		78




Contributions in aid of construction	163		149
Bad debt	37		28
Other	114		111

Valuation allowances	(224)		(245)
Total deferred tax assets	1,101		1,129

Deferred Tax Liabilities
Plant - net	3,898		3,749

Regulatory assets	432		376

Prepayments	39		47
Goodwill	38		22
Other	38		30
Total deferred tax liabilities	4,445		4,224
Net deferred tax liability	$	3,344	$	3,095

State deferred taxes are determined by entity and by jurisdiction. As a result, $12 million and $9 million of net deferred tax assets are shown as "Other noncurrent assets" on the Balance Sheets for 2024 and 2023.

At December 31, 2024, 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	$	5,011	$	224	$	(221)	2025-2044
State charitable contributions	10		1		(1)		2025-2029

Foreign capital loss	8		2		(2)		Indefinite


	Gross	Deferred Tax Asset	Valuation Allowance	Expiration
Credit carryforwards



Federal - other		14	—	2044
State recycling credit		8	—	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
2024	$	245	$	3		$	1	$	25	(a)	$	224
2023	213		54		(b)	—		22		(c)	245
2022	462		10			—		259		(d)	213

(a)In 2024, PPL recorded a $23 million decrease in a valuation allowance on a 2004 state net operating loss carryforward that expired in 2024.

(b)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.

(c)In 2023, PPL recorded a $22 million decrease in a valuation allowance on a 2003 state net operating loss carryforward that expired in 2023.

(d)In 2022, PPL recorded a $36 million decrease in a valuation allowance on a 2002 state net operating loss carryforward that expired in 2022 and a $213 million decrease in the valuation allowance due to the Pennsylvania rate change. See reconciliation of income tax table below.

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, and details of "Taxes, other than income" were as follows:


	2024		2023		2022
Income Tax Expense (Benefit)
Current - Federal (a)	$	23	$	(175)	$	(2)
Current - State	9		37		24

Total Current Expense (Benefit)	32		(138)		22
Deferred - Federal (a)	137		286		122
Deferred - State	64		48		68

Total Deferred Expense (Benefit), excluding operating loss carryforwards	201		334		190

Amortization of investment tax credit	(3)		(3)		(3)
Tax expense (benefit) of operating loss carryforwards
Deferred - Federal	1		3		2
Deferred - State	(3)		(12)		(10)
Total Tax Expense (Benefit) of Operating Loss Carryforwards	(2)		(9)		(8)
Total income tax expense (benefit)	$	228	$	184	$	201

Total income tax expense (benefit) - Federal	$	158	$	111	$	119
Total income tax expense (benefit) - State	70		73		82

Total income tax expense (benefit)	$	228	$	184	$	201

(a)In 2023, PPL purchased approximately $300 million of renewable tax credits and recorded a current tax benefit and a deferred tax expense for utilization of approximately $250 million of the credits in 2023 and prior years, per the three-year carry-back rule.

In the table above, the following income tax expense (benefit) are excluded from income taxes:


	2024		2023		2022
Discontinued operations	$	—	$	—	$	(42)




Other comprehensive income	(8)		(14)		11
Valuation allowance recorded to other comprehensive income	—		(1)		—
Total	$	(8)	$	(15)	$	(31)


	2024		2023		2022
Reconciliation of Income Tax Expense (Benefit)
Federal income tax on Income Before Income Taxes at statutory tax rate - 21%	$	234	$	194	$	192

State income taxes, net of federal income tax benefit	65		58		68
Valuation allowance adjustments (a)	2		12		9
Income tax credits (b)	(8)		(22)		(3)





Utility rate-making tax adjustments (c)	(21)		(10)		(8)
Amortization of excess deferred federal and state income taxes	(45)		(48)		(54)






Other	1		—		(3)
Total increase (decrease)	(6)		(10)		9
Total income tax expense (benefit)	$	228	$	184	$	201
Effective income tax rate	20.4%		19.9%		22.0%

(a)In 2024, 2023, and 2022, PPL recorded deferred income tax expense of $3 million, $11 million and $5 million for valuation allowances primarily related to increased Pennsylvania net operating loss carryforwards expected to be unutilized.

(b)In 2023, PPL purchased approximately $300 million of renewable tax credits and recorded a current tax benefit and a deferred tax expense for utilization of approximately $250 million of the credits in 2023 and prior years, per the three-year carry-back rule.

(c)Primarily consists of tax impacts of AFUDC equity and related depreciation across PPL utilities and flow through tax impacts. Flow through occurs when the regulator excludes deferred tax expense or benefit from recoverable costs when determining income tax expense.


	2024		2023		2022
Taxes, other than income
State gross earnings and state gross receipts	$	167	$	195	$	175


Property and other	207		197		157
Total	$	374	$	392	$	332

(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:


	2024		2023
Deferred Tax Assets
Accrued pension and postretirement costs	$	36	$	30
Contributions in aid of construction	120		105
Regulatory liabilities	40		43
Income taxes due to customers	184		191




Other	22		27
Total deferred tax assets	402		396

Deferred Tax Liabilities
Electric utility plant - net	1,934		1,810


Regulatory assets	160		119
Prepayments	30		36
Other	4		4
Total deferred tax liabilities	2,128		1,969
Net deferred tax liability	$	1,726	$	1,573

PPL Electric expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.


	2024		2023		2022
Income Tax Expense (Benefit)
Current - Federal	$	44	$	91	$	63
Current - State	4		31		20
Total Current Expense (Benefit)	48		122		83
Deferred - Federal	86		28		60
Deferred - State	42		18		31
Total Deferred Expense (Benefit), excluding operating loss carryforwards	128		46		91






Total income tax expense (benefit)	$	176	$	168	$	174

Total income tax expense (benefit) - Federal	$	130	$	119	$	123
Total income tax expense (benefit) - State	46		49		51
Total income tax expense (benefit)	$	176	$	168	$	174


	2024		2023		2022
Reconciliation of Income Tax Expense (Benefit)
Federal income tax on Income Before Income Taxes at statutory tax rate - 21%	$	158	$	144	$	147
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	47		49		54


Utility rate-making tax adjustments (a)	(16)		(9)		(7)
Amortization of excess deferred federal income taxes (b)	(10)		(11)		(12)
State income tax rate change (c)	—		—		(9)

Other	(3)		(5)		1
Total increase (decrease)	18		24		27
Total income tax expense (benefit)	$	176	$	168	$	174
Effective income tax rate	23.5%		24.5%		24.9%

(a)Primarily consists of tax impacts of AFUDC equity and related depreciation across PPL utilities and flow through tax impacts. Flow through occurs when the regulator excludes deferred tax expense or benefit from recoverable costs when determining income tax expense.

(b)In 2024, 2023, and 2022, PPL Electric recorded lower income tax expense for the amortization of excess deferred taxes that primarily resulted from the U.S. federal corporate income tax rate reduction from 35% to 21% enacted by the TCJA. This amortization represents each year's refund amount, prior to a tax gross-up, to be paid to customers for previously collected deferred taxes at higher income tax rates.


	2024		2023		2022
Taxes, other than income
State gross receipts	$	122	$	136	$	142
Property and other	9		7		7
Total	$	131	$	143	$	149

(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:


	2024		2023
Deferred Tax Assets

Contributions in aid of construction	$	18	$	18
Regulatory liabilities	18		19
Accrued pension and postretirement costs	4		3
Deferred investment tax credits	7		8
Income taxes due to customers	110		115
State tax credit carryforwards	6		8
Lease liabilities	4		4
Valuation allowances	(6)		(8)
Other	6		8
Total deferred tax assets	167		175

Deferred Tax Liabilities
Plant - net	875		877
Regulatory assets	88		67
Lease right-of-use assets	4		3
Other	3		4
Total deferred tax liabilities	970		951
Net deferred tax liability	$	803	$	776

At December 31, 2024, LG&E had $6 million of state credit carryforwards that expire in 2028 and a $6 million valuation allowance related to state credit carryforwards due to insufficient projected Kentucky taxable income.


	2024		2023		2022
Income Tax Expense (Benefit)
Current - Federal	$	60	$	70	$	60
Current - State	11		13		9
Total Current Expense (Benefit)	71		83		69
Deferred - Federal	1		(15)		(10)
Deferred - State	6		2		5
Total Deferred Expense (Benefit)	7		(13)		(5)
Amortization of investment tax credit - Federal	(1)		(1)		(1)




Total income tax expense (benefit)	$	77	$	69	$	63

Total income tax expense (benefit) - Federal	$	60	$	54	$	49
Total income tax expense (benefit) - State	17		15		14
Total income tax expense (benefit)	$	77	$	69	$	63


	2024		2023		2022
Reconciliation of Income Tax Expense (Benefit)
Federal income tax on Income Before Income Taxes at statutory tax rate - 21%	$	79	$	70	$	70
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	14		13		13
Amortization of excess deferred federal and state income taxes	(13)		(13)		(18)


Other	(3)		(1)		(2)
Total increase (decrease)	(2)		(1)		(7)
Total income tax expense (benefit)	$	77	$	69	$	63
Effective income tax rate	20.6%		20.6%		18.8%


	2024		2023		2022
Taxes, other than income
Property and other	$	49	$	48	$	48
Total	$	49	$	48	$	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:


	2024		2023
Deferred Tax Assets

Contributions in aid of construction	$	12	$	10
Regulatory liabilities	29		23

Deferred investment tax credits	20		21
Income taxes due to customers	124		131
State tax credit carryforwards	4		4
Lease liabilities	6		5
Valuation allowances	(2)		(2)
Other	4		5
Total deferred tax assets	197		197

Deferred Tax Liabilities
Plant - net	1,053		1,045
Regulatory assets	55		50
Pension and postretirement costs	6		7
Lease right-of-use assets	6		5
Other	1		2
Total deferred tax liabilities	1,121		1,109
Net deferred tax liability	$	924	$	912

At December 31, 2024, KU had $4 million of state credit carryforwards of which $2 million will expire in 2028 and $2 million that has an indefinite carryforward period. At December 31, 2024, KU had a $2 million valuation allowance related to state credit carryforwards due to insufficient projected Kentucky taxable income.


	2024		2023		2022
Income Tax Expense (Benefit)
Current - Federal	$	87	$	73	$	63
Current - State	17		13		11
Total Current Expense (Benefit)	104		86		74
Deferred - Federal	(15)		(11)		(3)
Deferred - State	2		4		7
Total Deferred Expense (Benefit)	(13)		(7)		4
Amortization of investment tax credit - Federal	(2)		(2)		(2)



Total income tax expense (benefit)	$	89	$	77	$	76

Total income tax expense (benefit) - Federal	$	70	$	60	$	58
Total income tax expense (benefit) - State	19		17		18
Total income tax expense (benefit)	$	89	$	77	$	76


	2024		2023		2022
Reconciliation of Income Tax Expense (Benefit)
Federal income tax on Income Before Income Taxes at statutory tax rate - 21%	$	93	$	82	$	84
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	16		15		16
Amortization of investment tax credit	(2)		(2)		(2)
Amortization of excess deferred federal and state income taxes	(17)		(17)		(21)


Other	(1)		(1)		(1)
Total decrease	(4)		(5)		(8)
Total income tax expense (benefit)	$	89	$	77	$	76
Effective income tax rate	20.0%		19.8%		19.1%


	2024		2023		2022
Taxes, other than income
Property and other	$	49	$	45	$	45
Total	$	49	$	45	$	45

(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 domestic 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, 2024, 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)	2020 and prior	2020 and prior
Kentucky (state)	2019 and prior	2019 and prior	2019 and prior	2019 and prior

Other

Transfer of Certain Credits under the Inflation Reduction Act (PPL)

The IRS released the final Internal Revenue Code Section 6418 regulations related to the transfer of certain credits under the Inflation Reduction Act. The regulations became effective on July 1, 2024 and did not and are not expected to have a material impact on the financial statements regarding prior or future credit transfers.

IRS Revenue Procedure 2023-15 (PPL and LG&E)

On April 14, 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. PPL and LG&E are currently reviewing the revenue procedure to determine what impact the guidance may have on their financial statements.

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.

LG&E's and KU's Kentucky base rates are calculated based on recovery of costs as well as 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. As such, LG&E and KU generally earn a return on regulatory assets.

(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 automatic 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:


	PPL				PPL Electric				LG&E				KU
	2024		2023		2024		2023		2024		2023		2024		2023
Current Regulatory Assets:

Rate adjustment mechanism	$	95	$	118	$	—	$	—	$	—	$	—	$	—	$	—
Renewable energy certificates	14		14		—		—		—		—		—		—
Derivative instruments	3		51		—		—		—		—		—		—
Smart meter rider	7		6		7		6		—		—		—		—
Storm damage expense rider	68		12		68		12		—		—		—		—


Transmission service charge	44		43		27		31		—		—		—		—
Transmission formula rate	14		5		2		—		—		—		—		—
ISR deferral	22		11		—		—		—		—		—		—
Gas line tracker	4		—		—		—		4		—		—		—
TCJA customer refund and recovery	21		—		21		—		—		—		—		—
DSIC	8		7		8		7		—		—		—		—
Other	20		26		—		1		4		7		1		3
Total current regulatory assets	$	320	$	293	$	133	$	57	$	8	$	7	$	1	$	3

Noncurrent Regulatory Assets:
Defined benefit plans	$	967	$	887	$	473	$	417	$	226	$	217	$	149	$	136
Plant outage cost	30		38		—		—		7		10		23		28
Net metering	147		112		—		—		—		—		—		—
Environmental cost recovery	96		99		—		—		—		—		—		—

Storm costs	113		97		22		—		20		15		29		14
Unamortized loss on debt	20		22		3		3		9		10		6		7
Interest rate swaps	4		7		—		—		4		7		—		—
Terminated interest rate swaps	53		58		—		—		31		34		22		24
Accumulated cost of removal of utility plant	173		178		173		178		—		—		—		—
AROs	280		289		—		—		75		76		205		213
Retired asset recovery	83		—		—		—		83		—		—		—
Derivative instruments	1		8		—		—		—		—		—		—
Gas line inspections	24		21		—		—		22		19		2		2
Advanced metering infrastructure	28		15		—		—		14		7		14		8
Other	41		43		2		—		—		—		8		7
Total noncurrent regulatory assets	$	2,060	$	1,874	$	673	$	598	$	491	$	395	$	458	$	439


	PPL				PPL Electric				LG&E				KU
	2024		2023		2024		2023		2024		2023		2024		2023
Current Regulatory Liabilities:
Generation supply charge	$	52	$	51	$	52	$	51	$	—	$	—	$	—	$	—

TCJA customer refund and recovery	—		5		—		5		—		—		—		—
Act 129 compliance rider	2		15		2		15		—		—		—		—
Transmission formula rate	1		21		—		18		—		—		—		—
Rate adjustment mechanism	71		72		—		—		—		—		—		—
Energy efficiency	25		23		—		—		—		—		—		—
Gas supply clause	—		15		—		—		—		15		—		—
DSM	17		1		—		—		7		—		10		1
Environmental cost recovery	12		—		—		—		6		—		6		—

Other	43		22		3		2		1		1		6		—
Total current regulatory liabilities	$	223	$	225	$	57	$	91	$	14	$	16	$	22	$	1


	PPL				PPL Electric				LG&E				KU
	2024		2023		2024		2023		2024		2023		2024		2023
Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	1,022	$	996	$	—	$	—	$	314	$	306	$	408	$	399
Power purchase agreement - OVEC	10		19		—		—		7		13		3		6
Net deferred taxes	1,899		1,977		739		763		439		459		498		523
Defined benefit plans	294		252		100		73		24		20		65		59
Terminated interest rate swaps	54		57		—		—		27		29		27		28
Energy efficiency	16		5		—		—		—		—		—		—
Other	40		34		—		—		4		—		8		3
Total noncurrent regulatory liabilities	$	3,335	$	3,340	$	839	$	836	$	815	$	827	$	1,009	$	1,018

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

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, 2024, the balances were $79 million for PPL, $44 million for LG&E and $35 million for KU. As of December 31, 2023, the balances were $86 million for PPL, $46 million for LG&E and $40 million for KU.

(PPL)

RIE is subject to a pension rate adjustment mechanism whereby the difference in amounts allowed to be recovered in rates versus 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 request from the PAPUC, the KPSC and the VSCC, as applicable, the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer such costs 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 reacquired 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.

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)

Distribution System Improvement Charge (DSIC)

The DSIC is authorized under Act 11 and is considered an alternative ratemaking mechanism providing more timely cost recovery of qualifying distribution system capital improvements. DSIC is charged to all customers taking distribution service as a percentage of total distribution revenue (excluding State Tax Adjustment Surcharge). DSIC is capped at 5% of the total amount billed to all customers for distribution service (including reconcilable riders) which provides a safeguard for customers. PPL Electric is permitted to utilize the DSIC mechanism so long as the rolling 12-month ROE for the applicable period does not exceed the PAPUC ROE in the company’s PAPUC quarterly financial report filing. The DSIC 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.

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, beginning in 2023, 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. 2023 was considered a transitional period as the calendar year rate

approved by FERC became effective April 1, 2023. 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.

Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric is currently in Phase IV of the energy efficiency and conservation plan which was approved in March 2021. Phase IV allows PPL Electric to recover the maximum $313 million over the five-year period, June 1, 2021 through May 31, 2026. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual Phase IV program costs are reconcilable after each 12-month period, and any over- or under-recovery from customers will be refunded or recovered over the next rate filing period.

Smart Meter Rider (SMR)

Act 129 requires each electric distribution company (EDC) with more than 100,000 customers to have a PAPUC approved Smart Meter Technology Procurement and Installation Plan (SMP). As of December 31, 2019, PPL Electric replaced substantially all of its old meters with meters that meet the Act 129 requirements under its SMP. In accordance with Act 129, EDCs are able to recover the costs and earn a return on capital of providing smart metering technology. PPL Electric uses the SMR to recover the costs to implement its SMP. The SMR is a reconciliation mechanism whereby any over- or under-recovery from prior years is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarters.

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.

TCJA Customer Refund and Recovery

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.

(PPL, LG&E and KU)

Fuel Adjustment Clauses

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in power purchases and the cost of fuel to generate electricity, including transportation costs, from the costs embedded in base rates are adjusted in LG&E's and KU's rates. The KPSC requires formal reviews at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel adjustment clause and, to the extent appropriate, may conduct public hearings and

reestablish the fuel charge included in base rates. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered within 12 months.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs and load for the fuel year (12 months ending March 31). The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the fuel year plus an adjustment for any under- or over-recovery of fuel expenses from the prior fuel year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered or refunded within 12 months.

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.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LG&E and KU, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LG&E and KU with offsets to regulatory liabilities. The regulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition. LG&E's and KU's customer rates continue to reflect the original contracts. See Notes 12 and 17 for additional discussion of the power purchase agreement.

Interest Rate Swaps

LG&E's unrealized gains and losses are recorded as regulatory assets or regulatory liabilities until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures in 2033.

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 will 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

In 2021 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 and 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. Recovery of these costs will be determined in the base rate case proceeding following the completion of the AMI implementation project.

(PPL)

Derivative Instruments

Derivative instruments that qualify for recovery from, or refund to, customers through future rates are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. The balance is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.

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.

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.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that are anticipated to be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

(PPL, LG&E and KU)

Environmental Cost Recovery

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 roll-in of ECR amounts to base rates each two-year period. The KPSC has authorized 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.

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.

Retired Asset Recovery (RAR) Rider

The RAR rider was established by KPSC orders in 2021 to provide recovery of and return on the remaining investment in 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, 2024 represent the remaining net book value and materials and supplies that cannot be used as a result of the retirement of Mill Creek Unit 1. The associated removal costs will be added to the RAR rider regulatory asset or regulatory liability as costs are incurred.

Regulatory Matters

Rhode Island Activities (PPL)

Advanced Metering Functionality (AMF)

In 2021, RIE filed its Updated AMF Business Case and Grid Modernization Plan (GMP) with the RIPUC in accordance with the Amended Settlement Agreement (ASA) approved by the RIPUC in August 2018, and which among other things, sought approval to deploy smart meters throughout the service territory. After PPL completed the acquisition of RIE, RIE filed a new AMF Business Case with the RIPUC in 2022, consisting of a detailed proposal for full-scale deployment of AMF across its electric service territory.

On September 27, 2023, the RIPUC unanimously approved RIE to deploy an AMF-based metering system for the electric distribution business. RIE is authorized to seek recovery of the approved capital investment through the ISR process with an overall multi-year cap on recovery at approximately $153 million, subject to certain terms, conditions and limitations with respect to the potential offsets and recoverability of certain costs. RIE is required to continue spending even if above the recovery cap, until it achieves the functionalities outlined in the AMF Business Case. RIE filed with the RIPUC for approval of (i) an updated electric Service Quality Plan on December 27, 2023, (ii) additional compliance tariff provisions regarding recovery and updated cost schedules to reflect the RIPUC's decision on December 22, 2023, and (iii) electric and gas tariff advice filings for RIPUC Automatic Meter Reading/AMF meter opt-out tariff provision on September 19, 2024. The RIPUC approved RIE’s revised service quality metrics with certain modifications on August 1, 2024 and October 30, 2024. In addition, the RIPUC approved RIE’s AMR/AMF opt-out tariff provisions for electric and natural gas with modifications on December 19, 2024 for effect January 1, 2025, and approved the proposed updated fees to be assessed at the start of the AMF roll-out. On January 7, 2025, RIE filed compliance tariffs to reflect the RIPUC’s ruling, which they approved at their January 23, 2025 Open Meeting.

Grid Modernization Plan (GMP)

RIE filed a new GMP with the RIPUC on December 30, 2022. The new GMP filing consists of a holistic suite of grid modernization investments that will provide RIE with the tools and capability to manage the electric distribution system more granularly considering a range of distributed energy resources adoption levels, accelerated by Rhode Island's climate mandates, while at the same time maintaining a safe and reliable electric distribution system. The GMP is an informational guidance document that supports the grid modernization investments to be proposed in future electric ISR plans. Consequently, RIE did not request approval from the RIPUC for any specific investments or seek cost recovery as part of the GMP; rather, RIE requested the RIPUC issues an order affirming RIE's compliance with its obligation to file a GMP that meets the requirements of the ASA. At an Open Meeting on November 21, 2024, the RIPUC unanimously ruled that RIE satisfied the requirement to file a GMP. This decision does not represent a ruling on the GMP and the docket will remain open, though RIE does not expect further action on this docket.

FY 2025 Gas ISR Plan

On December 22, 2023, RIE filed its FY 2025 Gas ISR Plan with the RIPUC with a budget that includes $185 million of capital investment spend plus up to an additional $11 million of contingency plan spending in connection with the PHMSA's potential enactment of regulations during FY 2025 that, if enacted would significantly alter RIE's leak detection and repair obligations under federal regulations. RIE also filed its proposed gas ISR plan budgetary and reconciliation framework, addressing issues raised in connection with its FY submission, with its FY 2025 ISR Plan. The RIPUC held hearings in March 2024, and on March 26, 2024, approved, the plan, including the proposed budgetary and reconciliation framework, with a total approved FY 2025 Gas ISR Plan of $180 million of which $168 million is for capital investment spend and $12 million spend for paving costs as operations and maintenance (O&M), plus the potential additional $11 million available if the above-mentioned regulations are implemented by the PHMSA. On March 28, 2024, the RIPUC approved RIE's compliance filing for rates effective April 1, 2024.

FY 2026 Gas ISR Plan

On December 31, 2024, RIE filed its FY 2026 Gas ISR Plan with the RIPUC with a budget that includes $187 million of capital investment spend and up to $15 million of additional contingency plan spend in connection with the PHMSA's potential enactment of regulations during FY 2026 that, if enacted, would significantly alter RIE's leak detection and repair obligations under federal regulations. The Plan also includes proposed spending on curb-to-curb paving of $22 million. A decision from the RIPUC on the Plan is expected by March 31, 2025. RIE cannot predict the outcome of this matter.

FY 2025 Electric ISR Plan

On December 21, 2023, RIE filed its FY 2025 Electric ISR Plan with the RIPUC with a budget that includes $141 million of capital investment spend, $13 million of vegetation management O&M spend and $1 million of Other O&M spend. RIE also filed its proposed electric ISR plan budgetary and reconciliation framework addressing issues raised in connection with its FY 2024 submission, with its FY 2025 ISR Plan. The RIPUC held hearings in March 2024, and on March 26, 2024, approved the plan, including the proposed budgetary and reconciliation framework, with modifications to the proposed capital investment spend, resulting in a total approved FY 2025 Electric ISR Plan of $132 million for capital investment spend, $13 million for vegetation management O&M spend, and $1 million for Other O&M spend. On March 28, 2024, the RIPUC approved RIE's compliance filing for rates effective April 1, 2024.

FY 2026 Electric ISR Plan

On December 23, 2024, RIE filed its FY 2026 Electric ISR Plan with the RIPUC with a budget that includes $160 million of capital investment spend, $14 million of vegetation O&M spend and $1 million of Other O&M spend. In addition, the FY 2026 Electric ISR Plan includes $88 million of capital investment spend for Advanced Metering Functionality (AMF) which, together with the $160 million of capital investment spend, results in total capital investment spend of $248 million. A decision from the RIPUC is expected by March 31, 2025. RIE cannot predict the outcome of this matter.

Kentucky Activities (PPL, LG&E and KU)

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 expenses portion of the costs incurred related to the storm. These are estimated to be $2 million for LG&E and $8 million for KU. LG&E and KU cannot predict the outcome of this matter.

Kentucky September 2024 Storm

In September 2024, LG&E and KU experienced significant winds and rain activity in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets. On October 15, 2024, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance expenses portion of the costs incurred related to the storm. On December 4, 2024, the KPSC issued an order approving LG&E’s and KU’s request for regulatory asset accounting treatment, with recovery amounts and amortization thereof to be determined in subsequent base rate

proceedings. LG&E and KU cannot predict the outcome of this matter. As of December 31, 2024, LG&E and KU recorded regulatory assets related to the storm of $2 million and $11 million.

Kentucky May 2024 Storm

In May 2024, LG&E and KU experienced significant windstorm activity in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets. On June 13, 2024, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance expenses portion of the costs incurred related to the storm. On July 2, 2024, the KPSC issued an order provisionally approving the request for accounting purposes, noting that the decision on approval of recovery would be determined in the future. On November 21, 2024, the KPSC issued an order confirming the approval of LG&E’s and KU’s request for regulatory asset accounting treatment, with recovery amounts and amortization thereof to be determined in subsequent base rate proceedings. LG&E and KU cannot predict the outcome of this matter. As of December 31, 2024, LG&E and KU recorded regulatory assets related to the storm of $4 million and $5 million.

KPSC Investigation Related to Winter Storm Elliott

On December 22, 2023, the KPSC initiated an investigation into the practices of LG&E and KU regarding the provision of electric service from December 23, 2022 through December 25, 2022, during a period of extreme temperatures during Winter Storm Elliott. The investigation was the result of LG&E's and KU's need to implement brief service interruptions to approximately 55,000 customers during this period. The purpose of the investigation was to supplement discovery and examination already completed through LG&E's and KU's CPCN proceedings, a legislative hearing completed in February 2023 and reports completed by the NERC and the FERC related to the issue. Additionally, the investigation was to evaluate LG&E's and KU's actions taken, or planned to be taken, since Winter Storm Elliott that affect their ability to provide service during periods of variable weather and power system stress. LG&E and KU believe actions taken during the period under question were necessary and appropriate. A hearing on the matter occurred on May 23, 2024. On January 7, 2025, the KPSC issued an Order finding that LG&E and KU did not willfully violate a regulation, statute or KPSC Order associated with the Winter Storm Elliot event. The case is now closed and removed from the KPSC’s docket.

Mill Creek Unit 1 and Unit 2 Retired Asset Recovery (RAR) (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 rider. LG&E expects these costs to be approximately $125 million and proposes to begin application of the RAR rider with bills issued in May 2025. On October 28, 2024, the KPSC issued an order to establish a procedural schedule regarding its investigation of the reasonableness of the proposed tariff. The KPSC intends to rule on the matter by February 28, 2025. LG&E cannot predict the outcome of this proceeding.

Mill Creek Unit 2 is expected to be retired in 2027. LG&E anticipates the recovery of associated costs, including the remaining net book value, for Mill Creek Unit 2 through the RAR rider. The remaining net book value of Mill Creek Unit 2 was approximately $221 million at December 31, 2024 and LG&E is continuing to depreciate using the current approved rates through its retirement date in 2027. LG&E expects to reclassify the net book value remaining at retirement, which is expected to total approximately $161 million, to a regulatory asset to be amortized over a period of ten years in accordance with the RAR.

Pennsylvania Activities (PPL and PPL Electric)

PAPUC investigation into billing issues

On January 31, 2023, the PAPUC initiated an investigation focused on billing issues related to estimated, irregular bills and customer service concerns following customer complaints, which for many customers were driven by increased prices for electricity supply. Certain bills issued during the time period of December 20, 2022 through January 9, 2023 were estimated due to a technical issue that prevented PPL Electric from providing actual collected meter data to customer facing and other internal systems. Customers also reported difficulties accessing PPL Electric's website and contacting the customer service call center. The PAPUC’s Bureau of Investigation & Enforcement (I&E) has directed PPL Electric to respond to certain inquiries and document requests. PPL Electric submitted its responses to the information request and cooperated fully with the investigation. PPL Electric reached a Settlement Agreement with I&E on November 21, 2023. In the settlement, PPL Electric agreed to pay a civil penalty of $1 million, make certain remedial improvements to its billing systems and processes, and agreed to not seek recovery for extraordinary costs incurred in responding to or resulting from the billing event. On November 21, 2023, PPL Electric and I&E submitted a Joint Petition for Approval of Settlement to the PAPUC. On January 18, 2024, the PAPUC issued an Order requesting public comment prior to the PAPUC entering a Final Order on the petition. Comments were due on February 28, 2024, and comments were filed by the Office of Consumer Advocate, CAUSE-PA (low-income advocate), and individual customers. On March 19, 2024, PPL Electric filed reply comments. On April 25, 2024, the PAPUC announced at its public meeting that it would be issuing an order approving the Settlement Agreement with modifications. The modifications included converting the $1 million civil penalty to a $1 million donation to PPL Electric's hardship fund, Operation HELP, and requiring PPL Electric to make various progress reports on efforts to remediate the billing issue. PPL Electric and I&E had 20 business days from the issuance of the PAPUC order to accept or reject the proposed modifications to the Settlement Agreement. The time period to withdraw from the Settlement Agreement expired on June 14, 2024, without PPL Electric or I&E withdrawing from the Settlement Agreement, and the terms of the Settlement Agreement, as modified by the PAPUC's order, are now final. PPL Electric is in the process of complying with the terms of the Settlement Agreement, and made the required contribution to Operation HELP on June 24, 2024.

PPL Electric incurred expenses, primarily related to billing write-offs, of $18 million and $34 million for the years ended December 31, 2024 and 2023 related to the billing issue. PPL Electric will not seek regulatory recovery of these costs.

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 November 21, 2024, the Administrative Law Judge in the proceeding issued a Recommended Decision recommending the denial of PPL Electric’s DSIC Cap Waiver Petition. PPL Electric filed exceptions to the Recommended Decision on December 11, 2024. Several of the other parties filed Reply Exceptions on December 23, 2024. The Administrative Law Judge's Recommended Decision and the Exceptions and Reply Exceptions are currently before the PAPUC for a final order. PPL Electric cannot predict the timing or outcome of that decision.

Act 129

The Pennsylvania Public Utility Code requires EDCs to meet, by specified dates, specified goals for reduction in customer electricity usage and peak demand. EDCs not meeting the requirements of Act 129 are subject to significant penalties. PPL Electric filed with the PAPUC its Act 129 Phase IV Energy Efficiency and Conservation Plan on November 30, 2020, for the five-year period starting June 1, 2021 and ending on May 31, 2026. PPL Electric's Phase IV Act 129 Plan was approved by the PAPUC at its March 25, 2021, public meeting.

The Pennsylvania Public Utility Code also requires EDCs to act as a default service provider (DSP), which provides electricity generation supply service to customers pursuant to a PAPUC-approved default service procurement plan. A DSP is able to recover the costs associated with its default service procurement plan.

In March 2024, PPL Electric filed a Petition for Approval of a new default service program and procurement plan with the PAPUC for the period June 1, 2025 through May 31, 2029. In August 2024, PPL Electric submitted a Joint Petition for Settlement in the proceeding. In September 2024, the Administrative Law Judge issued an Interim Order approving the proposed settlement without modification. The PAPUC adopted the Interim Order on November 7, 2024, without modification which finalized the settlement.

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. Oral argument before the D.C. Circuit Court of Appeals occurred on January 21, 2025. 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 base rates increases, provided, however, that increases associated with the FERC's May 18, 2023 order are expected to be subject to future rate proceedings.

Recovery of Transmission Costs (PPL)

Until December 2022, RIE's transmission facilities were operated in combination with the transmission facilities of National Grid's New England affiliates, Massachusetts Electric Company (MECO) and New England Power (NEP), as a single integrated system with NEP designated as the combined operator. As of January 1, 2023, RIE operates its own transmission facilities. ISO-NE allocates RIE's costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT). According to the FERC orders, RIE is compensated for its actual monthly transmission costs, with its authorized maximum Return on Equity (ROE) of 11.74% on its transmission assets.

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 recently 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.

Other

Purchase of Receivables Program

(PPL and PPL Electric)

In accordance with a PAPUC-approved purchase of accounts receivable program, PPL Electric purchases 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 2024, 2023 and 2022, PPL Electric purchased $1.5 billion, $1.5 billion and $1.3 billion of accounts receivable from alternative suppliers.

(PPL)

In 2021 and 2022, the RIPUC approved various components of a Purchase of Receivables Program (POR) in Rhode Island for effect on April 1, 2022. Municipal aggregators and non-regulated power producers (collectively, Competitive Suppliers) are eligible to participate in accordance with RIE's approved electric tariffs for municipal aggregation and non-regulated power producers. Under the POR program, RIE will purchase the Competitive Suppliers' accounts receivables, including existing receivables, at discounted rates, regardless of whether RIE has collected the owed monies from customers. The program is intended to make RIE whole through the implementation of a discount rate or Standard Complete Bill Percentage (SCBP) paid by Competitive Suppliers. RIE calculates the SCBP for each customer class and files the calculations with the RIPUC for review and approval by February 15 of each year. At an Open Meeting on March 26, 2024, the RIPUC approved the SCBP for effect beginning on April 1, 2024, for a one-year period.

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, 2024									December 31, 2023
	Expiration Date	Capacity		Borrowed		Letters of Credit and Commercial Paper Issued (d)		Unused Capacity		Borrowed		Letters of Credit and Commercial Paper Issued (d)
PPL
PPL Capital Funding
Syndicated Credit Facility (a) (b) (c)	Dec 2028	$	1,250	$	—	$	138	$	1,112	$	—	$	390
Bilateral Credit Facility (a) (b)	Feb 2025	100		—		—		100		—		—
Bilateral Credit Facility (a) (b)	Feb 2025	100		—		15		85		—		13
Total PPL Capital Funding Credit Facilities		$	1,450	$	—	$	153	$	1,297	$	—	$	403

PPL Electric
Syndicated Credit Facility (a) (b)	Dec 2028	650		—		1		649		—		511

Total PPL Electric Credit Facilities		$	650	$	—	$	1	$	649	$	—	$	511


	December 31, 2024									December 31, 2023
	Expiration Date	Capacity		Borrowed		Letters of Credit and Commercial Paper Issued (d)		Unused Capacity		Borrowed		Letters of Credit and Commercial Paper Issued (d)
LG&E
Syndicated Credit Facility (a) (b)	Dec 2028	500		—		25		475		—		—

Total LG&E Credit Facilities		$	500	$	—	$	25	$	475	$	—	$	—

KU
Syndicated Credit Facility (a) (b)	Dec 2028	400		—		140		260		—		93

Total KU Credit Facilities		$	400	$	—	$	140	$	260	$	—	$	93

(a)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.

(b)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 2025 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.

(c)Includes a $250 million borrowing sublimit for RIE and a $1 billion sublimit for PPL Capital Funding at December 31, 2024 and 2023. At December 31, 2024, PPL Capital Funding had $138 million of commercial paper outstanding and RIE had no commercial paper outstanding. At December 31, 2023, PPL Capital Funding had $365 million of commercial paper outstanding and RIE had $25 million of commercial paper outstanding. RIE's obligations under the facility are not guaranteed by PPL.

(d)Commercial paper issued reflects the undiscounted face value of the issuance.

(PPL)

In January 2025, PPL Capital Funding amended and restated its existing $1.25 billion syndicated credit facility to extend the termination date from December 6, 2028 to December 6, 2029 and to increase the borrowing capacity under the facility to $1.5 billion.

(PPL and PPL Electric)

In January 2025, PPL Electric amended and restated its existing $650 million syndicated credit facility to extend the termination date from December 6, 2028 to December 6, 2029 and to increase the borrowing capacity under the facility to $750 million.

(PPL and LG&E)

In January 2025, LG&E amended and restated its existing $500 million syndicated credit facility to extend the termination date from December 6, 2028 to December 6, 2029 and to increase the borrowing capacity under the facility to $600 million.

(PPL and KU)

In January 2025, KU amended and restated its existing $400 million syndicated credit facility to extend the termination date from December 6, 2028 to December 6, 2029 and to increase the borrowing capacity under the facility to $600 million.

(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, 2024							December 31, 2023
	Weighted - Average Interest Rate	Capacity		Commercial Paper Issuances (c)		Unused Capacity		Weighted - Average Interest Rate	Commercial Paper Issuances (c)
PPL Capital Funding (a)	4.76%	$	1,350	$	138	$	1,212	5.66%	$	365
RIE (b)		250		—		250		5.72%	25
PPL Electric		650		—		650		5.67%	510
LG&E	4.72%	500		25		475			—
KU	4.71%	400		140		260		5.64%	93
Total		$	3,150	$	303	$	2,847		$	993

(a)PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL.

(b)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, 2024, had a total capacity of $1.25 billion and under which they are both borrowers. PPL Capital Funding’s Commercial paper program is also backed by a separate bilateral credit facility for $100 million. The PPL Capital Funding syndicated credit facility includes a borrowing sublimit for RIE, which at December 31, 2024 was set at $250 million with the remaining $1 billion allocated to 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 $1.25 billion.

(c)Commercial paper issued reflects the undiscounted face value of the issuance.

(PPL Electric, LG&E and KU)

See Note 13 for a discussion of intercompany borrowings.

Long-term Debt (All Registrants)


				December 31,
	Weighted-Average Rate (d)		Maturities (d)	2024		2023
PPL
Senior Unsecured Notes	4.34	%	2026 - 2047	$	4,316	$	3,066
Senior Secured Notes/First Mortgage Bonds (a) (b) (c)	4.38	%	2025 - 2053	10,878		10,229
Exchangeable Senior Unsecured Notes	2.88	%	2028	1,000		1,000
Junior Subordinated Notes	7.25	%	2067	480		480

Total Long-term Debt before adjustments				16,674		14,775

Unamortized premium and (discount), net				(57)		(55)
Unamortized debt issuance costs				(114)		(108)
Total Long-term Debt				16,503		14,612
Less current portion of Long-term Debt				551		1
Total Long-term Debt, noncurrent				$	15,952	$	14,611

PPL Electric
Senior Secured Notes/First Mortgage Bonds (a) (b)	4.64	%	2027 - 2053	$	5,299	$	4,649

Total Long-term Debt Before Adjustments				5,299		4,649

Unamortized discount				(42)		(42)
Unamortized debt issuance costs				(43)		(40)
Total Long-term Debt				5,214		4,567
Less current portion of Long-term Debt				—		—
Total Long-term Debt, noncurrent				$	5,214	$	4,567


				December 31,
	Weighted-Average Rate (d)		Maturities (d)	2024		2023
LG&E
Senior Secured Notes/First Mortgage Bonds (a) (c)	4.01	%	2025 - 2049	$	2,489	$	2,489

Total Long-term Debt Before Adjustments				2,489		2,489

Unamortized discount				(4)		(4)
Unamortized debt issuance costs				(14)		(16)
Total Long-term Debt				2,471		2,469
Less current portion of Long-term Debt				300		—
Total Long-term Debt, noncurrent				$	2,171	$	2,469

KU
Senior Secured Notes/First Mortgage Bonds (a) (c)	4.22	%	2025 - 2050	$	3,089	$	3,089

Total Long-term Debt Before Adjustments				3,089		3,089

Unamortized premium				4		5
Unamortized discount				(8)		(9)
Unamortized debt issuance costs				(19)		(21)
Total Long-term Debt				3,066		3,064
Less current portion of Long-term Debt				250		—
Total Long-term Debt, noncurrent				$	2,816	$	3,064

(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 $13.3 billion and $12.4 billion at December 31, 2024 and 2023.

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 $6.0 billion and $5.9 billion at December 31, 2024 and 2023.

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 $7.5 billion and $7.3 billion at December 31, 2024 and 2023.

(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, 2024, 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, 2024, 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, 2024.

The aggregate maturities of long-term debt, based on sinking fund requirements, stated maturities or earlier put dates, for the periods 2025 through 2029 and thereafter are as follows:


	PPL		PPL Electric		LG&E		KU
2025	$	551	$	—	$	300	$	250
2026	904		—		90		164
2027	428		108		260		60
2028	1,350		—		—		—
2029	116		116		—		—
Thereafter	13,325		5,075		1,839		2,615
Total	$	16,674	$	5,299	$	2,489	$	3,089

(PPL)

In March 2024, RIE issued $500 million of 5.35% Senior Notes due 2034. RIE received proceeds of $496 million, net of discounts and underwriting fees, to be used to repay short-term debt and for other general corporate purposes.

In August 2024, PPL Capital Funding issued $750 million of 5.25% Senior Notes due 2034. PPL Capital Funding received proceeds of $741 million, net of discounts and underwriting fees, to be used to repay short-term debt and for other general corporate purposes.

(PPL and PPL Electric)

In January 2024, PPL Electric issued $650 million of 4.85% First Mortgage Bonds due 2034. PPL Electric received proceeds of $644 million, net of discounts and underwriting fees, to be used to repay short-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.

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)

Distributions and Related Restrictions

In November 2024, PPL declared its quarterly common stock dividend, payable January 2, 2025, at 25.75 cents per share (equivalent to $1.03 per annum). On February 13, 2025, PPL announced a quarterly common stock dividend of 27.25 cents per share, payable April 1, 2025, to shareowners of record as of March 10, 2025. 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, 2024, no interest payments were deferred.

(All Registrants)

PPL relies on dividends or loans from its subsidiaries to fund PPL's dividends to its common shareholders. The net assets of certain PPL subsidiaries are subject to legal restrictions. LG&E, KU, PPL Electric and RIE are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act. LG&E, KU, PPL Electric and RIE believe, however, that this statutory restriction, as applied to their circumstances, would not be construed or applied by the FERC to prohibit the payment from retained earnings of dividends that are not excessive and are for lawful and legitimate business purposes. In February 2012, LG&E and KU petitioned the FERC requesting authorization to pay dividends in the future based on retained earnings balances calculated without giving effect to the impact of purchase accounting adjustments for PPL's 2010 acquisition of LG&E and KU. In May 2012, the FERC approved the petitions with the further condition that each utility may not pay dividends if such payment would cause its adjusted equity ratio to fall below 30% of total capitalization. Accordingly, at December 31, 2024, net assets of $1.5 billion for LG&E and $2.0 billion for KU were restricted for purposes of paying dividends to LKE, and net assets of $1.8 billion for LG&E and $2.3 billion for KU were available for payment of dividends to LKE. LG&E and KU believe they will not be required to change their current dividend practices as a result of the foregoing requirement. In addition, under Virginia law, KU is prohibited from making loans to affiliates without the prior approval of the VSCC. There are no comparable statutes under Kentucky law applicable to LG&E and KU, or under Pennsylvania law applicable to PPL Electric. However, orders from the KPSC require LG&E and KU to obtain prior consent or approval before lending amounts to PPL.

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. The Acquisition expands PPL's portfolio of regulated natural gas and electricity transmission and distribution assets, has improved PPL's credit metrics and is expected to enhance long term earnings growth. Following the closing of the Acquisition, Narragansett Electric provides services doing business under the name Rhode Island Energy (RIE).

The consideration for the Acquisition consisted of approximately $3.8 billion in cash and approximately $1.5 billion of long-term debt assumed through the transaction. The fair value of the consideration paid for Narragansett Electric was as follows (in billions):


Aggregate enterprise consideration	$	5.3
Less: fair value of assumed long-term debt outstanding	1.5
Total cash consideration	$	3.8

The $3.8 billion total cash consideration paid was funded with proceeds from PPL's 2021 sale of its U.K. utility business.

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, $228 million, and $123 million were incurred for the years ended December 31, 2024, 2023, and 2022.

Commitments to the Rhode Island Division of Public Utilities and Carriers and the Attorney General of the State of Rhode Island

As a condition to the Acquisition, PPL made certain commitments to the Rhode Island Division of Public Utilities and Carriers and the Attorney General of the State of Rhode Island. As a result:

RIE provided a credit to all its electric and natural gas distribution customers in the total amount of $50 million ($40 million net of tax benefit). Based on the relative number of electric distribution customers and natural gas distribution customers as of November 1, 2022, RIE refunded, in the form of a bill credit, $33 million to electric customers and $17 million to natural gas customers of amounts collected from customers since the Acquisition date. Each electric customer received the same credit, and each natural gas customer received the same credit. A reduction of revenue and a regulatory liability of $50 million for the amounts refunded were recorded during the quarter ended September 30, 2022. These credits were issued during the fourth quarter of 2022. The amounts refunded did not impact RIE's earnings sharing regulatory mechanism.
RIE forgave approximately $44 million ($21 million net of allowance for doubtful accounts) in arrearages for low-income and protected residential customers, which represents 100% of the arrearages over 90 days for those customers as of March 31, 2022. PPL deemed these accounts uncollectible and fully reserved for them as of September 30, 2022, resulting in an increase to "Other operations and maintenance expense" on the Statement of Income of $23 million for the year ended December 31, 2022.
RIE will not file a base rate case seeking an increase in base distribution rates for natural gas and/or electric service sooner than three years from the Acquisition date, and RIE will not submit a request for a change in base rates unless and until there is at least twelve months of operating experience under PPL's exclusive leadership and after the TSA with National Grid terminates.
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) incurring costs related to severance payments, communications and branding changes, and other transition related costs. These costs, which are being expensed as incurred, were $307 million, $262 million, and $181 million for the years ended December 31, 2024, 2023, and 2022.
RIE will not seek to recover any transaction costs related to the Acquisition, which were $28 million through December 31, 2024, including an immaterial amount for the years ended December 31, 2024 and 2023, and $18 million for the year ended December 31, 2022. These amounts were recorded in "Other operations and maintenance" on the Statement of Income.
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, $7 million, and $3 million for the years ended December 31, 2024, 2023, and 2022.
In June 2022, RIE expensed $20 million of regulatory assets as of the Acquisition date for the Gas Business Enablement (GBE) project and for certain Cybersecurity/IT investments related to GBE. The expense was recorded to "Other operations and maintenance" on the Statements of Income for the year ended December 31, 2022. RIE will not seek to recover these regulatory assets from customers in any future proceedings.
RIE will exclude all goodwill from the ratemaking capital structure.
RIE will hold harmless Rhode Island customers from any changes to Accumulated Deferred Income Taxes (ADIT) as a result of the Acquisition. RIE reserves the right to seek rate adjustments based on future changes to ADIT that are not related to the Acquisition.
RIE will not increase its revenue requirement to a level higher than what would exist in the absence of the Acquisition as a result of any restatement of pension and other post-retirement benefits plan assets and liabilities to fair value after the close of the Acquisition.
Rhode Island Holdings contributed $2.5 million to the Rhode Island Commerce Corporation's Renewable Energy Fund and will not use any of the $2.5 million to meet its pre-existing renewable energy credit goals in Rhode Island or any other state. This contribution was made during the year ended December 31, 2022 and was recorded in "Other Income (Expense)" on the Statement of Income.
RIE will make available up to $2.5 million for the Rhode Island Attorney General to utilize as needed in evaluating PPL's report on RIE's specific decarbonization goals to support Rhode Island's 2021 Act on Climate or to assess the future of the gas distribution business in Rhode Island. This amount was accrued during the year ended December 31, 2022 and was recorded in "Other Income (Expense) - net" on the Statement of Income.
Various other operational and reporting commitments have been established.

Purchase Price Allocation

The operations of Narragansett Electric are subject to the accounting for certain types of regulation as prescribed by GAAP. The carrying value of Narragansett Electric’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of net assets and liabilities included in rate base. Therefore, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets acquired nor liabilities assumed reflect any adjustments related to these amounts.

Total goodwill resulting from the acquisition was $1,585 million. PPL has elected to not reflect the effects of purchase accounting in the separate financial statements of RIE or PPL's Rhode Island Regulated segment. Accordingly, the Rhode

Island Regulated segment includes $725 million of acquired legacy goodwill. The remaining excess purchase price of $860 million is included in PPL's Corporate and Other category for segment reporting purposes. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the ability of PPL to leverage its assembled workforce to take advantage of those growth opportunities and the attractiveness of stable, growing cash flows. The tax goodwill is deductible for income tax purposes over a 15 year period, and as such, deferred taxes will be recorded as the tax deductions are taken.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed that were recorded in PPL’s Consolidated Balance Sheet as of the Acquisition date. The allocation was subject to change during the one-year measurement period as additional information was obtained about the facts and circumstances that existed at closing. Adjustments to certain assets acquired and liabilities assumed during the year ended December 31, 2023 resulted in a decrease in goodwill of $1 million since the purchase price allocation as of December 31, 2022.


	Final Purchase Price Allocation
Assets

Current Assets
Cash and Cash Equivalents	$	154
Accounts Receivable (a)	195
Unbilled Revenues	54
Price Risk Management Assets	99
Regulatory Assets	75
Other Current Assets	65
Total Current Assets	642

Noncurrent Assets
Property, Plant and Equipment, net	3,992
Regulatory Assets	393
Goodwill	1,585
Other Noncurrent Assets	164
Total Noncurrent Assets	6,134

Total Assets	$	6,776

Liabilities

Current Liabilities
Long-Term Debt Due Within One Year	$	14
Accounts Payable	180
Taxes Accrued	44
Regulatory Liabilities	239
Other Current Liabilities	198
Total Current Liabilities	675

Noncurrent Liabilities
Long-Term Debt	1,496
Regulatory Liabilities	643
Other Deferred Credits and Noncurrent Liabilities	142
Noncurrent Liabilities	2,281

Total Purchase Price (Balance Sheet Net Assets)	$	3,820

(a)Amounts represent fair value as of May 25, 2022. The gross contractual amount is $255 million. Cash flows not expected to be collected as of May 25, 2022 were $60 million.

Pro Forma Financial Information

The actual RIE Operating Revenues and Net income attributable to PPL included in PPL's Statement of Income for the period ended December 31, 2022, and PPL's unaudited pro forma 2022 Operating Revenues and Net Income (Loss) attributable to PPL, including RIE, as if the Acquisition had occurred prior to January 1, 2022 are as follows.


	Operating Revenues		Net Income (Loss)
Actual RIE results included from May 25, 2022 - December 31, 2022 (a)	$	1,038	$	(44)
PPL Pro Forma for the year ended 2022	8,667		790

(a)Net Income (Loss) includes expenses of $98 million (pre-tax) related to commitments made as a condition of the Acquisition.

The pro forma financial information presented above has been derived from the historical consolidated financial statements of PPL and Narragansett Electric. Non-recurring items included in the 2022 pro forma financial information include: (a) $18 million (pre-tax) of transaction costs related to the Acquisition, primarily for advisory, accounting and legal fees incurred, (b) $223 million (pre-tax) of Acquisition integration costs, (c) a $50 million reduction of revenue (pre-tax), write-offs of $43 million (pre-tax) of certain accounts receivable and regulatory assets of RIE and $5 million (pre-tax) of expenses accrued in support of Rhode Island's decarbonization goals, all of which were conditions of the Acquisition, and (d) the income tax effect of these items, which was tax effected at the statutory federal income tax rate of 21%.

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 640 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.

See Note 7 for additional information on the CPCN filing.

Divestitures (PPL)

Sale of Safari Holdings

On September 29, 2022, PPL signed a definitive agreement to sell all of Safari Holdings membership interests to Aspen Power Services, LLC (Aspen Power). On November 1, 2022, PPL completed the sale (the Transaction).

Final closing adjustments were completed during the year ended December 31, 2023, resulting in an increase to the loss on sale of $6 million ($5 million net of tax), which was recorded in "Other operation and maintenance" on the Statements of Income for the year ended December 31, 2023. A loss on sale of $60 million ($46 million net of tax benefit) was recorded in "Other operation and maintenance" on the Statements of Income for the year ended December 31, 2022.

In connection with the closing of the Transaction, PPL provided certain guarantees and other assurances. Certain of these guarantees and other assurances have been terminated as of January 8, 2024. See Note 12 to the Financial Statements for additional information.

Discontinued Operations

Summarized Results of Discontinued Operations

On June 14, 2021, PPL WPD Limited completed the sale of PPL's U.K. utility business to National Grid Holdings One plc (National Grid U.K.), a subsidiary of National Grid plc. For the year ended December 31, 2022, the operations of the U.K. utility business are included in "Income from Discontinued Operations (net of income taxes)" on the Statements of Income, with the only component being an income tax benefit of $42 million. There were no discontinued operations activities for the years ended December 31, 2024 or 2023.

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 provide most union employees, as well as non-union employees hired before January 1, 2011, with a retirement benefit. Supplemental non-qualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives.

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.

(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
	2024		2023		2022		2024		2023		2022
Net periodic defined benefit costs (credits):
Service cost	$	35	$	34	$	51	$	6	$	6	$	7
Interest cost	183		188		144		29		30		20
Expected return on plan assets	(299)		(309)		(276)		(30)		(30)		(28)
Amortization of:
Prior service cost (credit)	3		6		8		1		1		1
Actuarial (gain) loss	10		2		51		(5)		(5)		(5)
Net periodic defined benefit costs (credits) prior to settlements and termination benefits	(68)		(79)		(22)		1		2		(5)
Settlements (a)	—		—		23		—		—		—

Net periodic defined benefit costs (credits)	$	(68)	$	(79)	$	1	$	1	$	2	$	(5)

Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets/Liabilities - Gross:
Net (loss)/gain allocated at acquisition	$	—	$	—	$	33	$	—	$	—	$	(49)
Settlement	—		—		(23)		—		—		—
Net (gain) loss	134		193		242		1		(6)		—
Prior service cost (credit)	(13)		2		—		—		—		—
Amortization of:
Prior service (cost) credit	(3)		(6)		(8)		(1)		(1)		(1)
Actuarial gain (loss)	(10)		(2)		(51)		5		5		5
Total recognized in OCI and regulatory assets/liabilities	108		187		193		5		(2)		(45)





Total recognized in net periodic defined benefit costs, OCI and regulatory assets/liabilities	$	40	$	108	$	194	$	6	$	—	$	(50)

(a)Settlement charges incurred as a result of the amount of lump sum payment distributions, primarily from the LKE qualified pension plan. In accordance with existing regulatory accounting treatment, LG&E and KU have primarily maintained the settlement charge in regulatory assets to be amortized in accordance with existing regulatory practice. The portion of the settlement attributed to LKE's operations outside of the jurisdiction of the KPSC has been charged to expense.

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
	2024		2023		2022		2024		2023		2022
OCI	$	25	$	52	$	142	$	2	$	—	$	13
Regulatory assets/liabilities	83		135		51		3		(2)		(58)
Total recognized in OCI and regulatory assets/liabilities	$	108	$	187	$	193	$	5	$	(2)	$	(45)

(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
	2024		2023		2024		2023
PPL
Discount rate	5.93	%	5.52	%	5.91	%	5.54	%
Rate of compensation increase	3.43	%	3.43	%	3.44	%	3.43	%

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
	2024		2023		2022		2024		2023		2022
PPL
Discount rate	5.52	%	5.52	%	3.35	%	5.54	%	5.54	%	3.54	%

Rate of compensation increase	3.43	%	3.43	%	3.74	%	3.43	%	3.43	%	2.84	%
Expected return on plan assets	8.25	%	8.25	%	7.25	%	7.28	%	7.38	%	6.52	%

(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:


	2024		2023		2022
PPL
Health care cost trend rate assumed for next year
– obligations	7.00	%	6.25	%	6.50	%
– cost	6.25	%	6.50	%	6.25	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)
– obligations	5.00	%	5.00	%	5.00	%
– cost	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate
– obligations	2033		2029		2029
– cost	2029		2029		2027

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


	Pension Benefits				Other Postretirement Benefits
	2024		2023		2024		2023
Change in Benefit Obligation
Benefit Obligation, beginning of period	$	3,454	$	3,333	$	538	$	534
Service cost	35		34		6		6
Interest cost	183		188		29		30
Participant contributions	—		—		8		9
Plan amendments	(13)		3		—		—
Actuarial (gain) loss	(131)		179		(4)		18

Settlements	—		(3)		—		—

Gross benefits paid	(284)		(280)		(56)		(59)
Federal subsidy	—		—		2		—

Benefit Obligation, end of period	3,244		3,454		523		538

Change in Plan Assets
Plan assets at fair value, beginning of period	3,176		3,149		438		417
Actual return on plan assets	34		297		25		54
Employer contributions	10		13		14		16
Participant contributions	—		—		7		7


Transfer out (a)	—		—		(13)		—
Settlements	—		(3)		—		—
Gross benefits paid	(284)		(280)		(54)		(56)

Plan assets at fair value, end of period	2,936		3,176		417		438

Funded Status, end of period	$	(308)	$	(278)	$	(106)	$	(100)

Amounts recognized in the Balance Sheets consist of:
Noncurrent asset	$	19	$	7	$	8	$	10
Current liability	(10)		(10)		(13)		(14)
Noncurrent liability	(317)		(275)		(101)		(96)
Net amount recognized, end of period	$	(308)	$	(278)	$	(106)	$	(100)

Amounts recognized in AOCI and regulatory assets/liabilities (pre-tax) consist of:
Prior service cost (credit)	$	(6)	$	11	$	9	$	10
Net actuarial (gain) loss	1,164		1,017		(90)		(96)
Total	$	1,158	$	1,028	$	(81)	$	(86)

Total accumulated benefit obligation for defined benefit pension plans	$	3,116	$	3,312

(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
	2024		2023		2024		2023
AOCI	$	283	$	235	$	16	$	14
Regulatory assets/liabilities	875		793		(97)		(100)
Total	$	1,158	$	1,028	$	(81)	$	(86)

The actuarial gain for pension plans in 2024 was primarily related to a change in the discount rate used to measure the benefit obligations of those plans. The actuarial loss for pension plans in 2023 was related to a change in the discount rate used to measure the benefit obligations of those plans.

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
	2024		2023
Projected benefit obligation	$	2,719	$	2,891
Fair value of plan assets	2,392		2,606

	ABO in excess of plan assets
	2024		2023
Accumulated benefit obligation	$	2,618	$	1,773
Fair value of plan assets	2,392		1,594

(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:


	2024		2023
Pension	$	(83)	$	(65)
Other postretirement benefits	(60)		(55)

(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:


	2024		2023
Pension	$	29	$	34
Other postretirement benefits	(44)		(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.


	2024		2023
Pension	$	46	$	51
Other postretirement benefits	(8)		(9)

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 2024 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				2024
	2024		2023		Target Asset Allocation
Growth Portfolio	55	%	54	%	55	%
Equity securities	30	%	31	%
Debt securities (a)	13	%	12	%
Alternative investments	12	%	11	%
Immunizing Portfolio	43	%	43	%	43	%
Debt securities (a)	35	%	36	%
Derivatives (b)	8	%	7	%
Liquidity Portfolio	2	%	3	%	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.

(PPL)

The fair value of net assets in the Master Trust by asset class and level within the fair value hierarchy was:


	December 31, 2024								December 31, 2023
	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	$	212	$	212	$	—	$	—	$	226	$	226	$	—	$	—
Equity securities:
U.S. Equity	63		63		—		—		36		36		—		—
U.S. Equity fund measured at NAV (a)	461		—		—		—		542		—		—		—

International equity fund at NAV (a)	376		—		—		—		431		—		—		—
Commingled debt measured at NAV (a)	461		—		—		—		528		—		—		—
Debt securities:
U.S. Treasury and U.S. government sponsored agency	150		149		1		—		159		159		—		—
Corporate	867		—		848		19		915		—		906		9
Other	13		—		13		—		14		—		13		1
Alternative investments:

Real estate measured at NAV (a)	72		—		—		—		61		—		—		—
Private equity measured at NAV (a)	114		—		—		—		105		—		—		—
Private credit partnerships measured at NAV (a)	16		—		—		—		13		—		—		—
Hedge funds measured at NAV (a)	181		—		—		—		192		—		—		—

Derivatives	(38)		—		(38)		—		93		—		93		—



PPL Services Corporation Master Trust assets, at fair value	2,948		$	424	$	824	$	19	3,315		$	421	$	1,012	$	10
Receivables and payables, net (b)	102								(16)
401(h) accounts restricted for other postretirement benefit obligations	(114)								(124)
Total PPL Services Corporation Master Trust pension assets	$	2,936							$	3,175

(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, 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

A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2023 is as follows:


	Corporate debt
Balance at beginning of period	$	16
Actual return on plan assets:
Relating to assets still held at the reporting date	(2)
Relating to assets sold during the period	4
Purchases, sales and settlements	(8)
Balance at end of period	$	10

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. 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, 2024, the Master Trust had unfunded commitments of $59 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.

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, 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
	2024		2023		2024
Asset Class
Equity securities	45	%	46	%	45	%
Debt securities (a)	49	%	48	%	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, 2024								December 31, 2023
	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	$	—	$	—	$	20	$	20	$	—	$	—
Equity securities:
Large-cap equity fund measure at NAV (a)	71		—		—		—		76		—		—		—
Commingled debt fund measured at NAV (a)	78		—		—		—		84		—		—		—
Global equity exchange-traded fund	70		70		—		—		72		72		—		—
Long-term bond exchange-traded fund	74		74		—		—		74		74		—		—




Total VEBA trust assets, at fair value	312		$	163	$	—	$	—	326		$	166	$	—	$	—
Receivables and payables, net (b)	(9)								(12)
401(h) account assets	114								124
Total other postretirement benefit plan assets	$	417							$	438

(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.

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 2025, 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 $10 million of benefit payments under these plans in 2025.

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 $13 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
2025	$	304	$	50	$	—
2026	297		49		—
2027	288		49		—
2028	282		48		—
2029	276		47		—
2030-2034	1,298		218		—

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:


	2024		2023		2022
PPL	$	53	$	48	$	36
PPL Electric	9		8		6
LG&E	8		8		7
KU	6		6		5

11. Jointly Owned Facilities

(PPL, LG&E and KU)

At December 31, 2024 and 2023, 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, 2024

	Trimble County Unit 1	75.00	%	$	462	$	124	$	1
	Trimble County Unit 2	75.00	%	1,549		323		10

	December 31, 2023

	Trimble County Unit 1	75.00	%	$	464	$	110	$	—
	Trimble County Unit 2	75.00	%	1,490		300		49

LG&E
	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 5	31.00	%	—		—		74
	Brown Wind	36.00	%	—		—		—

	December 31, 2023

	E.W. Brown Units 6-7	38.00	%	$	53	$	27	$	—
	Paddy's Run Unit 13 & E.W. Brown Unit 5	53.00	%	52		29		—
	Trimble County Unit 1	75.00	%	464		110		—
	Trimble County Unit 2	14.25	%	447		74		25
	Trimble County Units 5-6	29.00	%	37		17		—
	Trimble County Units 7-10	37.00	%	82		39		—
	Cane Run Unit 7	22.00	%	127		25		3
	E.W. Brown Solar Unit	39.00	%	10		3		—
	Solar Share	44.00	%	3		—		—
	Mercer Solar	37.00	%	7		—		—
	Mill Creek 5	31.00	%	—		—		2
	Brown Wind	36.00	%	—		—		—


		Ownership Interest		Electric Plant		Accumulated Depreciation		Construction Work in Progress
KU
	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 5	69.00	%	—		—		164
	Brown Wind	64.00	%	1		—		—

	December 31, 2023

	E.W. Brown Units 6-7	62.00	%	$	87	$	45	$	—
	Paddy's Run Unit 13 & E.W. Brown Unit 5	47.00	%	46		25		—
	Trimble County Unit 2	60.75	%	1,043		227		24
	Trimble County Units 5-6	71.00	%	86		41		—
	Trimble County Units 7-10	63.00	%	135		65		—
	Cane Run Unit 7	78.00	%	449		90		10
	E.W. Brown Solar Unit	61.00	%	16		5		—
	Solar Share	56.00	%	4		—		—
	Mercer Solar	63.00	%	12		—		1
	Mill Creek 5	69.00	%	—		—		3
	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			2026
Natural Gas Retail Supply			2025
Coal			2030
Coal Transportation and Fleeting Services			2033
Natural Gas Transportation			2055

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
2025	$	25	$	11	$	36
2026	27		12		39
2027	27		12		39
2028	25		11		36
2029	25		11		36
Thereafter	177		79		256
Total	$	306	$	136	$	442

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


	2024		2023		2022
LG&E	$	21	$	20	$	21
KU	9		9		9
Total	$	30	$	29	$	30

(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			Beyond 2030

RIE’s commitments under these long-term contracts subsequent to December 31, 2024 are summarized in the table below.


	Total		2025		2026-2027		2028-2029		Thereafter

Energy Purchase Obligations	$	936	$	274	$	240	$	122	$	300

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, involving a proposal for 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, which entered into service in October 2016;
the Three-State Procurement, involving six clean energy long-term contracts pursuant to the Rhode Island Long-Term Contracting Standard (LTCS) of which 36.427 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 408 MW expected to be operational in 2026; this contract was approved without remuneration but allows RIE to seek costs incurred under the agreement.

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 October 7, 2024, RIE issued an RFP soliciting 20 MW through 150 MW of nameplate capacity of renewable contracting capacity; this solicitation is driven by a terminated PPA and is required in order to fulfill the 90 MW under LTCS.

In addition to the LTCS, RIE has conditionally awarded 200 MW under the 2023 Rhode Island Offshore Wind RFP for newly developed offshore wind energy projects, under the Affordable Clean Energy Security Act (ACES), as amended in 2022. RIE is currently in the contract negotiation period. RIE must negotiate in good faith to achieve a commercially reasonable contract and may file such contract with the RIPUC for approval once negotiations are complete, which is tentatively scheduled for March 2025.

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 January 19, 2023, the Division filed a motion to dismiss RIPUC Docket No. 22-05-EE without prejudice. As grounds for its motion, the Division stated that sufficient evidence exists in the docket to warrant an independent summary investigation by the Division. If the Division finds sufficient grounds, the Division may proceed to a formal hearing regarding the matters under investigation. Upon the conclusion of its investigation, the Division will provide the RIPUC with a report outlining the Division’s findings and final decision. On January 30, 2023, the Rhode Island Attorney General filed an objection to the Division’s motion to dismiss; RIE and National Grid USA each filed responses with the RIPUC requesting that any additional action taken by the RIPUC or the Division be considered after National Grid USA completes its internal investigation report, which National Grid USA filed with the RIPUC on March 10, 2023. On February 24, 2023, the Division initiated the independent summary investigation that it had referenced in its motion to dismiss. The RIPUC held a hearing on March 28, 2023 to hear oral arguments regarding the Division’s motion to dismiss and subsequently denied the motion. On November 27, 2023, the Division filed testimony recommending the RIPUC disallow a portion of the performance incentive awarded from 2012 through 2021. On January 19, 2024, the Division and the Rhode Island Attorney General filed their respective briefs recommending that the RIPUC assess financial penalties on the company. The Division also recommended that the RIPUC consider further regulatory investigations and analysis within each of the energy efficiency dockets from 2012 through 2020, to confirm the accuracy of claimed savings and to document all conduct and actions that would trigger penalties. On April 2, 2024, the RIPUC issued an amended order that expressly expands the scope of the proceeding to address issues of accountability and the question of whether statutory penalties should be assessed against RIE relating to the manipulation of the

reporting of invoices affecting the recovery of past shareholder incentives and the resulting impact on RIE’s customers. This RIPUC proceeding remains open and, in parallel, the Division’s summary investigation remains ongoing. In the RIPUC proceeding, RIE and National Grid USA filed testimony on June 14, 2024, supporting their position that the appropriate amount to be refunded to the energy efficiency program is less than $1 million. The Division’s current position is that $11 million is the appropriate amount to be refunded to the energy efficiency program. This testimony does not address potential statutory penalties and the Division’s testimony on potential statutory penalties is due February 28, 2025. The Division’s testimony on accountability and potential statutory penalties is currently due February 21, 2025, and RIE’s and National Grid’s reply testimony will occur at the evidentiary hearings scheduled for March 2025. At this time, it is not possible to predict the final outcome, or determine the total amount of any additional liabilities that may be incurred by RIE in connection with this matter or the Division’s summary investigation. RIE does not expect this matter will have a material adverse effect on its results of operations, financial position or cash flows.

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.

Water/Waste (PPL, LG&E and KU)

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 is currently under evaluation by PPL, LG&E, and KU, but could potentially result in significant operational changes and additional controls for LG&E and KU plants. 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.

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, and oral argument is expected in the second half of 2025.

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.

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. LG&E and KU generally expect to complete all impoundment closures within five years of commencement, although a longer period may be required to complete closure of some facilities. Associated costs are expected to be subject to rate recovery.

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, 2024 and December 31, 2023, 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, 2024 and December 31, 2023, RIE had a recorded liability of $98 million and $99 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.

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 released 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. The Transportation Security Administration has determined that LG&E is within the scope of the directive, while RIE has not been notified of this distinction. The first security directive required notified owners/operators to implement cybersecurity incident reporting 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 relevant results and proposed mitigation to applicable DHS agencies. The second security directive, revised in July of 2024, requires refinement of the cybersecurity implementation plan and the cybersecurity assessment plan. LG&E does not believe the security directives have had or will have a significant impact on LG&E’s operations or financial condition.

Other

Guarantees and Other Assurances

(All Registrants)

In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. Examples of such agreements include guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage.

(PPL)

PPL fully and unconditionally guarantees all of the debt obligations of PPL Capital Funding.

(All Registrants)

The table below details guarantees provided as of December 31, 2024. "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 guarantees and indemnifications related to the sale of Safari Holdings, which PPL believes are reasonably possible but not probable of occurring. For reporting purposes, on a consolidated basis, the guarantees of PPL include the guarantees of its subsidiary Registrants.


	Exposure at December 31, 2024			Expiration Date
PPL
Indemnifications related to certain tax liabilities related to the sale of the U.K. utility business	£	50	(a)	2028
PPL guarantee of Safari payment obligations under certain sale/leaseback financing transactions related to the sale of Safari Holdings	$	100	(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)	Various
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.

(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.

(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 plus the support obligations provided by PPL under sale-leaseback financings and PPAs that will be replaced by Aspen Power. PPL's support obligations related to the PPAs were replaced by Aspen Power and terminated on January 8, 2024.

(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 $81 million at December 31, 2024, consisting of LG&E's share of $56 million and KU's share of $25 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.

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. 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.


	2024		2023		2022
PPL Electric from PPL Services	$	227	$	222	$	241
LG&E from LKS	105		115		153
LG&E from PPL Services	66		42		13
KU from LKS	130		150		171
KU from PPL Services	65		48		14

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, 2024, CEP Reserves had $222 million of borrowings outstanding. At December 31, 2023, CEP Reserves had no 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, 2024, LG&E's money pool unused capacity was $682 million. At December 31, 2024 LG&E had borrowings outstanding of $43 million from KU and/or LKE. At December 31, 2023, LG&E's borrowings outstanding from KU and/or LKE were not significant.

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, 2024, KU's money pool unused capacity was $437 million. At December 31, 2024 KU had borrowings outstanding of $73 million from LG&E and/or LKE. At December 31, 2023, KU's borrowings outstanding from LG&E and/or LKE were not significant.

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. 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. There was no intercompany receivable balance associated with these funds at December 31, 2023, as the initial allocation from the 2018 private letter ruling was depleted.

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:


	2024		2023		2022
Defined benefit plans - non-service credits (Note 10)	$	42	$	40	$	47
Interest income	33		32		4
AFUDC - equity component	47		30		22
Charitable contributions	(5)		(5)		(14)
Talen litigation (a)	(2)		(124)		1
Miscellaneous	(1)		(13)		(6)
Other Income (Expense) - net	$	114	$	(40)	$	54

(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:


	2024		2023		2022
Defined benefit plans - non-service credits (Note 10)	$	17	$	20	$	15
Interest income	8		8		3
AFUDC - equity component	23		16		16
Charitable contributions	(4)		(3)		(3)
Miscellaneous	1		(2)		(1)
Other Income (Expense) - net	$	45	$	39	$	30

(LG&E)

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


	2024		2023		2022
Defined benefit plans - non-service credits (Note 10)	$	3	$	—	$	3

AFUDC - equity component	8		3		1
Charitable contributions	(1)		(1)		(1)
Miscellaneous	2		1		1
Other Income (Expense) - net	$	12	$	3	$	4

(KU)

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


	2024		2023		2022
Defined benefit plans - non-service credits (Note 10)	$	8	$	6	$	9

AFUDC - equity component	9		3		1
Charitable contributions	(1)		(1)		—
Miscellaneous	(1)		—		(2)
Other Income (Expense) - net	$	15	$	8	$	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, 2024								December 31, 2023
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
PPL
Assets
Cash and cash equivalents	$	306	$	306	$	—	$	—	$	331	$	331	$	—	$	—

Restricted cash and cash equivalents (a)	33		33		—		—		51		51		—		—
Total Cash, Cash Equivalents and Restricted Cash (b)	339		339		—		—		382		382		—		—
Special use funds (a):
Money market fund	1		1		—		—		1		1		—		—
Commingled debt fund measured at NAV (c)	10		—		—		—		9		—		—		—
Commingled equity fund measured at NAV (c)	8		—		—		—		8		—		—		—
Total special use funds	19		1		—		—		18		1		—		—


	December 31, 2024								December 31, 2023
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Price risk management assets (d):
Gas contracts	9		—		4		5		1		—		1		—
Total assets	$	367	$	340	$	4	$	5	$	401	$	383	$	1	$	—

Liabilities
Price risk management liabilities (d):
Interest rate swaps	$	3	$	—	$	3	$	—	$	7	$	—	$	7	$	—


Gas contracts	13		—		10		3		60		—		41		19
Total price risk management liabilities	$	16	$	—	$	13	$	3	$	67	$	—	$	48	$	19

PPL Electric
Assets
Cash and cash equivalents	$	24	$	24	$	—	$	—	$	51	$	51	$	—	$	—

Total assets	$	24	$	24	$	—	$	—	$	51	$	51	$	—	$	—












LG&E
Assets
Cash and cash equivalents	$	8	$	8	$	—	$	—	$	18	$	18	$	—	$	—
Restricted cash and cash equivalents (a)	16		16		—		—		26		26		—		—
Total Cash, Cash Equivalents and Restricted Cash (b)	24		24		—		—		44		44		—		—

Total assets	$	24	$	24	$	—	$	—	$	44	$	44	$	—	$	—

Liabilities
Price risk management liabilities:
Interest rate swaps	$	3	$	—	$	3	$	—	$	7	$	—	$	7	$	—
Total price risk management liabilities	$	3	$	—	$	3	$	—	$	7	$	—	$	7	$	—

KU
Assets
Cash and cash equivalents	$	13	$	13	$	—	$	—	$	14	$	14	$	—	$	—
Restricted cash and cash equivalents (a)	16		16		—		—		24		24		—		—
Total Cash, Cash Equivalents and Restricted Cash (b)	29		29		—		—		38		38		—		—
Total assets	$	29	$	29	$	—	$	—	$	38	$	38	$	—	$	—

(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.

A reconciliation of net assets classified as Level 3 for the year ended December 31 is as follows:


	Gas Contracts
2024
Balance at beginning of period	$	(19)
Total unrealized gains (losses) recognized as Regulatory Assets/Regulatory Liabilities	2


Settlements	19
Balance at end of period	$	2

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 Swaps (*PPL, LG&E and KU)

To manage interest rate risk, PPL, LG&E and KU use interest rate contracts such as forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps. An income approach is used to measure the fair value of these contracts, 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 in Level 3 as the model inputs generally are not observable. RIE considers non-performance risk and liquidity risk in the valuation of derivative instruments classified as Level 2 and Level 3.

The significant unobservable inputs used in the fair value measurement of the gas derivative instruments are implied volatility and gas forward curves. A relative change in commodity price at various locations underlying the open positions can result in significantly different fair value estimates.

Financial Instruments Not Recorded at Fair Value (All Registrants)

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, 2024				December 31, 2023
	Carrying Amount (a)		Fair Value		Carrying Amount (a)		Fair Value
PPL	$	16,503	$	15,562	$	14,612	$	14,031
PPL Electric	5,214		4,862		4,567		4,475

LG&E	2,471		2,295		2,469		2,369
KU	3,066		2,750		3,064		2,861

(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

Risk Management Objectives

(All Registrants)

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 forward starting interest rate swaps to hedge changes 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.

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 Last Resort Service (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 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, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

Master Netting Arrangements (PPL, LG&E and KU)

Net derivative positions on the balance sheets are not offset against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.

PPL, LG&E and KU had no cash collateral posted or obligation to return cash collateral under master netting arrangements at December 31, 2024 and 2023.

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 swap contracts that qualify as cash flow hedges may be entered into to hedge floating interest rate risk associated with both existing and anticipated debt issuances. PPL had no such contracts at December 31, 2024.

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 2024, 2023 and 2022, PPL had no cash flow hedges reclassified into earnings associated with discontinued cash flow hedges.

At December 31, 2024, 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, 2024, 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, 2024. At December 31, 2024, RIE held contracts with notional volumes of 49 Bcf that range in maturity from 2025 through 2029.

Accounting and Reporting

(All Registrants)

All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless the NPNS is elected. NPNS contracts include certain full-requirement purchase contracts and other physical purchase contracts. Changes in the fair value of derivatives not designated as NPNS are recognized in earnings unless specific hedge accounting criteria are met and designated as such, except for the changes in fair values of LG&E's interest rate swaps that are recognized as regulatory assets or regulatory liabilities. See Note 7 for amounts recorded in regulatory assets and regulatory liabilities at December 31, 2024 and 2023.

See Note 1 for additional information on accounting policies related to derivative instruments.

(PPL)

The following table presents the fair value and location of derivative instruments recorded on the Balance Sheets:


	December 31, 2024								December 31, 2023
	Derivatives designated as hedging instruments				Derivatives not designated as hedging instruments				Derivatives designated as hedging instruments				Derivatives not designated as hedging instruments
	Assets		Liabilities		Assets		Liabilities		Assets		Liabilities		Assets		Liabilities
Current:
Price Risk Management
Assets/Liabilities (a):
Interest rate swaps (b)	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	1
Gas contracts	—		—		7		10		—		—		1		51
Total current	—		—		7		10		—		—		1		52
Noncurrent:
Price Risk Management
Assets/Liabilities (a):
Interest rate swaps (b)	—		—		—		3		—		—		—		6
Gas contracts	—		—		2		3		—		—		—		9

Total noncurrent	—		—		2		6		—		—		—		15
Total derivatives	$	—	$	—	$	9	$	16	$	—	$	—	$	1	$	67

(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
2024
Cash Flow Hedges:
Interest rate swaps	$	—	Interest Expense	$	(3)

Total	$	—		$	(3)

2023
Cash Flow Hedges:
Interest rate swaps	$	—	Interest Expense	$	(3)


Total	$	—		$	(3)


2022
Cash Flow Hedges:
Interest rate swaps	$	—	Interest Expense	$	(3)


Total	$	—		$	(3)


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivative	2024		2023		2022

Interest rate swaps	Interest Expense	—		—		(2)
Gas contracts	Energy Purchases	(40)		(19)		41
	Other income (expense) - net	—		$	(1)	$	—
	Total	$	(40)	$	(20)	$	39


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized as Regulatory Liabilities/Assets	2024		2023		2022
Gas contracts	Regulatory assets - current	$	48	$	9	$	39
	Regulatory assets - noncurrent	7		(8)		—
Interest rate swaps	Regulatory assets - noncurrent	4		—		11
	Total	$	59	$	1	$	50

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 swaps:
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 swaps:
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, 2022:


	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	$	513
The effects of cash flow hedges:
Gain (Loss) on cash flow hedging relationships:
Interest rate swaps:
Amount of gain (loss) reclassified from AOCI to income	(3)

(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, 2024				December 31, 2023
	Assets		Liabilities		Assets		Liabilities
Current:
Price Risk Management
Assets/Liabilities:
Interest rate swaps	$	—	$	—	$	—	$	1
Total current	—		—		—		1
Noncurrent:
Price Risk Management
Assets/Liabilities:
Interest rate swaps	—		3		—		6
Total noncurrent	—		3		—		6
Total derivatives	$	—	$	3	$	—	$	7

The following tables present 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)						2024						2023						2022
Interest rate swaps						Interest Expense						$	—					$	—					$	(2)


Derivative Instruments						Location of Gain (Loss)						2024						2023						2022
Interest rate swaps						Regulatory assets - noncurrent						$	4					$	—					$	11

(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, 2024
Derivatives
PPL	$	9	$	5	$	—	$	4	$	16	$	5	$	—	$	11

LG&E	—		—		—		—		3		—		—		3
December 31, 2023
Derivatives
PPL	$	1	$	—	$	—	$	1	$	67	$	—	$	—	$	67

LG&E	—		—		—		—		7		—		—		7

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, 2024, derivative contracts in a net liability position that contain credit risk-related contingent features was $3 million. The aggregate fair value of additional collateral requirements in the event of a credit downgrade below investment grade was $4 million.

17. Goodwill and Other Intangible Assets

Goodwill

(PPL)

The changes in the carrying amount of goodwill by segment were:


	Kentucky Regulated				Rhode Island Regulated				Corporate and Other				Total
	2024		2023		2024		2023		2024		2023		2024		2023
Balance at beginning of period (a)	$	662	$	662	$	725	$	725	$	860	$	861	$	2,247	$	2,248
Goodwill recognized during the period (b)	—		—		—		—		—		(1)		—		(1)


Total	$	662	$	662	$	725	$	725	$	860	$	860	$	2,247	$	2,247

(a)There were no accumulated impairment losses related to goodwill.

(b)Recognized as a result of purchase price allocation adjustments related to the acquisition of RIE. See Note 9 for additional information.

Other Intangible Assets

(PPL)

The gross carrying amount and the accumulated amortization of other intangible assets were:


	December 31, 2024				December 31, 2023
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Subject to amortization:
Contracts (a)	$	125	$	116	$	125	$	107
Renewable Energy Credits	20		—		15		—
Land rights and easements	432		147		411		143
Licenses and other	2		—		2		—
Total subject to amortization	579		263		553		250

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	$	597	$	263	$	571	$	250

(a)Gross carrying amount in 2024 and 2023 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.

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:
	2024		2023		2022
Intangible assets with no regulatory offset	$	5	$	5	$	5
Intangible assets with regulatory offset	8		9		9
Total	$	13	$	14	$	14

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


	2025		2026		2027		2028		2029
Intangible assets with no regulatory offset	$	4	$	4	$	4	$	4	$	4
Intangible assets with regulatory offset	8		2		—		—		—
Total	$	12	$	6	$	4	$	4	$	4

(PPL Electric)

The gross carrying amount and the accumulated amortization of other intangible assets were:


	December 31, 2024				December 31, 2023
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Subject to amortization:
Land rights and easements	$	396	$	141	$	389	$	138
Licenses and other	2		1		2		1
Total subject to amortization	398		142		391		139

Not subject to amortization due to indefinite life:
Land rights and easements	18		—		17		—
Total	$	416	$	142	$	408	$	139

Intangible assets are shown as "Intangibles" on the Balance Sheets.

Amortization expense was as follows:


	2024		2023		2022

Intangible assets with no regulatory offset	$	4	$	4	$	4

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


			2025						2026						2027						2028						2029
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, 2024				December 31, 2023
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Subject to amortization:

Land rights and easements	$	7	$	2	$	7	$	2

OVEC power purchase agreement (a)	86		79		86		73
Total subject to amortization	$	93	$	81	$	93	$	75

(a) 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:


	2024		2023		2022

Intangible assets with regulatory offset	$	6	$	6	$	6

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


			2025						2026						2027						2028						2029
Intangible assets with regulatory offset			$	6					$	1					$	—					$	—					$	—

(KU)

The gross carrying amount and the accumulated amortization of other intangible assets were:


	December 31, 2024				December 31, 2023
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Subject to amortization:

Land rights and easements	$	29	$	4	$	17	$	4

OVEC power purchase agreement (a)	39		36		39		33
Total subject to amortization	$	68	$	40	$	56	$	37

Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.

Amortization expense was as follows:


	2024	2023	2022

Intangible assets with regulatory offset	2	3	3

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


			2025						2026						2027						2028						2029
Intangible assets with regulatory offset			$	2					$	1					$	—					$	—					$	—

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.

The changes in the carrying amounts of AROs were as follows:


	PPL				LG&E				KU
	2024		2023		2024		2023		2024		2023
ARO at beginning of period	$	158	$	177	$	85	$	86	$	66	$	82

Accretion	8		9		4		4		4		5
Obligations incurred	9		2		3		1		6		1
Changes in estimated timing or cost	4		15		3		11		1		6
Obligations settled	(24)		(39)		(11)		(11)		(13)		(28)
Other	2		(6)		—		(6)				—
ARO at end of period	$	157	$	158	$	84	$	85	$	64	$	66

19. Accumulated Other Comprehensive Income (Loss)

(PPL)

The after-tax changes in AOCI by component for the years ended December 31 were as follows:


							Defined benefit plans
	Foreign currency translation adjustments		Unrealized gains (losses) on qualifying derivatives		Equity investees' AOCI		Prior service costs		Actuarial gain (loss)		Total
PPL
December 31, 2021	$	—	$	1	$	—	$	(6)	$	(152)	$	(157)
Amounts arising during the year	—		—		2		(1)		11		12
Reclassifications from AOCI	—		2		—		2		17		21

Net OCI during the year	—		2		2		1		28		33
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)

The following table presents PPL's gains (losses) and related income taxes for reclassifications from AOCI for the years ended December 31, 2024, 2023 and 2022. 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	2024		2023		2022		Affected Line Item on the Statements of Income





Qualifying derivatives
Interest rate swaps	$	(3)	$	(3)	$	(3)	Interest Expense




Total Pre-tax	(3)		(3)		(3)
Income Taxes	—		—		1
Total After-tax	(3)		(3)		(2)






Defined benefit plans
Prior service costs	(1)		(2)		(3)
Net actuarial loss	4		3		(24)
Total Pre-tax	3		1		(27)
Income Taxes	—		1		8
Total After-tax	3		2		(19)
Total reclassifications during the year	$	—	$	(1)	$	(21)

20. New Accounting Guidance Pending Adoption

(All Registrants)

Improvements to Income Tax Disclosures

In December 2023, the FASB issued guidance which requires public business entities to provide additional income tax disclosures including a disaggregated rate reconciliation as well as information on income taxes paid.

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, 2024. Early adoption is permitted for annual financial statements that have not yet been issued or made available for issuance.

The Registrants are currently assessing the impact of adopting this guidance.

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 (DD&A) 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.

The Registrants are currently assessing the impact of adopting this guidance.

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