FirstEnergy Solutions Corp.

The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

June 30, 2011 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 562 $ — $ 562
Derivative assets — commodity contracts — 283 — 283
Derivative assets — FTRs — — 2 2
Equity securities⁽³⁾
96 — — 96
Foreign government debt securities — 160 — 160
U.S. government debt securities — 316 — 316
U.S. state debt securities — 7 — 7
Other⁽²⁾
— 42 — 42

Total assets
$ 96 $ 1,370 $ 2 $ 1,468

Liabilities

Derivative liabilities — commodity contracts $ — $ (327 ) $ — $ (327 )

Total liabilities
$ — $ (327 ) $ — $ (327 )

Net assets (liabilities)⁽¹⁾
$ 96 $ 1,043 $ 2 $ 1,141

December 31, 2010 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 528 $ — $ 528
Derivative assets — commodity contracts — 241 — 241
Foreign government debt securities — 147 — 147
U.S. government debt securities — 308 — 308
U.S. state debt securities — 6 — 6
Other⁽²⁾
— 148 — 148

Total assets
$ — $ 1,378 $ — $ 1,378

Liabilities

Derivative liabilities — commodity contracts $ — $ (348 ) $ — $ (348 )

Total liabilities
$ — $ (348 ) $ — $ (348 )

Net assets (liabilities)⁽¹⁾
$ — $ 1,030 $ — $ 1,030

37

Table of Contents



September 30, 2011	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	53		$	—		$	53
Derivative assets — commodity contracts	—		200			—			200
Derivative assets — FTRs	—		—			2			2
Equity securities⁽³⁾	87		—			—			87
Foreign government debt securities	—		2			—			2
U.S. government debt securities	—		172			—			172
Other⁽²⁾	—		904			—			904
Total assets	$	87	$	1,331		$	2		$	1,420

Liabilities
Derivative liabilities — commodity contracts	$	—	$	(238	)	$	—		$	(238	)
Derivative liabilities — FTRs	—		—			(4		)	(4		)
Total liabilities	$	—	$	(238	)	$	(4	)	$	(242	)
Net assets (liabilities)⁽¹⁾	$	87	$	1,093		$	(2	)	$	1,178

December 31, 2010	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	528		$	—		$	528
Derivative assets — commodity contracts	—		241			—			241
Foreign government debt securities	—		147			—			147
U.S. government debt securities	—		308			—			308
U.S. state debt securities	—		6			—			6
Other⁽²⁾	—		148			—			148
Total assets	$	—	$	1,378		$	—		$	1,378

Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—		$	(348	)
Total liabilities	$	—	$	(348	)	$	—		$	(348	)
Net assets⁽¹⁾	$	—	$	1,030		$	—		$	1,030


⁽¹⁾		Excludes $7$(31) million and $7 million as of September 30, 2011 and December 31, 2010, respectively, of receivables, payables, ~~deferred~~ taxes and accrued income associated with the financial instruments reflected within the fair value table.



⁽²⁾		Primarily consists of short-term cash ~~and cash equivalents.~~investments.



⁽³⁾		NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy during the period ending ~~June~~September 30, ~~2011:~~2011:

Derivative Asset Derivative Liability Net
FTRs FTRs FTRs
(In millions)
January 1, 2011 Balance $ — $ — $ —
Realized gain (loss) — — —
Unrealized gain (loss) 1 — 1
Purchases 2 — 2
Issuances — — —
Sales — — —
Settlements (1 ) — (1 )
Transfers in (out) of Level 3 — — —

June 30, 2011 Balance $ 2 $ — $ 2

38

Table of Contents

Derivative Asset
FTRs

Derivative Liability
FTRs

Net
FTRs
(In millions)
January 1, 2011 Balance $ —
$ —
$ —
Realized gain (loss) —
—
—
Unrealized gain (loss) 4
(4 ) —
Purchases 2
—
2
Issuances —
—
—
Sales —
—
—
Settlements (4 ) —
(4 )
Transfers in (out) of Level 3 —
—
—
September 30, 2011 Balance $ 2
$ (4 ) $ (2 )

Ohio Edison Company

The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of ~~June~~September 30, 2011 and ~~December 31, 2010:~~

June 30, 2011 Level 1 Level 2 Level 3 Total
(In millions)
Assets

U.S. government debt securities $ — $ 131 $ — $ 131
Other — 2 — 2

Total assets⁽¹⁾
$ — $ 133 $ — $ 133

December 31, 2010 Level 1 Level 2 Level 3 Total
(In millions)
Assets

U.S. government debt securities $ — $ 124 $ — $ 124
Other — 2 — 2

Total assets⁽¹⁾
$ — $ 126 $ — $ 126

⁽¹⁾

~~Excludes $2 million and $1 million as of June 30, 2011 and~~ December 31, 2010:



September 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Other⁽²⁾	$	—	$	138	$	—	$	138
Total assets⁽¹⁾	$	—	$	138	$	—	$	138

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	124	$	—	$	124
Other	—		2		—		2
Total assets⁽¹⁾	$	—	$	126	$	—	$	126


⁽¹⁾	Excludes $(2) million and $1 million as of September 30, 2011 and December 31, 2010, respectively, of receivables, payables, ~~deferred~~ taxes and accrued income associated with the financial instruments reflected within the fair value table.


⁽²⁾	Primarily consists of short-term cash investments.

The Toledo Edison Company

The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

June 30, 2011 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 16 $ — $ 16
Equity securities⁽³⁾
26 — — 26
U.S. government debt securities — 33 — 33
U.S. state debt securities — 1 — 1
Other⁽²⁾
— 3 — 3

Total assets⁽¹⁾
$ 26 $ 53 $ — $ 79

December 31, 2010 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 7 $ — $ 7
U.S. government debt securities — 33 — 33
U.S. state debt securities — 1 — 1
Other⁽²⁾
— 35 — 35

Total assets⁽¹⁾
$ — $ 76 $ — $ 76

39

Table of Contents



September 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	7	$	—	$	7
Equity securities⁽³⁾	24		—		—		24
U.S. government debt securities	—		38		—		38
Other⁽²⁾	—		9		—		9
Total assets⁽¹⁾	$	24	$	54	$	—	$	78

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	7	$	—	$	7
U.S. government debt securities	—		33		—		33
U.S. state debt securities	—		1		—		1
Other⁽²⁾	—		35		—		35
Total assets⁽¹⁾	$	—	$	76	$	—	$	76


⁽¹⁾		Excludes ~~$(1)~~$2 million ~~and $2 million~~ as of ~~June 30, 2011 and~~ December 31, 2010 ~~respectively~~ of receivables, payables, ~~deferred~~ taxes and accrued income associated with the financial instruments reflected within the fair value table.



⁽²⁾		Primarily consists of short-term cash ~~and cash equivalents.~~investments.



⁽³⁾		NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

Jersey Central Power & Light Company

The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

June 30, 2011 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 81 $ — $ 81
Derivative assets — NUG contracts⁽¹⁾
— — 5 5
Equity securities⁽²⁾
21 — — 21
Foreign government debt securities — 13 — 13
U.S. government debt securities — 54 — 54
U.S. state debt securities — 215 — 215
Other — 14 — 14

Total assets
$ 21 $ 377 $ 5 $ 403

Liabilities

Derivative liabilities — NUG contracts⁽¹⁾
$ — $ — $ (240 ) $ (240 )

Total liabilities
$ — $ — $ (240 ) $ (240 )

Net assets (liabilities)⁽³⁾
$ 21 $ 377 $ (235 ) $ 163

December 31, 2010 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 23 $ — $ 23
Derivative assets — commodity contracts — 2 — 2
Derivative assets — NUG contracts⁽¹⁾
— — 6 6
Equity securities⁽²⁾
96 — — 96
U.S. government debt securities — 33 — 33
U.S. state debt securities — 236 — 236
Other — 4 — 4

Total assets
$ 96 $ 298 $ 6 $ 400

Liabilities

Derivative liabilities — NUG contracts⁽¹⁾
$ — $ — $ (233 ) $ (233 )

Total liabilities
$ — $ — $ (233 ) $ (233 )

Net assets (liabilities)⁽³⁾
$ 96 $ 298 $ (227 ) $ 167

40

Table of Contents



September 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Derivative assets — NUG contracts⁽¹⁾	$	—	$	—	$	4		$	4
Equity securities⁽²⁾	20		—		—			20
U.S. government debt securities	—		51		—			51
U.S. state debt securities	—		212		—			212
Other⁽⁴⁾	—		123		—			123
Total assets	$	20	$	386	$	4		$	410
Liabilities
Derivative liabilities — NUG contracts⁽¹⁾	$	—	$	—	$	(222	)	$	(222	)
Total liabilities	$	—	$	—	$	(222	)	$	(222	)

Net assets (liabilities)⁽³⁾	$	20	$	386	$	(218	)	$	188

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	23	$	—		$	23
Derivative assets — commodity contracts	—		2		—			2
Derivative assets — NUG contracts⁽¹⁾	—		—		6			6
Equity securities⁽²⁾	96		—		—			96
U.S. government debt securities	—		33		—			33
U.S. state debt securities	—		236		—			236
Other⁽⁴⁾	—		4		—			4
Total assets	$	96	$	298	$	6		$	400
Liabilities
Derivative liabilities — NUG contracts⁽¹⁾	$	—	$	—	$	(233	)	$	(233	)
Total liabilities	$	—	$	—	$	(233	)	$	(233	)

Net assets (liabilities)⁽³⁾	$	96	$	298	$	(227	)	$	167


⁽¹⁾		NUG contracts are subject to regulatory accounting and do not impact earnings.


⁽²⁾		NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.


⁽³⁾		Excludes $5$6 million and ~~$(3)~~$(3) million as of ~~June~~September 30, 2011 and December 31, 2010, respectively, of receivables, payables, ~~deferred~~ taxes and accrued income associated with the financial instruments reflected within the fair value table.

⁽⁴⁾
Primarily consists of short-term cash investments.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy during the periods ending ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

Derivative Asset Derivative Liability Net
NUG Contracts⁽¹⁾ NUG Contracts⁽¹⁾ NUG Contracts⁽¹⁾
(In millions)
January 1, 2011 Balance $ 6 $ (233 ) $ (227 )
Realized gain (loss) — — —
Unrealized gain (loss) (1 ) (71 ) (72 )
Purchases — — —
Issuances — — —
Sales — — —
Settlements — 64 64
Transfers in (out) of Level 3 — — —

June 30, 2011 Balance $ 5 $ (240 ) $ (235 )

January 1, 2010 Balance $ 8 $ (399 ) $ (391 )
Realized gain (loss) — — —
Unrealized gain (loss) (1 ) 36 35
Purchases — — —
Issuances — — —
Sales — — —
Settlements (1 ) 130 129
Transfers in (out) of Level 3 — — —

December 31, 2010 Balance $ 6 $ (233 ) $ (227 )

Table of Contents



	Derivative Asset NUG Contracts⁽¹⁾			Derivative Liability NUG Contracts⁽¹⁾			Net NUG Contracts⁽¹⁾
	(In millions)
January 1, 2011 Balance	$	6		$	(233	)	$	(227	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(2		)	(71		)	(73		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			82			82
Transfers in (out) of Level 3	—			—			—
September 30, 2011 Balance	$	4		$	(222	)	$	(218	)
January 1, 2010 Balance	$	8		$	(399	)	$	(391	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(1		)	36			35
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	(1		)	130			129
Transfers in (out) of Level 3	—			—			—
December 31, 2010 Balance	$	6		$	(233	)	$	(227	)


⁽¹⁾		Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

Metropolitan Edison Company

The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

June 30, 2011 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 138 $ — $ 138
Derivative assets — NUG contracts⁽¹⁾
— — 66 66
Equity securities⁽²⁾
33 — — 33
Foreign government debt securities — 20 — 20
U.S. government debt securities — 87 — 87
U.S. state debt securities — 2 — 2
Other — 22 — 22

Total assets
$ 33 $ 269 $ 66 $ 368

Liabilities

Derivative liabilities — NUG contracts⁽¹⁾
$ — $ — $ (122 ) $ (122 )

Total liabilities
$ — $ — $ (122 ) $ (122 )

Net assets (liabilities)⁽³⁾
$ 33 $ 269 $ (56 ) $ 246

December 31, 2010 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 32 $ — $ 32
Derivative assets — commodity contracts — 5 — 5
Derivative assets — NUG contracts⁽¹⁾
— — 112 112
Equity securities⁽²⁾
160 — — 160
Foreign government debt securities — 1 — 1
U.S. government debt securities — 88 — 88
U.S. state debt securities — 2 — 2
Other — 14 — 14

Total assets
$ 160 $ 142 $ 112 $ 414

Liabilities

Derivative liabilities — NUG contracts⁽¹⁾
$ — $ — $ (116 ) $ (116 )

Total liabilities
$ — $ — $ (116 ) $ (116 )

Net assets (liabilities)⁽³⁾
$ 160 $ 142 $ (4 ) $ 298

42

Table of Contents



September 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	—	$	—		$	—
Derivative assets — NUG contracts⁽¹⁾	—		—		52			52
Equity securities⁽²⁾	31		—		—			31
Foreign government debt securities	—		—		—			—
U.S. government debt securities	—		41		—			41
U.S. state debt securities	—		—		—			—
Other⁽⁴⁾	—		233		—			233
Total assets	$	31	$	274	$	52		$	357
Liabilities
Derivative liabilities — NUG contracts⁽¹⁾	$	—	$	—	$	(132	)	$	(132	)
Total liabilities	$	—	$	—	$	(132	)	$	(132	)

Net assets (liabilities)⁽³⁾	$	31	$	274	$	(80	)	$	225

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	32	$	—		$	32
Derivative assets — commodity contracts	—		5		—			5
Derivative assets — NUG contracts⁽¹⁾	—		—		112			112
Equity securities⁽²⁾	160		—		—			160
Foreign government debt securities	—		1		—			1
U.S. government debt securities	—		88		—			88
U.S. state debt securities	—		2		—			2
Other⁽⁴⁾	—		14		—			14
Total assets	$	160	$	142	$	112		$	414

Liabilities
Derivative liabilities — NUG contracts⁽¹⁾	$	—	$	—	$	(116	)	$	(116	)
Total liabilities	$	—	$	—	$	(116	)	$	(116	)
Net assets (liabilities)⁽³⁾	$	160	$	142	$	(4	)	$	298


⁽¹⁾		NUG contracts are subject to regulatory accounting and do not impact earnings.


⁽²⁾		NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.


⁽³⁾		Excludes ~~$(1)~~$(3) million and ~~$(9)~~$(9) million as of ~~June~~September 30, 2011 and December 31, 2010, respectively, of receivables, payables, ~~deferred~~ taxes and accrued income associated with the financial instruments reflected within the fair value table.

⁽⁴⁾
Primarily consists of short-term cash investments.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy during the periods ending ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

Derivative Asset Derivative Liability Net
NUG Contracts⁽¹⁾ NUG Contracts⁽¹⁾ NUG Contracts⁽¹⁾
(In millions)
January 1, 2011 Balance $ 112 $ (116 ) $ (4 )
Realized gain (loss) — — —
Unrealized gain (loss) (42 ) (36 ) (78 )
Purchases — — —
Issuances — — —
Sales — — —
Settlements (4 ) 30 26
Transfers in (out) of Level 3 — — —

June 30, 2011 Balance $ 66 $ (122 ) $ (56 )

January 1, 2010 Balance $ 176 $ (143 ) $ 33
Realized gain (loss) — — —
Unrealized gain (loss) (59 ) (38 ) (97 )
Purchases — — —
Issuances — — —
Sales — — —
Settlements (5 ) 65 60
Transfers in (out) of Level 3 — — —

December 31, 2010 Balance $ 112 $ (116 ) $ (4 )

Table of Contents



	Derivative Asset NUG Contracts⁽¹⁾			Derivative Liability NUG Contracts⁽¹⁾			Net NUG Contracts⁽¹⁾
	(In millions)
January 1, 2011 Balance	$	112		$	(116	)	$	(4	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(54		)	(61		)	(115		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	(6		)	45			39
Transfers in (out) of Level 3	—			—			—
September 30, 2011 Balance	$	52		$	(132	)	$	(80	)
January 1, 2010 Balance	$	176		$	(143	)	$	33
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(59		)	(38		)	(97		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	(5		)	65			60
Transfers in (out) of Level 3	—			—			—
December 31, 2010 Balance	$	112		$	(116	)	$	(4	)


⁽¹⁾		Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

Pennsylvania Electric Company

The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

June 30, 2011 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 69 $ — $ 69
Derivative assets — NUG contracts⁽¹⁾
— — 4 4
Equity securities⁽²⁾
20 — — 20
Foreign government debt securities 12 12
U.S. government debt securities — 52 — 52
U.S. state debt securities — 81 — 81
Other — 53 — 53

Total assets
$ 20 $ 267 $ 4 $ 291

Liabilities

Derivative liabilities — NUG contracts⁽¹⁾
$ — $ — $ (160 ) $ (160 )

Total liabilities
$ — $ — $ (160 ) $ (160 )

Net assets (liabilities)⁽³⁾
$ 20 $ 267 $ (156 ) $ 131

December 31, 2010 Level 1 Level 2 Level 3 Total
(In millions)
Assets

Corporate debt securities $ — $ 8 $ — $ 8
Derivative assets — commodity contracts — 2 — 2
Derivative assets — NUG contracts⁽¹⁾
— — 4 4
Equity securities⁽²⁾
81 — — 81
U.S. government debt securities — 9 — 9
U.S. state debt securities — 133 — 133
Other — 5 — 5

Total assets
$ 81 $ 157 $ 4 $ 242

Liabilities

Derivative liabilities — NUG contracts⁽¹⁾
$ — $ — $ (117 ) $ (117 )

Total liabilities
$ — $ — $ (117 ) $ (117 )

Net assets (liabilities)⁽³⁾
$ 81 $ 157 $ (113 ) $ 125

44

Table of Contents



September 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Derivative assets — NUG contracts⁽¹⁾	$	—	$	—	$	3		$	3
Equity securities⁽²⁾	19		—		—			19
U.S. government debt securities	—		28		—			28
U.S. state debt securities	—		98		—			98
Other⁽⁴⁾	—		144		—			144
Total assets	$	19	$	270	$	3		$	292
Liabilities
Derivative liabilities — NUG contracts⁽¹⁾	$	—	$	—	$	(188	)	$	(188	)
Total liabilities	$	—	$	—	$	(188	)	$	(188	)

Net assets (liabilities)⁽³⁾	$	19	$	270	$	(185	)	$	104

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	8	$	—		$	8
Derivative assets — commodity contracts	—		2		—			2
Derivative assets — NUG contracts⁽¹⁾	—		—		4			4
Equity securities⁽²⁾	81		—		—			81
U.S. government debt securities	—		9		—			9
U.S. state debt securities	—		133		—			133
Other⁽⁴⁾	—		5		—			5
Total assets	$	81	$	157	$	4		$	242
Liabilities
Derivative liabilities — NUG contracts⁽¹⁾	$	—	$	—	$	(117	)	$	(117	)
Total liabilities	$	—	$	—	$	(117	)	$	(117	)

Net assets (liabilities)⁽³⁾	$	81	$	157	$	(113	)	$	125


⁽¹⁾		NUG contracts are subject to regulatory accounting and do not impact earnings.


⁽²⁾		NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.


⁽³⁾		Excludes $1$1 million and ~~$(3)~~$(3) million as of ~~June~~September 30, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table.

⁽⁴⁾
Primarily consists of short-term cash investments.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG and commodity contracts held by Penelec and classified as Level 3 in the fair value hierarchy during the periods ended ~~June~~September 30, 2011 and December 31, ~~2010:~~2010:

Derivative Asset Derivative Liability Net
NUG Contracts⁽¹⁾ NUG Contracts⁽¹⁾ NUG Contracts⁽¹⁾
(In millions)
January 1, 2011 Balance $ 4 $ (117 ) $ (113 )
Realized gain (loss) — — —
Unrealized gain (loss) — (88 ) (88 )
Purchases — — —
Issuances — — —
Sales — — —
Settlements — 45 45
Transfers in (out) of Level 3 — — —

June 30, 2011 Balance $ 4 $ (160 ) $ (156 )

January 1, 2010 Balance $ 16 $ (101 ) $ (85 )
Realized gain (loss) — — —
Unrealized gain (loss) (11 ) (108 ) (119 )
Purchases — — —
Issuances — — —
Sales — — —
Settlements (1 ) 92 91
Transfers in (out) of Level 3 — — —

December 31, 2010 Balance $ 4 $ (117 ) $ (113 )

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	Derivative Asset NUG Contracts⁽¹⁾			Derivative Liability NUG Contracts⁽¹⁾			Net NUG Contracts⁽¹⁾
	(In millions)
January 1, 2011 Balance	$	4		$	(117	)	$	(113	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(139		)	(139		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	(1		)	68			67
Transfers in (out) of Level 3	—			—			—
September 30, 2011 Balance	$	3		$	(188	)	$	(185	)
January 1, 2010 Balance	$	16		$	(101	)	$	(85	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(11		)	(108		)	(119		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	(1		)	92			91
Transfers in (out) of Level 3	—			—			—
December 31, 2010 Balance	$	4		$	(117	)	$	(113	)


⁽¹⁾		Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

During the three months endedSeptember 30, 2011, FirstEnergy received approximately $130 million from assigning a substantially below-market, long-term fossil fuel contract to a third party. As a result, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of the assigned contract. The transaction reduced fuel costs during the quarter by approximately $123 million.

5.6. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that ~~qualify~~qualified and ~~are~~were designated as cash flow hedge instruments are recorded in AOCL. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. FirstEnergy has contractual derivative agreements through December 2018.

Cash Flow Hedges

FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating interest rates and commodity prices. The effective portion of gains and losses on ~~the~~a derivative contract are reported as a component of AOCL with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

As of December 31, 2010, commodity derivative contracts designated in cash flow hedging relationships were ~~$104~~$104 million of assets and ~~$101~~$101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships. Total net unamortized gains included in AOCL associated with dedesignated cash flow hedges totaled $8$12 million as of ~~June~~September 30, ~~2011.~~2011. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expenses ~~totaled $14~~were less than $1 million and ~~$19~~$19 million during the three months and ~~six~~nine months ended ~~June~~September 30, 2011, respectively. Approximately $3$1 million is expected to be amortized to expense during the next twelve months.

FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with

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anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of ~~June~~September 30, 2011, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled ~~$84~~$81 million ~~($55 million net of tax)~~ as of ~~June~~September 30, ~~2011.~~2011. Based on current estimates, approximately ~~$10~~$9 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCL into interest expense totaled $3$3 million during the three months ended ~~June~~September 30, 2011, and 2010 and $6$9 million during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010.

Fair Value Hedges

FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of ~~June~~September 30, 2011, no fixed-for-floating interest rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled ~~$113~~$107 million ~~($73 million net of tax)~~ as of ~~June~~September 30, ~~2011.~~2011. Based on current estimates, approximately ~~$22~~$21 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $6$5 million ~~and $2 million~~ during the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~$11~~$16 million and $3$7 million during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.

Commodity Derivatives

FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting.

Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas; primarily natural gas is used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Interest rate swaps include two interest rate swap agreements that ~~expire~~expired during 2011 with an aggregate notional value of ~~$200~~$200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.

As of ~~June~~September 30, 2011, FirstEnergy’s net liability position under commodity derivative contracts was ~~$45~~$41 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted ~~$81~~$49 million and ~~Allegheny~~AE Supply posted $2$1 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post ~~$49~~$48 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on commodity derivative contracts held as of ~~June~~September 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately ~~$31~~$14 million ~~($20 million net of tax)~~ during the next twelve months.

FTRs

FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.

The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.

The following tables summarize the fair value of derivative instruments in FirstEnergy’s Consolidated Balance Sheets:

~~Derivatives not designated as hedging instruments as~~

Table of ~~June 30, 2011:~~Contents


Derivative Assets

	Fair Value
	June 30,		December 31,
Derivatives not designated as hedging instruments:					Derivatives not designated as hedging instruments:
Derivative Assets					Derivative Assets				Derivative Liabilities
	2011		2010		Fair Value					Fair Value
	*(In millions)*				September 30, 2011		December 31, 2010			September 30, 2011		December 31, 2010
					(In millions)					(In millions)
Power Contracts									Power Contracts
Current Assets	$	210	$	96	$	157	$	96	Current Liabilities	$	190	$	209
Noncurrent Assets		102		40	68		40		Noncurrent Liabilities	67		38
FTRs									FTRs
Current Assets		13		—	4		—		Current Liabilities	13		—
Noncurrent Assets		—		—	—		—		Noncurrent Liabilities	—		—
NUGs					59		122		NUGs	542		467
Current Assets		4		3
Noncurrent Assets		71		119
Interest Rate Swaps									Interest Rate Swaps
Current Assets		4		—	—		—		Current Liabilities	—		—
Noncurrent Assets		—		—	—		—		Noncurrent Liabilities	—		—
Other									Other
Current Assets		—		10	—		10		Current Liabilities	—		—
Noncurrent Assets		—		—	—		—		Noncurrent Liabilities	—		—

Total Derivatives	$	404	$	268

Total Derivatives Assets					$	288	$	268	Total Derivatives Liabilities	$	812	$	714

Derivative Liabilities

Fair Value
June 30, December 31,
2011 2010
(In millions)

Power Contracts
Current Liabilities $ 274 $ 209
Noncurrent Liabilities 88 38
FTRs
Current Liabilities 7 —
Noncurrent Liabilities — —
NUGs
Current Liabilities 317 229
Noncurrent Liabilities 205 238
Interest Rate Swaps
Current Liabilities 5 —
Noncurrent Liabilities — —
Other
Current Liabilities — —
Noncurrent Liabilities — —

Total Derivatives $ 896 $ 714

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of ~~June~~September 30, ~~2011:~~2011:

Purchases Sales Net Units
(In thousands)
Power Contracts 45,573 (59,549 ) (13,976 ) MWH
FTRs 53,656 — 53,656 MWH
Interest Rate Swaps 200,000 (200,000 ) — notional dollars
NUGs 26,903 — 26,903 MWH



	Purchases	Sales	Net		Units
	(In thousands)
Power Contracts	34,956	49,696	(14,740	)	MWH
FTRs	45,730	27	45,703		MWH
NUGs	25,442	—	25,442		MWH

The effect of derivative instruments on the Consolidated Statements of Income during the three months and ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, are summarized in the following tables:

Three Months Ended June 30,
Power Interest
Contracts FTRs Rate Swaps Other Total
(In millions)
Derivatives in a Hedging Relationship

2011

Gain (Loss) Recognized in AOCL (Effective Portion) $ 14 $ — $ — $ — $ 14
Effective Gain (Loss) Reclassified to:⁽¹⁾

Purchase Power Expense — — — — —
Revenues — — — — —

2010

Gain (Loss) Recognized in AOCL (Effective Portion) $ — $ — $ — $ 3 $ 3
Effective Gain (Loss) Reclassified to:⁽¹⁾

Purchase Power Expense (3 ) — — — (3 )
Revenues (5 ) — — — (5 )
Fuel Expense — — — (4 ) (4 )
48

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														Three Months Ended September 30
														Power Contracts			FTRs			Interest Rate Swaps		Other			Total
														(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)														$	—		$	—		$	—	$	—		$	—
Effective Gain (Loss) Reclassified to: ⁽¹⁾
Purchased Power Expense														—			—			—		—			—
Revenues														—			—			—		—			—
2010
Gain (Loss) Recognized in AOCL (Effective Portion)														$	(1	)	$	—		$	—	$	3		$	2
Effective Gain (Loss) Reclassified to:⁽¹⁾
Purchased Power Expense														5			—			—		—			5
Revenues														(7		)	—			—		—			(7		)
Fuel Expense														—			—			—		(4		)	(4		)

Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	33		$	—		$	—	$	—	$	33
Purchased Power Expense														$	27		$	—		$	—	$	—		$	27
Revenues		(4	)		—			—		—		(4	)	3			—			—		—			3
Other Operating Expense		(34	)		13			—		—		(21	)	(11		)	(15		)	1		—			(25		)

Realized Gain (Loss) Reclassified to:
Purchase Power Expense		1			—			—		—		1
Purchased Power Expense														(5		)	—			—		—			(5		)
Revenues		(39	)		18			—		—		(21	)	(40		)	30			—		—			(10		)
Other Operating Expense		—			(59	)		—		—		(59	)	—			(35		)	—		—			(35		)

2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	66		$	—		$	—	$	—	$	66

Purchased Power Expense														$	3		$	—		$	—	$	—		$	3
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(26	)		—			—		—		(26	)
Purchased Power Expense														(22		)	—			—		—			(22		)

Derivatives Not in a Hedging Three Months Ended June 30,
Relationship with Regulatory Offset⁽²⁾ NUGs Other Total
(In millions)
2011

Unrealized Gain (Loss) to Derivative Instrument: $ (147 ) $ 2 $ (145 )
Unrealized Gain (Loss) to Regulatory Assets: 147 (2 ) 145

Realized Gain (Loss) to Derivative Instrument: 62 — 62
Realized Gain (Loss) to Regulatory Assets: (62 ) — (62 )

2010

Unrealized Gain (Loss) to Derivative Instrument: $ (35 ) — $ (35 )
Unrealized Gain (Loss) to Regulatory Assets: 35 — 35

Realized Gain (Loss) to Derivative Instrument: 68 — 68
Realized Gain (Loss) to Regulatory Assets: (68 ) — (68 )

Six Months Ended June 30,
Power Interest
Contracts FTRs Rate Swaps Other Total
(In millions)
Derivatives in a Hedging Relationship

2011

Gain (Loss) Recognized in AOCL (Effective Portion) $ 5 $ — $ — $ — $ 5
Effective Gain (Loss) Reclassified to:⁽¹⁾

Purchase Power Expense 16 — — — 16
Revenues (12 ) — — — (12 )

2010

Gain (Loss) Recognized in AOCL (Effective Portion) $ (2 ) $ — $ — $ 6 $ 4
Effective Gain (Loss) Reclassified to:⁽¹⁾

Purchase Power Expense (7 ) — — — (7 )
Revenues (5 ) — — — (5 )
Fuel Expense — — — (8 ) (8 )

Derivatives Not in a Hedging Relationship

2011

Unrealized Gain (Loss) Recognized in:
Purchase Power Expense $ 61 $ — $ — $ — $ 61
Revenues (3 ) — — — (3 )
Other Operating Expense (54 ) 13 1 — (40 )

Realized Gain (Loss) Reclassified to:
Purchase Power Expense (36 ) — — — (36 )
Revenues (29 ) 26 — — (3 )
Other Operating Expense — (87 ) — — (87 )

2010

Unrealized Gain (Loss) Recognized in:
Purchase Power Expense $ 39 $ — $ — $ — $ 39

Realized Gain (Loss) Reclassified to:
Purchase Power Expense (49 ) — — — (49 )



Derivatives Not in a Hedging	Six Months Ended June 30,									Three Months Ended September 30
Relationship with Regulatory Offset⁽²⁾	NUGs			Other			Total			NUGs			Other			Total
	*(In millions)*									(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(236	)	$	2		$	(234	)	$	(89	)	$	(3	)	$	(92	)
Unrealized Gain (Loss) to Regulatory Assets:		236			(2	)		234		89			3			92

Realized Gain (Loss) to Derivative Instrument:		134			(10	)		124		53			(3		)	50
Realized Gain (Loss) to Regulatory Assets:		(134	)		10			(124	)	(53		)	3			(50		)

2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(259	)		—		$	(259	)	$	(146	)	—			$	(146	)
Unrealized Gain (Loss) to Regulatory Assets:		259			—			259		146			—			146

Realized Gain (Loss) to Derivative Instrument:		146			(9	)		137		63			—			63
Realized Gain (Loss) to Regulatory Assets:		(146	)		9			(137	)	(63		)	—			(63		)

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	Nine Months Ended September 30
	Power Contracts			FTRs			Interest Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	5		$	—		$	—	$	—		$	5
Effective Gain (Loss) Reclassified to: ⁽¹⁾
Purchased Power Expense	16			—			—		—			16
Revenues	(12		)	—			—		—			(12		)
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(3	)	$	—		$	—	$	10		$	7
Effective Gain (Loss) Reclassified to:⁽¹⁾
Purchased Power Expense	(2		)	—			—		—			(2		)
Revenues	(11		)	—			—		—			(11		)
Fuel Expense	—			—			—		(11		)	(11		)
Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	88		$	—		$	—	$	—		$	88
Revenues	(1		)	—			—		—			(1		)
Other Operating Expense	(65		)	(1		)	2		—			(64		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(41		)	—			—		—			(41		)
Revenues	(69		)	56			—		—			(13		)
Other Operating Expense	—			(122		)	—		—			(122		)
2010
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	42		$	—		$	—	$	—		$	42
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(71		)	—			—		—			(71		)



Derivatives Not in a Hedging	Nine Months Ended September 30,
Relationship with Regulatory Offset⁽²⁾	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(325	)	$	—		$	(325	)
Unrealized Gain (Loss) to Regulatory Assets:	325			—			325
Realized Gain (Loss) to Derivative Instrument:	187			(14		)	173
Realized Gain (Loss) to Regulatory Assets:	(187		)	14			(173		)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(405	)	—			$	(405	)
Unrealized Gain (Loss) to Regulatory Assets:	405			—			405
Realized Gain (Loss) to Derivative Instrument:	209			(9		)	200
Realized Gain (Loss) to Regulatory Assets:	(209		)	9			(200		)


⁽¹⁾		The ineffective portion was immaterial.


⁽²⁾		Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or ~~refund~~credit to) customers during the three months and ~~six~~nine months ended ~~June~~September 30, 2011 and 2010:

Three Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset⁽¹⁾ NUGs Other Total
(In millions)
Outstanding net asset (liability) as of April 1, 2011 $ (362 ) $ — $ (362 )
Additions/Change in value of existing contracts (147 ) 2 (145 )
Settled contracts 62 — 62

Outstanding net asset (liability) as of June 30, 2011 $ (447 ) $ 2 $ (445 )

Outstanding net asset (liability) as of April 1, 2010 $ (590 ) $ 10 $ (580 )
Additions/Change in value of existing contracts (35 ) — (35 )
Settled contracts 68 — 68

Outstanding net asset (liability) as of June 30, 2010 $ (557 ) $ 10 $ (547 )

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Six Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset⁽¹⁾ NUGs Other Total
(In millions)
Outstanding net asset (liability) as of January 1, 2011 $ (345 ) $ 10 $ (335 )
Additions/Change in value of existing contracts (236 ) 2 (234 )
Settled contracts 134 (10 ) 124

Outstanding net asset (liability) as of June 30, 2011 $ (447 ) $ 2 $ (445 )

Outstanding net asset (liability) as of January 1, 2010 $ (444 ) $ 19 $ (425 )
Additions/Change in value of existing contracts (259 ) — (259 )
Settled contracts 146 (9 ) 137

Outstanding net asset (liability) as of June 30, 2010 $ (557 ) $ 10 $ (547 )



	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset⁽¹⁾	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of July 1, 2011	$	(447	)	$	2		$	(445	)
Additions/Change in value of existing contracts	(89		)	(3		)	(92		)
Settled contracts	53			(3		)	50
Outstanding net asset (liability) as of September 30, 2011	$	(483	)	$	(4	)	$	(487	)

Outstanding net asset (liability) as of July 1, 2010	$	(557	)	$	10		$	(547	)
Additions/Change in value of existing contracts	(146		)	—			(146		)
Settled contracts	63			—			63
Outstanding net asset (liability) as of September 30, 2010	$	(640	)	$	10		$	(630	)

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset⁽¹⁾	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts	(325		)	—			(325		)
Settled contracts	187			(14		)	173
Outstanding net asset (liability) as of September 30, 2011	$	(483	)	$	(4	)	$	(487	)

Outstanding net asset (liability) as of January 1, 2010	$	(444	)	$	19		$	(425	)
Additions/Change in value of existing contracts	(405		)	—			(405		)
Settled contracts	209			(9		)	200
Outstanding net asset (liability) as of September 30, 2010	$	(640	)	$	10		$	(630	)


⁽¹⁾		Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

6.7. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels.

FirstEnergy provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three ~~months~~ and ~~six~~nine months ended ~~June~~September 30, 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of ~~$105~~$112 million and ~~$262~~$375 million, respectively. ~~FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.~~

As a result of the merger with ~~Allegheny,~~AE, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and other postretirement benefit plans ~~other than pensions~~ as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny’s pension plans and other postretirement benefit plans ~~other than pensions~~ at the date of the merger were ~~$954~~$954 million and ~~$75~~$75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were ~~$1,341~~$1,341 million and ~~$272~~$272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s other postretirement benefit ~~plans other than pensions.~~plans.

The components of the consolidated net periodic cost for pension and OPEB benefits (including amounts capitalized) were as follows:

Three Months Ended Six Months Ended
June 30 June 30
Pension Benefit Cost (Credit) 2011 2010 2011 2010
(In millions)
Service cost $ 34 $ 25 $ 62 $ 49
Interest cost 97 79 181 157
Expected return on plan assets (115 ) (90 ) (216 ) (181 )
Amortization of prior service cost 4 3 7 6
Recognized net actuarial loss 48 47 97 94
Curtailments⁽¹⁾
— — (2 ) —
Special termination benefits⁽¹⁾
— — 9 —

Net periodic cost $ 68 $ 64 $ 138 $ 125

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	Three Months Ended September 30						Nine Months Ended September 30
Pension Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	34		$	25		$	97		$	74
Interest cost	96			79			277			236
Expected return on plan assets	(115		)	(90		)	(332		)	(271		)
Amortization of prior service cost	4			3			12			10
Recognized net actuarial loss	49			47			146			141
Curtailments⁽¹⁾	—			—			(2		)	—
Special termination benefits⁽¹⁾	—			—			9			—
Net periodic cost	$	68		$	64		$	207		$	190


⁽¹⁾		Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger.

Three Months Ended Six Months Ended
June 30 June 30
Other Postretirement Benefit Cost (Credit) 2011 2010 2011 2010
(In millions)
Service cost $ 3 $ 3 $ 7 $ 5
Interest cost 12 11 23 22
Expected return on plan assets (10 ) (9 ) (20 ) (18 )
Amortization of prior service cost (52 ) (48 ) (100 ) (96 )
Recognized net actuarial loss 14 15 28 30

Net periodic cost (credit) $ (33 ) $ (28 ) $ (62 ) $ (57 )



	Three Months Ended September 30						Nine Months Ended September 30
Other Postretirement Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	4		$	2		$	10		$	7
Interest cost	13			11			36			33
Expected return on plan assets	(10		)	(9		)	(30		)	(27		)
Amortization of prior service cost	(51		)	(48		)	(151		)	(144		)
Recognized net actuarial loss	14			15			42			45
Net periodic cost (credit)	$	(30	)	$	(29	)	$	(93	)	$	(86	)

Pension and OPEB obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic OPEB (including amounts capitalized) recognized by FirstEnergy’s subsidiaries were as follows:

Three Months Ended Six Months Ended
June 30 June 30
Pension Benefit Cost 2011 2010 2011 2010
(In millions)
FES $ 22 $ 22 $ 43 $ 44
OE 5 6 11 11
CEI 5 5 10 11
TE 2 2 3 4
JCP&L 5 6 11 12
Met-Ed 3 3 5 5
Penelec 4 5 9 9
Other FirstEnergy Subsidiaries 22 15 46 29

$ 68 $ 64 $ 138 $ 125

Three Months Ended Six Months Ended
June 30 June 30
Other Postretirement Benefit Credit 2011 2010 2011 2010
(In millions)
FES $ (8 ) $ (7 ) $ (14 ) $ (13 )
OE (5 ) (6 ) (12 ) (12 )
CEI (2 ) (1 ) (3 ) (3 )
TE — — (1 ) (1 )
JCP&L (2 ) (2 ) (3 ) (4 )
Met-Ed (2 ) (2 ) (5 ) (4 )
Penelec (2 ) (2 ) (5 ) (4 )
Other FirstEnergy Subsidiaries (12 ) (8 ) (19 ) (16 )

$ (33 ) $ (28 ) $ (62 ) $ (57 )



	Three Months Ended September 30				Nine Months Ended September 30
Pension Benefit Cost	2011		2010		2011		2010
	(In millions)
FES	$	22	$	22	$	66	$	66
OE	6		6		16		17
CEI	5		5		15		16
TE	1		2		4		5
JCP&L	5		6		15		19
Met-Ed	3		3		9		8
Penelec	4		5		13		14
Other FirstEnergy Subsidiaries	22		15		69		45
	$	68	$	64	$	207	$	190

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	Three Months Ended September 30						Nine Months Ended September 30
Other Postretirement Benefit Credit	2011			2010			2011			2010
	(In millions)
FES	$	(8	)	$	(7	)	$	(22	)	$	(20	)
OE	(6		)	(6		)	(17		)	(19		)
CEI	(1		)	(1		)	(5		)	(4		)
TE	(1		)	—			(1		)	(1		)
JCP&L	(1		)	(2		)	(5		)	(5		)
Met-Ed	(2		)	(2		)	(7		)	(6		)
Penelec	(2		)	(2		)	(7		)	(6		)
Other FirstEnergy Subsidiaries	(9		)	(9		)	(29		)	(25		)
	$	(30	)	$	(29	)	$	(93	)	$	(86	)

7.8. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries perform qualitative analyses to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

VIEs included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation ~~operations;~~operations, a portion of which was sold on October 18, 2011 (see Note 15); the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station and JCP&L's supply of BGS, of which ~~$295~~$287 million was outstanding as of ~~June~~September 30, ~~2011.~~2011.

FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the Consolidated Balance Sheets during the nine months endedSeptember 30, 2011, is primarily ~~the result~~due to equity contributions from owners of$22 million, partially offset by net losses of the noncontrolling interests ~~($15 million)~~of $17 million and ~~distributions~~an equity distribution to owners ~~($4 million) during the six months ended June 30, 2011.~~of $5 million.

In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance.

PATH-WV

PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.

Because of the nature of PATH-WV’s operations and its FERC approved rate mechanism, FirstEnergy’s maximum exposure to loss, through AE, consists of its equity investment in PATH-WV, which was ~~$27~~$28 million ~~at June~~ as of September 30, ~~2011.~~2011.

Power Purchase Agreements

FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the Utilities if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but four of these NUG entities, its subsidiaries do not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to

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evaluate entities.

Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended ~~June~~September 30, 2011, were ~~$55~~$44 million ~~$47~~, $31 million and ~~$21~~$14 million for JCP&L, PE and WP, respectively and ~~$120~~$164 million ~~$58~~, $89 million and ~~$26~~$40 million for the ~~six~~nine months ended ~~June~~September 30, 2011, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the three ~~months~~ and ~~six~~nine months ended ~~June~~September 30, 2010 were ~~$53~~$73 million and ~~$117~~$190 million, respectively.

In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity that WP may hold a variable interest, for which WP has taken the scope exception. As of ~~June~~September 30, 2011, WP’s reserve for this adverse purchase power commitment was ~~$59~~$56 million, including a current liability of ~~$11~~$11 million, and is being amortized over the life of the commitment.

Loss Contingencies

FirstEnergy has variable interests in certain sale and leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangement.

FES and the Ohio Companies are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of ~~June~~September 30, ~~2011:~~2011:

Maximum Discounted Lease Net
Exposure Payments, net⁽¹⁾ Exposure
(In millions)
FES $ 1,348 $ 1,156 $ 192
OE 635 445 190
CEI⁽²⁾
624 69 555
TE⁽²⁾
624 303 321



	Maximum Exposure		Discounted Lease Payments, net⁽¹⁾		Net Exposure
	(In millions)
FES	$	1,370	$	1,176	$	194
OE	613		455		158
CEI⁽²⁾	591		70		521
TE⁽²⁾	591		309		282


⁽¹⁾		The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is ~~$1.6 billion.~~$1.6 billion.



⁽²⁾		CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

8.9. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. As a result of the merger with ~~Allegheny in the first quarter of 2011,~~AE, FirstEnergy’s unrecognized income tax benefits increased by ~~$97 million.~~$97 million. During the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately ~~$30~~$30 million of income tax benefits, including $5$5 million that favorably affected FirstEnergy’s effective tax ~~rate for the second quarter and first six months of 2011.~~rate. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first ~~six~~nine months of 2011. After reaching settlements in 2010 on a ~~tentative agreement~~state tax matter and tax items at appeals with the IRS ~~on a tax item at appeals~~ related to the capitalization of certain costs for tax years 2005-2008 ~~as well as reaching a settlement~~and on ~~an unrelated state tax matter in~~gains and losses recognized from the ~~second quarter~~disposition of ~~2010,~~assets, FirstEnergy recognized approximately ~~$70~~$78 million of net income tax benefits, including ~~$13~~$21 million that favorably affected FirstEnergy’s effective tax rate for ~~the second quarter of~~ 2010. The remaining portion of the income tax benefit recognized in ~~the first six months of~~ 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item.

As of ~~June~~September 30, 2011, it is reasonably possible that approximately ~~$46~~$46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $4$4 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized income tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.

FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The interest associated with the settlement of the claim noted above favorably affected FirstEnergy’s effective tax rate by $6$6 million in ~~the first half of~~ 2011. ~~During the first six months of 2011, there~~There were no other material changes to the amount of accrued interest, except for a $6$6 million increase in accrued interest as a result of the merger with ~~Allegheny.~~AE. The reversal of accrued interest associated with the recognized income tax benefits noted above favorably affected FirstEnergy’s effective tax rate by ~~$11~~$11 million in the first ~~six~~nine months of 2010. The net amount of interest accrued as of ~~June~~September 30, 2011 was ~~$10~~$11 million, compared with $3$3 million as of December 31, ~~2010.~~2010.

As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by ~~$28~~

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$28 million in the first ~~six~~nine months of 2011.

The IRS issued guidance in the third quarter of 2011 providing a safe harbor method of tax accounting for electric transmission and distribution property to determine the tax treatment of repair costs for electric transmission and distribution assets. FirstEnergy is evaluating the method change for this temporary tax item and, if elected, is not expected to be material to the financial position or effective tax rates of FirstEnergy and the Utilities.

As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law in March 2010, beginning in 2013 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts under prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately ~~$13~~$13 million and a reduction in accumulated deferred tax assets associated with these subsidies. That charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.

Allegheny is currently under audit by the IRS for tax years 2007 and 2008. ~~The~~Allegheny has filed its 2010 and 2009 federal ~~return was filed~~returns and issuch filings are subject to review. State tax returns for tax years ~~2006~~2008 through ~~2009~~2010 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. ~~Tax~~FirstEnergy's tax returns for all state jurisdictions are open from ~~2006-2009.~~2008-2010, as well as 2005-2007 for New Jersey. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. ~~The 2009 tax year audit began in February 2009 and~~Tax years 2009-2011 are under review by the ~~2010 tax year audit began in February 2010.~~IRS. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition, or results of ~~operations.~~operations, cash flow or liquidity.

9.10. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of ~~June~~September 30, 2011, outstanding guarantees and other assurances aggregated approximately ~~$3.8~~$3.8 billion, consisting of parental guarantees ~~($0.8 billion)~~($0.9 billion), ~~subsidiaries’~~subsidiaries' guarantees ~~($2.6 billion)~~($2.5 billion), and surety bonds and LOCs ($($0.4 ~~billion)~~billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the ~~counterparties’~~counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, ~~FirstEnergy’s~~FirstEnergy's guarantee enables the ~~counterparty’s~~counterparty's legal claim to be satisfied by other FirstEnergy assets. FirstEnergy believes the likelihood is remote that such parental guarantees of ~~$0.2~~$0.3 billion (included in the ~~$0.8~~$0.9 billion discussed above) as of ~~June~~September 30, 2011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of ~~June~~September 30, 2011 ~~FirstEnergy’s~~, FirstEnergy's maximum exposure under these collateral provisions was ~~$625~~$594 million, consisting of ~~$522~~$495 million due to a below investment grade credit rating (of which ~~$265~~$257 million is due to an acceleration of payment or funding obligation) and ~~$103~~$99 million due to “material adverse event” contractual clauses. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to ~~$666 million.~~$662 million.

Most of ~~FirstEnergy’s~~FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of ~~$136~~$147 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on ~~FES’~~FES' and AE ~~Supply’s~~Supply's power portfolios as of ~~June~~September 30, 2011, and forward prices as of that date, FES and AE Supply have posted collateral of ~~$138~~$123 million and $2$1 million, respectively. Under a hypothetical adverse change in forward prices ~~(95%~~(95% confidence level change in forward prices over a one-year time horizon), FES and AE Supply would be required to post an additional ~~$17~~$16 million and $1 million of ~~collateral.~~collateral, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.

~~FES’~~FES' debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of

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each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.

Signal Peak and Global Rail are borrowers under a ~~$350~~$350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the ~~borrowers’~~borrowers' obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility. On October 18, 2011, FEV sold a portion of its ownership interest in Signal Peak and Global Rail (see Note 15). Following the sale, FirstEnergy, WMB Loan Ventures LLC and WMB Loan Ventures II LLC will continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing no earlier than January 1, 2012, and no later than June 30, 2012, or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on ~~FirstEnergy’s~~FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.

CAA Compliance

FirstEnergy is required to meet federally-approved SO₂ and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂ and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.

In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on coal-fired Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these three complaints.

The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the ~~CAA’s~~CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted ~~Met-Ed’s~~Met-Ed's motion to dismiss New ~~Jersey’s~~Jersey's and ~~Connecticut’s~~Connecticut's claims for injunctive relief against Met-Ed, but denied ~~Met-Ed’s~~Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of ~~Met-Ed’s~~Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this ~~matter.~~matter or estimate the possible loss or range of loss.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the Portland coal-fired plant based on “modifications” dating back to 1986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce ~~SO2~~SO₂ air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of Keystone, and Penelec, as former owner and operator of Shawville, are unable to predict the outcome of this ~~matter.~~matter or estimate the possible loss or range of loss.

In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the ~~CAA’s~~CAA's PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, ~~New York State Electric & Gas Corporation~~NYSEG and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the ~~CAA’s~~CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, ~~New York State Electric and Gas Corporation,~~NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer ~~City’s~~City's air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this ~~matter.~~matter or estimate the loss or possible range of loss. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. Mission is seeking indemnification from Penelec, the co-owner and operator of Homer City prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claims

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and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. ~~The scope~~On October 12 and 13, 2011, the Court dismissed all of ~~Penelec’s indemnity obligation~~the claims with prejudice, of the U.S. and the Commonwealth of Pennsylvania and the Sates of New Jersey and New York and all of the claims of the private parties, without prejudice to ~~and from Mission is under dispute and Penelec is unable to predict~~refile state law claims in state court, against all of the ~~outcome of this matter.~~defendants, including Penelec.

In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The ~~EPA’s~~EPA's NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating, maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including the ~~EPA’s~~EPA's information requests but, at this time, is unable to predict the outcome of this ~~matter.~~matter or estimate the possible loss or range of loss.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA ~~letter~~ from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation ~~units~~units: Albright, Armstrong, Fort Martin, Harrison, ~~Hatfield’s~~Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when ~~the~~a major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this ~~matter.~~matter or estimate the possible loss or range of loss.

In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired plants: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, ~~Hatfield’s~~Hatfield's Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the ~~Hatfield’s~~Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that ~~decision.~~decision and we are unable to predict the outcome or estimate the possible loss or range of loss.

In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the ~~Hatfield’s~~Hatfield's Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants in West Virginia. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.

State Air Quality Compliance

In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO₂ and NO_X,NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that ~~coalition’s~~coalition's regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NO_X,NOx, SO₂ and mercury, based on a PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the ~~Maryland Department of the Environment (MDE)~~MDE passed alternate NO_XNOx and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% ~~beginning~~ which began in 2010. The statutory exemption does not extend to R. Paul ~~Smith’s~~Smith's CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this ~~matter.~~matter or estimate the possible loss or range of loss.

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In January 2010, the WVDEP issued a NOV for opacity emissions at ~~Allegheny’s~~Allegheny's Pleasants coal-fired plant. ~~FirstEnergy is discussing with~~In August 2011, Allegheny and WVDEP ~~steps to resolve~~resolved the NOV ~~including installing~~through a Consent Order requiring installation of a reagent injection system to reduce ~~opacity.~~opacity by September 2012.

National Ambient Air Quality Standards

The ~~EPA’s~~EPA's CAIR requires reductions of NOx and SO₂ emissions in two phases (2009/2010 and 2015), ultimately capping ~~SO2~~SO₂ emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the ~~Court’s~~Court's opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2011, the EPA finalized the ~~Cross-State Air Pollution Rule (CSAPR)~~CSAPR to replace CAIR, which remains in effect until CSAPR becomes effective ~~(60~~(60 days after publication in the Federal Register). CSAPR requires reductions of NOx and ~~SO2~~SO₂ emissions in two phases (2012 and 2014), ultimately capping ~~SO2~~SO₂ emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. ~~FGCO’s~~On October 6, 2011, EPA proposed to revise the certain state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas) and generating unit allocations (for Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO₂ emissions and proposed to delay restrictions on interstate trading of NOx and SO₂emission allowances from 2012 to 2014. EPA's final CSAPR rule has been appealed to the U.S. Court of Appeals for the District of Columbia Circuit by various stakeholders, with several appellants seeking a stay of CSAPR pending its review by the Court. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to ~~FirstEnergy’s~~FirstEnergy's operations may result.

During the three months ended September 30, 2011, FirstEnergy recorded a pre-tax impairment charge of approximately $6 million ($1 million for FES and $5 million for AE Supply) for obsolete NOx emission allowances, including fair value adjustments in connection with the merger for AE Supply that can no longer be used after 2011. While the carrying value of FirstEnergy's SO₂ emission allowances are currently above market (currently reflected at $26 million on the Consolidated Balance Sheet as of September 30, 2011), Management determined that no impairment exists in the third quarter of 2011 since these allowances can be carried forward into future years. Management is ~~currently assessing~~continuing to assess the impact of CSAPR, other environmental proposals and other factors on ~~FirstEnergy’s~~FirstEnergy's competitive fossil generating facilities, including but not limited to, the impact on ~~value of our emissions~~its SO₂ emission allowances ~~(currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011)~~ and the continuing operations of its coal-fired plants.

Hazardous Air Pollutant Emissions

On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Final regulations are expected on or about December 16, 2011. Depending on the action taken by the EPA and how any future regulations are ultimately implemented, ~~FirstEnergy’s~~FirstEnergy's future cost of compliance with MACT regulations may be substantial and changes to ~~FirstEnergy’s~~FirstEnergy's operations may result.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, in June 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his ~~Administration’s~~Administration's “New Energy for America Plan” that includes, among other provisions, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure GHG emissions commencing in 2010 and ~~will require~~currently requires it to submit ~~reports commencing in 2011.~~reports. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The ~~EPA’s~~EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the ~~CAA’s~~CAA's NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents ~~(CO2)~~(CO₂) effective January 2, 2011 for existing facilities under the ~~CAA’s~~CAA's PSD program. ~~Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO~~₂ ~~pollutants.~~

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by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching ~~$30~~$30 billion over the next three years with a goal of increasing to ~~$100~~$100 billion by 2020; and establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

In 2009, the U.S. Court of Appeals for the Second Circuit and the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the ~~U. S.~~U.S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The ~~Court’s~~Court's ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy received notice of a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO₂emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to ~~FirstEnergy’s~~FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to ~~FirstEnergy’s~~FirstEnergy's operations.

In 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a ~~facility’s~~facility's cooling water system). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second ~~Circuit’s~~Circuit's opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power ~~plant’s~~plant's water intake channel to divert fish away from the ~~plant’s~~plant's water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore Plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the ~~EPA’s~~EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

In April 2011, the U.S. ~~Attorney’s~~Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. ~~This~~On August 5, 2011, EPA issued an information request pursuant to Sections 308 and 311 of the CWA for certain information pertaining to the oil spills and spill prevention measures at FirstEnergy facilities. FirstEnergy responded on October 10, 2011. On September 30, 2011, FirstEnergy executed tolling agreements with the EPA extending the statute of limitations to April 30, 2012. FGCO does not anticipate any losses resulting from this matter ~~has been referred back~~ to ~~EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.~~be material.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another ~~60-Day~~60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.

FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.

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Monongahela River Water Quality

In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the ~~Hatfield’s~~Hatfield's Ferry coal-fired plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA ~~DEP’s~~DEP's permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of ~~$150~~$150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. ~~The~~A hearing ison the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a ~~settlement.~~settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA ~~DEP’s~~DEP's recommended sulfate impairment designation. PA ~~DEP’s~~DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its ~~Hatfield’s~~Hatfield's Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the ~~Hatfield’s~~Hatfield's Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the ~~Hatfield’s~~Hatfield's Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending ~~WVDEP’s~~WVDEP's release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at ~~Hatfield’s~~Hatfield's Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the ~~EPA’s~~EPA's evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the ~~EPA’s~~EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. ~~FirstEnergy’s~~FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on our results of operations and financial condition.

~~The Little Blue Run (LBR) Coal Combustion By-products (CCB)~~LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the ~~Bruce Mansfield Plant~~BMP between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.

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The Utility Registrants have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of ~~June~~September 30, 2011, based on estimates of the total costs of cleanup, the Utility ~~Registrants’~~Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$133~~$103 million (JCP&L ~~— $69~~- $69 million, TE ~~— $1~~- $1 million, CEI ~~— $1~~- $1 million, FGCO ~~— $1~~- $1 million and FirstEnergy ~~— $61 million)~~- $31 million) have been accrued through ~~June~~September 30, ~~2011.~~2011. Included in the total are accrued liabilities of approximately ~~$63~~$63 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately ~~$59 million.~~$59 million. FirstEnergy recognized an additional expense of ~~$29~~$29 million during the second quarter of 2011; ~~$30~~$30 million had previously been reserved prior to 2011. FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses at those sites cannot be determined or reasonably estimated.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the ~~Plaintiffs’~~Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial ~~court’s~~court's decision decertifying the class. ~~Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court.~~ In November 2010, the Supreme Court issued an order denying ~~Plaintiffs’ motion.~~Plaintiffs' motion for leave to appeal. The ~~Court’s~~Court's order effectively ends the attempt to certify the class, ~~action attempt,~~ and leaves only nine ~~(9)~~ (9) plaintiffs to pursue their respective individual claims. The matter was referred back to the lower court, which set a trial date for February 13, 2012 for the remaining individual ~~plaintiffs~~plaintiffs. Plaintiffs have ~~yet to take any affirmative steps to pursue their individual claims.~~accepted an immaterial amount in final settlement of all matters and the settlement documentation is being finalized for execution by all parties.

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of ~~June~~September 30, 2011, FirstEnergy had approximately $2$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of ~~FirstEnergy’s~~FirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, ~~FirstEnergy’s~~FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately ~~$92.5 million.~~$92.5 million. On June 24, 2011, FENOC submitted a ~~$95~~$95 million parental guarantee to the NRC for its approval.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.

On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.

In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry ~~Nuclear~~nuclear facilities as a result of the ~~DOE~~DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to ~~so commence~~begin accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking ~~approximately $57 million in~~ damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.

On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. In a September 11, 2011 order, the NRC denied the request to suspend the licensing proceedings and referred to the NRC Task Force conducting a “Near-Term Evaluation of the Need for Agency Actions Following the Events in Japan” for those portions of the petitions requesting

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rulemaking.

On October 1, 2011, the Davis-Besse Plant was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaces a head installed in 2002, enhances safety, reliability and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, a sub-surface hairline crack was identified in one of the exterior architectural elements on the Shield Building, following opening of the building for installation of the new reactor head. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the Shield Building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. The team of industry-recognized structural concrete experts and Davis-Besse engineers evaluating this condition has determined the cracking does not affect the facility's structural integrity or safety. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in two localized areas of the Shield Building similar to those found in the architectural elements. FENOC has determined these two areas are not associated with the architectural element cracking and are investigating them as a separate issue. FENOC's overall investigation and analysis continues.Davis-Besse is currently expected to return to service around the end of November.
By a letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct a supplemental inspection using Inspection Procedure 95002, to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
On October 2, 2011, FENOC completed the controlled shutdown of the Perry plant due to the loss of a startup transformer. On October 11, 2011, FENOC submitted a Technical Specification change request to the NRC to clarify that a delayed access circuit is temporarily qualified for use as one of the required offsite power circuits. By a letter dated October 17, 2011, NRC authorized Perry to operate with a delayed access circuit for offsite power until December 12, 2011. Concurrently, a spare replacement transformer from Davis-Besse was transported to Perry for modification and installation.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at US reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ~~International Coal Group, Inc. (ICG),~~ICG, Anker ~~West Virginia Mining Company, Inc. (Anker WV),~~WV, and Anker ~~Coal Group, Inc. (Anker Coal).~~Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of ~~defendants’~~defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of ~~$80~~$80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of ~~$150~~$150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for ~~$104~~$104 million ($ ($90 million in future damages and ~~$14~~$14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. ~~The parties expect~~On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a ~~ruling sometime~~Notice of Appeal and a briefing schedule was issued with oral argument likely in ~~the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment.~~May of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.

Other Legal Matters

In February 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to ~~FirstEnergy’s~~FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above

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are described under Note 11, Regulatory Matters below.

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has an obligation, it discloses such obligations with the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, ~~matters,~~ it could have a material adverse effect on ~~FirstEnergy’s~~FirstEnergy's or its ~~subsidiaries’~~subsidiaries' financial condition, results of operations and cash flows.

~~10.~~11. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO ~~charged with establishing~~designated by FERC to establish and ~~enforcing~~enforce these reliability standards, although itNERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ~~Reliability~~~~First~~~~Corporation.~~RFC. All of ~~FirstEnergy’s~~FirstEnergy's facilities are located within the ~~Reliability~~~~First~~RFC region. FirstEnergy actively participates in the NERC and ~~Reliability~~~~First~~RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ~~Reliability~~~~First~~~~Corporation.~~RFC.

FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ~~Reliability~~~~First~~.RFC. Moreover, it is clear that the NERC, ~~Reliability~~~~First~~RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. ~~Still, any~~Any future inability on ~~FirstEnergy’s~~FirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

On December 9, 2008, a transformer at JCP~~&L’s~~&L's Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP~~&L’s~~&L's contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to ~~Reliability~~~~First~~RFC a vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ~~Reliability~~~~First~~RFC issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ~~Reliability~~~~First~~RFCon September 27, 2010. ~~In March~~On July 8, 2011, ~~Reliability~~~~First~~~~submitted its proposed findings~~RFC and Met-Ed signed a settlement ~~although~~agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a ~~final determination has not yet been made by FERC.~~

~~Allegheny has been subject~~penalty of $650,000, and for FirstEnergy to ~~routine audits with respect~~perform certain mitigating actions. These mitigating actions include inspecting FirstEnergy's transmission system using LiDAR technology, and reporting the results of inspections, and any follow-up work, to ~~its compliance with applicable reliability standards and has settled certain related issues. In addition, Reliability~~~~First~~~~is currently conducting certain investigations with regard~~RFC. FirstEnergy was performing the LiDAR work in response to certain ~~matters of compliance~~other industry directives issued by ~~Allegheny.~~NERC in 2010. NERC subsequently approved the settlement agreement and, on September 30, 2011, submitted the approved settlement to FERC for final approval. FERC approved the settlement agreement on October 28, 2011.

(B) MARYLAND

By statute enacted in 2007, the obligation of Maryland utilities to provide ~~standard offer service (SOS)~~SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a ~~five-year~~five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this ~~and other SOS-related pending proceedings discussed below.~~proceeding.

In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation

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resources in Maryland. In December 2009, Governor Martin ~~O’Malley~~O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and ~~at this time no further proceedings have been set~~on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order indicated that bids were due by November 11, 2011, that the MDPSC would be the entity evaluating all bids, and that a hearing on whether to require the purchase of generation in ~~this matter.~~light of the bids would be held on January 31, 2012, after receipt of further comments from all interested parties on January 13, 2012.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately ~~$101~~$101 million and would be recovered over the following six years. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, ~~to discuss details of PE’s~~PE's plans for additional and improved programs for the period 2012-2014 ~~began~~were filed on August 31, 2011. Hearings on those plans and the plans of the other utilities were held in ~~April 2011 and those programs are to be filed by September 1,~~mid October 2011.

In March 2009, the MDPSC issued an order temporarily suspending ~~until further notice~~ the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted ~~a set of proposed~~ regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each ~~utility’s~~utility's compliance with the standards, and may assess penalties of up to ~~$25,000~~$25,000 per day per violation. The MDPSC ~~has ordered that~~convened a working group of utilities, regulators, and other interested stakeholders ~~meet~~ to address the topics of the proposed rules. A draft of the rules was filed, along with ~~proposed~~the report of the working group, on October 27, 2011. Comments on the draft rules are due by November 16, and a hearing to ~~be filed by September 15,~~consider the rules and comments is scheduled for December 8 and 9, 2011. Separately, on ~~April~~July 7, 2011, the MDPSC ~~initiated a rulemaking with respect to issues related to~~adopted draft rules requiring monitoring and inspections for contact voltage. ~~On June 3, 2011,~~The draft rules were published in September, and then approved by the ~~MDPSC’s Staff issued a report and draft regulations. Comments~~MDPSC as final rules on October 31, 2011. The rules will go into effect after being published again in the ~~draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.~~Maryland Register.

(C) NEW JERSEY

In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). In its order of June 15,

On September 8, 2011, ~~the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and~~ the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requests that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition on September 28, 2011, stating, inter alia, that the Division of Rate Counsel analysis upon which ~~resolved both Petitions, resulting~~it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time. The matter is pending before the NJBPU.

On September 22, 2011, the NJBPU ordered that JCP&L hire a Special Reliability Master, subject to NJBPU approval, to evaluate JCP&L's design, operating, maintenance and performance standards as they pertain to the Morristown, New Jersey underground electric distribution system, and make recommendations to JCP&L and the NJBPU on the appropriate courses of action necessary to ensure adequate reliability and safety in ~~a net reduction in recovery of $0.8 million annually~~the Morristown underground network. A schedule for ~~all components~~the completion of the ~~SBC (including,~~Special Reliability Master's activities has not yet been established.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27,

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2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. The NJBPU has not indicated what additional action, if any, may be taken as ~~requested,~~ a ~~zero level~~result of ~~recovery of TMI-2 decommissioning costs).~~information obtained through this process.

(D) OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, ~~Delivery Capital Recovery~~ Rider ~~(Rider DCR),~~DCR, to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ~~ATSI’s~~ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals ~~$360~~$360 million dependent on the outcome of certain PJM proceedings, agreed to establish a ~~$12~~$12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio ~~Companies’ 3-year~~Companies' 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the ~~Companies’~~Ohio Companies' 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. On July 27, 2011, the PUCO denied that application for rehearing, but clarified that CEI and TE could apply for an amendment in the future for the 2010 benchmarks should it be necessary to do so. Failure to comply with the benchmarks or to obtain such an amendment may subject the ~~companies~~Ohio Companies to an assessment of a penalty by the ~~PUCO of a penalty.~~PUCO. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Ohio Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the ~~PUCO’s~~PUCO's decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On ~~May 4,~~September 7, 2011, the PUCO ~~granted~~denied those applications for ~~rehearing for the purpose of further consideration; however, no substantive ruling has been issued.~~rehearing.

requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. ~~Other parties to~~On August 3, 2011, the ~~proceeding filed comments asserting~~PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the ~~force majeure determination should not be granted,~~Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and ~~others requesting~~Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the ~~costs~~Ohio Companies' alternative energy recovery rider. Separately, one party has filed a request that the PUCO audit the cost of the Ohio ~~companies’ have incurred to comply~~Companies' compliance with the ~~renewable~~alternative energy ~~requirements.~~requirements and the Ohio Companies' compliance with Ohio law. The PUCO has not ~~yet acted~~ruled on ~~that application.~~this request.

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in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the ~~companies’~~Ohio Companies' application on May 25, 2011, ruling that the new credit be applied only to customers that heat with electricity and be phased out over an eight-year period and granting authority for the ~~companies~~Ohio Companies to recover deferred costs and associated carrying charges. OCC filed ~~applications~~an application for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO ~~has~~did not ~~yet acted~~act on the ~~applications~~application for ~~rehearing.~~rehearing within 30 days; thus, the application for rehearing is considered denied by operation of law. No appeal of this matter was filed and the time period in which to do so has expired.

(E) PENNSYLVANIA

The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the ~~PPUC’s~~PPUC's order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds will continue over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the ~~PPUC’s~~PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the ~~PPUC’s~~PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately ~~$254~~$254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ~~Met-Ed’s~~Met-Ed's and ~~Penelec’s~~Penelec's TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district ~~court.~~court., which was subsequently amended. The PPUC filed a Motion to Dismiss Met-Ed's and Penelec's Amended Complaint on September 15, 2011. Met-Ed and Penelec filed a Responsive brief in Opposition to the PPUC's Motion to Dismiss on October 11, 2011. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately ~~$254~~$254 million ($ ($189 million for Met-Ed and ~~$65~~$65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each of May 2008, ~~May~~ 2009 and ~~May~~ 2010, the PPUC approved ~~Met-Ed’s~~Met-Ed's and ~~Penelec’s~~Penelec's annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The ~~PPUC’s~~PPUC's approval in May 2010 authorized an increase to the TSC for ~~Met-Ed’s~~Met-Ed's customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the ~~PPUC’s~~PPUC's Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from ~~Penn’s~~Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the ~~utilities’~~utilities' plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. Act 129 also required utilities to file with the PPUC a ~~Smart Meter Implementation Plan (SMIP).~~SMIP.

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider ~~with rates~~became effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.

WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes

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measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.

Met-Ed, Penelec, Penn and WP submitted a preliminary status report on July 15, 2011, in which they reported on their compliance with statutory May 31, 2011 energy efficiency benchmarks. Preliminary results indicate that Met-Ed, Penelec and Penn will achieve their 2011 benchmarks; however WP may not. Final reports on actual results must be filed with the PPUC no later than November 15, 2011.

Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a ~~24-month~~24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately ~~$29.5~~$29.5 million, which ~~the~~ Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ~~ALJ’s Initial Decision~~PPUC approved the SMIP, as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June ~~2010, consistent with the Chairman’s Motion.~~2010. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the ~~PPUC’s~~PPUC's Order regarding the future ability to include smart meter costs in base rates, which the PPUC granted in part by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.

In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of ~~WP’s~~WP's approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and ~~Pennsylvania’s~~Pennsylvania's OCA filed a Joint Petition for Settlement addressing ~~WP’s~~WP's smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the ~~30-month~~30-month grace period authorized by the PPUC to continue ~~WP’s~~WP's efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.

~~In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further~~Following additional proceedings, ~~to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On~~on March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the ~~PPUC’s~~PPUC's Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on ~~WP’s~~WP's original smart meter implementation plan. ~~The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding.~~ A Joint Stipulation with the OSBA was also filed on March 9, 2011. ~~On May 3, 2011, the ALJ issued an Initial Decision recommending that the~~The PPUC ~~approve~~approved the Amended Joint Petition for Full ~~Settlement. The PPUC approved the Initial Decision~~Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional ~~30-day~~30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the ~~above~~ accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into ~~Pennsylvania’s~~Pennsylvania's retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and ~~West Penn~~WP submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony. A technical conference was held on August 10, 2011, and teleconferences are scheduled through December 14, 2011, to explore intermediate steps that can be taken to promote the development of a competitive market. An en banc hearing will be held on November 10, 2011. An intermediate work plan will be presented in December 2011 and a long range plan will be presented in the first quarter of 2012.

~~(F) VIRGINIA~~

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similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the ~~VSCC~~EDC before using its trademark or service mark. The Proposed Rulemaking Order calls for ~~authorization~~comments to ~~construct the Virginia portions~~be submitted within forty-five days of ~~the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw~~ its ~~application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion”~~publication in the ~~Federal Regulation and Rate Matters section~~Pennsylvania Bulletin, with no provision for ~~further discussion of this matter.~~

~~(G) WEST VIRGINIA~~

~~In August 2009, MP and PE filed with the WVPSC~~replies. The Order has not been published yet. If implemented these rules could require a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other partiessignificant change in the ~~proceeding that provided for:~~way FES, Met-Ed, Penelec, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

~~a $40 million annualized base rate increase effective June 29, 2010;~~

~~a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;~~

(F) WEST VIRGINIA

~~an additional $20 million annualized base rate increase effective in January 2011;~~

~~a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and~~

~~a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.~~

~~The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.~~

In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order ~~is expected~~was issued by ~~late~~the WVPSC in September ~~2011.~~2011 which conditionally approved MP's and PE's compliance plan, contingent on the outcome of the resource credits case discussed below.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. ~~If the~~The application iswas approved and the three facilities ~~would then be~~are capable of generating renewable credits which ~~would~~will assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition. A hearing was held at the WVPSC on August 25 and 26, 2011. An order is expected by the end of 2011.

In September 2011, MP and PE filed with the WVPSC to recover costs associated with fuel and purchased power (the ENEC) in the amount of $32 million which represents an approximate 3% overall increase in such costs over the past two years, primarily attributable to rising coal prices. The requested increase is partly offset by $2.5 million of synergy savings directly resulting from the merger of FirstEnergy and AE, which closed in February 2011. Under a cost recovery clause established by the WVPSC in 2007, MP and PE customer bills are adjusted periodically to reflect upward or downward changes in the cost of fuel and purchased power. The utilities' most recent request to recover costs for fuel and purchased power was in September 2009. A hearing on this matter is scheduled for November 29 - 30, 2011.

~~(H)~~

(G) FERC MATTERS

Rates for Transmission Service Between MISO and PJM

In November 2004, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ~~ALJ’s~~ALJ's rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. ~~The~~In July 2010, a petition for review of the order denying pending rehearing requests was filed at the U.S. Court of Appeals for the D.C. Circuit. In a subsequent compliance filing submitted to the FERC in August 2010, the Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy thereafter executed settlements with AEP, Dayton and the Exelon parties to fix ~~FirstEnergy’s~~FirstEnergy's liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon settlements were approved by FERC in November 2010, and the ~~relevant~~respective payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the ~~relevant~~respective payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. ~~Rehearings remain pending~~On September 30, 2011, the FERC issued an order denying all requests for rehearing of the May 2010 Order on Initial Decision, affirming that prior order in ~~this proceeding.~~all respects.

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PJM Transmission Rate

In April 2007, FERC issued an order (Opinion 494) finding that the PJM transmission ~~owners’~~owners' existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology, ~~(DFAX),~~ which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

~~FERC’s~~

FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed ~~FERC’s~~FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new ~~500+~~500 kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue ~~back~~ to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper ~~hearing"—~~hearing”-- meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. ~~PJM’s~~PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain ~~eastern utilities~~load serving entities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. ~~Certain eastern~~Other utilities and ~~their~~ state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into ~~PJM’s~~PJM's tariffs. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the ~~MISO’s~~MISO's tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to ~~PJM’s~~PJM's tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ~~ATSI’s~~ATSI's proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ~~ATSI’s~~ATSI's proposed treatment of the ~~MISO’s~~MISO's exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ~~ATSI’s~~ATSI's proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ~~ATSI’s~~ATSI's proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of ~~FERC’s~~FERC's decision to require a cost-benefit study analysis as part of ~~FERC’s~~FERC's evaluation of ~~ATSI’s~~ATSI's proposed transmission rates. ~~The~~Finally, and also on June 30, 2011, the MISO and the MISO TOs filed a competing compliance filing - one that would require ATSI to pay certain charges related to construction and operation of transmission projects within the MISO even though FERC ruled that ATSI cannot pass these costs on to ATSI's customers. ATSI on the one hand, and the MISO and MISO TOs on the other have, submitted subsequent filings - each of which is intended to refute the other's claims. ATSI's compliance filing and ~~ATSI’s~~ request for rehearing, as well as the pleadings that reflect the dispute between ATSI and the MISO/MISO TOs, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ~~ATSI’s~~ATSI's move into PJM. These orders approve ~~ATSI’s~~ATSI's proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect ~~ATSI’s~~ATSI's move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement between ATSI and MISO with regard to ~~ATSI’s~~ATSI's obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreement of ~~ATSI’s~~ATSI's responsibility for certain charges associated with long term firm transmission rights —- that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of ~~$1.8~~$1.8 million to the MISO. This settlement agreement has been submitted for ~~FERC’s~~FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ~~ATSI’s~~ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

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MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission ~~projects—described~~projects--described as MVPs —- are a class of transmission projects that are approved via ~~MISO’s~~MISO's formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, ~~MISO’s~~MISO's Board approved the first MVP project —-- the “Michigan Thumb Project.” Under ~~MISO’s~~MISO's proposal, the costs of MVP projects approved by ~~MISO’s~~MISO's Board prior to the June 1, 2011 effective date of ~~FirstEnergy’s~~FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately ~~$15~~$15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that ~~MISO’s~~MISO's proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on ~~MISO’s~~MISO's MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. ~~FERC’s~~FERC's order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the ~~MISO’s~~MISO's tariffs obligate ATSI to pay all charges that attached prior to ~~ATSI’s~~ATSI's exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of ~~FERC’s~~FERC's order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy ~~filed for~~requested rehearing of ~~FERC’s~~FERC's order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI. On October 21, 2011, FERC issued its order on rehearing. In the order, FERC noted that if liability for MVP costs were attached to ATSI prior to ATSI's exit, then ATSI would be responsible to pay the MVP charges. However, FERC did not address the question of whether liability for MVP costs should attach to ATSI. FirstEnergy is evaluating FERC's October 21, 2011 order, and continues to assess its future course of action.

As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ~~ATSI’s~~ATSI's proposed transmission ~~rates~~rate FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ~~ATSI’s~~ATSI's formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the ~~cost- benefit~~cost-benefit study. ATSI requested a rehearing of these parts of ~~FERC’s~~FERC's order and, pending this further legal process, has removed the MVP line items from its transmission rates.

On August 3, 2011, FirstEnergy filed a complaint with FERC based on the FERC's December 20, 2010, ruling. In the complaint, FirstEnergy argued that ATSI perfected the legal and financial requirements necessary to exit MISO before any MVP responsibilities could attach and asked FERC to rule that MISO cannot charge ATSI for MVP costs. On September 2, 2011, MISO, its TOs and other parties, filed responsive pleadings. MISO and its TOs argued that liability to pay for a single MVP project (the Michigan Thumb Project) attached to ATSI, before ATSI was able to exit MISO, and argued that FERC should order ATSI to pay a pro rata amount of the Michigan Thumb Project costs. On September 19, 2011, ATSI filed an answer stating its view that there are no legal or factual bases to charge the Michigan Thumb Project costs to ATSI. The complaint, and all subsequent pleadings, are pending before FERC. The October 21, 2011, FERC Order referenced above did not mention ATSI's rehearing order in the MVP docket. On October 31, 2011, FirstEnergy filed notice of its plans to appeal FERC's October 21, 2011, Order with the D.C. Circuit Court of Appeals.

FirstEnergy cannot predict the outcome of these proceedings at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the ~~California Department of Water Resources (CDWR)~~CDWR during 2001. The settlement proposal claims that CDWR is owed approximately ~~$190~~$190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the ~~judge’s~~judge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains

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pending.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of ~~this matter.~~either of the above matters.

PATH Transmission ~~Expansion~~Project

~~TrAIL Project.~~TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.

~~PATH Project.~~The PATH Project is comprised of a 765 kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of ~~analyses~~analysis using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order (November 19 Order) addressing various matters relating to the formula rate, FERC set the ~~project’s~~project's base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a ~~0.50%~~0.5% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. The PATH Companies, Joint Intervenors, Joint Consumer Advocates and FERC staff have agreed to a four year moratorium. A settlement was reached, which reflects a base ROE of 10.4% (plus authorized adders) effective January 1, 2011. Accordingly, the revised ROE will be reflected in a revised Projected Transmission Revenue Requirement for 2011 with true-up occurring in 2013. The FirstEnergy portion of the refund for March 1, 2008 through December 31, 2010 is approximately $2 million (inclusive of interest). The refund amount was computed using a base ROE of 10.8% plus authorized adders. On October 7, 2011 PATH and six intervenors submitted to FERC an unopposed settlement agreement. Contemporaneous with this submission, PATH LLC ~~is currently engaged in settlement discussions~~and the six intervenors filed with the ~~staff~~Chief Administrative Law Judge of FERC a joint motion for interim approval and ~~intervenors regarding resolution~~authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the ~~base return~~settlement agreement. On October 12, 2011, the motion for interim approval and authorization to implement the refund was granted by the Chief Administrative Law Judge. FERC has not acted on ~~equity.~~the settlement agreement.

Seneca Pumped Storage Project Relicensing

The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. ~~FERC’s~~FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and ~~pre-application document (PAD)~~PAD in the license docket.

On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PAD documents necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ~~‘competing application’~~'competing application' to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army ~~Corps.~~Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to ~~FirstEnergy’s~~FirstEnergy's petition, including motions to dismiss ~~FirstEnergy’s~~FirstEnergy's petition. The “project boundary” issue is pending before FERC.

~~The next steps in the relicensing process are for~~

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On September 11, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On September 26, 2011, third parties submitted comments regarding the parties' respective “Revised Study Plan” documents. On September 26, 2011, FirstEnergy submitted comments regarding certain factual and legal matters asserted in the Seneca Nation's Revised Study Plan document. On October 7, 2011, FirstEnergy submitted further comments to ~~define~~refute certain factual and legal arguments that were advanced by the Seneca Nation in comments that were submitted on September 26, 2011. On October 11, 2011, FERC Staff issued letters that finalize the studies that are to be performed. FirstEnergy and the Seneca Nation each will perform ~~certain environmental and operational~~the studies ~~to support their respective applications. These steps are expected to~~described in the October 11, 2011 Staff determination. The study process will run through approximately November of 2013.

FirstEnergy cannot predict the outcome of these proceedings at this time.

~~11.~~12. STOCK-BASED COMPENSATION PLANS

FirstEnergy has four types of stock-based compensation programs — LTIP, EDCP, ESOP and DCPD, as described below.

Allegheny’s stock-based awards were converted into FirstEnergy stock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and, where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of ~~Allegheny~~AE common stock.

(A) LTIP

FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.

Under FirstEnergy’s LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to be settled in common stock, with vesting periods ranging from two months to ten ~~years.~~years. Performance share awards are currently designated to be ~~paid~~settled in cash rather than common stock and therefore do not count against the limit on stock-based awards. There were 5.6 million shares available for future awards under the LTIP as of ~~June~~September 30, ~~2011.~~2011.

Restricted Stock and Restricted Stock Units

Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity for the nine months endedSeptember 30, 2011, was as follows:



			~~Six~~Nine Months		Ended
			~~Ended~~
		~~June~~September 30, 2011

Restricted stock and stock units outstanding as of January 1, 2011			1,878,022
Granted	907,898		~~891,881~~
Converted ~~Allegheny~~AE restricted stock			645,197
Exercised			(~~428,686~~435,358	)
Forfeited			(~~71,775~~213,039	)

Restricted stock and stock units outstanding as of ~~June~~September 30, 2011	2,782,720		~~2,914,639~~

The ~~891,881~~907,898 shares of restricted common stock granted during the ~~six~~nine months ended ~~June~~September 30, 2011, had a grant-date fair value of ~~$33.2~~$33.8 million and a weighted-average vesting period of ~~2.74~~2.76 years.

Restricted stock units include awards that will be settled in a specific number of shares of common stock after the service condition has been met. Restricted stock units also include performance-based awards that will be settled after the service condition has been met in a specified number of shares of common stock based on FirstEnergy’s performance compared to annual target performance metrics.

Compensation expense recognized during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, for restricted stock and restricted stock units, net of amounts capitalized, was approximately ~~$27~~$43 million and ~~$20~~$40 million, respectively.

Stock Options

Stock option activity for the ~~six~~nine months ended ~~June~~September 30, 2011 was as follows:

Weighted
Average
Number of Exercise
Stock Option Activities Shares Price

Stock options outstanding as of January 1, 2011 (all exercisable) 2,889,066 $ 35.18
Options granted 662,122 37.75
Converted Allegheny options 1,805,811 41.75
Options exercised (691,304 ) 31.38
Options forfeited/expired (78,978 ) 71.71

Stock options outstanding as of June 30, 2011 4,586,717 $ 38.09

(3,924,595 options exercisable)
72

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Stock Option Activities	Number of Shares		Weighted Average Exercise Price
Stock options outstanding as of January 1, 2011 (all exercisable)	2,889,066		$	35.18
Options granted	662,122		37.75
Converted AE options	1,805,811		41.75
Options exercised	(847,261	)	31.20
Options forfeited/expired	(110,085	)	71.65
Stock options outstanding as of September 30, 2011	4,399,653		$	38.12
(3,737,531 options exercisable)

Compensation expense recognized for stock options during the ~~six~~nine months ended ~~June~~September 30, 2011, was ~~$0.3 million.~~ $0.5 million. No expense was recognized during the ~~six~~nine months ended ~~June~~September 30, ~~2010.~~2010. Options granted during the ~~six~~nine months ended ~~June~~September 30, 2011, had a grant-date fair value of ~~$3.3~~$3.3 million and an expected weighted-average vesting period of 3.79 years.

Options outstanding by exercise price as of ~~June~~September 30, 2011, were as follows:

Weighted Remaining
Shares Under Average Contractual
Exercise Prices Options Exercise Price Life in Years

$20.02 – $30.74 1,045,122 $ 26.54 2.02
$30.89 – $40.93 3,160,440 37.30 4.17
$42.72 – $51.82 3,883 51.02 0.70
$53.06 – $62.97 54,559 56.15 3.02
$64.52 – $71.82 9,042 67.50 5.24
$73.39 – $80.47 311,003 80.17 3.81
$81.19 – $89.59 2,668 85.39 6.09

Total 4,586,717 $ 38.08 3.64

Exercise Prices Shares Under Options Weighted Average Exercise Price Remaining Contractual Life in Years
$20.02 – $30.74 987,607
$ 26.83
1.77
$30.89 – $40.93 3,061,503
37.36
3.96
$42.72 – $51.82 3,883
51.02
0.45
$53.06 – $62.97 41,219
53.94
2.90
$64.52 – $71.82 8,671
67.53
4.05
$73.39 – $80.47 294,102
80.22
3.71
$81.19 – $89.59 2,668
85.39
2.81
Total 4,399,653
$ 38.12
3.44

Performance Shares

Performance shares will be settled in cash and are accounted for as liability awards. Compensation expense (income) recognized for performance shares during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, net of amounts capitalized, totaled $2$2 million and ~~$(6)~~$(8) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the ~~six~~nine months ended ~~June~~September 30, 2011 and ~~2010.~~2010.

(B) ESOP

During 2011, shares of FirstEnergy common stock were purchased on the open market and contributed to participants’ accounts. Total ESOP-related compensation expense for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, net of amounts capitalized and dividends on common stock, ~~were $19~~was approximately $34 million and ~~$10~~$31 million, respectively.

(C) EDCP

There was no material compensation expense recognized on EDCP stock units during the ~~six~~nine months ended ~~June~~September 30, 2011, and ~~2010.~~2010.

(D) DCPD

DCPD expenses recognized during the ~~six~~nine months ended ~~June~~September 30, 2011, and 2010 were approximately $2$3 million in each period. The net liability recognized for DCPD of approximately $6$6 million as of ~~June~~September 30, 2011, is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.

Of the 1.7 million stock units authorized under the EDCP and DCPD, ~~1,076,779~~1,075,080 stock units were available for future awards as of ~~June~~September 30, ~~2011.~~2011.

~~12.~~13. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about

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significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective for FirstEnergy in the first quarter of 2012. FirstEnergy does not expect this amendment to have a material effect on its financial statements.

In June 2011, the FASB issued new accounting guidance that revises the manner in which entities ~~presents~~present comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is effective for FirstEnergy in the first quarter of 2012. This amendment will not have a material effect on FirstEnergy’s financial statements.

In September 2011, the FASB amended guidance regarding how entities test goodwill for impairment. Under the revised guidance, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount, including goodwill. The revised guidance is intended to reduce the cost and complexity of performing goodwill impairment tests and is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. FirstEnergy will adopt the new guidance for goodwill impairment tests performed after calendar year 2011 and does not expect that the adoption will have a significant impact on its financial statements.

~~13.~~14. SEGMENT INFORMATION

With the completion of the ~~Allegheny~~AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” ~~segment~~amounts consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.

The changes in FirstEnergy’s reportable segments during 2011 consisted primarily of the following:

Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with ~~Allegheny,~~AE, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.

A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL ~~Company~~ and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with ~~Allegheny.~~AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP ~~remain~~remained within the Regulated Distribution segment.

AE Supply, an operator of generation facilities that was acquired as part of the merger with ~~Allegheny,~~AE, was placed into the Competitive Energy Services segment.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.

The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH

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and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from ~~operation of~~operating a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.

The Competitive Energy Services segment, through FES and AE Supply, supplies electric power to end-use customers through retail and wholesale arrangements, including ~~associated~~affiliated company power sales to meet a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, ~~Maryland,~~ Michigan, New Jersey and ~~New Jersey.~~Maryland. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

~~The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including~~ AE Supply ~~and AE Supply’s interest in AGC. AE Supply~~together with its consolidated subsidiary, AGC owns, operates and controls the electric generation capacity of ~~its~~ 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.

This ~~business~~Competitive Energy Services segment controls approximately 20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.

~~The~~ Other/Corporate ~~segment~~ contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.

Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the ~~Utilities~~Utility Registrants do not have separate reportable operating segments.

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Segment Financial Information

Competitive Regulated
Regulated Energy Independent Other/ Reconciling
Three Months Ended Distribution Services Transmission Corporate Adjustments Consolidated
(In millions)
June 30, 2011

External revenues $ 2,485 $ 1,495 $ 105 $ (30 ) $ (7 ) $ 4,048
Internal revenues — 318 — — (306 ) 12

Total revenues 2,485 1,813 105 (30 ) (313 ) 4,060
Depreciation and amortization 240 107 18 7 — 372
Investment income (loss), net 27 15 — 1 (12 ) 31
Net interest charges 145 67 11 21 1 245
Income taxes 108 7 18 (30 ) (2 ) 101
Net income (loss) 184 12 31 (51 ) (5 ) 171
Total assets 26,932 17,146 2,339 1,179 — 47,596
Total goodwill 5,551 905 — — — 6,456
Property additions 302 197 45 25 — 569

June 30, 2010

External revenues $ 2,314 $ 795 $ 59 $ (21 ) $ (8 ) $ 3,139
Internal revenues 19 539 — — (558 ) —

Total revenues 2,333 1,334 59 (21 ) (566 ) 3,139
Depreciation and amortization 264 71 13 3 — 351
Investment income (loss), net 28 13 — — (10 ) 31
Net interest charges 124 33 5 9 (4 ) 167
Income taxes 81 75 7 (12 ) (17 ) 134
Net income (loss) 132 121 11 (20 ) 12 256
Total assets 21,457 11,102 993 914 — 34,466
Total goodwill 5,551 24 — — — 5,575
Property additions 157 290 15 27 — 489

Six Months Ended

June 30, 2011

External revenues $ 4,753 $ 2,736 $ 172 $ (53 ) $ (16 ) $ 7,592
Internal revenues — 661 — — (617 ) 44

Total revenues 4,753 3,397 172 (53 ) (633 ) 7,636
Depreciation and amortization 485 195 31 13 — 724
Investment income (loss), net 52 21 — 1 (22 ) 52
Net interest charges 276 122 20 40 — 458
Income taxes 164 10 25 (50 ) 30 179
Net income (loss) 280 17 44 (86 ) (39 ) 216
Total assets 26,932 17,146 2,339 1,179 — 47,596
Total goodwill 5,551 905 — — — 6,456
Property additions 479 411 72 56 — 1,018

June 30, 2010

External revenues $ 4,798 $ 1,514 $ 116 $ (43 ) $ (14 ) $ 6,371
Internal revenues 19 1,213 — — (1,165 ) 67

Total revenues 4,817 2,727 116 (43 ) (1,179 ) 6,438
Depreciation and amortization 577 148 25 6 — 756
Investment income (loss), net 54 14 — 1 (22 ) 47
Net interest charges 248 66 10 22 (7 ) 339
Income taxes 143 117 14 (24 ) (5 ) 245
Net income (loss) 235 190 23 (39 ) (4 ) 405
Total assets 21,457 11,102 993 914 — 34,466
Total goodwill 5,551 24 — — — 5,575
Property additions 309 619 29 40 — 997



Three Months Ended	Regulated Distribution		Competitive Energy Services			Regulated Independent Transmission		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
September 30, 2011
External revenues	$	2,934	$	1,714		$	106	$	(39	)	$	(9	)	$	4,706
Internal revenues	1		315			—		—			(303		)	13
Total revenues	2,935		2,029			106		(39		)	(312		)	4,719
Depreciation and amortization	282		110			16		6			—			414
Investment income (loss), net	32		28			—		—			(12		)	48
Net interest charges	144		73			12		21			—			250
Income taxes	170		136			20		(23		)	8			311
Net income (loss)	288		232			34		(39		)	(6		)	509
Total assets	26,951		16,541			2,353		816			—			46,661
Total goodwill	5,551		897			—		—			—			6,448
Property additions	281		197			34		—			—			512
September 30, 2010
External revenues	$	2,685	$	1,002		$	73	$	(22	)	$	(10	)	$	3,728
Internal revenues	60		599			—		—			(659		)	—
Total revenues	2,745		1,601			73		(22		)	(669		)	3,728
Depreciation and amortization	278		67			9		4			—			358
Investment income (loss), net	24		27			—		1			(6		)	46
Net interest charges	125		33			6		7			(4		)	167
Income taxes	124		(16		)	13		(9		)	7			119
Net income (loss)	202		(26		)	22		(14		)	(9		)	175
Total assets	21,763		11,078			1,011		856			—			34,708
Total goodwill	5,551		24			—		—			—			5,575
Property additions	191		264			18		(2		)	—			471
Nine Months Ended
September 30, 2011
External revenues	$	7,687	$	4,450		$	278	$	(92	)	$	(25	)	$	12,298
Internal revenues	1		976			—		—			(920		)	57
Total revenues	7,688		5,426			278		(92		)	(945		)	12,355
Depreciation and amortization	767		305			47		19			—			1,138
Investment income (loss), net	84		49			—		1			(34		)	100
Net interest charges	420		195			32		61			—			708
Income taxes	334		146			45		(73		)	38			490
Net income (loss)	568		249			78		(125		)	(45		)	725
Total assets	26,951		16,541			2,353		816			—			46,661
Total goodwill	5,551		897			—		—			—			6,448
Property additions	760		608			105		56			—			1,529
September 30, 2010
External revenues	$	7,483	$	2,518		$	189	$	(65	)	$	(24	)	$	10,101
Internal revenues	79		1,812			—		—			(1,824		)	67
Total revenues	7,562		4,330			189		(65		)	(1,848		)	10,168
Depreciation and amortization	855		215			34		10			—			1,114
Investment income (loss), net	78		41			—		2			(28		)	93
Net interest charges	373		99			16		29			(11		)	506
Income taxes	267		101			27		(33		)	2			364
Net income (loss)	437		164			45		(53		)	(13		)	580
Total assets	21,763		11,078			1,011		856			—			34,708
Total goodwill	5,551		24			—		—			—			5,575
Property additions	499		883			47		38			—			1,467

Reconciling adjustments primarily consist of elimination of intersegment transactions.

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~~14. IMPAIRMENT OF~~15. IMPAIRMENTS AND LONG-LIVED ASSETS PENDING SALE

FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. ~~The following events described in the sections below occurred during for the first six months of 2011 that indicated the carrying value of certain assets may not be recoverable.~~

Fremont Energy Center

On March 11, 2011, FirstEnergy and American Municipal Power, Inc., entered into an agreement for the sale of Fremont Energy Center, which includes two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of ~~$11~~$11 million to operating income during the quarter ended March 31, ~~2011.~~2011. On July 28, 2011, FirstEnergy closed the sale of Fremont Energy Center to American Municipal Power, Inc.

Peaking Facilities

During the first ~~six~~nine months of 2011, FirstEnergy assessed the carrying values of certain peaking facilities that will more likely than not be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market. The result of this evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. FirstEnergy recorded impairment charges of $7$3 million and ~~$21~~$23 million during the three ~~months~~ and ~~six~~nine months ended ~~June~~September 30, 2011, respectively, as a result of the recoverability evaluation. On October 18, 2011, FirstEnergy closed on the sale of the Richland and Stryker Peaking Facilities which are capable of generating a total of 450 MW of peaking capacity.

Signal Peak

On October 18, 2011, FirstEnergy announced that a subsidiary of Gunvor Group, Ltd purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. As part of the transaction, FirstEnergy received approximately $257.5 million in proceeds and retained a 33-1/3% equity ownership in the joint venture. The transaction will result in an estimated after-tax gain of approximately $370 million, which includes a revaluation of its retained equity ownership. FirstEnergy previously consolidated this joint venture and, as a result of the sale, its retained 33-1/3% interest will be accounted for using the equity method of accounting.

As of September 30, 2011, assets and liabilities of the Signal Peak mining and transportation operations that were reclassified on FirstEnergy's Consolidated Balance Sheet include the following:



(In millions)
Assets Pending Sale:
	Current assets	$	17
	Property, plant and equipment	369
	Deferred charges and other assets	16
		402

Liabilities Related to Assets Pending Sale:
	Current liabilities	31
	Long-term debt	360
	Noncurrent liabilities	10
		401
Net Assets Pending Sale		$	1

In addition, the Noncontrolling interest reported on FirstEnergy's Consolidated Balance Sheet as of September 30, 2011, included approximately $(50) million relating to the joint venture.

~~15.~~16. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and ~~their~~the associated cost ~~for~~of nuclear power plant decommissioning, reclamation of sludge disposal ponds and closure of coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations, ~~(primarily~~primarily for asbestos ~~remediation).~~remediation.

The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear

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generating facilities (OE for its leasehold ~~interest~~interests in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES, OE, TE, JCP&L, Met-Ed and Penelec use an expected cash flow approach to measure the fair value of their nuclear decommissioning ARO.

During the first quarter of 2011, studies were completed to update the estimated cost of decommissioning the Perry nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and OE and reduced the liability for each subsidiary in the amounts of ~~$40~~$40 million and $6$6 million, respectively.

During the second quarter of 2011, studies were completed to update the estimated cost of decommissioning the Davis-Besse nuclear facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and reduced the liability for FES in the amount of ~~$5 million.~~$5 million.

The revisions to the estimated cash flows had no significant impact on accretion of the obligation during the three months and ~~six~~nine months ended ~~June~~September 30, 2011, when compared to the same periods of ~~2010.~~2010.

~~16.~~17. SUPPLEMENTAL GUARANTOR INFORMATION

In 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.

The condensed consolidating statements of income for the three ~~month~~months and ~~six month periods~~nine months ended ~~June~~September 30, 2011 and 2010, consolidating balance sheets as of ~~June~~September 30, 2011 and December 31, 2010 and consolidating statements of cash flows for the ~~three~~nine months ended ~~June~~September 30, 2011 and 2010 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
~~(Unaudited)~~

For the Three Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES
$ 1,275 $ 535 $ 393 $ (911 ) $ 1,292

EXPENSES:

Fuel 6 266 44 — 316
Purchased power from affiliates 902 9 65 (911 ) 65
Purchased power from non-affiliates 332 (3 ) — — 329
Other operating expenses 159 115 143 12 429
Provision for depreciation 1 32 36 (1 ) 68
General taxes 16 8 6 — 30
Impairment of long-lived assets — 7 — — 7

Total expenses 1,416 434 294 (900 ) 1,244

OPERATING INCOME (LOSS)
(141 ) 101 99 (11 ) 48

OTHER INCOME (EXPENSE):

Investment income — 1 15 — 16
Miscellaneous income (expense), including net income from equity investees 123 1 — (120 ) 4
Interest expense — affiliates — (1 ) (1 ) — (2 )
Interest expense — other (24 ) (28 ) (16 ) 16 (52 )
Capitalized interest — 5 5 — 10

Total other income (expense) 99 (22 ) 3 (104 ) (24 )

INCOME (LOSS) BEFORE INCOME TAXES
(42 ) 79 102 (115 ) 24

INCOME TAXES (BENEFITS)
(62 ) 25 38 3 4

NET INCOME
$ 20 $ 54 $ 64 $ (118 ) $ 20

(Unaudited)

For the Three Months Ended September 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES $ 1,445
$ 686
$ 371
$ (1,035 ) $ 1,467

OPERATING EXPENSES:

Fuel 6
323
57
—
386
Purchased power from affiliates 1,031
4
55
(1,035 ) 55
Purchased power from non-affiliates 330
(2 ) —
—
328
Other operating expenses 164
100
129
12
405
Provision for depreciation 1
32
37
(1 ) 69
General taxes 19
9
3
—
31
Impairment of long-lived assets —
2
—
—
2
Total operating expenses 1,551
468
281
(1,024 ) 1,276

OPERATING INCOME (LOSS) (106 ) 218
90
(11 ) 191

OTHER INCOME (EXPENSE):

Investment income —
—
28
—
28
Miscellaneous income (expense), including net income from equity investees 187
16
—
(194 ) 9
Interest expense — affiliates —
(1 ) (1 ) —
(2 )
Interest expense — other (24 ) (26 ) (16 ) 15
(51 )
Capitalized interest —
3
5
—
8
Total other income (expense) 163
(8 ) 16
(179 ) (8 )

INCOME BEFORE INCOME TAXES 57
210
106
(190 ) 183

INCOME TAXES (BENEFITS)
(53 ) 82
42
2
73

NET INCOME $ 110
$ 128
$ 64
$ (192 ) $ 110

79
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
~~(Unaudited)~~

For the Six Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES
$ 2,642 $ 1,278 $ 862 $ (2,098 ) $ 2,684

EXPENSES:

Fuel 7 560 92 — 659
Purchased power from affiliates 2,087 11 134 (2,098 ) 134
Purchased power from non-affiliates 629 (3 ) — — 626
Other operating expenses 321 233 331 25 910
Provision for depreciation 2 63 74 (3 ) 136
General taxes 27 19 14 — 60
Impairment charges of long-lived assets — 20 — — 20

Total expenses 3,073 903 645 (2,076 ) 2,545

OPERATING INCOME (LOSS)
(431 ) 375 217 (22 ) 139

OTHER INCOME (EXPENSE):

Investment income 1 1 20 — 22
Miscellaneous income, including net income from equity investees 356 2 — (350 ) 8
Interest expense — affiliates (1 ) (1 ) (1 ) — (3 )
Interest expense — other (48 ) (56 ) (33 ) 32 (105 )
Capitalized interest — 10 10 — 20

Total other income (expense) 308 (44 ) (4 ) (318 ) (58 )

INCOME (LOSS) BEFORE INCOME TAXES
(123 ) 331 213 (340 ) 81

INCOME TAXES (BENEFITS)
(179 ) 119 80 5 25

NET INCOME
$ 56 $ 212 $ 133 $ (345 ) $ 56

(Unaudited)

For the Nine Months Ended September 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES $ 4,087
$ 1,964
$ 1,233
$ (3,133 ) $ 4,151

OPERATING EXPENSES:

Fuel 13
883
149
—
1,045
Purchased power from affiliates 3,118
15
189
(3,133 ) 189
Purchased power from non-affiliates 959
(5 ) —
—
954
Other operating expenses 485
333
460
37
1,315
Provision for depreciation 3
95
111
(4 ) 205
General taxes 46
28
17
—
91
Impairment of long-lived assets —
22
—
—
22
Total operating expenses 4,624
1,371
926
(3,100 ) 3,821

OPERATING INCOME (LOSS) (537 ) 593
307
(33 ) 330

OTHER INCOME (EXPENSE):

Investment income 1
1
48
—
50
Miscellaneous income, including net income from equity investees 543
18
—
(544 ) 17
Interest expense — affiliates (1 ) (2 ) (2 ) —
(5 )
Interest expense — other (72 ) (82 ) (49 ) 47
(156 )
Capitalized interest —
13
15
—
28
Total other income (expense) 471
(52 ) 12
(497 ) (66 )

INCOME (LOSS) BEFORE INCOME TAXES (66 ) 541
319
(530 ) 264

INCOME TAXES (BENEFITS)
(232 ) 201
122
7
98

NET INCOME $ 166
$ 340
$ 197
$ (537 ) $ 166

80
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
~~(Unaudited)~~

For the Three Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES
$ 1,307 $ 581 $ 339 $ (901 ) $ 1,326

EXPENSES:

Fuel 7 302 34 — 343
Purchased power from affiliates 913 8 49 (901 ) 69
Purchased power from non-affiliates 310 — — — 310
Other operating expenses 81 94 117 12 304
Provision for depreciation 1 27 36 (1 ) 63
General taxes 6 9 7 — 22

Total expenses 1,318 440 243 (890 ) 1,111

OPERATING INCOME (LOSS)
(11 ) 141 96 (11 ) 215

OTHER INCOME (EXPENSE):

Investment income 2 — 11 — 13
Miscellaneous income, including net income from equity investees 151 1 — (148 ) 4
Interest expense — affiliates — (2 ) — — (2 )
Interest expense — other (24 ) (28 ) (15 ) 16 (51 )
Capitalized interest — 20 4 — 24

Total other income (expense) 129 (9 ) — (132 ) (12 )

INCOME BEFORE INCOME TAXES
118 132 96 (143 ) 203

INCOME TAXES (BENEFITS)
(16 ) 48 34 3 69

NET INCOME
$ 134 $ 84 $ 62 $ (146 ) $ 134

(Unaudited)

For the Three Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES $ 1,576
$ 645
$ 381
$ (1,013 ) $ 1,589

OPERATING EXPENSES:

Fuel 13
329
49
—
391
Purchased power from affiliates 1,059
13
57
(1,013 ) 116
Purchased power from non-affiliates 446
—
—
—
446
Other operating expenses 84
96
116
12
308
Provision for depreciation 1
24
36
(1 ) 60
General taxes 6
9
7
—
22
Impairment of long-lived assets —
292
—
—
292
Total operating expenses 1,609
763
265
(1,002 ) 1,635

OPERATING INCOME (LOSS) (33 ) (118 ) 116
(11 ) (46 )

OTHER INCOME (EXPENSE):
Investment income 1
—
29
—
30
Miscellaneous income, including net income from equity investees 5
2
—
(4 ) 3
Interest expense — affiliates —
(2 ) —
—
(2 )
Interest expense — other (25 ) (26 ) (15 ) 16
(50 )
Capitalized interest —
19
4
—
23
Total other income (expense) (19 ) (7 ) 18
12
4

INCOME (LOSS) BEFORE INCOME TAXES

(52 ) (125 ) 134
1
(42 )
INCOME TAXES (BENEFITS) (15 ) (44 ) 52
2
(5 )

NET INCOME (LOSS)
$ (37 ) $ (81 ) $ 82
$ (1 ) $ (37 )

81
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
~~(Unaudited)~~

For the Six Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES
$ 2,674 $ 1,149 $ 765 $ (1,874 ) $ 2,714

EXPENSES:

Fuel 12 582 77 — 671
Purchased power from affiliates 1,881 12 111 (1,874 ) 130
Purchased power from non-affiliates 760 — — — 760
Other operating expenses 134 194 256 24 608
Provision for depreciation 2 54 73 (3 ) 126
General taxes 11 24 14 — 49
Impairment of long-lived assets — 2 — — 2

Total expenses 2,800 868 531 (1,853 ) 2,346

OPERATING INCOME (LOSS)
(126 ) 281 234 (21 ) 368

OTHER INCOME (EXPENSE):

Investment income 4 — 10 — 14
Miscellaneous income, including net income from equity investees 317 1 — (311 ) 7
Interest expense to affiliates — (4 ) (1 ) — (5 )
Interest expense — other (48 ) (54 ) (31 ) 32 (101 )
Capitalized interest — 36 8 — 44

Total other income (expense) 273 (21 ) (14 ) (279 ) (41 )

INCOME BEFORE INCOME TAXES
147 260 220 (300 ) 327

INCOME TAXES (BENEFITS)
(67 ) 97 78 5 113

NET INCOME
$ 214 $ 163 $ 142 $ (305 ) $ 214

(Unaudited)

For the Nine Months Ended September 30, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)

REVENUES $ 4,250
$ 1,794
$ 1,146
$ (2,887 ) $ 4,303

OPERATING EXPENSES:

Fuel 26
911
125
—
1,062
Purchased power from affiliates 2,940
26
167
(2,887 ) 246
Purchased power from non-affiliates 1,206
—
—
—
1,206
Other operating expenses 218
290
372
36
916
Provision for depreciation 3
78
109
(4 ) 186
General taxes 18
32
21
—
71
Impairment of long-lived assets —
294
—
—
294
Total operating expenses 4,411
1,631
794
(2,855 ) 3,981

OPERATING INCOME (LOSS) (161 ) 163
352
(32 ) 322

OTHER INCOME (EXPENSE):

Investment income 4
1
39
—
44
Miscellaneous income, including net income from equity investees 323
2
—
(315 ) 10
Interest expense to affiliates —
(6 ) (1 ) —
(7 )
Interest expense — other (72 ) (81 ) (46 ) 48
(151 )
Capitalized interest 1
55
11
—
67
Total other income (expense) 256
(29 ) 3
(267 ) (37 )

INCOME BEFORE INCOME TAXES 95
134
355
(299 ) 285

INCOME TAXES (BENEFITS)
(82 ) 52
130
8
108

NET INCOME $ 177
$ 82
$ 225
$ (307 ) $ 177

82
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
~~(Unaudited)~~

As of June 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)
ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ — $ 6 $ — $ — $ 6
Receivables-
Customers 450 — — — 450
Associated companies 481 425 263 (679 ) 490
Other 24 23 4 — 51
Notes receivable from associated companies 6 410 74 — 490
Materials and supplies, at average cost 54 253 192 — 499
Derivatives 221 — — — 221
Prepayments and other 34 14 1 — 49

1,270 1,131 534 (679 ) 2,256

PROPERTY, PLANT AND EQUIPMENT:

In service 101 6,105 5,634 (385 ) 11,455
Less — Accumulated provision for depreciation 19 2,067 2,298 (178 ) 4,206

82 4,038 3,336 (207 ) 7,249
Construction work in progress 10 198 486 — 694
Property, plant and equipment held for sale, net — 487 — — 487

92 4,723 3,822 (207 ) 8,430

INVESTMENTS:

Nuclear plant decommissioning trusts — — 1,184 — 1,184
Investment in associated companies 5,302 — — (5,302 ) —
Other 1 9 — — 10

5,303 9 1,184 (5,302 ) 1,194

DEFERRED CHARGES AND OTHER ASSETS:

Accumulated deferred income tax benefits 18 344 — (362 ) —
Customer intangibles 129 — — — 129
Goodwill 24 — — — 24
Property taxes — 16 25 — 41
Unamortized sale and leaseback costs — 6 — 70 76
Derivatives 135 — — — 135
Other 39 97 7 (68 ) 75

345 463 32 (360 ) 480

$ 7,010 $ 6,326 $ 5,572 $ (6,548 ) $ 12,360

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 1 $ 436 $ 671 $ (20 ) $ 1,088
Short-term borrowings-
Associated companies 453 88 — — 541
Other — 1 — — 1
Accounts payable-
Associated companies 665 231 165 (668 ) 393
Other 80 111 — — 191
Derivatives 242 — — — 242
Other 69 137 46 10 262

1,510 1,004 882 (678 ) 2,718

CAPITALIZATION:

Total equity 3,858 2,728 2,556 (5,285 ) 3,857
Long-term debt and other long-term obligations 1,483 2,050 706 (1,239 ) 3,000

5,341 4,778 3,262 (6,524 ) 6,857

NONCURRENT LIABILITIES:

Deferred gain on sale and leaseback transaction — — — 942 942
Accumulated deferred income taxes — — 504 (288 ) 216
Asset retirement obligations — 28 847 — 875
Retirement benefits 50 245 — — 295
Lease market valuation liability — 194 — — 194
Derivatives 85 — — — 85
Other 24 77 77 — 178

159 544 1,428 654 2,785

$ 7,010 $ 6,326 $ 5,572 $ (6,548 ) $ 12,360

(Unaudited)

As of September 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ —
$ 6
$ —
$ —
$ 6
Receivables-
Customers 452
—
—
—
452
Affiliated companies 438
504
234
(698 ) 478
Other 22
21
18
—
61
Notes receivable from affiliated companies 262
921
2
(845 ) 340
Materials and supplies, at average cost 58
224
195
—
477
Derivatives 170
—
—
—
170
Prepayments and other 49
12
—
—
61
1,451
1,688
449
(1,543 ) 2,045

PROPERTY, PLANT AND EQUIPMENT:
In service 82
6,111
5,632
(385 ) 11,440
Less — Accumulated provision for depreciation 17
2,097
2,379
(179 ) 4,314
65
4,014
3,253
(206 ) 7,126
Construction work in progress 13
216
589
—
818
Property, plant and equipment held for sale, net —
—
—
—
—
78
4,230
3,842
(206 ) 7,944
INVESTMENTS:
Nuclear plant decommissioning trusts —
—
1,187
—
1,187
Investment in affiliated companies 5,486
—
—
(5,486 ) —
Other 1
9
—
—
10
5,487
9
1,187
(5,486 ) 1,197

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits 12
286
—
(298 ) —
Customer intangibles 126
—
—
—
126
Goodwill 24
—
—
—
24
Property taxes —
16
25
—
41
Unamortized sale and leaseback costs —
—
—
68
68
Derivatives 136
—
—
—
136
Other 39
102
10
(68 ) 83
337
404
35
(298 ) 478
$ 7,353
$ 6,331
$ 5,513
$ (7,533 ) $ 11,664

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 1
$ 385
$ 512
$ (21 ) $ 877
Short-term borrowings-
Affiliated companies 750
70
25
(845 ) —
Accounts payable-
Affiliated companies 689
268
159
(691 ) 425
Other 80
90
—
—
170
Derivatives 175
—
—
—
175
Other 75
182
50
16
323
1,770
995
746
(1,541 ) 1,970
CAPITALIZATION:
Total equity 3,958
2,858
2,608
(5,466 ) 3,958
Long-term debt and other long-term obligations 1,484
1,942
706
(1,240 ) 2,892
5,442
4,800
3,314
(6,706 ) 6,850

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction —
—
—
934
934
Accumulated deferred income taxes —
—
523
(220 ) 303
Asset retirement obligations —
27
862
—
889
Retirement benefits 51
248
—
—
299
Lease market valuation liability —
183
—
—
183
Derivatives 67
—
—
—
67
Other 23
78
68
—
169
141
536
1,453
714
2,844
$ 7,353
$ 6,331
$ 5,513
$ (7,533 ) $ 11,664

83
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
~~(Unaudited)~~

As of December 31, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)
ASSETS

CURRENT ASSETS:

Cash and cash equivalents $ — $ 9 $ — $ — $ 9
Receivables-
Customers 366 — — — 366
Associated companies 333 357 126 (338 ) 478
Other 21 56 13 — 90
Notes receivable from associated companies 34 189 174 — 397
Materials and supplies, at average cost 41 276 228 — 545
Derivatives 182 — — — 182
Prepayments and other 48 10 1 — 59

1,025 897 542 (338 ) 2,126

PROPERTY, PLANT AND EQUIPMENT:

In service 96 6,198 5,412 (385 ) 11,321
Less — Accumulated provision for depreciation 17 2,020 2,162 (175 ) 4,024

79 4,178 3,250 (210 ) 7,297
Construction work in progress 9 520 534 — 1,063

88 4,698 3,784 (210 ) 8,360

INVESTMENTS:

Nuclear plant decommissioning trusts — — 1,146 — 1,146
Investment in associated companies 4,942 — — (4,942 ) —
Other — 12 — — 12

4,942 12 1,146 (4,942 ) 1,158

DEFERRED CHARGES AND OTHER ASSETS:

Accumulated deferred income tax benefits 43 412 — (455 ) —
Customer intangibles 134 — — — 134
Goodwill 24 — — — 24
Property taxes — 16 25 — 41
Unamortized sale and leaseback costs — 10 — 63 73
Derivatives 98 — — — 98
Other 21 71 14 (58 ) 48

320 509 39 (450 ) 418

$ 6,375 $ 6,116 $ 5,511 $ (5,940 ) $ 12,062

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:

Currently payable long-term debt $ 101 $ 419 $ 632 $ (20 ) $ 1,132
Short-term borrowings-
Associated companies — 12 — — 12
Accounts payable-
Associated companies 351 213 250 (347 ) 467
Other 139 102 — — 241
Derivatives 266 — — — 266
Other 56 183 46 37 322

913 929 928 (330 ) 2,440

CAPITALIZATION:

Common stockholder’s equity 3,788 2,515 2,414 (4,929 ) 3,788
Long-term debt and other long-term obligations 1,519 2,119 793 (1,250 ) 3,181

5,307 4,634 3,207 (6,179 ) 6,969

NONCURRENT LIABILITIES:

Deferred gain on sale and leaseback transaction — — — 959 959
Accumulated deferred income taxes — — 448 (390 ) 58
Asset retirement obligations — 27 865 — 892
Retirement benefits 48 237 — — 285
Lease market valuation liability — 217 — — 217
Derivatives 81 — — — 81
Other 26 72 63 — 161

155 553 1,376 569 2,653

$ 6,375 $ 6,116 $ 5,511 $ (5,940 ) $ 12,062

(Unaudited)

As of December 31, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ —
$ 9
$ —
$ —
$ 9
Receivables-
Customers 366
—
—
—
366
Affiliated companies 333
357
126
(338 ) 478
Other 21
56
13
—
90
Notes receivable from affiliated companies 34
189
174
—
397
Materials and supplies, at average cost 41
276
228
—
545
Derivatives 182
—
—
—
182
Prepayments and other 48
10
1
—
59
1,025
897
542
(338 ) 2,126

PROPERTY, PLANT AND EQUIPMENT:
In service 96
6,198
5,412
(385 ) 11,321
Less — Accumulated provision for depreciation 17
2,020
2,162
(175 ) 4,024
79
4,178
3,250
(210 ) 7,297
Construction work in progress 9
520
534
—
1,063
88
4,698
3,784
(210 ) 8,360

INVESTMENTS:
Nuclear plant decommissioning trusts —
—
1,146
—
1,146
Investment in affiliated companies 4,942
—
—
(4,942 ) —
Other —
12
—
—
12
4,942
12
1,146
(4,942 ) 1,158
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits 43
412
—
(455 ) —
Customer intangibles 134
—
—
—
134
Goodwill 24
—
—
—
24
Property taxes —
16
25
—
41
Unamortized sale and leaseback costs —
10
—
63
73
Derivatives 98
—
—
—
98
Other 21
71
14
(58 ) 48
320
509
39
(450 ) 418
$ 6,375
$ 6,116
$ 5,511
$ (5,940 ) $ 12,062

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ 101
$ 419
$ 632
$ (20 ) $ 1,132
Short-term borrowings-
Affiliated companies —
12
—
—
12
Accounts payable-
Affiliated companies 351
213
250
(347 ) 467
Other 139
102
—
—
241
Derivatives 266
—
—
—
266
Other 56
183
46
37
322
913
929
928
(330 ) 2,440

CAPITALIZATION:
Common stockholder’s equity 3,788
2,515
2,414
(4,929 ) 3,788
Long-term debt and other long-term obligations 1,519
2,119
793
(1,250 ) 3,181
5,307
4,634
3,207
(6,179 ) 6,969

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction —
—
—
959
959
Accumulated deferred income taxes —
—
448
(390 ) 58
Asset retirement obligations —
27
865
—
892
Retirement benefits 48
237
—
—
285
Lease market valuation liability —
217
—
—
217
Derivatives 81
—
—
—
81
Other 26
72
63
—
161
155
553
1,376
569
2,653
$ 6,375
$ 6,116
$ 5,511
$ (5,940 ) $ 12,062

84
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
~~(Unaudited)~~

For the Six Months Ended June 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)

NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
$ (329 ) $ 321 $ 200 $ (10 ) $ 182

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt — 140 107 — 247
Short-term borrowings, net 453 77 — — 530
Redemptions and Repayments-
Long-term debt (135 ) (192 ) (155 ) 10 (472 )
Other (9 ) (1 ) (1 ) — (11 )

Net cash provided from (used for) financing activities 309 24 (49 ) 10 294

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (6 ) (109 ) (219 ) — (334 )
Sales of investment securities held in trusts — — 513 — 513
Purchases of investment securities held in trusts — — (545 ) — (545 )
Loans to associated companies, net 28 (221 ) 100 — (93 )
Customer acquisition costs (2 ) — — — (2 )
Other — (18 ) — — (18 )

Net cash provided from (used for) investing activities 20 (348 ) (151 ) — (479 )

Net change in cash and cash equivalents — (3 ) — — (3 )
Cash and cash equivalents at beginning of period — 9 — — 9

Cash and cash equivalents at end of period $ — $ 6 $ — $ — $ 6

(Unaudited)

For the Nine Months Ended September 30, 2011 FES FGCO NGC Eliminations Consolidated
(In millions)

NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (367 ) $ 539
$ 374
$ (9 ) $ 537

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Long-term debt —
140
107
—
247
Short-term borrowings, net 750
59
25
(834 ) —
Redemptions and Repayments-
Long-term debt (136 ) (351 ) (313 ) 9
(791 )
Short-term borrowings, net —
—
—
(12 ) (12 )
Other (8 ) (1 ) (2 ) 1
(10 )
Net cash provided from (used for) financing activities 606
(153 ) (183 ) (836 ) (566 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (8 ) (143 ) (322 ) —
(473 )
Proceeds from asset sales 9
510
—
—
519
Sales of investment securities held in trusts —
—
1,613
—
1,613
Purchases of investment securities held in trusts —
—
(1,654 ) —
(1,654 )
Loans to affiliated companies, net (228 ) (732 ) 172
845
57
Customer acquisition costs (2 ) —
—
—
(2 )
Other (10 ) (24 ) —
—
(34 )
Net cash provided from (used for) investing activities (239 ) (389 ) (191 ) 845
26

Net change in cash and cash equivalents
—
(3 ) —
—
(3 )
Cash and cash equivalents at beginning of period —
9
—
—
9
Cash and cash equivalents at end of period $ —
$ 6
$ —
$ —
$ 6

85
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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
~~(Unaudited)~~

For the Six Months Ended June 30, 2010 FES FGCO NGC Eliminations Consolidated
(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
$ (223 ) $ 163 $ 287 $ (9 ) $ 218

CASH FLOWS FROM FINANCING ACTIVITIES:

New Financing-
Short-term borrowings, net — 76 — — 76
Redemptions and Repayments-
Long-term debt — (261 ) (43 ) 9 (295 )
Other (1 ) — — — (1 )

Net cash used for financing activities (1 ) (185 ) (43 ) 9 (220 )

CASH FLOWS FROM INVESTING ACTIVITIES:

Property additions (4 ) (333 ) (229 ) — (566 )
Proceeds from asset sales — 116 — — 116
Sales of investment securities held in trusts — — 957 — 957
Purchases of investment securities held in trusts — — (979 ) — (979 )
Loans to associated companies, net 332 241 58 — 631
Customer acquisition costs (105 ) — — — (105 )
Leasehold improvement payments to associated companies — — (51 ) — (51 )
Other 1 (2 ) — — (1 )

Net cash provided from (used for) investing activities 224 22 (244 ) — 2

Net change in cash and cash equivalents — — — — —
Cash and cash equivalents at beginning of period — — — — —

Cash and cash equivalents at end of period $ — $ — $ — $ — $ —

(Unaudited)



For the Nine Months Ended September 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)

NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(289	)	$	402		$	520		$	(9	)	$	624
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			250			—			—			250
Redemptions and Repayments-
Long-term debt	(1		)	(261		)	(43		)	9			(296		)
Other	(1		)	—			—			—			(1		)
Net cash used for financing activities	(2		)	(11		)	(43		)	9			(47		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(417		)	(379		)	—			(801		)
Proceeds from asset sales	—			117			—			—			117
Sales of investment securities held in trusts	—			—			1,478			—			1,478
Purchases of investment securities held in trusts	—			—			(1,511		)	—			(1,511		)
Loans to affiliated companies, net	406			(89		)	(14		)	—			303
Customer acquisition costs	(110		)	—			—			—			(110		)
Leasehold improvement payments to affiliated companies	—			—			(51		)	—			(51		)
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) investing activities	291			(391		)	(477		)	—			(577		)
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			—			—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—		$	—		$	—

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~~Item 2.~~		Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Earnings ~~available~~Available to FirstEnergy Corp. in the third quarter of 2011 were ~~$181~~$511 million, or basic and diluted earnings of ~~$0.43~~$1.22 per share of common stock, compared with ~~$265~~$179 million, or basic and diluted earnings of ~~$0.87~~$0.59 per share of common stock in the ~~second~~third quarter of 2010. Earnings ~~available~~Available to FirstEnergy Corp. in the first ~~six~~nine months of 2011 were ~~$231~~$742 million or basic ~~and diluted~~ earnings of ~~$0.61~~$1.89 ($1.88 diluted) per share of common stock, compared with ~~$420~~$599 million or basic earnings of ~~$1.38 ($1.37~~$1.97 ($1.96 diluted) per share of common stock in the first ~~six~~nine months of 2010. The principal reasons for the ~~decreases~~changes in basic earnings per share are summarized below.

Three Months Six Months
Change In Basic Earnings Per Share From Prior Year⁽¹⁾ Ended June 30 Ended June 30
Basic Earnings Per Share - 2010 $ 0.87 $ 1.38
Non-core asset sales/impairments (0.01 ) (0.04 )
Trust securities impairments 0.01 0.02
Mark-to-market adjustments (0.10 ) (0.02 )
Income tax charge from healthcare legislation - 2010 — 0.04
Regulatory charges - 2011 (0.01 ) (0.05 )
Regulatory charges - 2010 — 0.08
Litigation resolution (0.06 ) (0.07 )
Merger related costs (0.02 ) (0.31 )
Segment operating results -⁽²⁾

Regulated Distribution 0.02 —
Competitive Energy Services (0.15 ) (0.24 )
Interest expense, net of amounts capitalized (0.04 ) (0.08 )
Merger accounting — commodity contracts (0.08 ) (0.12 )
Net merger accretion⁽³⁾
0.02 0.06
Settlement of uncertain tax positions (0.03 ) (0.05 )
Other expenses 0.01 0.01

Basic Earnings Per Share - 2011 $ 0.43 $ 0.61



Change In Basic Earnings Per Share From Prior Year	Three Months Ended September 30			Nine Months Ended September 30
Basic Earnings Per Share - 2010	$	0.59		$	1.97
Non-core asset sales/impairments	0.58			0.54
Trust securities impairments	(0.01		)	0.01
Mark-to-market adjustments	0.02			—
Income tax charge from healthcare legislation - 2010	—			0.04
Regulatory charges	0.02			0.06
Litigation resolution	(0.01		)	(0.07		)
Merger-related costs	0.03			(0.27		)
Segment operating results⁽¹⁾ -
Regulated Distribution	0.02			0.02
Competitive Energy Services	0.13			(0.09		)
Regulated Independent Transmission	(0.03		)	(0.05		)
Interest expense, net of amounts capitalized	(0.05		)	(0.13		)
Merger accounting — commodity contracts	(0.06		)	(0.18		)
Net merger accretion⁽²⁾	0.01			0.10
Settlement of uncertain tax positions	—			(0.05		)
Other	(0.02		)	(0.01		)
Basic Earnings Per Share - 2011	$	1.22		$	1.89


⁽¹⁾		~~Amounts shown are net of income tax effect~~


⁽²⁾		Excludes amounts that are shown separately

⁽³⁾
⁽²⁾	Excludes merger accounting — commodity contracts, regulatory charges, mark-to-market adjustments and merger-related costs that are shown separately

Merger

On February 25, 2011, the merger between FirstEnergy and ~~Allegheny~~AE closed. Pursuant to the terms of the Agreement and Plan of Merger between FirstEnergy, ~~Element~~ Merger Sub ~~Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub)~~ and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a ~~wholly-owned~~wholly owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.

In connection with the merger, FirstEnergy recorded ~~approximately $7 million of~~ merger transaction costs of approximately $2 million ($1 million net of tax) and $14 million ($11 million net of tax) during ~~each of~~ the ~~second quarter of~~three months ended September 30, 2011 and 2010, respectively, and approximately ~~$89~~$91 million ($73 million net of tax) and ~~$21~~$35 million ($26 million net of ~~merger transaction costs~~tax) during the first ~~six~~nine months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. FirstEnergy’s consolidated financial statements include Allegheny’s results of operations and financial position effective February 25, 2011. In addition, during the three months ended ~~June~~September 30, 2011, ~~$10~~$3 million ($1 million net of tax) of merger integration costs and $8$2 million ($1 million net of tax) of charges from merger settlements approved by regulatory agencies were recognized. In the first ~~six~~nine months of 2011, ~~$85~~$88 million ($67 million net of tax) of merger integration costs and ~~$32~~$33 million ($20 million net of tax) of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be

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material in future periods.

FirstEnergy expects to achieve ~~the~~its 2011 merger benefits target resulting from the merger with ~~Allegheny.~~AE. Through ~~June~~September 2011, FirstEnergy has taken actions and completed savings initiatives that will allow the company to capture merger benefits of approximately ~~$132~~$165 million pre-tax on an annual basis, or ~~63%~~79% of the $210 million annual target. ~~The $132 million realized from savings initiatives completed through June, along with the impact of initiatives still underway, will be reflected in earnings throughout 2011.~~

Operational Matters

~~TrAIL~~Richland and Stryker Peaking Power Plants

On ~~May 19,~~October 18, 2011 ~~TrAIL’s 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.~~

~~ATSI Integrated into PJM~~

~~On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy’s generation, transmission and distribution facilities are now in PJM.~~

~~Perry Refueling~~

On June 7, 2011, the Perry Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

~~New Nuclear Emergency Operations Facilities~~

In June 2011, FENOC broke ground for new Emergency Operations Facilities for the Beaver Valley Power Station and Perry Nuclear Power Plant. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies. FENOC is expected to break ground for a similar facility for the Davis-Besse Nuclear Power Station in August 2011.

~~Fremont Energy Center~~

~~On July 28, 2011,~~, FirstEnergy closed on the ~~previously announced~~ sale of ~~Fremont Energy Center~~its Richland (432 MW) and Stryker (18 MW) Peaking Facilities for approximately $80 million. The proceeds from the sale of these non-core assets will be used to ~~American Municipal Power, Inc. for $510~~reduce FirstEnergy's net debt position.

Signal Peak

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. purchased a one-third interest in the Signal Peak coal mine in Montana. The sale strengthens FirstEnergy's balance sheet in the following ways:

Proceeds of $257.5 million ~~based~~ will be used to reduce FirstEnergy's net debt position

De-consolidation of Signal Peak will result in the reduction of indebtedness by $360 million and an increase to equity of $50 million on ~~685 MW~~FirstEnergy’s Consolidated Balance Sheet

Estimated gain on sale and revaluation of ~~output. The purchase price can be incrementally increased, not to exceed~~remaining ownership stake will increase equity by an additional ~~$16~~$370 million

Following the sale, FirstEnergy, through its wholly owned subsidiary, FEV, has a one-third interest in Global Mining Holding Company, LLC, a joint venture that owns Signal Peak. FGCO has revised its coal purchase agreement with Signal Peak to ~~reflect additional transmission export capacity~~reduce delivery from up to ~~707 MW.~~7.5 million tons annually to an obligation to accept up to 2 million tons each year.

~~Financial Matters~~

~~On April 29,~~FirstEnergy Utilities Respond to Hurricane Irene

In late August, 2011, FirstEnergy experienced unprecedented damage in its service territory as a result of Hurricane Irene. Approximately 1 million customers were affected by outages in areas served by its subsidiaries JCP&L, Met-Ed, ~~redeemed $13.69~~Penelec and PE. Approximately 5,000 FirstEnergy employees and 1,000 contractors, including utility line workers from other utilities, assisted with the restoration work. The cost of the storm was approximately $78 million, of ~~pollution~~which $3 million reduced pre-tax income in the third quarter of 2011 and $75 million was capitalized or deferred for future recovery from customers.

Davis-Besse Outage

On October 1, 2011, the Davis-Besse Plant was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaces a head installed in 2002, enhances safety, reliability and features control ~~revenue bonds at par value.~~

rod nozzles made of material less susceptible to cracking. On ~~May 4,~~October 10, 2011, ~~AE terminated its $250 million credit facility due to other available funding sources following completion~~a sub-surface hairline crack was identified in one of the ~~merger~~exterior architectural elements on the Shield Building, following opening of the building for installation of the new reactor head. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the Shield Building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. The team of industry-recognized structural concrete experts and Davis-Besse engineers evaluating this condition has determined the cracking does not affect the facility's structural integrity or safety. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in two localized areas of the Shield Building similar to those found in the architectural elements. FENOC has determined these two areas are not associated with ~~FirstEnergy.~~the architectural element cracking and are investigating them as a separate issue. FENOC's overall investigation and analysis continues.Davis-Besse is currently expected to return to service around the end of November.

~~On May 31,~~Financial Matters

During the third quarter of 2011, ~~JCP&L and Met-Ed~~FirstEnergy redeemed or repurchased ~~$500~~approximately $425.8 million ~~and $150 million, respectively,~~principal amount of ~~their equity from FirstEnergy to maintain an appropriate capital structure.~~

~~On June 1, 2011, FGCO repurchased $40~~PCRBs, as summarized in the following table. Approximately $28.5 million of ~~pollution control revenue bonds and is holding those bonds for future remarketing or refinancing.~~

On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated entities and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

~~On July 29, 2011,~~ FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 millionFMBs and $98.9 million ~~aggregate principal amount~~ of NGC FMBs ~~previously delivered~~associated with such PCRBs were returned for cancellation by the associated LOC providers.

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	Subsidiaries	Amount
		(In millions)
	AE Supply		$	53.0	^(a)
	FGCO		$	158.1	^(b)
	NGC		$	158.9	^(b)
	MP		$	70.2	^(a)
^(a)Includes $14.4 million in PCRBs redeemed for which MP and AE Supply are co-obligors.
^(b)Subject to market conditions, these bonds are being held for future remarketing.

~~Regulatory Matters~~

~~NYSEG Ruling~~

~~On July 11, 2011, FirstEnergy was found to be~~ a ~~potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York.~~third party. As a result, FirstEnergy ~~recognized additional expense~~entered into a new long-term contract with another supplier for replacement fuel based on current market prices. The new contract runs for nine years, which is the remaining term of ~~$29 million~~the assigned contract. The transaction reduced fuel costs during the ~~second~~ quarter ~~of 2011; $30~~by approximately $123 million ~~had previously been reserved prior to 2011.~~

~~Marginal transmission loss recovery~~.

On March 3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC’s order. On June 14, 2011, the Commonwealth Court affirmed the PPUC’s decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court’s decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the amounts at issue pending outcome of the court appeals.

FIRSTENERGY’S BUSINESS

With the completion of the Allegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment included FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other” ~~segment~~amounts consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.

The changes in FirstEnergy’s reportable segments during the first quarter of 2011 consisted primarily of the following:

AE Supply, an operator of generation facilities that was acquired as part of the merger with ~~Allegheny,~~AE, was placed into the Competitive Energy Services segment.

Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES and the ~~Utilities~~Utility Registrants do not have separate reportable operating segments.

The Regulated Independent Transmission segment transmits electricity through transmission lines. Its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving

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transmission-related revenues from ~~operation of~~operating a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.

This business segment controls approximately 20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.

~~The~~ Other and Reconciling Adjustments ~~segment~~ contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment as well as reconciling adjustments for the elimination of intersegment transactions.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. Results from the pre-merged companies have been segregated from the Allegheny companies for variance reporting and analysis. A reconciliation of segment financial results is provided in Note 1314 to the consolidated financial statements. Earnings available to FirstEnergy by business segment were as follows:

Three Months Ended Six Months Ended
June 30 June 30
Increase Increase
2011 2010 (Decrease) 2011 2010 (Decrease)
(In millions, except per share data)
Earnings (Loss) By Business Segment:

Regulated Distribution $ 184 $ 132 $ 52 $ 280 $ 235 $ 45
Competitive Energy Services 12 121 (109 ) 17 190 (173 )
Regulated Independent Transmission 31 11 20 44 23 21
Other and reconciling adjustments* (46 ) 1 (47 ) (110 ) (28 ) (82 )

Earnings available to FirstEnergy Corp. $ 181 $ 265 $ (84 ) $ 231 $ 420 $ (189 )

Basic Earnings Per Share
$ 0.43 $ 0.87 $ (0.44 ) $ 0.61 $ 1.38 $ (0.77 )
Diluted Earnings Per Share
$ 0.43 $ 0.87 $ (0.44 ) $ 0.61 $ 1.37 $ (0.76 )



	Three Months Ended September 30									Nine Months Ended September 30
	2011			2010			Increase (Decrease)			2011			2010			Increase (Decrease)
	(In millions, except per share data)
Earnings (Loss) By Business Segment:
Regulated Distribution	$	288		$	202		$	86		$	568		$	437		$	131
Competitive Energy Services	232			(26		)	258			249			164			85
Regulated Independent Transmission	34			22			12			78			45			33
Other and reconciling adjustments*	(43		)	(19		)	(24		)	(153		)	(47		)	(106		)
Earnings available to FirstEnergy Corp.	$	511		$	179		$	332		$	742		$	599		$	143

Basic Earnings Per Share	$	1.22		$	0.59		$	0.63		$	1.89		$	1.97		$	(0.08	)
Diluted Earnings Per Share	$	1.22		$	0.59		$	0.63		$	1.88		$	1.96		$	(0.08	)


*		Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

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Summary of Results of Operations — ~~Second~~Third Quarter 2011 Compared with ~~Second~~Third Quarter 2010

Financial results for FirstEnergy’s business segments in the ~~second~~third quarter of 2011 and 2010 were as follows:

Competitive Regulated Other and
Regulated Energy Independent Reconciling FirstEnergy
Second Quarter 2011 Financial Results Distribution Services Transmission Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 2,352 $ 1,394 $ — $ — $ 3,746
Other 133 101 105 (37 ) 302
Internal — 318 — (306 ) 12

Total Revenues 2,485 1,813 105 (343 ) 4,060

Expenses:
Fuel 73 562 — — 635
Purchased power 1,144 382 — (306 ) 1,220
Other operating expenses 438 640 19 8 1,105
Provision for depreciation 153 107 15 7 282
Amortization of regulatory assets 87 — 3 — 90
General taxes 180 51 8 3 242

Total Expenses 2,075 1,742 45 (288 ) 3,574

Operating Income 410 71 60 (55 ) 486

Other Income (Expense):
Investment income 27 15 — (11 ) 31
Interest expense (148 ) (79 ) (12 ) (26 ) (265 )
Capitalized interest 3 12 1 4 20

Total Other Expense (118 ) (52 ) (11 ) (33 ) (214 )

Income Before Income Taxes 292 19 49 (88 ) 272
Income taxes 108 7 18 (32 ) 101

Net Income (Loss) 184 12 31 (56 ) 171
Loss attributable to noncontrolling interest — — — (10 ) (10 )

Earnings (loss) available to FirstEnergy Corp. $ 184 $ 12 $ 31 $ (46 ) $ 181



Third Quarter 2011 Financial Results	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,809		$	1,611		$	—		$	—		$	4,420
Other	125			103			106			(48		)	286
Internal	1			315			—			(303		)	13
Total Revenues	2,935			2,029			106			(351		)	4,719

Operating Expenses:
Fuel	92			540			—			—			632
Purchased power	1,293			362			—			(306		)	1,349
Other operating expenses	498			540			15			(29		)	1,024
Provision for depreciation	159			110			17			6			292
Amortization of regulatory assets	123			—			(1		)	—			122
General taxes	200			55			9			5			269
Impairment of long-lived assets	—			9			—			—			9
Total Operating Expenses	2,365			1,616			40			(324		)	3,697

Operating Income	570			413			66			(27		)	1,022
Other Income (Expense):
Investment income	32			28			—			(12		)	48
Interest expense	(147		)	(82		)	(13		)	(25		)	(267		)
Capitalized interest	3			9			1			4			17
Total Other Expense	(112		)	(45		)	(12		)	(33		)	(202		)

Income Before Income Taxes	458			368			54			(60		)	820
Income taxes	170			136			20			(15		)	311
Net Income (Loss)	288			232			34			(45		)	509
Loss attributable to noncontrolling interest	—			—			—			(2		)	(2		)
Earnings Available to FirstEnergy Corp.	$	288		$	232		$	34		$	(43	)	$	511

Competitive Regulated Other and
Regulated Energy Independent Reconciling FirstEnergy
Second Quarter 2010 Financial Results Distribution Services Transmission Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 2,243 $ 739 $ — $ — $ 2,982
Other 71 56 59 (29 ) 157
Internal 19 539 — (558 ) —

Total Revenues 2,333 1,334 59 (587 ) 3,139

Expenses:
Fuel — 350 — — 350
Purchased power 1,291 330 — (558 ) 1,063
Other operating expenses 331 340 16 (14 ) 673
Provision for depreciation 106 71 10 3 190
Amortization of regulatory assets 158 — 3 — 161
General taxes 138 27 7 4 176

Total Expenses 2,024 1,118 36 (565 ) 2,613

Operating Income 309 216 23 (22 ) 526

Other Income (Expense):
Investment income 28 13 — (10 ) 31
Interest expense (125 ) (57 ) (6 ) (19 ) (207 )
Capitalized interest 1 24 1 14 40

Total Other Expense (96 ) (20 ) (5 ) (15 ) (136 )

Income Before Income Taxes 213 196 18 (37 ) 390
Income taxes 81 75 7 (29 ) 134

Net Income (Loss) 132 121 11 (8 ) 256
Loss attributable to noncontrolling interest — — — (9 ) (9 )

Earnings available to FirstEnergy Corp. $ 132 $ 121 $ 11 $ 1 $ 265

Changes Between Second Quarter 2011 Competitive Regulated Other and
and Second Quarter 2010 Financial Regulated Energy Independent Reconciling FirstEnergy
Results Increase (Decrease) Distribution Services Transmission Adjustment Consolidated
(In millions)

Revenues:
External
Electric $ 109 $ 655 $ — $ — $ 764
Other 62 45 46 (8 ) 145
Internal (19 ) (221 ) — 252 12

Total Revenues 152 479 46 244 921

Expenses:
Fuel 73 212 — — 285
Purchased power (147 ) 52 — 252 157
Other operating expenses 107 300 3 22 432
Provision for depreciation 47 36 5 4 92
Amortization of regulatory assets (71 ) — — — (71 )
General taxes 42 24 1 (1 ) 66

Total Expenses 51 624 9 277 961

Operating Income 101 (145 ) 37 (33 ) (40 )

Other Income (Expense):
Investment income (1 ) 2 — (1 ) —
Interest expense (23 ) (22 ) (6 ) (7 ) (58 )
Capitalized interest 2 (12 ) — (10 ) (20 )

Total Other Expense (22 ) (32 ) (6 ) (18 ) (78 )

Income Before Income Taxes 79 (177 ) 31 (51 ) (118 )
Income taxes 27 (68 ) 11 (3 ) (33 )

Net Income 52 (109 ) 20 (48 ) (85 )
Loss attributable to noncontrolling interest — — — (1 ) (1 )

Earnings available to FirstEnergy Corp. $ 52 $ (109 ) $ 20 $ (47 ) $ (84 )

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Third Quarter 2010 Financial Results Regulated Distribution Competitive
Energy Services Regulated
Independent Transmission Other and
Reconciling Adjustments FirstEnergy Consolidated
(In millions)
Revenues:
External
Electric $ 2,609
$ 940
$ —
$ —
$ 3,549
Other 76
62
73
(32 ) 179
Internal 60
599
—
(659 ) —
Total Revenues 2,745
1,601
73
(691 ) 3,728

Operating Expenses:
Fuel —
400
—
—
400
Purchased power 1,473
505
—
(659 ) 1,319
Other operating expenses 400
345
15
(22 ) 738
Provision for depreciation 102
67
9
4
182
Amortization of regulatory assets 176
—
—
—
176
General taxes 167
28
8
3
206
Impairment of long-lived assets —
292
—
—
292
Total Operating Expenses 2,318
1,637
32
(674 ) 3,313

Operating Income 427
(36 ) 41
(17 ) 415
Other Income (Expense):
Investment income 24
27
—
(5 ) 46
Interest expense (125 ) (56 ) (6 ) (21 ) (208 )
Capitalized interest —
23
—
18
41
Total Other Expense (101 ) (6 ) (6 ) (8 ) (121 )

Income Before Income Taxes 326
(42 ) 35
(25 ) 294
Income taxes 124
(16 ) 13
(2 ) 119
Net Income (Loss) 202
(26 ) 22
(23 ) 175
Loss attributable to noncontrolling interest —
—
—
(4 ) (4 )
Earnings Available to FirstEnergy Corp. $ 202
$ (26 ) $ 22
$ (19 ) $ 179

92
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Changes Between Third Quarter 2011 and Third Quarter 2010 Financial Results
Increase (Decrease)
Regulated Distribution Competitive
Energy Services Regulated
Independent Transmission Other and
Reconciling Adjustments FirstEnergy Consolidated
(In millions)
Revenues:
External
Electric $ 200
$ 671
$ —
$ —
$ 871
Other 49
41
33
(16 ) 107
Internal (59 ) (284 ) —
356
13
Total Revenues 190
428
33
340
991

Operating Expenses:
Fuel 92
140
—
—
232
Purchased power (180 ) (143 ) —
353
30
Other operating expenses 98
195
—
(7 ) 286
Provision for depreciation 57
43
8
2
110
Amortization of regulatory assets (53 ) —
(1 ) —
(54 )
General taxes 33
27
1
2
63
Impairment of long-lived assets —
(283 ) —
—
(283 )
Total Operating Expenses 47
(21 ) 8
350
384

Operating Income 143
449
25
(10 ) 607
Other Income (Expense):
Investment income 8
1
—
(7 ) 2
Interest expense (22 ) (26 ) (7 ) (4 ) (59 )
Capitalized interest 3
(14 ) 1
(14 ) (24 )
Total Other Expense (11 ) (39 ) (6 ) (25 ) (81 )

Income Before Income Taxes 132
410
19
(35 ) 526
Income taxes 46
152
7
(13 ) 192
Net Income 86
258
12
(22 ) 334
Loss attributable to noncontrolling interest —
—
—
2
2
Earnings Available to FirstEnergy Corp. $ 86
$ 258
$ 12
$ (24 ) $ 332

Regulated Distribution — ~~Second~~Third Quarter 2011 Compared with ~~Second~~Third Quarter 2010

Net income increased by ~~$52~~$86 million in the ~~second~~third quarter of 2011 compared to the ~~second~~third quarter of 2010, primarily due to earnings from the Allegheny companies and increased operating margins from the pre-merger companies (FirstEnergy excluding the Allegheny Companies) as a result of reduced purchased power costs, partially offset by reduced revenues.

Revenues —

The increase in total revenues resulted from the following sources:

Three Months
Ended June 30 Increase
Revenues by Type of Service 2011 2010 (Decrease)
(In millions)
Pre-merger companies:
Distribution services $ 810 $ 851 $ (41 )

Generation sales:
Retail 747 1,097 (350 )
Wholesale 104 180 (76 )

Total generation sales 851 1,277 (426 )

Transmission 51 141 (90 )
Other 66 64 2

Total pre-merger companies 1,778 2,333 (555 )

Allegheny companies 707 — 707

Total Revenues $ 2,485 $ 2,333 $ 152

93

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	Three Months Ended September 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Pre-merger companies:
Distribution services	$	963	$	1,041	$	(78	)
Generation sales:
Retail	951		1,267		(316		)
Wholesale	99		171		(72		)
Total generation sales	1,050		1,438		(388		)
Transmission	95		155		(60		)
Other	59		111		(52		)
Total pre-merger companies	2,167		2,745		(578		)
Allegheny companies	768		-		768
Total Revenues	$	2,935	$	2,745	$	190

The decrease in distribution service revenues for the pre-merger companies primarily reflects lower transition revenues due to the completion of transition cost recovery for CEI in December 2010, and an NJBPU-approved rate adjustment that became effective March 1, 2011, for all of JCP&L's customer classes, partially offset by increased rates associated with the recovery of deferred distribution ~~costs.~~costs and increased KWH deliveries. Distribution deliveries (excluding the Allegheny companies) ~~decreased~~increased by ~~1.1%~~2.1% in the ~~second~~third quarter of 2011 from the ~~second~~third quarter of ~~2010.~~2010. The change in distribution deliveries by customer class is summarized in the following table:

Increase
Electric Distribution KWH Deliveries 2011 2010 (Decrease)
(in thousands)
Pre-merger companies:
Residential 8,623 8,663 (0.5 )%
Commercial 7,926 8,121 (2.4 )%
Industrial 8,798 8,846 (0.5 )%
Other 126 132 (4.5 )%

Total pre-merger companies 25,473 25,762 (1.1 )%

Allegheny companies 9,527 — —

Total Electric Distribution KWH Deliveries 35,000 25,762 35.9 %

~~Lower~~



	Three Months Ended September 30		Increase
Electric Distribution KWH Deliveries	2011	2010	(Decrease)
	(in thousands)
Pre-merger companies:
Residential	11,443	11,342	0.9	%
Commercial	8,967	9,034	(0.7	)%
Industrial	9,532	8,954	6.4	%
Other	128	130	(1.7	)%
Total pre-merger companies	30,070	29,460	2.1	%
Allegheny companies	10,580
Total Electric Distribution KWH Deliveries	40,650	29,460	38.0	%

Higher deliveries to residential ~~and~~customers reflected increased load growth slightly offset by lower weather-related usage in the third quarter of 2011. Lower deliveries to commercial customers reflected decreased weather-related usage ~~in the second quarter of 2011 as cooling degree days decreased by 17.3% from~~compared to the same period in 2010. While cooling degree days were 29% above normal, they were 2% below 2010 ~~and soft economic conditions affecting the commercial sector.~~levels. In the industrial sector, KWH deliveries ~~decreased by 4% to automotive customers, partially offset by~~ increased ~~deliveries~~ to steel and electrical equipment customers by 9% and 11%, respectively, partially offset by decreased deliveries to automotive customers of ~~11% and 15%, respectively.~~3%.

The following table summarizes the price and volume factors contributing to the ~~$426~~$388 milliondecrease in generation revenues for the pre-merger companies in the ~~second~~third quarter of 2011 compared to the ~~second~~third quarter of ~~2010:~~2010:

Increase
Source of Change in Generation Revenues (Decrease)
(In millions)

Retail:
Effect of decrease in sales volumes $ (447 )
Change in prices 96

(351 )

Wholesale:
Effect of decrease in sales volumes (8 )
Change in prices (67 )

(75 )

Net Decrease in Generation Revenues $ (426 )

94

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	Increase
Source of Change in Generation Revenues	(Decrease)
	(In millions)

Retail:
Effect of decrease in sales volumes	$	(451	)
Change in prices	136
	(315		)
Wholesale:
Effect of decrease in sales volumes	(43		)
Change in prices	(30		)
	(73		)
Net Decrease in Generation Revenues	$	(388	)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the service territories of the pre-merger companies in the ~~second~~third quarter of 2011, compared with the ~~second~~third quarter of ~~2010.~~2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to ~~77%~~78% from ~~61%~~64% for the Ohio ~~companies~~Companies and to ~~55%~~54% from 10% for Met-Ed’s, Penelec’s and ~~Penelec’s~~Penn's service areas.

The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased ~~$90~~ $60million primarily due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.

The Allegheny companies added ~~$707~~$768 million ofto revenues ~~for~~in the ~~second~~third quarter of 2011, including ~~$155~~$184 million for distribution services, ~~$486~~ $519million ~~for~~from generation sales and ~~$66~~$65 million ~~relating to~~of transmission revenues.

Operating Expenses —

Total operating expenses increased by ~~$51~~$47 million due to the following:

Purchased power costs, excluding the Allegheny companies, were ~~$483~~$529 millionlower in the ~~second~~third quarter of 2011 due primarily to a decrease in volumes required. Decreased power purchased from FES reflected the increase in customer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $349 million in purchased power costs in the third quarter of 2011.



	Increase
Source of Change in Purchased Power	(Decrease)
	(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs	$	(226	)
Change due to increased volumes	125
	(101		)
Purchases from FES:
Change due to increased unit costs	27
Change due to decreased volumes	(436		)
	(409		)
Increase in costs deferred	(19		)
Total pre-merger companies	(529		)
Purchases by Allegheny companies	349
Net Decrease in Purchased Power Costs	$	(180	)

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Transmission expenses decreased $77 million primarily due to congestion costs for Met-Ed and Penelec in the third quarter of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.

Energy Efficiency program costs, which are also recovered through rates, increased by $15 million.

Hurricane Irene storm restoration maintenance expenses primarily impacting JCP&L and Met-Ed totaled $53 million in the third quarter of 2011, of which $50 million was deferred for future recovery from customers.

Merger-related costs increased $3 million in the third quarter of 2011 compared to the same period of 2010.

The inclusion of Allegheny Energy resulted in the following expenses in the third quarter of 2011:



Allegheny Expenses	In Millions

Purchased power	$	349
Fuel	92
Transmission	38
Amortization of regulatory assets, net	(2		)
Other	81
General taxes	39
Depreciation expense	48
Total Operating Expenses	$	645

Other Expense —

Other expense increased $11 million in the third quarter of 2011 due to interest expense on debt of the Allegheny companies partially offset by higher investment income on OE's and TE's nuclear decommissioning trusts.

Regulated Independent Transmission — Third Quarter 2011 Compared with Third Quarter 2010

Net income increased by $12 million in the third quarter of 2011 compared to the third quarter of 2010 due to earnings associated with TrAIL and PATH of $26 million, partially offset by decreased earnings for ATSI of $14 million.

Revenues —

Total revenues increased by $33 million principally due to revenues from TrAIL and PATH, partially offset by a decrease in ATSI revenues due to the transition from MISO to PJM and the completion of vegetation management cost recovery in May 2011.

Revenues by transmission asset owner are shown in the following table:



Revenues by	Three Months Ended September 30				Increase
Transmission Asset Owner	2011		2010		(Decrease)
	(In millions)
ATSI	$	49	$	73	$	(24	)
TrAIL	53		—		53
PATH	4		—		4
Total Revenues	$	106	$	73	$	33

Operating Expenses —

Total operating expenses increased by $8 million principally due to the addition of TrAIL and PATH in 2011.

Other Expense —

Other expense increased $6 million in the third quarter of 2011 due to additional interest expense associated with TrAIL.

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Competitive Energy Services — Third Quarter 2011 Compared with Third Quarter 2010

Net income increased by $258 million in the third quarter of 2011, compared to the third quarter of 2010, primarily due to last year's $292 million third quarter impairment charge ($181 million net of tax) related to operational changes at certain smaller coal-fired units. In addition, the current quarter experienced higher sales margins, partially offset by higher operation and maintenance expenses, non-core asset impairments and the effect of mark-to-market adjustments.

Revenues —

Total revenues increased by $428 million in the third quarter of 2011 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR and structured sales.

The increase in total revenues resulted from the following sources:



	Three Months Ended September 30					Increase
Revenues by Type of Service	2011			2010		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	1,071		$	717	$	354
POLR and Structured Sales	193			700		(507		)
Wholesale	131			123		8
Transmission	30			22		8
RECs	12			—		12
Other	49			39		10
Allegheny Companies	543			—		543
Total Revenues	$	2,029		$	1,601	$	428

Allegheny Companies
Direct and Governmental Aggregation	$	26
POLR and Structured Sales	165
Wholesale	330
Transmission	26
Other	(4		)
Total Revenues	$	543



	Three Months Ended September 30		Increase
MWH Sales by Type of Service	2011	2010	(Decrease)
	(In thousands)
Direct	12,675	7,817	62.1	%
Governmental Aggregation	5,195	3,791	37.0	%
POLR and Structured Sales	3,228	13,367	(75.9	)%
Wholesale	1,334	1,743	(23.5	)%
Allegheny Companies	8,930	—	—
Total Sales	31,362	26,718	17.4	%

Allegheny Companies
Direct	413
POLR	2,603
Structured Sales	179
Wholesale	5,735
Total Sales	8,930

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The increase in direct and governmental aggregation revenues of $354 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio and Illinois that provided generation to approximately 1.7 million residential and small commercial customers at the end of September 2011 compared to approximately 1.2 million at the end of September 2010. Partially offsetting this increase, sales to residential and small commercial customers were adversely affected by weather that was 2% cooler this year in the markets served than in 2010.

The decrease in POLR and structured revenues of $507 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by higher unit prices to the Pennsylvania Companies. This decline in POLR and structured sales is the result of FES no longer having the responsibility to supply these default service requirements and is consistent with our business strategy to selectively participate in POLR auctions.

Wholesale revenues increased $8 million due to higher prices in the wholesale market, partially offset by reduced generation available for sale.

The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):



	Increase
Source of Change in Direct and Governmental Aggregation	(Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	282
Change in prices	(22		)
	260
Governmental Aggregation:
Effect of increase in sales volumes	97
Change in prices	(3		)
	94
Net Increase in Direct and Governmental Aggregation Revenues	$	354



	Increase
Source of Change in POLR and Structured Revenues	(Decrease)
	(In millions)
POLR:
Effect of decrease in sales volumes	$	(530	)
Change in prices	23
	$	(507	)



	Increase
Source of Change in Wholesale Revenues	(Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(29	)
Change in prices	37
	$	8

Transmission revenues increased by $8 million primarily due to higher PJM congestion revenue. The revenues derived from the sale of RECs increased $12 million in the third quarter of 2011.

Operating Expenses —

Total operating expenses decreased by $21 million in the third quarter of 2011 due to the following:

Purchased power costs, excluding the Allegheny companies, decreased $177 million as lower volumes ($237 million) were partially offset by higher unit prices ($60 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec that FES no longer has the requirement to

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serve.

Fuel costs in the third quarter of 2011 were $129 million below the third quarter of 2010, principally reflecting cash received from assigning a substantially below-market, long-term fossil fuel contract to a third party. In connection with its merger integration initiatives and risk management strategy, FirstEnergy continues to evaluate opportunities with respect to its commodity contracts. As a result of the assignment, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices.

Fossil operating costs increased by $6 million and nuclear operating costs by $16 million due primarily to higher labor, contractor and materials and equipment costs resulting from an increase in planned and unplanned outages.

Transmission expenses increased $40 million due primarily to increases in PJM of $133 million from higher congestion, network and line loss costs, partially offset by lower MISO transmission expenses of $93 million due to lower congestion, network, and line loss costs.

General taxes increased by $14 million due to an increase in revenue-related taxes.

Depreciation expense increased $9 million due to property additions since the third quarter of 2010.

Impairments of long-lived assets decreased $283 million principally due to an impairment charge of $292 million related to operational changes at certain smaller, coal-fired units that was recorded in the third quarter of 2010.

Other operating expenses increased by $23 million primarily due to higher mark-to-market adjustments ($26 million).

The inclusion of the Allegheny companies’ operations contributed $460 million to operating expenses, including a $7 million mark-to-market adjustment relating primarily to power contracts, as shown in the following table:




Source of Operating Expense (Credit)
	(In millions)
Allegheny companies
Fuel	$	269
Purchased power	34
Fossil generation	36
Transmission	69
Mark-to-Market	(7		)
General taxes	13
Other	12
Depreciation	34
Total Operating Expense	$	460

Other Expense —

Total other expense in the third quarter of 2011 was $39 million higher than the third quarter of 2010, primarily due to an increase in net interest expense. The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($23 million) and lower capitalized interest ($14 million) associated with the completion of the Sammis AQC project in 2010.

Other — Third Quarter of 2011 Compared with Third Quarter of 2010

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Summary of Results of Operations — First Nine Months of 2011 Compared with the First Nine Months of 2010

Financial results for FirstEnergy’s business segments in the first nine months of 2011 and 2010 were as follows:



First Nine Months 2011 Financial Results	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	7,336		$	4,167		$	—		$	—		$	11,503
Other	351			283			278			(117		)	795
Internal	1			976			—			(920		)	57
Total Revenues	7,688			5,426			278			(1,037		)	12,355

Operating Expenses:
Fuel	189			1,531			—			—			1,720
Purchased power	3,616			1,062			—			(923		)	3,755
Other operating expenses	1,322			1,807			51			(50		)	3,130
Provision for depreciation	428			305			42			19			794
Amortization of regulatory assets	339			—			5			—			344
General taxes	556			150			25			17			748
Impairment of long-lived assets	—			30			—			11			41
Total Operating Expenses	6,450			4,885			123			(926		)	10,532

Operating Income	1,238			541			155			(111		)	1,823
Other Income (Expense):
Investment income	84			49			—			(33		)	100
Interest expense	(427		)	(226		)	(34		)	(76		)	(763		)
Capitalized interest	7			31			2			15			55
Total Other Expense	(336		)	(146		)	(32		)	(94		)	(608		)

Income Before Income Taxes	902			395			123			(205		)	1,215
Income taxes	334			146			45			(35		)	490
Net Income	568			249			78			(170		)	725
Loss attributable to noncontrolling interest	—			—			—			(17		)	(17		)
Earnings Available to FirstEnergy Corp.	$	568		$	249		$	78		$	(153	)	$	742

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First Nine Months 2010 Financial Results	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	7,250		$	2,348		$	—		$	—		$	9,598
Other	233			170			189			(89		)	503
Internal	79			1,812			—			(1,824		)	67
Total Revenues	7,562			4,330			189			(1,913		)	10,168

Operating Expenses:
Fuel	—			1,084			—			—			1,084
Purchased power	4,159			1,285			—			(1,824		)	3,620
Other operating expenses	1,090			1,037			45			(60		)	2,112
Provision for depreciation	312			215			28			10			565
Amortization of regulatory assets	543			—			6			—			549
General taxes	459			92			22			14			587
Impairment of long-lived assets	—			294			—			—			294
Total Operating Expenses	6,563			4,007			101			(1,860		)	8,811

Operating Income	999			323			88			(53		)	1,357
Other Income (Expense):
Investment income	78			41			—			(26		)	93
Interest expense	(375		)	(169		)	(17		)	(67		)	(628		)
Capitalized interest	2			70			1			49			122
Total Other Expense	(295		)	(58		)	(16		)	(44		)	(413		)

Income Before Income Taxes	704			265			72			(97		)	944
Income taxes	267			101			27			(31		)	364
Net Income	437			164			45			(66		)	580
Loss attributable to noncontrolling interest	—			—			—			(19		)	(19		)
Earnings Available to FirstEnergy Corp.	$	437		$	164		$	45		$	(47	)	$	599

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Changes Between First Nine Months 2011 and First Nine Months 2010 Financial Results Increase (Decrease)	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	86		$	1,819		$	—		$	—		$	1,905
Other	118			113			89			(28		)	292
Internal	(78		)	(836		)	—			904			(10		)
Total Revenues	126			1,096			89			876			2,187

Operating Expenses:
Fuel	189			447			—			—			636
Purchased power	(543		)	(223		)	—			901			135
Other operating expenses	232			770			6			10			1,018
Provision for depreciation	116			90			14			9			229
Amortization of regulatory assets	(204		)	—			(1		)	—			(205		)
General taxes	97			58			3			3			161
Impairment of long-lived assets	—			(264		)	—			11			(253		)
Total Operating Expenses	(113		)	878			22			934			1,721

Operating Income	239			218			67			(58		)	466
Other Income (Expense):
Investment income	6			8			—			(7		)	7
Interest expense	(52		)	(57		)	(17		)	(9		)	(135		)
Capitalized interest	5			(39		)	1			(34		)	(67		)
Total Other Expense	(41		)	(88		)	(16		)	(50		)	(195		)

Income Before Income Taxes	198			130			51			(108		)	271
Income taxes	67			45			18			(4		)	126
Net Income	131			85			33			(104		)	145
Loss attributable to noncontrolling interest	—			—			—			2			2
Earnings Available to FirstEnergy Corp.	$	131		$	85		$	33		$	(106	)	$	143

Regulated Distribution — First Nine Months of 2011 Compared to First Nine Months of 2010

Net income increased by $131 million in the first nine months of 2011, compared to the first nine months of 2010, primarily due to the absence of a $35 million regulatory asset impairment recorded in 2010 and the earnings contribution of the Allegheny companies, partially offset by the absence of a favorable property tax settlement in 2010.

Revenues —

The increase in total revenues resulted from the following sources:

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	Nine Months Ended September 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Pre-merger companies:
Distribution services	$	2,683	$	2,774	$	(91	)
Generation sales:
Retail	2,571		3,542		(971		)
Wholesale	319		568		(249		)
Total generation sales	2,890		4,110		(1,220		)
Transmission	182		453		(271		)
Other	180		225		(45		)
Total pre-merger companies	5,935		7,562		(1,627		)
Allegheny companies	1,753		-		1,753
Total Revenues	$	7,688	$	7,562	$	126

The decrease in distribution service revenues for the pre-merger companies primarily reflects lower transition revenues due to the completion of transition cost recovery for CEI in December 2010, and an NJBPU-approved rate adjustment that became effective March 1, 2011 for all of JCP&L's customer classes, partially offset by increased rates associated with the recovery of deferred distribution costs and increased KWH deliveries. Distribution deliveries (excluding the Allegheny companies) increased by 1.2% in the first nine months of 2011 from the same period in 2010. The change in distribution deliveries by customer class is summarized in the following table:



	Nine Months Ended September 30		Increase
Electric Distribution KWH Deliveries	2011	2010	(Decrease)
	(in thousands)
Pre-merger companies:
Residential	30,704	30,460	0.8	%
Commercial	24,822	25,108	(1.1	)%
Industrial	27,172	26,151	3.9	%
Other	383	392	(2.3	)%
Total pre-merger companies	83,081	82,111	1.2	%
Allegheny companies	23,648
Total Electric Distribution KWH Deliveries	106,729	82,111	30.0	%

Higher deliveries to residential customers reflected increased load growth slightly offset by lower weather-related usage for the first nine months of 2011. Lower deliveries to commercial customers reflected decreased weather-related usage compared to the same period in 2010. While cooling degree days were 29% above normal, they were 7% below 2010 levels. Industrial deliveries increased by 11% to steel, 15% to electrical equipment, and 6% to chemical customers, partially offset by lower sales to automotive customers and paper manufacturing customers of 2% and 6%, respectively.

The following table summarizes the price and volume factors contributing to the $1,220 milliondecrease in generation revenues in the first nine months of 2011 compared to the same period of 2010:

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	Increase
Source of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(1,277	)
Change in prices	306
	(971		)
Wholesale:
Effect of decrease in sales volumes	(54		)
Change in prices	(195		)
	(249		)
Net Decrease in Generation Revenues	$	(1,220	)

The decrease in retail generation sales volume was due to increased customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the first nine months of 2011 compared to the same period in 2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 76% from 60% for the Ohio Companies and to 50% from 9% for Met-Ed’s, Penelec’s and Penn's service areas.

The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased $271 million primarily due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.

The Allegheny companies added $1,753 million of revenues for the first nine months of 2011, including $401million for distribution services, $1,196 million from generation sales and $156 million of transmission revenues.

Operating Expenses —

Total operating expenses decreased by $113 million due to the following:

Purchased power costs, excluding the Allegheny companies, were $1,371 millionlower in the first nine months of 2011 due to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added ~~$336~~$828 million in to purchased power costs in the ~~second quarter~~first nine months of ~~2011.~~2011.

Increase
Source of Change in Purchased Power (Decrease)
(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs $ (161 )
Change due to increased volumes 88

(73 )

Purchases from FES:
Change due to increased unit costs 20
Change due to decreased volumes (398 )

(378 )

Increase in costs deferred (32 )

Total pre-merger companies (483 )

Purchases by Allegheny companies 336

Net Decrease in Purchased Power Costs $ (147 )



	Increase
Source of Change in Purchased Power	(Decrease)
	(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs	$	(591	)
Change due to increased volumes	403
	(188		)
Purchases from FES:
Change due to increased unit costs	99
Change due to decreased volumes	(1,246		)
	(1,147		)
Increase in costs deferred	(36		)
Total pre-merger companies	(1,371		)
Purchases by Allegheny companies	828
Net Decrease in Purchased Power Costs	$	(543	)

104

Table of Contents

Transmission expenses decreased ~~$29~~$254 million primarily due to lower PJM network transmission expenses ~~and congestion costs of $70 million~~ for Met-Ed and Penelec ~~partially offset by transmission expenses for the Allegheny companies of $41 million~~ in the ~~second quarter~~first nine months of ~~2011.~~2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.

Energy ~~Efficiency~~efficiency program costs, which are also recovered through rates, increased ~~by $43~~$77 million.

The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of ~~2010.~~

~~Net amortization of regulatory assets decreased $71 million due primarily to reduced transition cost recovery and increased deferral of energy efficiency program costs.~~

	•		~~Fuel expenses for MP were $73 million in the second quarter of 2011.~~

	•		~~Operating expenses for the Allegheny companies were $95 million in the second quarter of 2011.~~

	•		~~Depreciation expense for the Allegheny companies was $48 million in the second quarter of 2011.~~

~~Merger-related costs increased $4 million in the second quarter of 2011 compared to the same period of 2010.~~

~~General taxes increased $42 million primarily due to property taxes and gross receipts taxes incurred by the Allegheny companies in the second quarter of 2011.~~

~~Other Expense —~~

~~Other expense increased $22 million in the second quarter of 2011 due to interest expense on debt of the Allegheny companies.~~

~~Regulated Independent Transmission — Second Quarter 2011 Compared with Second Quarter~~ 2010

Net income increased by $20 million in the second quarter of 2011 compared to the second quarter of 2010 due to earnings associated with TrAIL and PATH ($22 million), partially offset by decreased earnings for ATSI ($1 million).

~~Revenues —~~

~~Revenues by transmission asset owner are shown in the following table:~~

Three Months
Revenues by Ended June 30 Increase
Transmission Asset Owner 2011 2010 (Decrease)
(In millions)
ATSI $ 54 $ 59 $ (5 )
TrAIL 46 — 46
PATH 5 — 5

Total Revenues $ 105 $ 59 $ 46

~~Expenses —~~

~~Total expenses increased by $9 million principally due to TrAIL and PATH operating expenses.~~

~~Other Expense —~~

~~Other expense increased $6 million in the second quarter of 2011 due to additional interest expense associated with TrAIL.~~

~~Competitive Energy Services — Second Quarter 2011 Compared with Second Quarter 2010~~

Net income decreased by $109 million in the second quarter of 2011, compared to the second quarter of 2010, primarily due to reduced sales margins, non-core asset impairments and the effect of mark-to-market adjustments.

~~Revenues —~~

Total revenues increased by $479 million in the second quarter of 2011 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR sales.

~~The increase in total revenues resulted from the following sources:~~

Three Months
Ended June 30 Increase
Revenues by Type of Service 2011 2010 (Decrease)
(In millions)
Direct and Governmental Aggregation $ 925 $ 586 $ 339
POLR and Structured Sales 231 615 (384 )
Wholesale 66 77 (11 )
Transmission 30 19 11
RECs 12 — 12
Other 38 37 1
Allegheny Companies 511 — 511

Total Revenues
$ 1,813 $ 1,334 $ 479

Allegheny Companies

Direct and Governmental Aggregation $ 26
POLR and Structured Sales 185
Wholesale 267
Transmission 32
Other 1

Total Revenues
$ 511

Three Months
Ended June 30 Increase
MWH Sales by Type of Service 2011 2010 (Decrease)
(In thousands)
Direct 11,547 7,004 64.9 %
Governmental Aggregation 3,970 2,715 46.2 %
POLR and Structured Sales 3,718 11,600 (67.9 )%
Wholesale 395 1,108 (64.4 )%
Allegheny Companies 8,051 — —

Total Sales
27,681 22,427 23.4 %

Allegheny Companies

Direct 425
POLR 2,169
Structured Sales 846
Wholesale 4,611

Total Sales
8,051

The increase in direct and governmental aggregation revenues of $339 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio, providing generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million at the end of June 2010. Partially offsetting the increase, were sales to residential and small commercial customers that were adversely affected by weather in the market served that was 17% cooler than in 2010.

The decrease in POLR revenues of $384 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for direct retail and aggregation sales.

~~Wholesale revenues decreased $11 million due to reduced generation available for sale in the wholesale market.~~

~~The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):~~

Increase
Source of Change in Direct and Governmental Aggregation (Decrease)
(In millions)
Direct Sales:
Effect of increase in sales volumes $ 267
Change in prices (13 )

254

Governmental Aggregation:
Effect of increase in sales volumes 80
Change in prices 5

85

Net Increase in Direct and Governmental Aggregation Revenues $ 339

Increase
Source of Change in POLR and Structured Revenues (Decrease)
(In millions)
POLR:
Effect of decrease in sales volumes $ (418 )
Change in prices 34

(384 )


	~~Increase~~
~~Source of Change in Wholesale Revenues~~	~~(Decrease)~~
	*~~(In millions)~~*
~~Wholesale:~~
~~Effect of decrease in sales volumes~~		~~(49~~	)
~~Change in prices~~		38

		~~(11~~	)

~~Transmission revenues increased by $11 million due primarily to higher PJM congestion revenue. The revenues derived from the sale of RECs increased $12 million in the second quarter of 2011.~~

~~Expenses —~~

~~Total expenses increased by $624 million in the second quarter of 2011 due to the following:~~

Fuel costs decreased by $27 million primarily due to decreased volumes ($56 million), partially offset by higher unit prices ($29 million). Volumes decreased due to lower generation at the fossil units. Higher unit prices reflect increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.

Purchased power costs were unchanged as higher unit costs ($70 million) were offset by lower volumes purchased ($70 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.

Fossil operating costs increased by $18 million due primarily to higher labor, contractor and materials and equipment costs due to in increase in outages, both planned and unplanned, from the previous year.

Nuclear operating costs increased by $33 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.

Transmission expenses increased by $66 million due primarily to increases in PJM of $91 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $25 million due to lower network and line loss costs.

~~General taxes increased by $10 million due to an increase in revenue-related taxes.~~

Other expenses increased by $36 million primarily due to: a $14 million mark-to-market adjustment; a $7 million impairment charge related to non-core assets; and an $8 million increase in intercompany billings. The intercompany billings increased due to merger related costs and increased intersegment billings for leasehold costs from the Ohio Companies.

~~The inclusion of the Allegheny companies’ operations contributed $488 million to expenses, including a $9 million mark-to-market adjustment relating primarily to power contracts.~~

~~Other Expense —~~

Total other expense in the second quarter of 2011 was $32 million higher than the second quarter of 2010, primarily due to a $34 million increase in net interest expense partially offset by an increase in investment income ($2 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($22 million) and lower capitalized interest ($12 million) associated with the completion of the Sammis AQC project in 2010.

Increase
Source of Expense Changes (Decrease)
(In millions)

Allegheny Companies

Fuel $ 238
Purchased power 53
Fossil 55
Transmission 75
Mark-to-Market 9
General taxes 11
Other 15
Depreciation 32

Total Expense $ 488

~~Other — Second Quarter of 2011 Compared with Second Quarter of 2010~~

~~Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses,~~ resulted in a $47 million decrease in earnings available to FirstEnergy in the second quarter of 2011 compared to the same period in 2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($29 million), decreased capitalized interest ($10 million) resulting from completed construction projects and increased interest expense due to the 2010 termination of interest rate swap agreements ($7 million).

~~Summary of Results of Operations — First Six Months of 2011 Compared with the First Six Months of 2010~~

~~Financial results for FirstEnergy’s business segments in the first six months of 2011 and 2010 were as follows:~~

Competitive Regulated Other and
Regulated Energy Independent Reconciling FirstEnergy
First Six Months 2011 Financial Results Distribution Services Transmission Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 4,527 $ 2,556 $ — $ — $ 7,083
Other 226 180 172 (69 ) 509
Internal — 661 — (617 ) 44

Total Revenues 4,753 3,397 172 (686 ) 7,636

Expenses:
Fuel 97 991 — — 1,088
Purchased power 2,323 700 — (617 ) 2,406
Other operating expenses 824 1,288 36 (10 ) 2,138
Provision for depreciation 269 195 25 13 502
Amortization of regulatory assets 216 — 6 — 222
General taxes 356 95 16 12 479

Total Expenses 4,085 3,269 83 (602 ) 6,835

Operating Income 668 128 89 (84 ) 801

Other Income (Expense):
Investment income 52 21 — (21 ) 52
Interest expense (280 ) (144 ) (21 ) (51 ) (496 )
Capitalized interest 4 22 1 11 38

Total Other Expense (224 ) (101 ) (20 ) (61 ) (406 )

Income Before Income Taxes 444 27 69 (145 ) 395
Income taxes 164 10 25 (20 ) 179

Net Income (Loss) 280 17 44 (125 ) 216
Loss attributable to noncontrolling interest — — — (15 ) (15 )

Earnings available to FirstEnergy Corp. $ 280 $ 17 $ 44 $ (110 ) $ 231

Competitive Regulated Other and
Regulated Energy Independent Reconciling FirstEnergy
First Six Months 2010 Financial Results Distribution Services Transmission Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 4,641 $ 1,408 $ — $ — $ 6,049
Other 157 106 116 (57 ) 322
Internal 19 1,213 — (1,165 ) 67

Total Revenues 4,817 2,727 116 (1,222 ) 6,438

Expenses:
Fuel — 684 — — 684
Purchased power 2,686 780 — (1,165 ) 2,301
Other operating expenses 690 692 30 (38 ) 1,374
Provision for depreciation 210 148 19 6 383
Amortization of regulatory assets 367 — 6 — 373
General taxes 292 64 14 11 381

Total Expenses 4,245 2,368 69 (1,186 ) 5,496

Operating Income 572 359 47 (36 ) 942

Other Income (Expense):
Investment income 54 14 — (21 ) 47
Interest expense (250 ) (113 ) (11 ) (46 ) (420 )
Capitalized interest 2 47 1 31 81

Total Other Expense (194 ) (52 ) (10 ) (36 ) (292 )

Income Before Income Taxes 378 307 37 (72 ) 650
Income taxes 143 117 14 (29 ) 245

Net Income (Loss) 235 190 23 (43 ) 405
Loss attributable to noncontrolling interest — — — (15 ) (15 )

Earnings available to FirstEnergy Corp. $ 235 $ 190 $ 23 $ (28 ) $ 420

Changes Between First Six Months 2011 and Competitive Regulated Other and
First Six Months 2010 Financial Results Regulated Energy Independent Reconciling FirstEnergy
Increase (Decrease) Distribution Services Transmission Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ (114 ) $ 1,148 $ — $ — $ 1,034
Other 69 74 56 (12 ) 187
Internal (19 ) (552 ) — 548 (23 )

Total Revenues (64 ) 670 56 536 1,198

Expenses:
Fuel 97 307 — — 404
Purchased power (363 ) (80 ) — 548 105
Other operating expenses 134 596 6 28 764
Provision for depreciation 59 47 6 7 119
Amortization of regulatory assets (151 ) — — — (151 )
General taxes 64 31 2 1 98

Total Expenses (160 ) 901 14 584 1,339

Operating Income 96 (231 ) 42 (48 ) (141 )

Other Income (Expense):
Investment income (2 ) 7 — — 5
Interest expense (30 ) (31 ) (10 ) (5 ) (76 )
Capitalized interest 2 (25 ) — (20 ) (43 )

Total Other Expense (30 ) (49 ) (10 ) (25 ) (114 )

Income Before Income Taxes 66 (280 ) 32 (73 ) (255 )
Income taxes 21 (107 ) 11 9 (66 )

Net Income 45 (173 ) 21 (82 ) (189 )
Loss attributable to noncontrolling interest — — — — —

Earnings available to FirstEnergy Corp. $ 45 $ (173 ) $ 21 $ (82 ) $ (189 )

~~Regulated Distribution — First Six Months of 2011 Compared to First Six Months of 2010~~

Net income increased by $45 million in the first six months of 2011, compared to the first six months of 2010, primarily due to the absence of a $35 million regulatory asset impairment recorded in 2010 and the earnings contribution of the Allegheny companies, partially offset by a favorable property tax settlement recognized in 2010.

~~Revenues —~~

~~The decrease in total revenues resulted from the following sources:~~

Six Months
Ended June 30 Increase
Revenues by Type of Service 2011 2010 (Decrease)
(In millions)
Pre-merger companies:
Distribution services $ 1,719 $ 1,733 $ (14 )

Generation sales:
Retail 1,620 2,272 (652 )
Wholesale 220 397 (177 )

Total generation sales 1,840 2,669 (829 )

Transmission 88 299 (211 )
Other 123 116 7

Total pre-merger companies 3,770 4,817 (1,047 )
Allegheny companies 983 — 983

Total Revenues $ 4,753 $ 4,817 $ (64 )

~~The decrease in distribution service revenues for the pre-merger companies primarily reflects lower transition revenues due to the completion of transition~~comparative cost recovery for CEI in December 2010, partially offset by increased rates associated with the recovery of deferred distribution costs. Distribution deliveries (excluding the Allegheny companies) increased approximately 360,000 KWH (0.7%), primarily driven by an increase of 443,000 KWH (2.6%) in the industrial class. Distribution deliveries by customer class are summarized in the following table:

Increase
Electric Distribution KWH Deliveries 2011 2010 (Decrease)
(in thousands)
Pre-merger companies:
Residential 19,261 19,119 0.7 %
Commercial 15,855 16,074 (1.4 )%
Industrial 17,640 17,197 2.6 %
Other 256 262 (2.3 )%

Total pre-merger companies 53,012 52,652 0.7 %

Allegheny companies 13,068 — —

Total Electric Distribution KWH Deliveries 66,080 52,652 25.5 %

Lower distribution deliveries to commercial customers reflected soft economic conditions in this sector and decreased weather-related usage in the first six months of 2011 as cooling degree days were 17% below the same period in 2010. The increase in ~~distribution deliveries to industrial customers was~~2011.

Hurricane Irene storm restoration maintenance expenses primarily due to recovering economic conditions in the Utilities’ service territory compared to the first six months of 2010. Industrial deliveries increased by 12% to steel customers, 16% to electrical equipmentimpacting JCP&L and ~~component manufacturing customers and 10% to non-metallic mineral customers, partially offset by 2% lower sales to automotive customers.~~

~~The following table summarizes the price and volume factors contributing to the $829 million decrease in generation revenues in the first six months of 2011 compared to the same period of 2010:~~

Increase
Source of Change in Generation Revenues (Decrease)
(In millions)
Retail:
Effect of decrease in sales volumes $ (826 )
Change in prices 174

(652 )

Wholesale:
Effect of decrease in sales volumes (2 )
Change in prices (175 )

(177 )

Net Decrease in Generation Revenues $ (829 )

The decrease in retail generation sales volume was due to increased customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the first six months of 2011 compared to the same period in 2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 75% from 57% for the Ohio companies and to 48% from 9% for Met-Ed’s and Penelec’s service areas. The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed ~~and Penelec in the PJM market.~~

Transmission revenues decreased $211 million due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.

The Allegheny companies added $983 million of revenues for the first six months of 2011, including $216 million for distribution services, $676 million from generation sales and $91 million relating to transmission revenues.

~~Expenses —~~

~~Total expenses decreased by $160 million due to the following:~~

Purchased power costs, excluding the Allegheny companies, were $843 million lower in the first six months of 2011 due to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $481 million in purchased power costs in the first six months of 2011.

Increase
Source of Change in Purchased Power (Decrease)
(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs $ (356 )
Change due to increased volumes 277

(79 )

Purchases from FES:
Change due to increased unit costs 63
Change due to decreased volumes (809 )

(746 )

Increase in costs deferred (18 )

Total pre-merger companies (843 )

Purchases by Allegheny companies 481

Net Decrease in Purchased Power Costs $ (362 )

Transmission expenses decreased $124 million primarily due to lower PJM network transmission expenses and congestion costs of $177 million for Met-Ed and Penelec, partially offset by transmission expenses for the Allegheny companies oftotaled $53 million in the ~~first six months of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.~~

~~Energy efficiency program costs, which are also recovered through rates, increased $62 million.~~

~~The absence of a $7 million favorable JCP&L labor settlement that occurred in the second~~third quarter of ~~2010.~~

2011, of which $50 million was deferred for future recovery from customers.

A provision for excess and obsolete material of $13 million was recognized in the first ~~six~~nine months of 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.

Net amortization of regulatory assets decreased ~~$150~~$189 million primarily due to reduced net PJM transmission cost and transition cost recovery and the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio Companies' ESP on March 23, 2010, partially offset by increased energy efficiency cost ~~recovery.~~

recovery and future recovery for Hurricane Irene costs.

~~Fuel expenses for MP were $97~~Merger-related costs increased $56 million in the first ~~six~~nine months of ~~2011.~~

~~Operating expenses for the Allegheny companies were $131 million in the first six months of 2011.~~

~~Merger-related costs increased $46 million in the first six months of~~ 2011 compared to the same period of ~~2010.~~2010.

~~Depreciation expense for the Allegheny companies was $64 million.~~

General taxes increased by ~~$64~~$8 million primarily due to ~~taxes incurred by the Allegheny companies and~~ the absence of a favorable property tax settlement recognized in 2010.

The inclusion of Allegheny Energy resulted in the following expenses in 2011:

Allegheny Expense In Millions

Purchased power $ 828
Fuel 189
Transmission 91
Amortization or regulatory assets, net (15 )
Other 199
General taxes 89
Depreciation expense 112
Total Operating Expenses $ 1,493

Other Expense —

Other expense increased by ~~$30~~$41 million in the first ~~six~~nine months of 2011 primarily due to interest expense on debt of the Allegheny ~~companies.~~companies and lower investment income on OE's and TE's nuclear decommissioning trusts.

Regulated Independent Transmission — First ~~Six~~Nine Months2011 Compared with First ~~Six~~Nine Months2010

Net income increased by ~~$21~~$33 million in the first ~~six~~nine months of 2011 compared to the first ~~six~~nine months of 2010 due to earnings associated with TrAIL and PATH ~~($27 million),~~of $52 million, partially offset by decreased earnings for ATSI ~~($6 million).~~of $19 million.

~~100~~

Revenues —

Total revenues increased by $89 million principally due to revenues from TrAIL and PATH partially offset by a decrease in ATSI revenues primarily due to the transition from MISO to PJM and the completion of vegetation management cost recovery in May 2011.

Revenues by transmission asset owner are shown in the following table:

Six Months
Revenues by Ended June 30 Increase
Transmission Asset Owner 2011 2010 (Decrease)
(In millions)
ATSI $ 106 $ 116 $ (10 )
TrAIL 61 — 61
PATH 5 — 5

Total Revenues $ 172 $ 116 $ 56

105

Table of Contents

Revenues by Nine Months
Ended September 30 Increase
Transmission Asset Owner 2011 2010 (Decrease)
(In millions)
ATSI $ 155
$ 189
$ (34 )
TrAIL 114
—
114
PATH 9
—
9
Total Revenues $ 278
$ 189
$ 89

Operating Expenses —

Total operating expenses increased by ~~$14~~$22 million principally due to TrAIL and PATH operating expenses.

Other Expense —

Other expense increased ~~$10~~$16 million in the first ~~six~~nine months of 2011 due to interest expense associated with TrAIL.

Competitive Energy Services — First ~~Six~~Nine Months of 2011 Compared to First ~~Six~~Nine Months of 2010

Net income ~~decreased~~increased by ~~$173~~$85 million in the first ~~six~~nine months of 2011, compared to the first ~~six~~nine months of 2010, primarily due to ~~lower~~higher sales ~~margin,~~margins, that were partially offset by higher O&M expenses, an inventory reserve adjustment ~~non-core asset impairments~~ and the effect of mark-to-market adjustments. 2011 results were also impacted by the absence of a $292 million ($181 million net-of-tax) non-core impairment charge taken in the third quarter of 2010.

Revenues —

Total revenues increased ~~$670~~$1,096 million in the first ~~six~~nine months of 2011 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR and structured sales.

The increase in total revenues resulted from the following sources:

Six Months
Ended June 30 Increase
Revenues by Type of Service 2011 2010 (Decrease)
(In millions)
Direct and Governmental Aggregation $ 1,765 $ 1,097 $ 668
POLR and Structured Sales 607 1,315 (708 )
Wholesale 156 142 14
Transmission 56 36 20
RECs 44 67 (23 )
Other 79 70 9
Allegheny Companies 690 — 690

Total Revenues
$ 3,397 $ 2,727 $ 670

Allegheny Companies

Direct and Governmental Aggregation $ 34
POLR and Structured Sales 254
Wholesale 357
Transmission 44 ��
Other 1

Total Revenues
$ 690

~~101~~



	Nine Months Ended September 30					Increase
Revenues by Type of Service	2011			2010		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	2,836		$	1,814	$	1,022
POLR and Structured Sales	798			2,014		(1,216		)
Wholesale	288			265		23
Transmission	86			58		28
RECs	55			67		(12		)
Other	130			112		18
Allegheny Companies	1,233			—		1,233
Total Revenues	$	5,426		$	4,330	$	1,096

Allegheny Companies
Direct and Governmental Aggregation	$	60
POLR and Structured Sales	419
Wholesale	687
Transmission	70
Other	(3		)
Total Revenues	$	1,233

Six Months
Ended June 30 Increase
MWH Sales by Type of Service 2011 2010 (Decrease)
(In thousands)
Direct 21,219 12,857 65.0 %
Governmental Aggregation 8,279 5,447 52.0 %
POLR and Structured Sales 9,561 25,344 (62.3 )%
Wholesale 1,380 1,538 (10.3 )%
Allegheny Companies 10,687 — —

Total Sales
51,126 45,186 13.1 %

Allegheny Companies

Direct 570
POLR 2,981
Structured Sales 1,149
Wholesale 5,987

Total Sales
10,687

106

Table of Contents



	Nine Months Ended September 30		Increase
MWH Sales by Type of Service	2011	2010	(Decrease)
	(In thousands)
Direct	33,893	20,675	63.9	%
Governmental Aggregation	13,475	9,238	45.9	%
POLR and Structured Sales	12,789	38,711	(67.0	)%
Wholesale	2,714	3,281	(17.3	)%
Allegheny Companies	19,617
Total Sales	82,488	71,905	14.7	%

Allegheny Companies
Direct	983
POLR	5,584
Structured Sales	1,328
Wholesale	11,722
Total Sales	19,617

The increase in direct and governmental aggregation revenues of ~~$668~~$1,022 million resulted ~~from increased revenue~~ from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio and Illinois that provided generation to approximately ~~1.5~~1.7 million residential and small commercial customers at the end of ~~June~~September 2011 compared to approximately ~~1.1~~1.2 million customers at the end of ~~June~~September 2010.

The decrease in POLR revenues of ~~$708~~$1,216 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to ~~non-associated companies~~non-affiliates and higher unit prices to the Pennsylvania ~~Companies~~Companies. This decline in POLR and structured sales is the result of FES no longer having the responsibility to supply these default service requirements and is consistent with our business ~~strategy. Participation~~strategy to selectively participate in POLR ~~auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for our direct retail and aggregation sales.~~auctions.

Wholesale revenues increased by ~~$14~~$23 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by units that moved to PJM were partially offset by losses on financially settled sales.

The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):

Increase
Source of Change in Direct and Governmental Aggregation (Decrease)
(In millions)
Direct Sales:
Effect of increase in sales volumes $ 493
Change in prices (20 )

473

Governmental Aggregation:
Effect of increase in sales volumes 176
Change in prices 19

195

Net Increase in Direct and Governmental Aggregation Revenues $ 668

~~102~~



	Increase
Source of Change in Direct and Governmental Aggregation	(Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	775
Change in prices	(41		)
	734
Governmental Aggregation:
Effect of increase in sales volumes	276
Change in prices	12
	288
Net Increase in Direct and Governmental Aggregation Revenues	$	1,022

Increase
Source of Change in POLR Revenues (Decrease)
(In millions)
POLR:
Effect of decrease in sales volumes $ (819 )
Change in prices 111

(708 )


	~~Increase~~
~~Source of Change in Wholesale Revenues~~	~~(Decrease)~~
~~Wholesale:~~
~~Effect of decrease in sales volumes~~		~~(15~~	)
~~Change in prices~~		29

		14

107

Table of Contents



	Increase
Source of Change in POLR Revenues	(Decrease)
	(In millions)
POLR:
Effect of decrease in sales volumes	$	(1,349	)
Change in prices	133
	$	(1,216	)



	Increase
Source of Change in Wholesale Revenues	(Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(46	)
Change in prices	69
	$	23

Transmission revenues increased by ~~$20~~$28 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs declined ~~$23~~$12 million in the first ~~six~~nine months of 2011.

Operating Expenses —

Total operating expenses increased by ~~$901~~$878 million in the first ~~six~~nine months of 2011 due to the following:

Fuel costs decreased by $13 million primarily due to decreased volumes ($28 million), partially offset by higher unit prices ($15 million). Volumes decreased due to lower generation from the fossil units. Unit prices increased primarily due to increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.

Purchased power costs, excluding the Allegheny companies, decreased by ~~$154~~$331 million due primarily to lower volumes purchased ($~~248~~481 million) partially offset by higher unit costs ($94150 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and ~~Penelec.~~

Penelec that FES no longer has the requirement to serve.

Fuel costs decreased by $142 million principally reflecting cash received from assigning a substantially below-market long-term fossil fuel contract to a third party. In connection with its merger integration initiatives and risk management strategy, FirstEnergy continues to evaluate opportunities with respect to its commodity contracts. As a result of the assignment, FirstEnergy entered into a new long-term contract with another supplier for replacement fuel based on current market prices. Fuel costs also reflect the impacts of decreased volumes ($54 million), partially offset by higher unit prices due to increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.

Fossil operating costs increased by ~~$20~~$25 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.

Nuclear operating costs increased by ~~$48~~$64 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring ~~this year.~~in 2011. While Davis-Besse had a refueling outage ~~last year,~~in 2010, the work performed ~~during the second quarter of 2010~~ was largely capital-related.

Transmission expenses increased by ~~$176~~$216 million primarily due ~~primarily~~ to increases in PJM of ~~$198~~$332 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of ~~$22~~$116 million.

General taxes increased by ~~$12~~$30 million due to an increase in revenue-related taxes.

Depreciation expense increased $13 million due to increased property additions primarily related to AQC projects.

Impairments of long-lived assets decreased $264 million principally due an impairment charge of $292 million related to operational changes at certain smaller, coal-fired units that was recorded in the third quarter of 2010.

Other expenses increased by ~~$93~~$94 million primarily due to: a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger; a ~~$20~~$19 million ~~impairment charge related to non-core assets;~~increase in mark-to-market adjustments; a $3 million increase in professional and contractor costs and a $9$15 million increase in intercompany billings. ~~The intercompany~~Intercompany billings increased due to ~~merger related~~merger-related costs, ~~and increased~~partially offset by lower intersegment billings for leasehold costs from the Ohio Companies.

~~103~~

The inclusion of the Allegheny companies’ operations ~~contributed $719~~added $1,173 million to expenses, including a ~~$43~~$36 million mark-to-market adjustment relating primarily to power ~~contracts.~~contracts, as shown in the following table:

Increase
Source of Expense Changes (Decrease)
(In millions)
Allegheny Companies

Fuel $ 320
Purchased power 74
Fossil 82
Transmission 99
Mark-to-Market 43
General taxes 15
Other 43
Depreciation 43

Total Expense $ 719

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Source of Operating Expense
(In millions)
Allegheny Companies
Fuel $ 589
Purchased power 108
Fossil 118
Transmission 168
Mark-to-Market 36
General taxes 28
Other 49
Depreciation 77
Total Operating Expense $ 1,173

Other Expense —

Total other expense in the first ~~six~~nine months of 2011 was ~~$49~~$88 million higher than the first ~~six~~nine months of 2010, primarily due to a ~~$56~~$96 million increase in net interest expense, partially offset by an increase in nuclear decommissioning trust investment income ($78 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($3054 million) and lower capitalized interest ($2539 million) associated with the completion of the Sammis AQC project in 2010.

Other — First ~~Six~~Nine Months of 2011 Compared to First ~~Six~~Nine Months of 2010

Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in ~~an $82~~a $106 million decrease in earnings available to FirstEnergy in the first ~~six~~nine months of 2011 compared to the same period in ~~2010.~~2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($29 million), decreased capitalized interest and increased depreciation expense resulting from completed construction projects placed into service ($2743 million), decreased investment income ($7 million) and an asset impairment charge in the first quarter of 2011 ($1211 million) ~~and increased income taxes ($9 million)~~.

Regulatory Assets

FirstEnergy and the Utilities prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatoryRegulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides the balance of net regulatory assets by company as of ~~June~~September 30, 2011, and December 31, 2010, and changes during the ~~six~~nine months then ended:

June 30, December 31, Increase
Regulatory Assets 2011 2010 (Decrease)
(In millions)
OE $ 393 $ 400 $ (7 )
CEI 320 370 (50 )
TE 89 72 17
JCP&L 469 513 (44 )
Met-Ed 341 296 45
Penelec 222 163 59
Other* 348 12 336

Total $ 2,182 $ 1,826 $ 356



Regulatory Assets	September 30, 2011		December 31, 2010		Increase (Decrease)
	(In millions)
OE	$	343	$	400	$	(57	)
CEI	291		370		(79		)
TE	70		72		(2		)
JCP&L	461		513		(52		)
Met-Ed	372		296		76
Penelec	264		163		101
Other*	359		12		347
Total	$	2,160	$	1,826	$	334


*		2011 includes ~~$337~~$350 million related to the Allegheny companies.

~~104~~

The following tables provide information about the composition of net regulatory assets as of ~~June~~September 30, 2011 and December 31, 2010 and the changes during the ~~six months then ended:~~nine month period:

Amount of
Increase
(Decrease)
June 30, December 31, Increase Attributable
Regulatory Assets by Source 2011 2010 (Decrease) to AE
(In millions)
Regulatory transition costs $ 899 $ 770 $ 129 $ —
Customer receivables for future income taxes 502 326 176 160
Loss on reacquired debt 53 48 5 8
Employee postretirement benefits 11 16 (5 ) —
Nuclear decommissioning and spent fuel disposal costs (201 ) (184 ) (17 ) —
Asset removal costs (228 ) (237 ) 9 22
MISO/PJM transmission costs 292 184 108 76
Deferred generation costs 454 386 68 15
Distribution costs 284 426 (142 ) —
Other 116 91 25 56

Total $ 2,182 $ 1,826 $ 356 $ 337

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Regulatory Assets by Source	September 30, 2011			December 31, 2010			Increase (Decrease)			Amount of Increase Attributable to AE
	(In millions)
Regulatory transition costs	$	883		$	770		$	113		$	—
Customer receivables for future income taxes	513			326			187			165
Loss on reacquired debt	51			48			3			8
Employee postretirement benefits	9			16			(7		)	—
Nuclear decommissioning and spent fuel disposal costs	(203		)	(184		)	(19		)	—
Asset removal costs	(232		)	(237		)	5			26
Deferred transmission costs	313			184			129			87
Deferred generation costs	389			386			3			13
Deferred distribution costs	276			426			(150		)	—
Other	161			91			70			51
Total	$	2,160		$	1,826		$	334		$	350

FirstEnergy had ~~$385~~$377 million of net regulatory liabilities as of ~~June~~September 30, 2011, including ~~$376~~$367 million of net regulatory liabilities ~~acquired as part of the merger with AE~~attributable to Allegheny that are primarily related to ~~customer receivables for future income taxes and~~ asset removal costs.

Regulatory assets that do not earn a current return totaled approximately ~~$345~~$496 million as of ~~June~~September 30, 2011, of which ~~$138~~$126 million relates to purchase accounting fair value adjustments to corresponding liabilities that do not accrue interest.

Regulatory assets not earning a current return for Met-Ed and Penelec were $158 million and $139 million, respectively, and include certain regulatory transition costs and PJM transmission ~~costs of approximately $144 million and $34 million, respectively.~~costs. The regulatory transition costs are expected to be recovered by 2020.

Regulatory assets not earning a current return for JCP&L were $80 million and include certain storm damage costs and pension and postretirement benefits ~~of approximately $34 million~~ that are expected to be recovered by ~~2014.~~2021.

Regulatory assets not earning a current return for FirstEnergy’s other utility subsidiaries ~~include~~was $119 million and includes certain deferred generation and other costs ~~of approximately $133 million~~ that are expected to be recovered though 2026.

CAPITAL RESOURCES AND LIQUIDITY

As of ~~June~~September 30, 2011, FirstEnergy had ~~$476~~$291 million of cash and cash equivalents available to fund investments, operations and capital expenditures. In addition to internal sources to fund liquidity and capital requirements for 2011 and beyond, FirstEnergy may rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities.

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.

A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its capital ~~resource~~ requirements. To mitigate risk, FirstEnergy’s business strategy stresses financial discipline and a strong focus on execution. Major elements include the expectation of: adequate cash from operations, opportunities for favorable long-term earnings growth in the competitive generation markets, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital ~~expenditure~~spending program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend and a successful merger integration.

~~105~~

As of ~~June~~September 30, 2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to ~~the classification of certain variable interest rate PCRBs as~~ currently payable long-term debt, ~~and short-term borrowings. Currently payable long-term debt~~which, as of ~~June~~September 30, 2011, included the following (in millions):

Currently Payable Long-term Debt
PCRBs supported by bank LOCs⁽¹⁾
$ 949
AE Supply unsecured note 503
FirstEnergy Corp. unsecured note 250
FGCO and NGC unsecured PCRBs⁽¹⁾
136
WP unsecured note 80
NGC collateralized lease obligation bonds 59
Sinking fund requirements 50
Other notes 31

$ 2,058

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Currently Payable Long-term Debt	(In millions)
Met-Ed, Penelec, FGCO and NGC PCRBs supported by bank LOCs ⁽¹⁾	$	632
AE Supply unsecured note	503
FirstEnergy Corp. unsecured note	250
FGCO and NGC unsecured PCRBs ⁽¹⁾	243
WP unsecured note	80
NGC collateralized lease obligation bonds	59
Sinking fund requirements	52
Other notes	21
	$	1,840


⁽¹⁾		These PCRBs are classified as currently payable long-term debt solely because applicable Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.

Credit Facility Borrowings and Liquidity

FirstEnergy had ~~approximately $656 million and $700 million of~~no significant short-term borrowings as of ~~June~~September 30, 2011 and approximately $700 million as of December 31, 2010 ~~respectively.~~. FirstEnergy’s available liquidity as of ~~July 29,~~October 28, 2011, is summarized in the following table:

Available
Company Type Maturity Commitment Liquidity
(In millions)
FirstEnergy⁽¹⁾
Revolving June 2016 $ 2,000 $ 1,751
FES / AE Supply Revolving June 2016 2,500 2,449
TrAIL Revolving Jan. 2013 450 450
AGC Revolving Dec. 2013 50 —

Subtotal $ 5,000 $ 4,650
Cash — 586

Total $ 5,000 $ 5,236



Company	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy⁽¹⁾	Revolving	June 2016	$	2,000	$	1,951
FES / AE Supply	Revolving	June 2016	2,500		2,485
TrAIL	Revolving	Jan. 2013	450		450
AGC	Revolving	Dec. 2013	50		—
		Subtotal	$	5,000	$	4,886
		Cash	—		834
		Total	$	5,000	$	5,720


⁽¹⁾		FirstEnergy Corp. and regulated subsidiary borrowers.

During March 2011, the accounts receivable financing arrangements for OE, TE, Penelec and Met-Ed were terminated in favor of other sources of liquidity that were deemed more economical. In May 2011, AE terminated its $250 million credit facility. AE now participates in the unregulated money pool (see FirstEnergy Money Pools below).

Revolving Credit Facilities

~~On June 17, 2011,~~ FirstEnergy and certain of its subsidiaries ~~entered into~~participate in two ~~new~~ five-year syndicated revolving credit facilities with aggregate commitments of $4.5 billion ~~(New Facilities)~~(Facilities).

An aggregate amount of $2 billion is available to be borrowed under a syndicated revolving credit facility ~~(New FirstEnergy~~(FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the ~~New~~ FirstEnergy Facility are FirstEnergy, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec, PE and WP. An additional $2.5 billion is available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility ~~(New FES/AESupply Facility).~~

~~The New Facilities replaced a FirstEnergy $2.75 billion revolving credit facility, an~~ (FES/AE Supply $1 billion revolving credit facility, a MP $110 million revolving credit facility, a PE $150 million revolving credit facility and a WP $200 million revolving credit facility, all of which were terminated as of June 17, 2011. Initial borrowings under the New Facilities were used to pay off outstanding obligations under these prior revolving credit facilities.Facility).

Commitments under each of the ~~New~~ Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the ~~New~~ Facilities are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended.

Borrowings under each of the ~~New~~ Facilities are subject to acceleration upon the occurrence of events of default that each borrower considers usual and customary, including a cross-default for other indebtedness in excess of $100 million. Defaults by either FES or AE Supply or their respective subsidiaries under the ~~New~~ FES/~~AESupply~~AE Supply Facility or other indebtedness generally will not cross-default to FirstEnergy under the ~~New~~ FirstEnergy Facility.

~~106~~

The following table summarizes the borrowing sub-limits for each borrower under the ~~facilities,~~Facilities, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of ~~June~~September 30, ~~2011:~~2011:

New Revolving Regulatory and
Credit Facility Other Short-Term
Borrower Sub-Limit Debt Limitations
(In millions)
FirstEnergy $ 2,000 — ^(a)
FES $ 1,500 — ^(b)
AE Supply $ 1,000 — ^(b)
OE $ 500 $ 500
CEI $ 500 $ 500
TE $ 500 $ 500
JCP&L $ 425 $ 411 ^(c)
Met-Ed $ 300 $ 300 ^(c)
Penelec $ 300 $ 300 ^(c)
West Penn $ 200 $ 200 ^(c)
MP $ 150 $ 150 ^(c)
PE $ 150 $ 150 ^(c)
ATSI $ 100 $ 100
Penn $ 50 $ 33 ^(c)

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Borrower	Revolving Credit Facility Sub-Limit			Regulatory and Other Short-Term Debt Limitations
	(In millions)
FirstEnergy		$	2,000		—		^(a)
FES		$	1,500		—		^(b)
AE Supply		$	1,000		—		^(b)
OE		$	500		$	500
CEI		$	500		$	500
TE		$	500		$	500
JCP&L		$	425		$	411	^(c)
Met-Ed		$	300		$	300	^(c)
Penelec		$	300		$	300	^(c)
West Penn		$	200		$	200	^(c)
MP		$	150		$	150	^(c)
PE		$	150		$	150	^(c)
ATSI		$	100		$	100
Penn		$	50		$	33	^(c)


^(a)		No limitations.


^(b)		No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.


^(c)		Excluding amounts which may be borrowed under the regulated companies’ money pool.

The entire amount of the ~~New~~ FES/AE Supply Facility and $700 million of the ~~New~~ FirstEnergy Facility, subject to each borrower’s sub-limit, is available for the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the ~~New~~ Facilities and against the applicable borrower’s borrowing sub-limit.

Each of the ~~New~~ Facilities contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of ~~June~~September 30, 2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the ~~New~~ Facilities) were as follows:



Borrower
FirstEnergy	~~56.9~~55.1	%
FES	~~54.1~~48.2	%
OE	~~56.2~~54.7	%
Penn	~~34.4~~36.1	%
CEI	~~56.3~~55.8	%
TE	~~58.4~~57.4	%
JCP&L	~~43.9~~41.7	%
Met-Ed	~~53.5~~52.5	%
Penelec	~~55.5~~54.0	%
ATSI	~~54.9~~54.3	%
MP	~~59.3~~54.8	%
PE	~~60.1~~57.1	%
WP	~~53.9~~49.9	%
AE Supply	~~39.4~~38.4	%

As of ~~June~~September 30, 2011, FirstEnergy could issue additional debt of approximately ~~$7.8~~$9.1 billion, or recognize a reduction in equity of approximately ~~$4.2~~$4.9 billion, and remain within the limitations of the financial covenants required by its credit facility.

~~107~~

The ~~New~~ Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the ~~facilities~~Facilities are related to the credit ratings of the company borrowing the funds.

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Table of Contents

In addition to the ~~New~~ Facilities, FirstEnergy also has ~~access to~~established an additional $500 million of revolving credit facilities ~~relating~~that are available to ~~the Allegheny companies (TrAIL — $450 million~~TrAIL ($450 million) and AGC ~~$50~~($50 million). until January 2013 and December 2013, respectively.

Under the terms of its credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed ~~70% and~~ 65% of the sum of its debt and equity as of the last day of each calendar quarter through ~~June 30, 2011 and~~ December 31, ~~2012, respectively.~~2012. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE. As of September 30, 2011, the debt to total capitalization ratios for TrAIL and AGC (as defined under each of their credit facilities) were 38% and 50%, respectively.

As of September 30, 2011, TrAIL could issue additional debt of approximately $330 million, or recognize a reduction in equity of approximately $510 million and AGC could issue additional debt of approximately $40 million, or recognize a reduction in equity of approximately $70 million, and remain within the limitations of the financial covenants required by their credit facilities.

FirstEnergy Money Pools

FirstEnergy’s regulated companies ~~excluding regulated companies acquired in the Allegheny merger,~~ also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first ~~six~~nine months of 2011 was ~~0.43%~~0.47% per annum for the regulated companies’ money pool and ~~0.46%~~0.44% per annum for the unregulated companies’ money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have ~~filed with~~received the appropriate regulatory ~~commissions to receive approval~~approvals to become part of the FirstEnergy regulated money pool.

Pollution Control Revenue Bonds

As of ~~June~~September 30, 2011, FirstEnergy’s currently payable long-term debt included approximately ~~$949~~$632 million (FES — ~~$875~~$558 million, Met-Ed — $29 million and Penelec — $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay bank LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

The LOCs for ~~FirstEnergy~~FirstEnergy's variable interest rate PCRBs were issued by the following banks as of ~~June~~September 30, ~~2011:~~2011:

Aggregate LOC Reimbursements of
LOC Bank Amount⁽¹⁾ LOC Termination Date LOC Draws Due
(In millions)
UBS $ 272 April 2014 April 2014
The Bank of Nova Scotia 178 Beginning June 2012 Multiple dates⁽²⁾
CitiBank N.A. 165 June 2014 June 2014
Wachovia Bank 153 March 2014 March 2014
The Royal Bank of Scotland 131 June 2012 6 months
US Bank 60 April 2014 6 months

Total $ 959



LOC Bank	Aggregate LOC Amount⁽¹⁾		LOC Termination Date	Reimbursements of LOC Draws Due
	(In millions)
UBS	$	272	April 2014	April 2014
CitiBank N.A.	165		June 2014	June 2014
Wachovia Bank	153		March 2014	March 2014
The Bank of Nova Scotia	49		April 2014	Multiple dates⁽²⁾
Total	$	639


⁽¹⁾		Includes approximately ~~$10~~$7 million of applicable interest coverage.


⁽²⁾		Shorter of 6 months or LOC termination ~~date ($49 million) and shorter of one year or LOC termination date ($129 million).~~date.

~~On March 17,~~During the third quarter of 2011, ~~FES completed the remarketing of $207~~FirstEnergy redeemed or repurchased approximately $425.8 million variable rate PCRBs. These PCRBs remained in a variable interest mode, supported by bank LOC’s. Also, on March 1, 2011, FES repurchased $50 million of non-LOC backed fixed rate PCRBs that were subject to purchase on demand by the owner on that date.

On April 1, 2011, FES completed the remarketing of an additional $97 million of non-LOC backed commercial paper rate and fixed rate PCRBs (including the $50 million repurchased on March 1) into variable rate modes with LOC support. Also on April 1, 2011, Penelec completed the remarketing of $25 million of non-LOC backed commercial paper rate PCRBs into a variable rate mode with LOC support.

~~108~~

~~In connection with the remarketings, approximately $207 million aggregate~~ principal amount of ~~FMBs previously delivered to LOC providers were cancelled, and approximately $50 million aggregate principal amount of FMBs delivered to secure~~ PCRBs, ~~were cancelled on May 31, 2011.~~

~~On April 29, Met-Ed redeemed $14~~as summarized in the following table. Approximately $28.5 million of ~~PCRBs at par value.~~

~~On June 1, 2011,~~ FGCO ~~repurchased $40 million of PCRBs and, subject to market conditions and other considerations, is holding those bonds for future remarketing or refinancing.~~

On July 29, 2011, FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 millionFMBs and $98.9 million ~~aggregate principal amount~~ of NGC FMBs ~~previously delivered to certain~~associated with such PCRBs were returned for cancellation by the associated LOC providers.



	Subsidiaries	Amount
		(In millions)
	AE Supply		$	53.0	^(a)
	FGCO		$	158.1	^(b)
	NGC		$	158.9	^(b)
	MP		$	70.2	^(a)
^(a)Includes $14.4 million in PCRBs redeemed for which MP and AE Supply are co-obligors.
^(b)Subject to market conditions, these bonds are being held for future remarketing.

113

Table of ~~the LOC providers by FGCO and NGC, respectively, will be cancelled in connection with the mandatory purchases.~~Contents

Long-Term Debt Capacity

As of ~~June~~September 30, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately ~~$2.5~~$2.6 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to ~~$100~~$115 million and $19 million, respectively. As a result of its indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately ~~$363~~$361 million and ~~$365~~$352 million, respectively, under provisions of their senior note indentures as of ~~June~~September 30, ~~2011.~~2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of ~~June~~September 30, 2011, MP, PE and WP had the capability to issue approximately ~~$1.0~~$1.3 billion of additional FMBs in the aggregate.

Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as of ~~June~~September 30, 2011, FGCO had the capability to issue ~~$2.5~~$2.2 billion of additional FMBs under the terms of that indenture. ~~Due to the sale of Fremont Energy Center on July 28, 2011, FGCO’s capability to issue additional FMBs was reduced by $510 million.~~ Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as of ~~June~~September 30, 2011, NGC had the capability to issue ~~$1.7~~$1.9 billion of additional FMBs as of ~~June~~September 30, 2011 under the terms of that indenture. In connection with the third quarter 2011 PCRB repurchases, $28.5 million of FGCO and $98.9 million of NGC FMBs were returned by the associated LOC providers and canceled.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On ~~February 25,~~March 21, 2011, ~~Moody’s~~S&P affirmed the ratings and stable outlook of FirstEnergy and its ~~regulated utilities,~~subsidiaries. On May 27, 2011, Fitch upgraded ~~AE’s senior unsecured~~ ratings for certain subsidiaries and revised the outlook to stable from negative for FirstEnergy and FES. On August 18, 2011, Moody's downgraded ratings for FES to Baa3 from ~~Ba1~~Baa2 and ~~placed the ratings for FES under review for possible downgrade. On March 1, 2011, Fitch affirmed the ratings and~~revised FES' outlook ~~of FirstEnergy and its subsidiaries.~~to stable. The following table displays FirstEnergy’s and its subsidiaries’ securities ratings as of ~~July 29,~~October 28, 2011.

Senior Secured

Senior Unsecured

Issuer

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

FirstEnergy Corp.

—

BB+

Baa3

BBB

~~Allegheny~~

—

~~BB+~~

~~Baa3~~

—

FES

—

BBB-

~~Baa2~~Baa3

BBB

AE Supply

~~BBB~~—

~~Baa2~~—

~~BBB~~—

BBB-

Baa3

BBB-

AGC

—

BBB-

Baa3

~~BBB+~~BBB

ATSI

—

BBB-

Baa1

A-

CEI

BBB

Baa1

BBB

BBB-

Baa3

BBB-

JCP&L

—

BBB-

Baa2

BBB+

Met-Ed

BBB

A-

BBB-

Baa2

BBB+

Baa1

A-

BBB-

Baa3

BBB+

BBB

BBB+

BBB-

Baa2

BBB

Penelec

BBB

BBB+

BBB-

Baa2

BBB

Penn

BBB+

—

BBB+

Baa1

A-

BBB-

Baa3

BBB+

BBB

Baa1

BBB

—

TrAIL

—

—��

—

BBB-

Baa2

A-

BBB+

A-

BBB-

Baa2

BBB+

Changes in Cash Position

As of ~~June~~September 30, 2011, FirstEnergy had ~~$476~~$291 million of cash and cash equivalents compared to approximately $1$1 billion as of ~~December 31, 2010. As of June 30, 2011 and~~ December 31, 2010. As of September 30, 2011 and December 31, 2010, FirstEnergy had approximately $78 million and $13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

~~109~~

During the first ~~six~~nine months of 2011, FirstEnergy received $1.4 billion from cash dividends and equity repurchases by its subsidiaries and paid ~~$420~~$651 million in cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.

Cash Flows From Operating Activities

FirstEnergy’s consolidated net cash from operating activities is provided primarily by its regulated distribution, regulated independent transmission and competitive energy services ~~energy delivery services and regulated independent transmission~~ businesses (see Results of Operations above). Net cash provided from operating

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activities increased by ~~$173~~$156 million during the first ~~six~~nine months of 2011 compared to the same period in 2010, as summarized in the following table:

Six Months
Ended June 30 Increase
Operating Cash Flows 2011 2010 (Decrease)
(In millions)
Net income $ 216 $ 405 $ (189 )
Non-cash charges 1,229 789 440
Pension trust contribution (262 ) — (262 )
Working capital and other (152 ) (336 ) 184

$ 1,031 $ 858 $ 173



	Nine Months Ended September 30						Increase
Operating Cash Flows	2011			2010			(Decrease)
	(In millions)
Net income	$	725		$	580		$	145
Non-cash charges	1,841			1,648			193
Pension trust contributions	(375		)	—			(375		)
Working capital and other	38			(155		)	193
	$	2,229		$	2,073		$	156

The increase in non-cash charges and other adjustments is primarily due to increased deferred taxes ~~and investment tax credits driven by~~resulting from bonus depreciation ~~and the 2011 pension contribution ($393 million)~~($377 million) and increased depreciation ~~from~~attributable to the acquired Allegheny ~~Companies ($119 million),~~companies ($229 million). These increases were partially offset by decreased asset impairments due to the impairment of certain FGCO facilities recorded in 2010 ($256 million) and lower amortization of regulatory assets from reduced net PJM transmission cost and transition cost recovery ~~($151 million)~~($205 million).

The increase in cash flows from working capital and other is primarily due to decreased receivables from higher customer collections ~~($355 million)~~($311 million) and decreased materials and supplies from the inventory valuation adjustment in the first quarter of 2011 ~~($41 million)~~($68 million), partially offset by ~~increased prepayments and other current assets driven by higher prepaid taxes ($187 million)~~decreased payables ($138 million).

Cash Flows From Financing Activities

In the first ~~six~~nine months of 2011, cash used for financing activities was ~~$1,039~~$2,402 million compared to ~~$484~~$870 million in the comparable period of ~~2010.~~2010. The following ~~table summarizes~~tables summarize new debt financing (net of any discounts) and redemptions:

Six Months
Ended June 30
Debt Issuances and Redemptions 2011 2010
(In millions)
New Issues

Pollution control notes $ 272 $ —
Long-term revolving credit 70 —
Unsecured Notes 161 —

$ 503 $ —

Redemptions

Pollution control notes $ 312 $ 251
Long-term revolving credit 475 —
Senior secured notes 166 55
First mortgage bonds 14 —
Unsecured notes 35 100

$ 1,002 $ 406

Short-term borrowings, net $ (44 ) $ 281



	Nine Months Ended September 30
Debt Issuances and Redemptions	2011			2010
	(In millions)
New Issues
PCRBs	$	272		$	250
Long-term revolving credit	70			—
Unsecured Notes	261			1
	$	603		$	251
Redemptions
PCRBs	$	738		$	251
Long-term revolving credit	495			—
Senior secured notes	187			63
First mortgage bonds	14			7
Unsecured notes	147			101
	$	1,581		$	422

Short-term borrowings, net	$	(700	)	$	(171	)

Excluding PCRBs and sinking-fund requirements, issuances and redemptions during the third quarter of 2011 ~~FES paid off at maturity a $100 million term loan that was secured by FMBs. In April 2011, FirstEnergy entered into a $150 million unsecured term loan with an April 2013 maturity.~~were are follows:

~~110~~

~~In 2011 FES repurchased and retired $20 million~~



Date	Company	Type of Debt	Issued (Redeemed)
			(In millions)
July, 2011	AGC	Unsecured notes	$	100
August, 2011	AGC	Unsecured notes	$	(100	)

115

Table of ~~its 6.80% unsecured senior notes and $15 million of its 6.05% unsecured senior notes. In April 2011, Met-Ed redeemed approximately $14 million of FMBs securing PCRBs.~~Contents

During the remainder of 2011 FirstEnergy and its subsidiaries ~~expect~~may continue to pursue, from time to time, ~~continued~~ reductions in outstanding long-term debt ~~of up to approximately $1.0 to $1.5 billion~~ through redemptions, open market or privately negotiated purchases. Any such transactions will be subject to prevailing market conditions, liquidity requirements, timing of asset sales and other factors.

Cash Flows From Investing Activities

Cash used for investing activities in the first ~~six~~nine months of 2011 resulted from cash used for property additions, partially offset by the cash acquired in the Allegheny ~~merger.~~merger and proceeds from asset sales. The following table summarizes investing activities for the first ~~six~~nine months of 2011 and the comparable period of 2010 by business segment:

Summary of Cash Flows Property
Provided from (Used for) Investing Activities Additions Investments Other Total
(In millions)
Sources (Uses)

Six Months Ended June 30, 2011

Regulated distribution $ (479 ) $ (2 ) $ (25 ) $ (506 )
Competitive energy services (411 ) (32 ) (335 ) (778 )
Regulated independent transmission (72 ) (1 ) (1 ) (74 )
Cash received in Allegheny merger — 590 — 590
Other and reconciling items (56 ) (21 ) 310 233

Total $ (1,018 ) $ 534 $ (51 ) $ (535 )

Six Months Ended June 30, 2010

Regulated distribution $ (309 ) $ 87 $ (18 ) $ (240 )
Competitive energy services (619 ) (11 ) (1 ) (631 )
Regulated independent transmission (29 ) — (2 ) (31 )
Other and reconciling items (40 ) (25 ) — (65 )

Total $ (997 ) $ 51 $ (21 ) $ (967 )



Summary of Cash Flows Provided from (Used for) Investing Activities	Property Additions			Investments			Other			Total
	(In millions)
Sources (Uses)
Nine Months Ended September 30, 2011
Regulated distribution	$	(760	)	$	(3	)	$	(55	)	$	(818	)
Competitive energy services	(608		)	466			(30		)	(172		)
Regulated independent transmission	(105		)	(1		)	(1		)	(107		)
Cash received in Allegheny merger	—			590			—			590
Other and reconciling adjustments	(56		)	(17		)	25			(48		)
Total	$	(1,529	)	$	1,035		$	(61	)	$	(555	)

Nine Months Ended September 30, 2010
Regulated distribution	$	(499	)	$	82		$	13		$	(404	)
Competitive energy services	(884		)	(26		)	(53		)	(963		)
Regulated independent transmission	(47		)	—			(2		)	(49		)
Other and reconciling adjustments	(37		)	(26		)	34			(29		)
Total	$	(1,467	)	$	30		$	(8	)	$	(1,445	)

Net cash used in investing activities during the first ~~six~~nine months of 2011 decreased by ~~$432~~$890 million compared to the same period of ~~2010.~~2010. The decrease was principally due to cash acquired in the Allegheny merger ($($590 ~~million)~~million) and an increase in proceeds from asset sales ($402 million), partially offset by ~~a decrease~~an increase in net ~~proceeds from asset sales~~purchases of investment securities ($90 million) and ~~higher~~increased property additions ~~($137 million)~~($62 million).

During ~~the second half~~last quarter of 2011, capital requirements for property additions and capital leases are ~~expected~~estimated to be approximately ~~$1.2 billion,~~$638 million, including approximately ~~$122~~$35 million for nuclear fuel.

GUARANTEES AND OTHER ASSURANCES

~~111~~

As of ~~June~~September 30, 2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated ~~$3.8~~$3.8 billion, as summarized below:

Maximum
Guarantees and Other Assurances Exposure
(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts⁽¹⁾
$ 223
OVEC obligations 300
Other⁽²⁾
301

824

Subsidiaries’ Guarantees
Energy and Energy-Related Contracts 155
FES’ guarantee of NGC’s nuclear property insurance 70
FES’ guarantee of FGCO’s sale and leaseback obligations 2,324
Other 19

2,568

Surety Bonds 136
LOC⁽³⁾
269

405

Total Guarantees and Other Assurances $ 3,797

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Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts⁽¹⁾	$	280
OVEC obligations	300
Other⁽²⁾	298
	878
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts	154
FES’ guarantee of NGC’s nuclear property insurance	79
FES’ guarantee of FGCO’s sale and leaseback obligations	2,324
Other	16
	2,573
Surety Bonds	147
LOCs⁽³⁾	237
	384
Total Guarantees and Other Assurances	$	3,835


⁽¹⁾		Issued for open-ended terms, with a 10-day termination right by FirstEnergy.


⁽²⁾		Includes guarantees of ~~$95~~$95 million for nuclear decommissioning funding assurances, ~~$161~~$161 million supporting OE’s sale and leaseback arrangement, and ~~$35~~$33 million for railcar leases.



⁽³⁾		Includes ~~$105~~$74 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, ~~$122~~$121 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE, ~~and $39~~$39 million pledged in connection with the sale and leaseback of Perry by ~~OE.~~OE and a $3 million LOC issued in connection with an AVE contractual obligation.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. FirstEnergy believes the likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration or funding obligation or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of ~~June~~September 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was ~~$625~~$594 million, as shown below:

Collateral Provisions FES AE Supply Utilities Total
(In millions)
Credit rating downgrade to below investment grade⁽¹⁾
$ 440 $ 4 $ 78 $ 522
Material adverse event⁽²⁾
33 57 13 103

Total $ 473 $ 61 $ 91 $ 625



Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade ⁽¹⁾	$	405	$	7	$	83	$	495
Material adverse event ⁽²⁾	32		56		11		99
Total	$	437	$	63	$	94	$	594


⁽¹⁾		Includes ~~$206~~$204 million and ~~$59~~$53 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.



⁽²⁾		Includes ~~$32~~$29 million that is also considered an acceleration of payment or funding obligation for FES.

~~112~~

Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical ~~adverse price movements~~increase in prices in the underlying commodity markets would increase the total potential amount to ~~$666~~$662 million, as shown below:

Collateral Provisions FES AE Supply Utilities Total
(In millions)
Credit rating downgrade to below investment grade⁽¹⁾
$ 477 $ 5 $ 78 $ 560
Material adverse event⁽²⁾
36 57 13 106

Total $ 513 $ 62 $ 91 $ 666

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Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade ⁽¹⁾	$	466	$	17	$	83	$	566
Material adverse event ⁽²⁾	29		56		11		96
Total	$	495	$	73	$	94	$	662


⁽¹⁾		Includes ~~$206~~$204 million and ~~$59~~$53 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.



⁽²⁾		Includes ~~$32~~$29 million that is also considered an acceleration of payment or funding obligation for FES.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of ~~$136~~$147 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolios as of ~~June~~September 30, 2011, and forward prices as of that date, FES and AE Supply have posted collateral of ~~$138~~$123 million and $2$1 million, respectively. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one-year time horizon), FES and AE Supply would be required to post an additional ~~$17~~$16 million and $1 million of ~~collateral.~~collateral, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.

Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the ~~borrowers’~~borrowers' obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility. On October 18, 2011, FEV sold a portion of its ownership interest in Signal Peak and Global Rail (see Note 15). Following the sale, FirstEnergy, WMB Loan Ventures LLC and WMB Loan Ventures II LLC will continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing no earlier than January 1, 2012, and no later than June 30, 2012, or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture.

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, was $1.6 billion as of ~~June~~September 30, ~~2011.~~2011.

MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.

Commodity Price Risk

FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy established a Risk Policy Committee, comprised of members of senior management, which provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.

~~113~~

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates

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of fair value for financial reporting purposes and for internal management decision making (see Note 56 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of ~~June~~September 30, 2011 are summarized by year in the following table:

Source of Information-
Fair Value by Contract Year 2011 2012 2013 2014 2015 Thereafter Total
(In millions)
Prices actively quoted⁽¹⁾
$ — $ — $ — $ — $ — $ — $ —
Other external sources⁽²⁾
(287 ) (169 ) (48 ) (38 ) — — (542 )
Prices based on models 9 (3 ) — — — 44 50

Total⁽³⁾
$ (278 ) $ (172 ) $ (48 ) $ (38 ) $ — $ 44 $ (492 )



Source of Information- Fair Value by Contract Year	2011			2012			2013			2014			2015			Thereafter		Total
	(In millions)
Prices actively quoted⁽¹⁾	$	—		$	—		$	—		$	—		$	—		$	—	$	—
Other external sources⁽²⁾	(230		)	(192		)	(72		)	(54		)	—			—		(548		)
Prices based on models	(3		)	(5		)	—			—			(1		)	33		24
Total⁽³⁾	$	(233	)	$	(197	)	$	(72	)	$	(54	)	$	(1	)	$	33	$	(524	)


⁽¹⁾		Represents exchange traded New York Mercantile Exchange futures and options.


⁽²⁾		Primarily represents contracts based on broker and IntercontinentalExchange quotes.


⁽³⁾		Includes ~~$445~~$487 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of ~~June~~September 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately ~~$31~~$14 million ~~($20 million net of tax)~~ during the next 12 months.

Equity Price Risk

The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of ~~June~~September 30, 2011, the FirstEnergy pension plan was invested in approximately ~~31%~~27% of equity securities, ~~46%~~50% of fixed income securities, 9%11% of absolute return strategies, 6% of real estate, 4% of private equity and 4%2% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three ~~months~~ and ~~six~~nine months ended ~~June~~September 30, 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of ~~$105~~$112 million and ~~$262~~$375 million, respectively. ~~FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.~~

NDT funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of ~~June~~September 30, 2011, approximately ~~87%~~19% of the funds were invested in fixed income securities, ~~10%~~9% of the funds were invested in equity securities and 3%72% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately ~~$1,779~~$393 million, ~~$197~~$180 million and ~~$69~~$1,493 million for fixed income securities, equity securities and short-term investments, respectively, as of ~~June~~September 30, 2011, excluding $6$22 million in a net liability position of receivables, payables ~~deferred taxes~~ and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$20~~$18 million reduction in fair value as of ~~June~~September 30, 2011. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their NDT as other-than-temporary impairments. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the first ~~six~~nine months of 2011, approximately $1 million, $4 million and $1 million was contributed to ~~NDT~~the NDTs of JCP&L, OE and TE, respectively. ~~On March 28, 2011,~~ FENOC has submitted ~~its biennial report on nuclear decommissioning funding~~a $95 million parental guarantee to the ~~NRC. This submittal identified~~NRC for a ~~total shortfall~~short-fall in nuclear decommissioning funding for Beaver Valley Unit 1 and ~~Perry of $92 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.~~Perry.

CREDIT RISK

Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

~~114~~

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a

119

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current weighted average risk rating for energy contract counterparties of BBB (S&P). As of ~~June~~September 30, 2011, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 11% of FirstEnergy’s total approved credit risk comprised of ~~2.4%~~2% for FES, ~~1.6%~~2% for JCP&L, ~~2.0%~~2% for Met-Ed, ~~3.4%~~3% for WP and a combined ~~2.0%~~2% for the Ohio Companies.

OUTLOOK

~~Reliability Initiatives~~

RELIABILITY INITIATIVES

~~Maryland~~

MARYLAND

~~115~~

In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin ~~O’Malley~~O'Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request

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for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and ~~at this time no further proceedings have been set~~on September 29, 2011, the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC by October 7, 2011. The RFPs were issued by the utilities as ordered by the MDPSC. The order indicated that bids were due by November 11, 2011, that the MDPSC would be the entity evaluating all bids, and that a hearing on whether to require the purchase of generation in ~~this matter.~~light of the bids would be held on January 31, 2012, after receipt of further comments from all interested parties on January 13, 2012.

On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each ~~utility’s~~utility's compliance with the standards, and may assess penalties of up to ~~$25,000~~$25,000 per day per violation. The MDPSC ~~has ordered that~~convened a working group of utilities, regulators, and other interested stakeholders ~~meet~~ to address the topics of the proposed rules. A draft of the rules was filed, along with ~~proposed~~the report of the working group, on October 27, 2011. Comments on the draft rules are due by November 16, and a hearing to ~~be filed by September 15,~~consider the rules and comments is scheduled for December 8 and 9, 2011. Separately, on ~~April~~July 7, 2011, the MDPSC ~~initiated a rulemaking with respect to issues related to~~adopted draft rules requiring monitoring and inspections for contact voltage. ~~On June 3, 2011,~~The draft rules were published in September, and then approved by the ~~MDPSC’s Staff issued a report and draft regulations. Comments~~MDPSC as final rules on ~~the draft regulations were submitted on June 17, 2011, and a hearing was held July 7,~~October 31, 2011. ~~Final regulations related to contact voltage have not yet been adopted.~~

~~New Jersey~~

~~In March 2009 and~~The rules will go into effect after being published again in ~~February 2010, JCP&L filed annual SBC Petitions with~~ the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). In its order of June 15,Maryland Register.

NEW JERSEY

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held on September 26 and 27, 2011, to solicit public comments regarding the state of preparedness and responsiveness of the local electric distribution companies prior to, during and after Hurricane Irene. By subsequent Notice issued September 28, 2011, additional hearings were held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. The NJBPU has not indicated what additional action, if any, may be taken as ~~requested,~~ a ~~zero level~~result of ~~recovery~~information obtained through this process.

121

Table of ~~TMI-2 decommissioning costs).~~Contents

OHIO

~~Ohio~~

~~116~~

Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio ~~Companies’~~Companies' aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio ~~Companies’~~Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. ~~Other parties to~~On August 3, 2011, the ~~proceeding filed comments asserting~~PUCO granted the Ohio Companies' force majeure request for 2010 and increased their 2011 benchmark by the amount of SRECs generated in Ohio that the ~~force majeure determination should not be granted,~~Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and ~~others requesting~~Policy Center and Nucor Steel Marion, Inc. filed applications for rehearing. The Ohio Companies filed their response on September 12, 2011. These applications for rehearing were denied by the PUCO on September 20, 2011, but as part of its Entry on Rehearing the PUCO opened a new docket to review the ~~costs~~Ohio Companies' alternative energy recovery rider. Separately, one party has filed a request that the PUCO audit the cost of the Ohio ~~companies’ have incurred to comply~~Companies' compliance with the ~~renewable~~alternative energy ~~requirements.~~requirements and the Ohio Companies' compliance with Ohio law. The PUCO has not ~~yet acted~~ruled on ~~that application.~~this request.

In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and

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charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the ~~companies’~~Ohio Companies' application on May 25, 2011, ruling that the new credit be applied only to customers that heat with electricity and be phased out over an eight-year period and granting authority for the ~~companies~~Ohio Companies to recover deferred costs and associated carrying charges. OCC filed ~~applications~~an application for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO ~~has~~did not ~~yet acted~~act on the ~~applications~~application for ~~rehearing.~~

~~117~~

~~Pennsylvania~~rehearing within 30 days; thus, the application for rehearing is considered denied by operation of law. No appeal of this matter was filed and the time period in which to do so has expired.

PENNSYLVANIA

On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of Met-Ed, Penelec and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements.

Met-Ed, Penelec, Penn and WP submitted a preliminary status report on July 15, 2011, in which they reported on their compliance

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with statutory May 31, 2011 energy efficiency benchmarks. Preliminary results indicate that Met-Ed, Penelec and Penn will achieve their 2011 benchmarks; however WP may not. Final reports on actual results must be filed with the PPUC no later than November 15, 2011.

~~118~~

~~Virginia~~

~~In September 2010, PATH-VA filed~~The PPUC issued a Proposed Rulemaking Order on August 25, 2011 which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an ~~application~~EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included

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in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the ~~VSCC~~EDC before using its trademark or service mark. The Proposed Rulemaking Order calls for ~~authorization~~comments to ~~construct the Virginia portions~~be submitted within forty-five days of ~~the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw~~ its ~~application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion”~~publication in the ~~Federal Regulation and Rate Matters section~~Pennsylvania Bulletin, with no provision for ~~further discussion of this matter.~~

~~119~~

~~West Virginia~~

~~a $40 million annualized base rate increase effective June 29, 2010;~~

~~a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;~~

WEST VIRGINIA

	•		~~an additional $20 million annualized base rate increase effective in January 2011;~~

	•		~~a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and~~

~~a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.~~

~~The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.~~

FERC ~~Matters~~MATTERS

Rates for Transmission Service Between MISO and PJM

PJM Transmission Rate

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the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology, ~~(DFAX),~~ which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

~~120~~

~~FERC’s~~FERC's Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed ~~FERC’s~~FERC's ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new ~~500+~~500 kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue ~~back~~ to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing”—-- meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. ~~PJM’s~~PJM's filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain ~~eastern utilities~~load serving entities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. ~~Certain eastern~~Other utilities and ~~their~~ state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.

RTO Realignment

MISO Multi-Value Project Rule Proposal

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are approved via ~~MISO’s~~MISO's formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, ~~MISO’s~~MISO's Board approved the first MVP project —-- the “Michigan Thumb Project.” Under ~~MISO’s~~MISO's proposal, the costs of MVP projects approved by ~~MISO’s~~MISO's Board prior to the June 1, 2011 effective date of ~~FirstEnergy’s~~FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately ~~$15~~$15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

~~121~~

As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ~~ATSI’s~~ATSI's proposed transmission ~~rates~~rate FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ~~ATSI’s~~ATSI's formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost-benefit study. ATSI requested a rehearing of these parts of ~~FERC’s~~FERC's order and, pending this further legal process, has removed the MVP line items from its transmission rates.

FirstEnergy cannot predict the outcome of these proceedings at this time.

California Claims Matters

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2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of ~~this matter.~~either of the above matters.

PATH Transmission ~~Expansion~~Project

~~122~~

Seneca Pumped Storage Project Relicensing

~~The next steps in the relicensing process are for~~

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documents. On September 26, 2011, FirstEnergy submitted comments regarding certain factual and legal matters asserted in the Seneca Nation's Revised Study Plan document. On October 7, 2011, FirstEnergy submitted further comments to ~~define~~refute certain factual and legal arguments that were advanced by the Seneca Nation in comments that were submitted on September 26, 2011. On October 11, 2011, FERC Staff issued letters that finalize the studies that are to be performed. FirstEnergy and the Seneca Nation each will perform ~~certain environmental and operational~~the studies ~~to support their respective applications. These steps are expected to~~described in the October 11, 2011 Staff determination. The study process will run through approximately November of 2013.

FirstEnergy cannot predict the outcome of these proceedings at this time.

~~Environmental Matters~~ENVIRONMENTAL MATTERS

CAA Compliance

~~123~~

129

Table of ~~this matter.~~Contents

~~124~~

FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.

State Air Quality Compliance

National Ambient Air Quality Standards

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Hazardous Air Pollutant Emissions

~~125~~

Climate Change

At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO₂, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching ~~$30~~$30 billion over the next three years with a goal of increasing to ~~$100~~$100 billion by 2020; and establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union,

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Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

Clean Water Act

~~126~~

benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power ~~plant’s~~plant's water intake channel to divert fish away from the ~~plant’s~~plant's water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore Plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the ~~EPA’s~~EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.

Monongahela River Water Quality

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criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA ~~DEP’s~~DEP's permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of ~~$150~~$150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. ~~The~~A hearing ison the parties' appeals was scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a ~~settlement.~~settlement, and has rescheduled a hearing, if necessary, for July 2012. If these settlement discussions are successful, AE Supply anticipates that its obligations will not be material. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

~~127~~

Regulation of Waste Disposal

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that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of ~~June~~September 30, 2011, based on estimates of the total costs of cleanup, the Utility ~~Registrants’~~Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$133~~$103 million (JCP&L ~~— $69~~- $69 million, TE ~~— $1~~- $1 million, CEI ~~— $1~~- $1 million, FGCO ~~— $1~~- $1 million and FirstEnergy ~~— $61 million)~~- $31 million) have been accrued through ~~June~~September 30, ~~2011.~~2011. Included in the total are accrued liabilities of approximately ~~$63~~$63 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately ~~$59 million.~~$59 million. FirstEnergy recognized an additional expense of ~~$29~~$29 million during the second quarter of 2011; ~~$30~~$30 million had previously been reserved prior to 2011. FirstEnergy determined that it is reasonably possible that it or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses at those sites cannot be determined or reasonably estimated.

~~Other Legal Proceedings~~OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

Nuclear Plant Matters

~~128~~

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC's Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse's operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.

On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. In a September 11, 2011 order, the NRC denied the request to suspend the licensing proceedings and referred to the NRC Task Force conducting a “Near-Term Evaluation of the Need for Agency Actions Following the Events in Japan” for those portions of the petitions requesting rulemaking.

On October 1, 2011, the Davis-Besse Plant was safely shut down for a scheduled outage to install a new reactor vessel head and

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complete other maintenance activities. The new reactor head, which replaces a head installed in 2002, enhances safety, reliability and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, a sub-surface hairline crack was identified in one of the exterior architectural elements on the Shield Building, following opening of the building for installation of the new reactor head. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the Shield Building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. The team of industry-recognized structural concrete experts and Davis-Besse engineers evaluating this condition has determined the cracking does not affect the facility's structural integrity or safety. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in two localized areas of the Shield Building similar to those found in the architectural elements. FENOC has determined these two areas are not associated with the architectural element cracking and are investigating them as a separate issue. FENOC's overall investigation and analysis continues.Davis-Besse is currently expected to return to service around the end of November.
By a letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct a supplemental inspection using Inspection Procedure 95002, to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.
On October 2, 2011, FENOC completed the controlled shutdown of the Perry plant due to the loss of a startup transformer. On October 11, 2011, FENOC submitted a Technical Specification change request to the NRC to clarify that a delayed access circuit is temporarily qualified for use as one of the required offsite power circuits. By a letter dated October 17, 2011, NRC authorized Perry to operate with a delayed access circuit for offsite power until December 12, 2011. Concurrently, a spare replacement transformer from Davis-Besse was transported to Perry for modification and installation.
In light of the impacts of the earthquake and tsunami on the reactors in Fukushima, Japan, the NRC conducted inspections of emergency equipment at US reactors. The NRC also established a Near-Term Task Force to review its processes and regulations in light of the incident, and, on July 12, 2011, the Task Force issued its report of recommendations for regulatory changes. On October 18, 2011, the NRC approved the Staff recommendations, and directed the Staff to implement its near-term recommendations without delay. Ultimately, the adoption of the Staff recommendations on near-term actions is likely to result in additional costs to implement plant modifications and upgrades required by the regulatory process over the next several years, which costs are likely to be material.

ICG Litigation

Other Legal Matters

~~129~~

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can

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reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has an obligation, it discloses such obligations with the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, ~~matters,~~ it could have a material adverse effect on ~~FirstEnergy’s~~FirstEnergy's or its ~~subsidiaries’~~subsidiaries' financial condition, results of operations and cash flows.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

See Note 1213 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.

~~130~~

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FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, and through its principal subsidiaries, FGCO and NGC, owns or leases, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

FES’ revenues are derived from sales to individual retail customers, sales to communities in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, ~~Maryland,~~ Michigan, New Jersey and ~~New Jersey.~~Maryland. In 2010, FES also supplied the POLR default service requirements of Met-Ed and Penelec.

The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions and weather conditions.

For additional information with respect to FES, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Executive Summary- Operational Matters and Financial Matters, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income decreased by ~~$158~~$11 million in the first ~~six~~nine months of 2011 compared to the same period of ~~2010.~~2010. The decrease was primarily due to ~~lower sales margin,~~higher operating expenses, an inventory reserve adjustment ~~non-core asset impairments~~ and the effect of mark-to-market ~~adjustments.~~adjustments, partially offset by lower non-core asset impairment charges.

Revenues

Total revenues decreased ~~$30~~$152 million, or 1%3.5%, in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to reduced POLR and structured sales, partially offset by growth in direct and governmental aggregation sales.

The decrease in total revenues resulted from the following sources:



	Nine Months Ended September 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	2,836	$	1,814	$	1,022
POLR and Structured Sales	798		2,014		(1,216		)
Wholesale	288		265		23
Transmission	86		58		28
RECs	55		67		(12		)
Other	88		85		3
Total Revenues	$	4,151	$	4,303	$	(152	)

~~131~~



	Nine Months Ended September 30		Increase
MWH Sales by Type of Service	2011	2010	(Decrease)
	(In thousands)
Direct	33,893	20,675	63.9	%
Governmental Aggregation	13,475	9,238	45.9	%
POLR and Structured Sales	12,789	38,711	(67.0	)%
Wholesale	2,714	3,281	(17.3	)%
Total Sales	62,871	71,905	(12.6	)%

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The increase in direct and governmental aggregation revenues of ~~$668~~$1,022 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio and Illinois that provided generation to approximately ~~1.5~~1.7 million residential and small commercial customers at the end of ~~June~~September 2011 compared to approximately ~~1.1~~1.2 million customers at the end of ~~June~~September 2010.

The decrease in POLR revenues of ~~$708~~$1,216 million was due to lower sales volumes to Met-Ed, ~~and Penelec, primarily due to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and~~ Penelec and ~~reduced sales to~~ the Ohio Companies, partially offset by increased sales to ~~non-associated companies~~non-affiliates and higher unit prices to the Pennsylvania ~~Companies~~Companies. This decline is the result of FES no longer having the responsibility to supply these default service requirements and is consistent with our business ~~strategy. Participation~~strategy to selectively participate in POLR ~~auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for direct retail and aggregation sales.~~auctions.

Wholesale revenues ~~increased~~increased by ~~$14~~$23 million due to higher wholesale prices, partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by generating units that moved to PJM were partially offset by losses on financially settled sales.

The following tables summarize the price and volume factors contributing to changes in revenues:

Increase
Source of Change in Direct and Governmental Aggregation (Decrease)
(In millions)
Direct Sales:
Effect of increase in sales volumes $ 493
Change in prices (20 )

473

Governmental Aggregation:
Effect of increase in sales volumes 176
Change in prices 19

195

Net Increase in Direct and Governmental Aggregation Revenues
$ 668

Increase
Source of Change in POLR Revenues (Decrease)
(In millions)
POLR:
Effect of decrease in sales volumes $ (819 )
Change in prices 111

$ (708 )


	Increase
Source of Change in Wholesale Revenues	(Decrease)
Wholesale:
				Increase
Source of Change in Direct and Governmental Aggregation				(Decrease)
				(In millions)
Direct Sales:
Effect of increase in sales volumes	$	(15	)	$	775
Change in prices		29		(41		)
				734
	$	14
Governmental Aggregation:
Effect of increase in sales volumes				276
Change in prices				12
				288
Net Increase in Direct and Governmental Aggregation Revenues				$	1,022



	Increase
Source of Change in POLR Revenues	(Decrease)
	(In millions)
POLR:
Effect of decrease in sales volumes	$	(1,349	)
Change in prices	133
	$	(1,216	)



	Increase
Source of Change in Wholesale Revenues	(Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(46	)
Change in prices	69
	$	23

Transmission revenues ~~increased~~increased by ~~$20~~$28 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs ~~declined $23~~decreased$12 million in the first ~~six~~nine months of 2011.

Operating Expenses

Total operating expenses ~~increased~~decreased by ~~$199~~$160 million in the first ~~six~~nine months of 2011, compared with the same period of ~~2010.~~2010.

~~132~~

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first ~~six~~nine months of 2011 compared with the same period last year:

Increase
Source of Change in Fuel and Purchased Power (Decrease)
(In millions)
Fossil Fuel:
Change due to increased unit costs $ 2
Change due to volume consumed (29 )

(27 )

Nuclear Fuel:
Change due to increased unit costs 14
Change due to volume consumed 1

15

Non-affiliated Purchased Power:
Change due to increased unit costs 108
Change due to volume purchased (242 )

(134 )

Affiliated Purchased Power:
Change due to increased unit costs 34
Change due to volume purchased (30 )

4

Net Decrease in Fuel and Purchased Power Costs
$ (142 )

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	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	13
Change due to volume consumed	(54		)
	(41		)

Nuclear Fuel:
Change due to increased unit costs	23
Change due to volume consumed	1
	24

Non-affiliated Purchased Power:
Change due to increased unit costs	199
Change due to volume purchased	(451		)
	(252		)

Affiliated Purchased Power:
Change due to decreased unit costs	(19		)
Change due to volume purchased	(38		)
	(57		)
Net Decrease in Fuel and Purchased Power Costs	$	(326	)

Total fuel costs decreased by ~~$12~~$17 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, as a result of reduced generation at the fossil units, partially offset by higher fossil unit costs. Fossil unit ~~prices~~costs increased primarily due to increased coal transportation costs. Nuclear fuel expenses increased primarily due to higher unit prices following the refueling outages that occurred in 2010.

Non-affiliated purchased power costs decreased by ~~$134~~$252 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower volumes purchased, partially offset by higher unit costs. The decrease in volume relates to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec inthat FES no longer has the ~~first half of 2011.~~requirement to serve. Affiliated purchased power costs ~~increased~~decreased by $4$57 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to ~~higher~~lower unit costs ~~partially offset by~~and decreased volumes purchased.

Other operating expenses increased by ~~$302~~$399 million in the first ~~six~~nine months of 2011, compared to the same period of 2010 due to the following:

Transmission expenses increased by ~~$176~~$216 million due primarily to increases in PJM of ~~$198~~$332 million from higher congestion, network and line loss expense, partially offset by lower MISO transmission expenses of ~~$22~~$116 million.

Fossil operating costs increased by ~~$20~~$25 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.

A $54 million provision for excess and obsolete material related to revised inventory practices adopted in connection with the Allegheny ~~merger.~~

merger and an increase in mark-to-market adjustments of $24 million.

Impairment charges ofon long-lived assets ~~increased~~decreased by ~~$18~~$272 million due to ~~impairments~~a charge related to operational changes at certain ~~non-core~~smaller, coal-fired units that were recorded in the third quarter of 2010, partially offset by impairments of peaking facilities available for sale during the first ~~six~~nine months of 2011.

General taxes increased by ~~$11~~$20 million due to an increase in revenue-related taxes.

Provision for depreciation increased by $19 million due to the AQC projects being placed in service at the end of 2010.

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Other Expense

Total other expense increased by ~~$17~~$29 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to a $39 milliondecrease in capitalized interest ~~($24 million)~~ associated with the completion of the Sammis AQC project in 2010, partially offset by ~~increased~~a $6 millionincrease in investment income ~~($8 million)~~ from higher NDT income.

~~133~~

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OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE procures generation services for those franchise customers electing to retain OE and Penn as their power supplier.

For additional information with respect to OE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Results of Operations- Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

~~Earnings available to parent decreased by $5 million in~~Net income was unchanged for the first ~~six~~nine months of 2011, compared to the same period of ~~2010. The decrease primarily resulted from lower~~2010, as decreased revenues and ~~higher~~increased other operating expenses ~~partially~~were offset by ~~lower~~decreased purchased power ~~costs and amortization of regulatory assets.~~

~~Revenues~~costs.

Revenues ~~decreased~~

Revenues decreased by ~~$171~~$187 million, or ~~18%~~13%, in the first ~~six~~nine months of 2011, compared with the same period in 2010, due to a decrease in generation revenues, partially offset by higher distribution and wholesale generation revenues.

Distribution revenues increased by ~~$31~~$72 million in the first ~~six~~nine months of 2011, compared to the same period in 2010, due to ~~an increase in~~increased KWH deliveries ~~in the residential and industrial sectors~~ and higher average prices in all customer classes. The higher KWH deliveries in the residential class were driven primarily by increased load growth slightly offset by lower weather-related ~~usage in the first six months of 2011, reflecting a 6% increase in heating degree days.~~usage. The increase in distribution deliveries to commercial and industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territory. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.

Changes in distribution KWH deliveries and revenues in the first ~~six~~nine months of 2011, compared to the same period in 2010, are summarized in the following tables:



Distribution KWH Deliveries	Increase

Residential		~~3.0~~2.5	%
Commercial		~~0.2~~0.9	%
Industrial		~~3.5~~7.8	%

Increase in Distribution Deliveries		~~2.4~~3.8	%

Distribution Revenues Increase
(In millions)
Residential $ 19
Commercial 7
Industrial 5

Increase in Distribution Revenues
$ 31



Distribution Revenues	Increase
	(In millions)
Residential	$	37
Commercial	16
Industrial	19
Increase in Distribution Revenues	$	72

Retail generation revenues decreased by ~~$211~~$266 million primarily due to a decrease in KWH sales from increased customer shopping and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE ~~defers~~and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales were primarily the result of increased customer shopping ~~partially offset by increased weather-related usage~~ in the first ~~six~~nine months of 2011 ~~as described above.~~. The ~~increase~~increases in customer shopping for residential, commercial and industrial customer classes ~~was 23%~~were 21%, ~~14%~~12% and 8%7%, respectively.

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Decreases in retail generation KWH sales and revenues in the first ~~six~~nine months of 2011, compared to the same period in 2010, are summarized in the following tables:



Retail Generation KWH Sales	Decrease

Residential		(~~30.7~~30.8	)%
Commercial		(~~39.0~~36.3	)%
Industrial		(~~25.4~~21.4	)%

Decrease in Retail Generation Sales		(~~31.2~~29.9	)%

Retail Generation Revenues Decrease
(In millions)
Residential $ (128 )
Commercial (52 )
Industrial (31 )

Decrease in Retail Generation Revenues
$ (211 )



Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(171	)
Commercial	(65		)
Industrial	(30		)
Decrease in Retail Generation Revenues	$	(266	)

Wholesale generation revenues increased by ~~$15~~$14 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.

Operating Expenses

Total operating expenses ~~decreased~~decreased by ~~$171~~$192 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The following table presents changes from the prior period by expense category:

Increase
Expenses - Changes (Decrease)
(In millions)
Purchased power costs $ (175 )
Other operating expenses 36
Amortization of regulatory assets, net (36 )
General taxes 4

Net Decrease in Expenses
$ (171 )



	Increase
Operating Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(259	)
Other operating expenses	59
Provision for depreciation	1
Amortization of regulatory assets, net	1
General taxes	6
Net Decrease in Operating Expenses	$	(192	)

Purchased power costs decreased in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower KWH purchases resulting from reduced generation sales requirements ~~in the first six months of 2011~~ coupled with lower unit costs. The increase in other operating expenses for the first ~~six~~nine months of 2011 compared to the same period of 2010 was principally due to expenses associated with refueling outages at OE’s leased Perry Unit 1 and Beaver Valley Unit 2 that were absent in ~~2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011.~~2010. General taxes increased as a result of higher property taxes.

~~Other Expense~~

~~Other expense increased by $3 million in the first six months of 2011, compared to the same period of 2010 due to lower nuclear decommissioning trust investment income.~~142

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also procures generation services for those customers electing to retain CEI as their power supplier.

For additional information with respect to CEI, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Results of Operations- Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Earnings available to parent ~~decreased slightly~~increased $1 million in the first ~~six~~nine months of 2011, compared to the same period of 2010. The ~~decrease~~increase in earnings was due to lower ~~revenues,~~purchased power costs and amortization of regulatory assets, partially offset by lower ~~purchased power and amortization of regulatory assets.~~revenues.

Revenues

Revenues decreased by ~~$183~~$268 million, or ~~29%~~28%, in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower retail generation and distribution revenues.

Distribution revenues decreased by ~~$14~~$43 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower average unit prices for the residential and industrial customer classes, partially offset by increased KWH deliveries to ~~the residential and commercial~~these customer classes. The lower average unit prices were the result of the absence of transition charges in 2011. Higher KWH deliveries to ~~the~~ residential ~~class were driven~~customers reflected increased load growth slightly offset by ~~increased~~lower weather-related usage ~~in the first six months of 2011, reflecting a 15% increase in heating degree days in CEI’s service territory. Lower distribution~~that also drove lower deliveries to commercial customers. In the industrial ~~customers reflected softer~~sector, KWH deliveries increased primarily as a result of recovering economic conditions in ~~this sector.~~CEI's service territory.

Changes in distribution KWH deliveries and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



	Increase
Distribution KWH Deliveries	(Decrease)

Residential	1.6	~~2.2~~	%
Commercial	(0.6	~~2.9~~	)%
Industrial	1.6	~~(3.1~~	)%

Net Increase in Distribution Deliveries		~~0.6~~	%
0.8			%

Increase
Distribution Revenues (Decrease)
(In millions)
Residential $ 2
Commercial 17
Industrial (33 )

Net Decrease in Distribution Revenues
$ (14 )

~~136~~



	Increase
Distribution Revenues	(Decrease)
	(In millions)
Residential	$	(1	)
Commercial	7
Industrial	(49		)
Net Decrease in Distribution Revenues	$	(43	)

Retail generation revenues decreased by ~~$169~~$224 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to lower KWH sales in all customer classes resulting from increased customer shopping and lower average unit prices for the commercial and residential customer classes. ~~Customer shopping has increased for residential, commercial and industrial classes by 22%, 13% and 36%, respectively.~~ Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. ~~Reduced~~Lower KWH sales were ~~primarily~~ the result of increased customer shopping ~~in the first six months~~for residential, commercial and industrial classes of ~~2011, partially offset by the impact of increased weather-related usage by residential customers as described above.~~18%, 10% and 37%, respectively. Lower average unit prices in the residential customer class were the result of generation credits in place for 2011.

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Decreases in retail generation sales and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



Retail Generation KWH Sales	Decrease

Residential		(~~46.6~~43.0	)%
Commercial		(~~44.2~~40.4	)%
Industrial		(~~69.8~~71.1	)%

Decrease in Retail Generation Sales		(~~55.0~~53.7	)%

Retail Generation Revenues Decrease
(In millions)
Residential $ (69 )
Commercial (46 )
Industrial (54 )

Decrease in Retail Generation Revenues
$ (169 )

Retail Generation Revenues Decrease
(In millions)
Residential $ (87 )
Commercial (59 )
Industrial (78 )
Decrease in Retail Generation Revenues $ (224 )

Operating Expenses

Total operating expenses decreased by ~~$173~~$262 million in the first ~~six~~nine months of 2011, compared to the same period of 2010. The following table presents the change from the prior ~~period~~year by expense category:

Increase
Expenses - Changes (Decrease)
(In millions)
Purchased power costs $ (155 )
Other operating costs 6
Amortization of regulatory assets, net (34 )
General taxes 10

Net Decrease in Expenses
$ (173 )



	Increase
Operating Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(227	)
Other operating expenses	10
Amortization of regulatory assets, net	(56		)
General taxes	11
Net Decrease in Operating Expenses	$	(262	)

Purchased power costs decreased ~~in the first six months of 2011~~ due to lower KWH purchases resulting from reduced sales ~~requirements in the first six months of 2011.~~requirements. Other operating expenses increased ~~principally~~ due to 2011 inventory valuation adjustments. ~~Decreased amortization~~Amortization of regulatory assets ~~was~~decreased primarily due to the completion of transition cost recovery at the end of 2010 and deferred ~~residential generation credits~~purchased power costs in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased ~~in the first six months of 2011~~ due to increased property taxes as compared to the same period of 2010.

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THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also procures generation services for those customers electing to retain TE as their power supplier.

For additional information with respect to TE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Results of Operation- Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Earnings available to parent increased by $3$4 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The increase primarily resulted from lower purchased power costs ~~and higher cost deferrals,~~from affiliates, partially offset by lower revenues and higher other operating expenses.

Revenues

Revenues decreased by ~~$40~~$40 million, or ~~16%~~10%, in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to a decrease in retail generation revenues, partially offset by higher distribution revenues and wholesale generation revenues.

Distribution revenues increased by $3$20 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to higher residential, ~~revenues, partially~~commercial and industrial revenues. Higher KWH deliveries to residential customers reflected increased load growth slightly offset by lower weather-related usage that also drove lower deliveries to commercial customers. In the industrial ~~revenues. Residential revenues were the~~sector, KWH deliveries increased primarily as a result of higher KWH deliveries and average unit prices. The higher KWH deliveries in the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 14% increase in heating degree days, partially offset by a 23% decrease in cooling degree days in TE’s service territory. Industrial revenues were impacted by lower average unit prices, partially offset by higher KWH deliveries from recovering economic ~~conditions.~~conditions in TE's service territory.

Changes in distribution KWH deliveries and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:


	~~Increase~~
Distribution KWH Deliveries	Increase (Decrease)

Residential	2.8	~~4.5~~	%
Commercial		(~~2.5~~1.7	)%
Industrial	3.2	~~3.7~~	%

Net Increase in Distribution Deliveries		~~2.6~~	%
2.1			%

Increase
Distribution Revenues (Decrease)
(In millions)
Residential $ 5
Commercial —
Industrial (2 )

Net Increase in Distribution Revenues
$ 3



Distribution Revenues	Increase
	(In millions)
Residential	$	11
Commercial	5
Industrial	4
Increase in Distribution Revenues	$	20

Retail generation revenues decreased by ~~$53~~$70 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower KWH sales from increased customer shopping and lower unit prices for all customer classes. Lower KWH sales were the result of increased customer shopping, which has increased in the residential, commercial and industrial classes by 15%, 11% and 4%, respectively. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. ~~Lower KWH sales were the result~~

145

Table of increased customer shopping, partially offset by increased weather-related usage as described above. Customer shopping has increased for residential, commercial and industrial classes by 16%, 13% and 5%, respectively.Contents

~~138~~

Decreases in retail generation KWH sales and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



Retail Generation KWH Sales	Decrease

Residential		(~~28.3~~28.9	)%
Commercial		(~~46.6~~42.1	)%
Industrial		(~~11.7~~10.5	)%

Decrease in Retail Generation Sales		(~~22.6~~21.6	)%

Retail Generation Revenues Decrease
(In millions)
Residential $ (16 )
Commercial (13 )
Industrial (24 )

Decrease in Retail Generation Revenues
$ (53 )



Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(25	)
Commercial	(17		)
Industrial	(28		)
Decrease in Retail Generation Revenues	$	(70	)

Wholesale revenues increased by $9$11 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.

Operating Expenses

Total operating expenses decreased by ~~$42~~$44 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The following table presents changes from the prior period by expense category:

Increase
Expenses - Changes (Decrease)
(In millions)
Purchased power costs $ (53 )
Other operating expenses 18
Deferral of regulatory assets, net (8 )
General Taxes 1

Net Decrease in Expenses
$ (42 )



Operating Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(73	)
Other operating expenses	25
Deferral of regulatory assets, net	3
General Taxes	1
Net Decrease in Operating Expenses	$	(44	)

Purchased power costs ~~decreased~~decreased in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower KWH purchases resulting from reduced generation sales requirements in the first ~~six~~nine months of 2011 coupled with lower unit costs. The increase in other operating costs for the first ~~six~~nine months of 2011 was primarily due to expenses associated with the 2011 refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. The net deferral of regulatory assets ~~reduced~~increased expenses due to ~~higher PUCO-approved cost deferrals~~more recovery of costs deferred in prior years during the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~

~~Other Expense~~2010.

Other Expense

Other expense ~~increased~~increased by $2$1 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower nuclear decommissioning trust investment income.

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JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

~~As authorized by JCP&L’s Board of Directors, on May 31, 2011 JCP&L returned $500 million of capital to FirstEnergy Corp., the sole owner of all of the shares of JCP&L’s common stock.~~

For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Results of Operations- Regulatory Assets, Capital Resources and Liquidity, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income ~~decreased~~decreased by ~~$18~~$18 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The decrease was primarily due to lower revenues and higher other operating expenses, partially offset by reductions in purchased power costs ~~other operating costs~~ and ~~net~~ amortization of regulatory ~~assets.~~

~~Revenues~~assets, net.

Revenues ~~decreased~~

Revenues decreased by ~~$190~~$380 million, or ~~13%~~16%, in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The decrease in revenues was due to lower distribution, retail generation and ~~retail~~wholesale generation revenues, partially offset by an increase in ~~wholesale generation and~~ other revenues.

Distribution revenues decreased by ~~$71~~$134 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to an NJBPU-approved rate adjustment that became effective March 1, 2011, for all customer ~~classes.~~classes, and lower KWH deliveries. The lower KWH deliveries to the residential class were influenced by decreased weather-related usage in the first ~~six~~nine months of 2011 ~~reflecting a 16% decrease in cooling degree days offsetting a 7% increase in heating degree days in JCP&L’s service territory.~~. Lower distribution deliveries to commercial and industrial customers reflected ~~soft~~the impact of economic conditions into these sectors.

Decreases in distribution KWH deliveries and revenues in the first ~~six~~nine months of 2011 compared to the same period of 2010 are summarized in the following tables:



Distribution KWH Deliveries	Decrease

Residential		(~~2.5~~1.5	)%
Commercial		(~~3.3~~2.4	)%
Industrial		(~~1.8~~2.4	)%

Decrease in Distribution Deliveries		(~~2.7~~2.0	)%

Distribution Revenues Decrease
(In millions)
Residential $ (33 )
Commercial (31 )
Industrial (7 )

Decrease in Distribution Revenues
$ (71 )



Distribution Revenues	Decrease
	(In millions)
Residential	$	(65	)
Commercial	(57		)
Industrial	(12		)
Decrease in Distribution Revenues	$	(134	)

Retail generation revenues decreased by ~~$132~~$234 million due to lower retail generation KWH sales in all customer classes primarily due to an increase in customer shopping. Customer shopping has increased for the residential, commercial and industrial classes by ~~10%~~11%, ~~11%~~10% and 4%5%, respectively. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to ~~current period~~ earnings.

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Decreases in retail generation KWH sales and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



Retail Generation KWH Sales	Decrease

Residential		(~~12.1~~12.0	)%
Commercial		(~~26.2~~23.7	)%
Industrial		(~~24.8~~27.9	)%

Decrease in Retail Generation Sales		(~~16.7~~15.7	)%

Retail Generation Revenues Decrease
(In millions)
Residential $ (68 )
Commercial (59 )
Industrial (5 )

Decrease in Retail Generation Revenues
$ (132 )



Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(136	)
Commercial	(89		)
Industrial	(9		)
Decrease in Retail Generation Revenues	$	(234	)

Wholesale generation revenues ~~increased~~decreased by $6$21 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to ~~an increase~~a decrease in PJM spot market energy sales.

Other revenues increased by $8$9 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues.

Operating Expenses

Total operating expenses decreased by ~~$163~~$347 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The following table presents changes from the prior period by expense category:

Increase
Expenses - Changes (Decrease)
(In millions)
Purchased power costs $ (126 )
Other operating costs (6 )
Provision for depreciation (3 )
Amortization of regulatory assets, net (29 )
General taxes 1

Net Decrease in Expenses
$ (163 )



	Increase
Operating Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(254	)
Other operating expenses	38
Provision for depreciation	1
Amortization of regulatory assets, net	(134		)
General taxes	2
Net Decrease in Operating Expenses	$	(347	)

Purchased power costs ~~decreased~~decreased by ~~$126~~$254 million in the first ~~six~~nine months of 2011 due to lower requirements from reduced retail generation sales. Other operating ~~costs decreased~~expenses increased by $6$38 million in the first ~~six~~nine months of 2011 principally from ~~lower~~Hurricane Irene storm restoration maintenance costs, partially offset by lower labor costs. ~~The amortization~~Amortization of regulatory assets, ~~decreased~~net, decreased by ~~$29~~$134 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011 and higher Hurricane Irene deferred storm restoration costs, partially offset by ~~lower storm cost deferrals and the~~a write-off of nonrecoverable NUG costs.

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METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers ~~electing to retain Met-Ed as their~~who have not elected an alternate power supplier. Met-Ed procures power under its ~~Default Service Plan (DSP)~~DSP, in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.

~~As authorized by Met-Ed’s Board of Directors, Met-Ed returned $150 million of capital to FirstEnergy Corp. on May 31, 2011, the sole owner of all of the shares of Met-Ed’s common stock.~~

For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Results of Operations- Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income ~~increased~~increased by ~~$10~~$21 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The increase was primarily due to decreased purchased power, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.

Revenues

~~Revenue decreased~~Revenues decreased by ~~$279~~$446 million, or ~~30%~~32%, in the first ~~six~~nine months of 2011 compared to the same period of 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.

Distribution revenues decreased by ~~$154~~$252 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution ~~rate. Slightly higher~~rate, partially offset by increased KWH deliveries. Higher KWH deliveries ~~reflect~~to residential customers reflected increased load growth slightly offset by lower weather-related usage ~~due~~that also drove lower deliveries to ~~an 8% increase~~commercial customers. In the industrial sector, KWH deliveries increased primarily as a result of recovering economic conditions in ~~heating degree days offsetting a 15% decrease in cooling degree days in the first six months of 2011, compared to the same period in 2010.~~Met-Ed's service territory.

Changes in distribution KWH deliveries and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:


	~~Increase~~
Distribution KWH Deliveries	Increase (Decrease)

Residential	0.5	~~0.2~~	%
Commercial		(~~4.1~~1.1	)%
Industrial	3.1	~~3.6~~	%

Net Increase in Distribution Deliveries		~~0.5~~	%
1.1			%

Distribution Revenues Decrease
(In millions)
Residential $ (58 )
Commercial (47 )
Industrial (49 )

Decrease in Distribution Revenues
$ (154 )



Distribution Revenues	Decrease
	(In millions)
Residential	$	(95	)
Commercial	(71		)
Industrial	(86		)
Decrease in Distribution Revenues	$	(252	)

Retail generation revenues decreased by ~~$10~~$27 million in the first ~~six~~nine months of 2011 compared to the same period of 2010, due to lower KWH sales to all customer classes resulting from increased customer shopping. ~~Customer shopping has increased for residential, commercial and industrial classes by 1%, 42% and 87%, respectively.~~ The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

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Changes in retail generation KWH sales and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



Retail Generation KWH Sales	Decrease

Residential		(~~1.0~~1.1	)%
Commercial		(~~44.7~~46.4	)%
Industrial		(~~87.6~~90.2	)%

Decrease in Retail Generation Sales		(~~43.1~~43.9	)%

Increase
Retail Generation Revenues (Decrease)
(In millions)
Residential $ 88
Commercial (14 )
Industrial (84 )

Net Decrease in Retail Generation Revenues
$ (10 )



Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	133
Commercial	(18		)
Industrial	(142		)
Net Decrease in Retail Generation Revenues	$	(27	)

Wholesale revenues decreased by ~~$105~~$157 million in the first ~~six~~nine months of 2011, compared to the same period of 2010 ~~primarily due to~~, reflecting lower RPM revenues for Met-Ed ~~ending certain capacity purchase for resale contracts.~~in the PJM market.

Transmission revenues decreased by ~~$11~~$10 million in the first ~~six~~nine months of 2011 compared to the same period of 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed's generation procurement plan. Met-Ed ~~defers~~deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to ~~current period earnings.~~earnings in the period.

Operating Expenses

Total operating expenses ~~decreased $290~~decreased $472 million in the first ~~six~~nine months of 2011 compared to the same period of ~~2010.~~2010. The following table presents changes from the prior year by expense category:


~~Expenses - Changes~~	~~Decrease~~
	*~~(In millions)~~*
~~Purchased power costs~~	$	~~(149~~	)
~~Other operating costs~~		~~(95~~	)
~~Provision for depreciation~~		(1	)
~~Amortization of regulatory assets, net~~		~~(43~~	)
~~General taxes~~		(2	)

~~Decrease in Expenses~~	$	~~(290~~	)



Operating Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(241	)
Other operating expenses	(189		)
Provision for depreciation	1
Amortization of regulatory assets, net	(35		)
General taxes	(8		)
Net Decrease in Operating Expenses	$	(472	)

Purchased power costs decreased by ~~$149~~$241 million in the first ~~six~~nine months of 2011 due to a decrease in KWH purchased to source generation sales requirements, partially offset by higher unit costs. Decreased power purchased from affiliates reflects the increase in customer shopping described above and the termination of Met-Ed's partial requirements PSA with FES at the end of 2010. Other operating costs decreased ~~$95~~$189 million in the first ~~six~~nine months of 2011 compared to the same period in 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above) partially offset by increased costs for energy efficiency programs. The amortization of regulatory assets decreased ~~$43~~by $35 million in the first ~~six~~nine months of 2011 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $2$8 million in the first ~~six~~nine months of 2011 primarily due to lower gross receipts taxes.

Other Expense

In the first ~~six~~nine months of 2011, interest income decreased by $2$3 million primarily due to reduced CTC stranded asset balances compared to the same period of ~~2010.~~2010.

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PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated electric transmission and distribution services. Penelec also procures generation service for those customers ~~electing to retain Penelec as their~~who have not elected an alternative power supplier. Penelec procures power under its ~~Default Service Plan (DSP)~~DSP, in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.

For additional information with respect to Penelec, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Results of Operation- Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income increased by $2$2 million in the first ~~six~~nine months of 2011, compared to the same period of ~~2010.~~2010. The increase was primarily due to lower purchased power and other operating costs, partially offset by lower revenues and higher net amortization of regulatory assets.

~~Revenues~~

Revenues

Revenues decreased by ~~$193~~$322 million, or ~~25%~~28%, in the first ~~six~~nine months of 2011 compared to the same period of ~~2010.~~2010. The decrease in revenue was primarily due to lower distribution, ~~revenues,~~ retail ~~and~~generation, wholesale generation ~~revenues,~~ and transmission revenues.

Distribution revenues decreased by $5$13 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rate, partially offset by a ~~PPUC approved~~PPUC-approved rate adjustment for NUG costs. Lower KWH deliveries to commercial customers reflected decreased weather-related usage compared to the same period of 2010. Higher KWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territories, compared to the first ~~six~~nine months of ~~2010. Lower KWH deliveries to residential and commercial customers in the first six months of 2011 reflected lower weather-related usage as cooling degree days were 10% below the same period in 2010.~~2010.

Changes in distribution KWH deliveries and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



	Increase
Distribution KWH Deliveries	(Decrease)

Residential	—	~~(1.2~~	)%
Commercial		(~~4.7~~3.0	)%
Industrial	4.3	~~7.3~~	%

Net Increase in Distribution Deliveries		~~1.4~~	%
1.0			%

Increase
Distribution Revenues (Decrease)
(In millions)
Residential $ 3
Commercial (14 )
Industrial 6

Net Decrease in Distribution Revenues
$ (5 )



	Increase
Distribution Revenues	(Decrease)
	(In millions)
Residential	$	3
Commercial	(22		)
Industrial	6
Net Decrease in Distribution Revenues	$	(13	)

Retail generation revenues decreased by ~~$80~~$149 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to lower KWH sales for all customer classes resulting from increased customer shopping. ~~The increase in customer shopping for residential, commercial and industrial customer classes was 2%, 45% and 81%, respectively.~~ The impact of customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

~~144~~

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Changes in retail generation KWH sales and revenues in the first ~~six~~nine months of 2011, compared to the same period of 2010, are summarized in the following tables:



Retail Generation KWH Sales	Decrease

Residential		(~~2.7~~3.9	)%
Commercial		(~~47.1~~50.7	)%
Industrial		(~~87.4~~91.0	)%

Decrease in Retail Generation Sales		(~~47.5~~50.7	)%

Increase
Retail Generation Revenues (Decrease)
(In millions)
Residential $ 52
Commercial (35 )
Industrial (97 )

Net Decrease in Retail Generation Revenues
$ (80 )



	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	72
Commercial	(58		)
Industrial	(163		)
Net Decrease in Retail Generation Revenues	$	(149	)

Wholesale generation revenues decreased by ~~$98~~$151 million in the first ~~six~~nine months of 2011, compared to the same period of 2010 ~~due to~~, reflecting lower RPM revenues for Penelec ~~no longer purchasing non-NUG capacity for resale to~~in the PJM ~~market beginning in 2011.~~market.

Transmission revenues decreased by ~~$11~~$9 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Penelec's generation procurement plan. Penelec ~~defers~~deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to ~~current period earnings.~~earnings for the period.

Operating Expenses

Total operating expenses decreased by ~~$200~~$335 million in the first ~~six~~nine months of 2011, as compared with the same period of ~~2010.~~2010. The following table presents changes from the prior year by expense category:

Increase
Expenses - Changes (Decrease)
(In millions)
Purchased power costs $ (192 )
Other operating costs (53 )
Amortization of regulatory assets, net 46
Provision for depreciation (1 )

Net Decrease in Expenses
$ (200 )



	Increase
Operating Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(326	)
Other operating costs	(73		)
Amortization of regulatory assets, net	67
General taxes	(3		)
Net Decrease in Operating Expenses	$	(335	)

Purchased power costs decreased by ~~$192~~$326 million in the first ~~six~~nine months of 2011, compared to the same period of 2010, due to decreased KWH purchased to source generation sales requirements. Decreased power purchased from affiliates reflected the increase in customer shopping described above and the termination of Penelec's partial requirements PSA with FES at the end of 2010. Other operating costs decreased by ~~$53~~$73 million in the first ~~six~~nine months of 2011, due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). The net amortization of ~~net~~ regulatory assets increased by ~~$46~~$67 million in the first ~~six~~nine months of 2011, primarily due to reduced NUG deferrals as a result of a ~~PPUC approved~~PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.

~~145~~

Other Expenses

Other expenses increased by $3 million in the first nine months of 2011, compared to the same period of 2010, due to lower miscellaneous income from jobbing and contracting work.

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Table of Contents


~~ITEM 3.~~		ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES


~~ITEM 4.~~		~~CONTROLS AND PROCEDURES~~

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The management of each registrant, with the participation of each registrant’s chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of the registrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and ~~15(d)-15(e)~~15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer of each registrant have concluded that each respective registrant’s disclosure controls and procedures were effective as of the end of the period covered by this report.

(b) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

During the quarter ended ~~June~~September 30, 2011, other than changes resulting from the Allegheny merger discussed below, there have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s, FES’, OE’s, CEI’s, TE’s, JCP&L’s, Met-Ed’s and Penelec’s internal control over financial reporting.

On February 25, 2011, the merger between FirstEnergy and Allegheny closed. FirstEnergy is currently in the process of integrating Allegheny’s operations, processes, and internal controls. See Note 2 to the consolidated financial statements in Part I, Item I for additional information relating to the merger.

~~146~~

PART II. OTHER INFORMATION


~~ITEM 1.~~		ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 910 and 1011 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS


~~ITEM 1A.~~		~~RISK FACTORS~~

For the quarter ended ~~June~~September 30, 2011, there have been no material changes to the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2010, as modified by changes to certain risk factors disclosed in our Quarterly Report on Form 10-Q for the period ended March 31, 2011.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


~~ITEM 2.~~		~~UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

(c) FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the ~~second~~third quarter of 2011.

Period
April May June Second Quarter

Total Number of Shares Purchased^(a)
213,550 367,422 428,966 1,009,938

Average Price Paid per Share
$ 38.59 $ 42.62 $ 44.44 $ 42.54

Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs — — — —

Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs — — — —



	Period
	July		August		September		Third Quarter

Total Number of Shares Purchased^(a)	69,273		114,813		502,921		687,007
Average Price Paid per Share	$	44.57	$	43.00	$	43.63	$	43.62
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs	—		—		—		—
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs	—		—		—		—


^(a)		Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, ~~Inc,~~Inc., Non-Employee Director Stock Plan, Allegheny Energy, ~~Inc,~~Inc., Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.

ITEM 5. OTHER INFORMATION


~~ITEM 5.~~		~~OTHER INFORMATION~~

Signal Peak Mine Safety

During the third quarter FirstEnergy, through its FEV ~~wholly-owned~~wholly owned subsidiary, ~~has~~held a 50% interest in Global Mining Group LLC, a

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joint venture ~~that owns~~owning Signal Peak which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup Montana. The operation of the Mine is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act).

On October 18, 2011, FirstEnergy announced that Gunvor Group, Ltd. signed an agreement to purchase a one-third interest in the Signal Peak coal mine in Montana. As a result of the sale, FirstEnergy, through its wholly owned subsidiary, FEV, will have a 33-1/3% interest in Global Mining Holding Company, LLC, a joint venture that owns Signal Peak.

Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was enacted on July 21, 2010, contains new reporting requirements regarding mine safety, including, to the extent applicable, disclosing in periodic reports filed under the Securities Exchange Act of 1934 the receipt of certain notifications from the ~~MSHA.~~MSHA

~~147~~

Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended ~~June~~September 30, ~~2011:~~2011:

Signal
Peak
Number of significant and substantial violations of mandatory health or safety standards under 104* 30
Number of orders issued under 104(b)* —
Number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under 104(d)* —
Number of flagrant violations under 110(b)(2)* —
Number of imminent danger orders issued under 107(a)* —
MSHA written notices under Mine Act section 104(e)* of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern —
Pending Mine Safety Commission legal actions (including any contested citations issued) 8
Number of mining related fatalities —
Total dollar value of proposed assessments $ 6,989



	Signal Peak
Number of significant and substantial violations of mandatory health or safety standards under 104*	43
Number of orders issued under 104(b)*	—
Number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under 104(d)*	—
Number of flagrant violations under 110(b)(2)*	—
Number of imminent danger orders issued under 107(a)*	—
MSHA written notices under Mine Act section 104(e)* of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern	—
Pending Mine Safety Commission legal actions (including any contested citations issued)	5
Number of mining related fatalities	—
Total dollar value of proposed assessments	$	6,104


*		References to sections under Mine Act

The inclusion of this information in this report is not an admission by FirstEnergy that it controls Signal Peak or that Signal Peak is FirstEnergy’s subsidiary for purposes of Section 1503 or for any other purpose,

More detailed information about the Mine, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Signal Peak operates the Mine under the MSHA identification number 2401950.

ITEM 6. EXHIBITS



~~ITEM 6.~~		~~EXHIBITS~~


Exhibit Number

FirstEnergy
	~~3.1~~		Amendment to the Amended Articles of Incorporation of FirstEnergy Corp. dated as of February 25, 2011 (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 3.1, File No. 21011)

	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		Fixed charge ratios

	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)

	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

	101	*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

~~148~~


~~Exhibit Number~~
~~FES~~
	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Solutions Corp., and Allegheny Energy Supply Company, LLC, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		~~Fixed charge ratios~~

	~~31.1~~		~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)~~

	~~31.2~~		~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)~~

	32		~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350~~

	~~101~~	*	~~The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended June~~September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

FES
OE
	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		Fixed charge ratios

	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)

	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

	101	*	The following materials from the Quarterly Report on Form 10-Q of ~~Ohio Edison Company.~~FirstEnergy Solutions Corp. for the period ended ~~June~~September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

OE
~~CEI~~
	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		Fixed charge ratios

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Table of Contents


	~~31.1~~
31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)

	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

	101	*	The following materials from the Quarterly Report on Form 10-Q of The Cleveland Electric Illuminating Company. for the period ended June 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

~~149~~


~~Exhibit Number~~
TE
	~~10.1~~		~~Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company,~~ Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		~~Fixed charge ratios~~

	~~31.1~~		~~Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)~~

	~~31.2~~		~~Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)~~

	32		~~Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350~~

	~~101~~	*	~~The following materials from the Quarterly Report on Form 10-Q of The Toledo~~ Edison Company. for the period ended ~~June~~September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

CEI
~~JCP&L~~
	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		Fixed charge ratios

	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)

	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

	101	*	The following materials from the Quarterly Report on Form 10-Q of ~~Jersey Central Power & Light~~The Cleveland Electric Illuminating Company. for the period ended ~~June~~September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

TE
~~Met-Ed~~
	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		Fixed charge ratios

	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)

	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

~~150~~


~~Exhibit Number~~
	101	*	The following materials from the Quarterly Report on Form 10-Q of ~~Metropolitan~~The Toledo Edison Company. for the period ended ~~June~~September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

JCP&L
~~Penelec~~
	~~10.1~~		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.

	12		Fixed charge ratios

	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)

	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)

	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
101	*	The following materials from the Quarterly Report on Form 10-Q of Jersey Central Power & Light Company. for the period ended September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

Met-Ed
12		Fixed charge ratios
31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
101	*	The following materials from the Quarterly Report on Form 10-Q of Metropolitan Edison Company. for the period ended September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.

Penelec
12		Fixed charge ratios
31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
101	*	The following materials from the Quarterly Report on Form 10-Q of Pennsylvania Electric Company. for the period ended ~~June~~September 30, 2011, formatted in XBRL (extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.


*		Users of these data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of these data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of

155

Table of Contents

the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.



Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

000-53742	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402



Large Accelerated Filerþ		FirstEnergy Corp.

Accelerated Filero		N/A

Non-accelerated Filer (Do not check if a smaller reporting company)þ		FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

Smaller Reporting Companyo		N/A



	OUTSTANDING
CLASS	AS OF ~~JULY 29,~~OCTOBER 31, 2011
FirstEnergy Corp., $.10 par value		418,216,437
FirstEnergy Solutions Corp., no par value		7
Ohio Edison Company, no par value		60
The Cleveland Electric Illuminating Company, no par value		67,930,743
The Toledo Edison Company, $5 par value		29,402,054
Jersey Central Power & Light Company, $10 par value		13,628,447
Metropolitan Edison Company, no par value		740,905
Pennsylvania Electric Company, $20 par value		4,427,577



AE		Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
AESC		Allegheny Energy Service Corporation, a subsidiary of AE
AE Supply		Allegheny Energy Supply Company LLC, an unregulated generation subsidiary of AE
AET		Allegheny Energy Transmission, LLC, a parent of TrAIL and PATH
AGC		Allegheny Generating Company, a generation subsidiary of AE
Allegheny		Allegheny Energy, Inc., together with its consolidated subsidiaries
AVE		Allegheny Ventures, Inc.
ATSI		American Transmission Systems, Incorporated, which owns and operates transmission facilities
CEI		The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC		FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FES		FirstEnergy Solutions Corp., which provides energy-related products and services
FESC		FirstEnergy Service Company, which provides legal, financial and other corporate support services
FEV		FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FGCO		FirstEnergy Generation Corp., which owns and operates non-nuclear generating facilities
FirstEnergy		FirstEnergy Corp., a public utility holding company
Global Rail		A joint venture between FEV and WMB Loan Ventures II LLC, that owns coal transportation operations near Roundup, Montana
GPU		GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, that merged with FirstEnergy on November 7, 2001
JCP&L		Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
~~Met-Ed~~Merger Sub	Element Merger Sub, Inc., a Maryland corporation and a wholly owned subsidiary of FirstEnergy
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MP		Monongahela Power Company, a West Virginia electric utility operating subsidiary of AE
NGC		FirstEnergy Nuclear Generation Corp., which owns nuclear generating facilities
OE		Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies		CEI, OE and TE
PATH		Potomac-Appalachian Transmission Highline LLC, a joint venture between Allegheny and a subsidiary of ~~American Electric Power Company, Inc.~~AEP
PATH-VA		PATH Allegheny Virginia Transmission Corporation
PE		The Potomac Edison Company, a Maryland electric operating subsidiary of AE
Penelec		Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn		Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies		Met-Ed, Penelec, Penn and WP
PNBV		PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport		Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak		A joint venture between FEV, ~~and~~ WMB Loan Ventures LLC and Gunvor Group, Ltd. that owns mining operations near Roundup, Montana
TE		The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL		Trans-Allegheny Interstate Line Company
Utilities		OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, MP, PE and WP
Utility Registrants		OE, CEI, TE, JCP&L, Met-Ed and Penelec
WP		West Penn Power Company, a Pennsylvania electric utility operating subsidiary of AE

The following abbreviations and acronyms are used to identify frequently used terms in this report:

ALJ		Administrative Law Judge
~~AOCL~~Anker WV	Anker West Virginia Mining Company, Inc.
Anker Coal	Anker Coal Group, Inc.
AOCL	Accumulated Other Comprehensive Loss
AEP		American Electric Power Company, Inc.
AQC		Air Quality Control
ARO		Asset Retirement Obligation
ARR		Auction Revenue Rights


CCB		Coal Combustion By-products
CDWR		California Department of Water Resources
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act
CFL	Compact Florescent Light-bulb
CO₂		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
CTC		Competitive Transition Charge
CWA		Clean Water Act
CWIP		Construction Work in Progress
DCPD		Deferred Compensation Plan for Outside Directors
DOE		United States Department of Energy
DOJ		United States Department of Justice
DPA		Department of the Public Advocate, Division of Rate Counsel (New Jersey)
DSP		Default Service Plan
~~EDCP~~EDC	Electric Distribution Company
EDCP	Executive Deferred Compensation Plan
EE&C		Energy Efficiency and Conservation
~~EIS~~EGS	Electric Generation Supplier
EIS	Energy Insurance Services, Inc.
EMP		Energy Master Plan
ENEC		Expanded Net Energy Cost
EPA		United States Environmental Protection Agency
~~ESOP~~ERO	Electric Reliability Organization
ESOP	Employee Stock Ownership Plan
ESP		Electric Security Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
~~FMB~~Fitch	Fitch Ratings
FMB	First Mortgage Bond
FPA		Federal Power Act
FRR		Fixed Resource Requirement
FTRs		Financial Transmission Rights
GAAP		Accounting Principles Generally Accepted ~~Accounting Principles~~ in the United States
~~RGGI~~		~~Regional Greenhouse Gas Initiative~~
GHG		Greenhouse Gases
~~IRS~~ICG	International Coal Group inc.
IRS	Internal Revenue Service
JOA		Joint Operating Agreement
kV		Kilovolt
KWH		Kilowatt-hours
LBR		Little Blue Run
LED		Light-Emitting Diode
~~LOC~~LiDAR	Light Detection and Ranging
LOC	Letter of Credit
LSE		Load Serving Entity



Yesþ Noo		FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company



Yeso Noþ		FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

TABLE OF CONTENTS

	Page

	Part I. Financial Information

~~Page~~ Glossary of Terms	iii

Item 1. Financial Statements

	FirstEnergy Corp.
~~Part I. Financial Information~~

~~Glossary of Terms~~		~~iii~~

~~Item 1. Financial Statements~~

~~FirstEnergy Corp.~~

Consolidated Statements of Income		1

Consolidated Statements of Comprehensive Income		2

Consolidated Balance Sheets		3

Consolidated Statements of Cash Flows		4

FirstEnergy Solutions Corp.
Consolidated Statements of Income and Comprehensive Income	5
Consolidated Balance Sheets	6
Consolidated Statements of Cash Flows	7

Ohio Edison Company
Consolidated Statements of Income and Comprehensive Income	8
Consolidated Balance Sheets	9
Consolidated Statements of Cash Flows	10

The Cleveland Electric Illuminating Company
Consolidated Statements of Income and Comprehensive Income	11
Consolidated Balance Sheets	12
Consolidated Statements of Cash Flows	13

The Toledo Edison Company
Consolidated Statements of Income and Comprehensive Income	14
Consolidated Balance Sheets	15
Consolidated Statements of Cash Flows	16

Jersey Central Power & Light Company

Consolidated Statements of Income and Comprehensive Income		5
			17
Consolidated Balance Sheets		6
			18
Consolidated Statements of Cash Flows		7	19

~~Ohio~~Metropolitan Edison Company

Consolidated Statements of Income and Comprehensive Income		8
			20
Consolidated Balance Sheets		9
			21
Consolidated Statements of Cash Flows		10	22

~~The Cleveland~~Pennsylvania Electric ~~Illuminating~~ Company

Consolidated Statements of Income and Comprehensive Income	23

TABLE OF CONTENTS (Continued)
		11
	Page

Consolidated Balance Sheets			12
				24
Consolidated Statements of Cash Flows			13	25

~~The Toledo Edison Company~~Combined Notes To Consolidated Financial Statements				26

~~Consolidated Statements of Income and Comprehensive Income~~			14

~~Consolidated Balance Sheets~~			15

~~Consolidated Statements of Cash Flows~~			16

~~Jersey Central Power & Light Company~~

~~Consolidated Statements of Income and Comprehensive Income~~			17

~~Consolidated Balance Sheets~~			18

~~Consolidated Statements of Cash Flows~~			19

~~Metropolitan Edison Company~~

~~Consolidated Statements of Income and Comprehensive Income~~			20

~~Consolidated Balance Sheets~~			21

~~Consolidated Statements of Cash Flows~~			22

~~Pennsylvania Electric Company~~

~~Consolidated Statements of Income and Comprehensive Income~~			23

~~Consolidated Balance Sheets~~			24

~~Consolidated Statements of Cash Flows~~			25


		~~Page~~

~~Combined Notes To Consolidated Financial Statements~~			27

Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries			84	87

Management’s Narrative Analysis of Results of Operations

FirstEnergy Solutions Corp.			~~131~~
				137
Ohio Edison Company			~~134~~
				141
The Cleveland Electric Illuminating Company			~~136~~
				143
The Toledo Edison Company			~~138~~
				145
Jersey Central Power & Light Company			~~140~~
				147
Metropolitan Edison Company			~~142~~
				149
Pennsylvania Electric Company			~~144~~	151

Item 3. Quantitative and Qualitative Disclosures About Market Risk			~~146~~	153

Item 4. Controls and Procedures — FirstEnergy	153

~~146~~ Part II. Other Information

Item 1. Legal Proceedings	153

~~Part II. Other Information~~Item 1A. Risk Factors				153

~~Item 1. Legal Proceedings~~			~~147~~

~~Item 1A. Risk Factors~~			~~147~~

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			~~147~~	153

Item 5. Other Information			~~147~~	153

Item 6. Exhibits			~~148~~

~~Exhibit 10.1~~154
~~Exhibit 12~~
~~Exhibit 31.1~~
~~Exhibit 31.2~~
~~Exhibit 32~~
~~EX-101 INSTANCE DOCUMENT~~
~~EX-101 SCHEMA DOCUMENT~~
~~EX-101 CALCULATION LINKBASE DOCUMENT~~
~~EX-101 LABELS LINKBASE DOCUMENT~~
~~EX-101 PRESENTATION LINKBASE DOCUMENT~~
~~EX-101 DEFINITION LINKBASE DOCUMENT~~

GLOSSARY OF TERMS, Continued

ASLB	Atomic Safety and Licensing Board
BGS		Basic Generation Service
BMP		Bruce Mansfield Plant
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CATR		Clean Air Transport Rule
CBP		Competitive Bid Process

GLOSSARY OF TERMS, Continued

LTIP		Long-Term Incentive Plan
MACT		Maximum Achievable Control Technology
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MEIUG		Met-Ed Industrial Users Group
MISO		Midwest Independent Transmission System Operator, Inc.
Moody’s		Moody’s Investors Service, Inc.
MRO		Market Rate Offer
MSHA		Mine Safety and Health Administration
MTEP		MISO Regional Transmission Expansion Plan
MVP		Multi-value Project
MW		Megawatts
MWH		Megawatt-hours
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trusts
NERC		North American Electric Reliability Corporation
NJBPU		New Jersey Board of Public Utilities
NNSR		Non-Attainment New Source Review
NOAC		Northwest Ohio Aggregation Coalition
NOPEC		Northeast Ohio Public Energy Council
NOV		Notice of Violation
NO_X	NOx	Nitrogen Oxide
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission


NSR		New Source Review
NUG		Non-Utility Generation
NUGC		Non-Utility Generation Charge
~~NYSEG~~NYPSC	New York State Public Service Commission
NYSEG	New York State Electric and Gas
~~OCC~~OCA	Office of Consumer Advocate
OCC	Ohio Consumers’ Counsel
OCI		Other Comprehensive Income
OPEB		Other Post-Employment Benefits
OSBA		Office of Small Business Advocate
OVEC		Ohio Valley Electric Corporation
PAD	Pre-application Document
PA DEP		Pennsylvania Department of Environmental Protection
PCRB		Pollution Control Revenue Bond
PICA		Pennsylvania Intergovernmental Cooperation Authority
PJM		PJM Interconnection L. L. C.
POLR		Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC		Pennsylvania Public Utility Commission
~~PSCWV~~		~~Public Service Commission of West Virginia~~
PSA		Power Supply Agreement
PSD		Prevention of Significant Deterioration
PUCO		Public Utilities Commission of Ohio
PURPA		Public Utility Regulatory Policies Act of 1978
RECs		Renewable Energy Credits
~~RFP~~RFC	ReliabilityFirst Corporation
RFP	Request for Proposal
RGGI		Regional Greenhouse Gas Initiative
~~RPM~~Rider DCR	Delivery Capital Recovery Rider

GLOSSARY OF TERMS, Continued

ROE	Return on Equity
RPM	Reliability Pricing Model
RTEP		Regional Transmission Expansion Plan
RTC		Regulatory Transition Charge
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Service
SB221		Amended Substitute Senate Bill 221
SBC		Societal Benefits Charge
SEC		~~U.S.~~United States Securities and Exchange Commission
~~SIP~~SECA	Seams Elimination Cost Adjustment
SIP	State Implementation Plan(s) Under the Clean Air Act
SMIP		Smart Meter Implementation Plan
SNCR		Selective Non-Catalytic Reduction
SO₂		Sulfur Dioxide
SOS		Standard Offer Service
~~TBC~~SRECs	Solar Renewable Energy Credits
TBC	Transition Bond Charge
TDS		Total Dissolved Solid
TMDL		Total Maximum Daily Load
TMI-2		Three Mile Island Unit 2
~~TSC~~TO	Transmission Owner
TSC	Transmission Service Charge
VIE		Variable Interest Entity
VSCC		Virginia State Corporation Commission
WVDEP		West Virginia Department of Environmental Protection
WVPSC		Public Service Commission of West Virginia


	Three Months						Six Months
	Ended June 30						Ended June 30
In millions, except per share amounts	2011			2010			2011			2010
REVENUES:
Electric utilities	$	2,590		$	2,373		$	4,925		$	4,916
Unregulated businesses		1,470			766			2,711			1,522

Total revenues*		4,060			3,139			7,636			6,438


EXPENSES:
Fuel		635			350			1,088			684
Purchased power		1,220			1,063			2,406			2,301
Other operating expenses		1,105			673			2,138			1,374
Provision for depreciation		282			190			502			383
Amortization of regulatory assets		90			161			222			373
General taxes		242			176			479			381

Total expenses		3,574			2,613			6,835			5,496


OPERATING INCOME		486			526			801			942


OTHER INCOME (EXPENSE):
Investment income		31			31			52			47
Interest expense		(265	)		(207	)		(496	)		(420	)
Capitalized interest		20			40			38			81

Total other expense		(214	)		(136	)		(406	)		(292	)


INCOME BEFORE INCOME TAXES		272			390			395			650

INCOME TAXES		101			134			179			245


NET INCOME		171			256			216			405

Loss attributable to noncontrolling interest		(10	)		(9	)		(15	)		(15	)


EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	181		$	265		$	231		$	420


EARNINGS PER SHARE OF COMMON STOCK:
Basic	$	0.43		$	0.87		$	0.61		$	1.38
Diluted	$	0.43		$	0.87		$	0.61		$	1.37
AVERAGE SHARES OUTSTANDING:
Basic		418			304			380			304
Diluted		420			305			382			305
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK		—			—		$	0.55		$	0.55


	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010

STATEMENTS OF INCOME
REVENUES:
Electric sales	$	202,148		$	280,180		$	408,890		$	592,677
Excise tax collections		15,706			15,495			33,851			33,068

Total revenues		217,854			295,675			442,741			625,745


EXPENSES:
Purchased power from affiliates		36,040			99,422			82,208			208,815
Purchased power from non-affiliates		23,099			32,651			41,319			70,049
Other operating expenses		31,625			28,937			66,661			60,172
Provision for depreciation		18,488			18,336			36,914			36,447
Amortization of regulatory assets, net		18,166			30,807			41,536			75,946
General taxes		36,954			28,840			77,166			67,329

Total expenses		164,372			238,993			345,804			518,758


OPERATING INCOME		53,482			56,682			96,937			106,987


OTHER INCOME (EXPENSE):
Investment income		5,637			6,605			12,234			14,152
Miscellaneous income		1,038			675			1,674			1,257
Interest expense		(32,135	)		(33,262	)		(65,213	)		(66,883	)
Capitalized interest		36			7			63			33

Total other expense		(25,424	)		(25,975	)		(51,242	)		(51,441	)


INCOME BEFORE INCOME TAXES		28,058			30,707			45,695			55,546

INCOME TAXES		6,209			8,785			10,645			19,628


*		Includes excise tax collections of ~~$116~~$137 million and ~~$99~~$120 million in the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~$235~~$371 million and ~~$208~~$328 million in the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.



(In millions, except share amounts)	September 30, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	291		$	1,019
Receivables-
Customers, net of allowance for uncollectible accounts of $37 in 2011 and $36 in 2010	1,633			1,392
Other, net of allowance for uncollectible accounts of $9 in 2011 and $8 in 2010	247			176
Materials and supplies, at average cost	822			638
Prepaid taxes	214			199
Derivatives	195			182
Other	189			92
	3,591			3,698

ASSETS PENDING SALE (Note 15)	402			—

PROPERTY, PLANT AND EQUIPMENT:
In service	39,350			29,451
Less — Accumulated provision for depreciation	11,803			11,180
	27,547			18,271
Construction work in progress	1,720			1,517
	29,267			19,788
INVESTMENTS:
Nuclear plant decommissioning trusts	2,060			1,973
Investments in lease obligation bonds	414			476
Nuclear fuel disposal trust	218			208
Other	440			345
	3,132			3,002
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,448			5,575
Regulatory assets	2,160			1,826
Intangible assets	910			256
Other	751			660
	10,269			8,317
	$	46,661		$	34,805
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,840		$	1,486
Short-term borrowings	—			700
Accounts payable	1,009			872
Accrued taxes	482			326
Accrued compensation and benefits	350			315
Derivatives	202			266
Other	980			733
	4,863			4,698

LIABILITIES RELATED TO ASSETS PENDING SALE (Note 15)	401			—

CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 and 375,000,000 shares, respectively- 418,216,437 and 304,835,407 shares outstanding, respectively	42			31
Other paid-in capital	9,782			5,444
Accumulated other comprehensive loss	(1,436		)	(1,539		)
Retained earnings	4,658			4,609
Total common stockholders’ equity	13,046			8,545
Noncontrolling interest	(31		)	(32		)
Total equity	13,015			8,513
Long-term debt and other long-term obligations	15,823			12,579
	28,838			21,092
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	5,315			2,879
Retirement benefits	2,045			1,868
Asset retirement obligations	1,473			1,407
Deferred gain on sale and leaseback transaction	934			959
Adverse power contract liability	665			466
Other	2,127			1,436
	12,559			9,015
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	46,661		$	34,805



(In thousands, except share amounts)	September 30, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	244		$	238
Receivables-
Customers, net of allowance for uncollectible accounts of $3,169 in 2011 and $4,589 in 2010	99,752			183,744
Affiliated companies	20,962			77,047
Other	7,077			11,544
Notes receivable from affiliated companies	110,999			23,236
Materials and supplies, at average cost	18,118			398
Prepayments and other	5,208			3,258
	262,360			299,465
UTILITY PLANT:
In service	2,434,038			2,396,893
Less — Accumulated provision for depreciation	950,395			932,246
	1,483,643			1,464,647
Construction work in progress	64,139			38,610
	1,547,782			1,503,257
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes	286,814			340,029
Other	10,035			10,074
	296,849			350,103
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	1,688,521			1,688,521
Regulatory assets	290,556			370,403
Pension assets	15,240			—
Property taxes	80,614			80,614
Other	12,826			11,486
	2,087,757			2,151,024
	$	4,194,748		$	4,303,849
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	202		$	161
Short-term borrowings from affiliated companies	23,303			105,996
Accounts payable-
Affiliated companies	24,236			32,020
Other	13,271			14,947
Accrued taxes	76,256			84,668
Accrued interest	39,253			18,555
Other	41,058			44,569
	217,579			300,916
CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 105,000,000 shares - 67,930,743 shares outstanding	889,221			887,087
Accumulated other comprehensive loss	(145,532		)	(153,187		)
Retained earnings	565,578			568,906
Total common stockholder’s equity	1,309,267			1,302,806
Noncontrolling interest	14,886			18,017
Total equity	1,324,153			1,320,823
Long-term debt and other long-term obligations	1,831,032			1,852,530
	3,155,185			3,173,353
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	636,842			622,771
Accumulated deferred investment tax credits	10,363			10,994
Retirement benefits	77,526			95,654
Other	97,253			100,161
	821,984			829,580
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,194,748		$	4,303,849


Note		Page
Number		Number

1	Organization and Basis of Presentation		27

2	Merger		27

3	Earnings Per Share		31

4	Fair Value of Instruments		31

5	Derivative Instruments		45

6	Pension Benefits and Other Postretirement Benefits		50

7	Variable Interest Entities		52

8	Income Taxes		53

9	Commitments, Guarantees and Contingencies		54

10	Regulatory Matters		61

11	Stock-Based Compensation Plans		70

12	New Accounting Standards and Interpretations		72

13	Segment Information		72

14	Impairment of Long-Lived Assets		74

15	Asset Retirement Obligations		75

16	Supplemental Guarantor Information		75



Note Number		Page Number

1	Organization and Basis of Presentation	27

2	Merger	27

3	Goodwill	30

4	Earnings Per Share	31

5	Fair Value Measurements	31

6	Derivative Instruments	46

7	Pension and Other Postretirement Benefits	51

8	Variable Interest Entities	53

9	Income Taxes	54

10	Commitments, Guarantees and Contingencies	55

11	Regulatory Matters	63

12	Stock-Based Compensation Plans	72

13	New Accounting Standards and Interpretations	73

14	Segment Information	74

15	Impairments and Long-Lived Assets Pending Sale	77

16	Asset Retirement Obligations	77

17	Supplemental Guarantor Information	78


Shares of Allegheny common stock outstanding on February 24, 2011		170
Exchange ratio		0.667

Number of shares of FirstEnergy common stock issued		113
Closing price of FirstEnergy common stock on February 24, 2011	$	38.16

Fair value of shares issued by FirstEnergy	$	4,327
Fair value of replacement share-based compensation awards relating to pre-merger service		27

Total consideration transferred	$	4,354



Shares of AE common stock outstanding on February 24, 2011	170
Exchange ratio	0.667
Number of shares of FirstEnergy common stock issued	113
Closing price of FirstEnergy common stock on February 24, 2011	$	38.16
Fair value of shares issued by FirstEnergy	$	4,327
Fair value of replacement share-based compensation awards relating to pre-merger service	27
Total consideration transferred	$	4,354


(In millions)

Current assets	$	1,494
Property, plant and equipment		9,656
Investments		138
Goodwill		881
Other noncurrent assets		1,347
Current liabilities		(716	)
Noncurrent liabilities		(3,452	)
Long-term debt and other long-term obligations		(4,994	)

	$	4,354



(In millions)

Current assets	$	1,493
Property, plant and equipment	9,656
Investments	138
Goodwill	873
Other noncurrent assets	1,352
Current liabilities	(718		)
Noncurrent liabilities	(3,446		)
Long-term debt and other long-term obligations	(4,994		)
	$	4,354


			Competitive		Regulated
	Regulated		Energy		Independent		Other/
(In millions)	Distribution		Services		Transmission		Corporate		Consolidated

Balance as of December 31, 2010	$	5,551	$	24	$	—	$	—	$	5,575

Merger with Allegheny		—		881		—		—		881


Balance as of June 30, 2011	$	5,551	$	905	$	—	$	—	$	6,456


	Preliminary		Weighted Average
(In millions)	Valuation		Amortization Period
Above market contracts:
Energy contracts	$	189	10 years
NUG contracts		124	25 years
Coal supply contracts		516	8 years

		829

Below market contracts:
NUG contracts		143	13 years
Coal supply contracts		83	7 years
Transportation contract		35	8 years

		261


Net intangible assets	$	568



(In millions)	Preliminary Valuation		Weighted Average Amortization Period
Above market contracts:
Energy contracts	$	189	10 years
NUG contracts	124		25 years
Coal supply contracts	516		8 years
	829
Below market contracts:
NUG contracts	143		13 years
Coal supply contracts	83		7 years
Transportation contract	35		8 years
	261

Net intangible assets	$	568


	Intangible
(In millions)	Assets
Purchase contract assets
NUG	$	198
OVEC		54

		252

Intangible assets
Coal contracts		487
FES customer intangible assets		129
Energy contracts		105

		721


Total intangible assets	$	973



(In millions)	Intangible Assets
Purchase contract assets:
NUG	$	181
OVEC	53
	234

Other intangible assets:
Coal contracts	465
FES customer intangible assets	126
Energy contracts	85
	676
Total intangible assets	$	910


	April 1 –		February 26 –
(In millions, except per share amounts)	June 30, 2011		June 30, 2011

Total revenues	$	1,181	$	1,618
Earnings available to FirstEnergy Corp.⁽¹⁾		63		17

Basic Earnings Per Share	$	0.15	$	0.04
Diluted Earnings Per Share	$	0.15	$	0.04



	July 1 -		February 25 -
(In millions, except per share amounts)	September 30, 2011		September 30, 2011
Total revenues	$	1,273	$	2,891
Earnings Available to FirstEnergy Corp.⁽¹⁾	$	130	$	147

Basic Earnings Per Share	$	0.31	$	0.37
Diluted Earnings Per Share	$	0.31	$	0.37


⁽¹⁾		Includes Allegheny’s after-tax merger costs of $4$1 million and ~~$56~~$57 million, respectively.


	Three Months Ended				Six Months Ended
(Pro forma amounts in millions, except	June 30				June 30
per share amounts)	2011		2010		2011		2010

Revenues	$	4,062	$	4,401	$	8,848	$	9,086
Earnings available to FirstEnergy	$	186	$	389	$	323	$	644

Basic Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.54

Diluted Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.53


	Three Months				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2011		2010		2011		2010
	*(In millions, except per share amounts)*

Earnings available to FirstEnergy Corp.	$	181	$	265	$	231	$	420

Weighted average number of basic shares outstanding⁽¹⁾		418		304		380		304
Assumed exercise of dilutive stock options and awards		2		1		2		1

Weighted average number of diluted shares outstanding⁽¹⁾		420		305		382		305


Basic earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.38

Diluted earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.37



	Three Months Ended September 30				Nine Months Ended September 30
Reconciliation of Basic and Diluted Earnings per Share	Three Months Ended September 30				Nine Months Ended September 30
of Common Stock	2011		2010		2011		2010
	(In millions, except per share amounts)

Earnings Available to FirstEnergy Corp.	$	511	$	179	$	742	$	599

Weighted average number of basic shares outstanding⁽¹⁾	418		304		392		304
Assumed exercise of dilutive stock options and awards⁽²⁾	2		1		2		1
Weighted average number of diluted shares outstanding⁽¹⁾	420		305		394		305

Basic earnings per share of common stock	$	1.22	$	0.59	$	1.89	$	1.97
Diluted earnings per share of common stock	$	1.22	$	0.59	$	1.88	$	1.96