FE 10-Q Quarterly Report Sept. 30, 2011 | Alphaminr
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FE 10-Q Quarter ended Sept. 30, 2011

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10-Q 1 fe-9302011x10q.htm FORM 10-Q FE-9.30.2011-10Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-Q
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to __________________ _
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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
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
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes þ No o
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
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer þ
FirstEnergy Corp.
Accelerated Filer o
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 Company o
N/A
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No þ
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
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
OUTSTANDING
CLASS
AS OF 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

FirstEnergy Corp. is the sole holder of 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 common stock.
This combined Form 10-Q is separately filed by 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. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.

FirstEnergy Web Site
Each of the registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s Internet web site at www.firstenergycorp.com.
These reports are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post important information on FirstEnergy’s Internet web site and recognize FirstEnergy’s Internet web site as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under SEC Regulation FD. Information contained on FirstEnergy’s Internet web site shall not be deemed incorporated into, or to be part of, this report.
OMISSION OF CERTAIN INFORMATION
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 meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

Forward-Looking Statements: This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.

Actual results may differ materially due to:
•
The speed and nature of increased competition in the electric utility industry.
•
The impact of the regulatory process on the pending matters in the various states in which we do business including, but not limited to, matters related to rates.
•
The status of the PATH project in light of PJM’s direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
•
Business and regulatory impacts from ATSI’s realignment into PJM Interconnection, L.L.C.
•
Economic or weather conditions affecting future sales and margins.
•
Changes in markets for energy services.
•
Changing energy and commodity market prices and availability.
•
Financial derivative reforms that could increase our liquidity needs and collateral costs.
•
The continued ability of FirstEnergy’s regulated utilities to collect transition and other costs.
•
Operation and maintenance costs being higher than anticipated.
•
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR, and the effects of the EPA’s recently released MACT proposal to establish certain mercury and other emission standards for electric generating units.
•
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
•
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan’s Fukushima Daiichi Nuclear Plant).
•
Issues that could delay the current outage at Davis-Besse for the installation of the new reactor vessel head, including indications of cracking in the plant's shield building currently under investigation.
•
Adverse legal decisions and outcomes related to Met-Ed’s and Penelec’s ability to recover certain transmission costs through their transmission service charge riders.
•
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
•
Replacement power costs being higher than anticipated or inadequately hedged.
•
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
•
Changes in customers’ demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
•
The ability to accomplish or realize anticipated benefits from strategic goals.
•
FirstEnergy's ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
•
The ability to experience growth in the distribution business.
•
The changing market conditions that could affect the value of assets held in FirstEnergy’s nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy and its subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
•
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.
•
Changes in general economic conditions affecting FirstEnergy and its subsidiaries.
•
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy’s and its subsidiaries’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
•
The continuing uncertainty of the national and regional economy and its impact on FirstEnergy’s and its subsidiaries’ major industrial and commercial customers.
•
Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.
•
Issues arising from the recently completed merger of FirstEnergy and Allegheny Energy, Inc. and the ongoing coordination of their combined operations including FirstEnergy’s ability to maintain relationships with customers, employees and suppliers, as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.
•
The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.
Dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the

indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.

TABLE OF CONTENTS

Page
Part I. Financial Information
Item 1. Financial Statements

i

TABLE OF CONTENTS (Continued)

Page

ii

GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

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
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 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, 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
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

iii

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
CCB
Coal Combustion By-products
CDWR
California Department of Water Resources
CERCLA
Comprehensive Environmental Response, Compensation, and Liability Act
CFL
Compact Florescent Light-bulb
CO 2
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
EDC
Electric Distribution Company
EDCP
Executive Deferred Compensation Plan
EE&C
Energy Efficiency and Conservation
EGS
Electric Generation Supplier
EIS
Energy Insurance Services, Inc.
EMP
Energy Master Plan
ENEC
Expanded Net Energy Cost
EPA
United States Environmental Protection Agency
ERO
Electric Reliability Organization
ESOP
Employee Stock Ownership Plan
ESP
Electric Security Plan
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings
FMB
First Mortgage Bond
FPA
Federal Power Act
FRR
Fixed Resource Requirement
FTRs
Financial Transmission Rights
GAAP
Accounting Principles Generally Accepted in the United States
GHG
Greenhouse Gases
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
LiDAR
Light Detection and Ranging
LOC
Letter of Credit
LSE
Load Serving Entity

iv

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
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
NYPSC
New York State Public Service Commission
NYSEG
New York State Electric and Gas
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
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
RFC
Reliability First Corporation
RFP
Request for Proposal
RGGI
Regional Greenhouse Gas Initiative
Rider DCR
Delivery Capital Recovery Rider

v

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
United States Securities and Exchange Commission
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
SO 2
Sulfur Dioxide
SOS
Standard Offer Service
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
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

vi

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
In millions, except per share amounts
2011
2010
2011
2010
REVENUES:
Electric utilities
$
3,041

$
2,757

$
7,966

$
7,673

Unregulated businesses
1,678

971

4,389

2,495

Total revenues*
4,719

3,728

12,355

10,168

OPERATING EXPENSES:
Fuel
632

400

1,720

1,084

Purchased power
1,349

1,319

3,755

3,620

Other operating expenses
1,024

738

3,130

2,112

Provision for depreciation
292

182

794

565

Amortization of regulatory assets
122

176

344

549

General taxes
269

206

748

587

Impairment of long-lived assets
9

292

41

294

Total operating expenses
3,697

3,313

10,532

8,811

OPERATING INCOME
1,022

415

1,823

1,357

OTHER INCOME (EXPENSE):
Investment income
48

46

100

93

Interest expense
(267
)
(208
)
(763
)
(628
)
Capitalized interest
17

41

55

122

Total other expense
(202
)
(121
)
(608
)
(413
)
INCOME BEFORE INCOME TAXES
820

294

1,215

944

INCOME TAXES
311

119

490

364

NET INCOME
509

175

725

580

Loss attributable to noncontrolling interest
(2
)
(4
)
(17
)
(19
)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
$
511

$
179

$
742

$
599

EARNINGS PER SHARE OF COMMON STOCK:
Basic
$
1.22

$
0.59

$
1.89

$
1.97

Diluted
$
1.22

$
0.59

$
1.88

$
1.96

AVERAGE SHARES OUTSTANDING:
Basic
418

304

392

304

Diluted
420

305

394

305

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
$
1.10

$
1.10

$
1.65

$
1.65

*
Includes excise tax collections of $137 million and $120 million in the three months ended September 30, 2011 and 2010 , respectively, and $371 million and $328 million in the nine months ended September 30, 2011 and 2010 , respectively.

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


1

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Three Months
Ended September 30
Nine Months
Ended September 30
(In millions)
2011
2010
2011
2010
NET INCOME
$
509

$
175

$
725

$
580

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits
15

17

145

47

Unrealized gain on derivative hedges
2

6

13

16

Change in unrealized gain on available-for-sale securities
(26
)
20

(7
)
32

Other comprehensive income (loss)
(9
)
43

151

95

Income taxes (benefits) on other comprehensive income (loss)
(6
)
14

48

30

Other comprehensive income (loss), net of tax
(3
)
29

103

65

COMPREHENSIVE INCOME
506

204

828

645


COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
(2
)
(4
)
(17
)
(19
)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.
$
508

$
208

$
845

$
664


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



2

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(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


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


3

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In millions)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
725

$
580

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
794

565

Amortization of regulatory assets
344

549

Nuclear fuel and lease amortization
152

123

Deferred purchased power and other costs
(222
)
(192
)
Deferred income taxes and investment tax credits, net
636

259

Deferred rents and lease market valuation liability
(17
)
(21
)
Accrued compensation and retirement benefits
95

48

Commodity derivative transactions, net
(22
)
(40
)
Pension trust contributions
(375
)
—

Asset impairments
59

315

Cash collateral paid, net
(66
)
(54
)
Interest rate swap transactions
—

129

Gain on investment securities held in trusts
(56
)
(39
)
Decrease (increase) in operating assets-
Receivables
139

(172
)
Materials and supplies
62

(6
)
Prepayments and other current assets
(1
)
(4
)
Increase (decrease) in operating liabilities-
Accounts payable
(154
)
(16
)
Accrued taxes
20

(18
)
Accrued interest
67

63

Other
49

4

Net cash provided from operating activities
2,229

2,073

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt
603

251

Redemptions and Repayments-
Long-term debt
(1,581
)
(422
)
Short-term borrowings, net
(700
)
(171
)
Common stock dividend payments
(651
)
(503
)
Other
(73
)
(25
)
Net cash used for financing activities
(2,402
)
(870
)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(1,529
)
(1,467
)
Proceeds from asset sales
519

117

Sales of investment securities held in trusts
3,678

2,577

Purchases of investment securities held in trusts
(3,801
)
(2,610
)
Customer acquisition costs
(2
)
(110
)
Cash investments
51

56

Cash received in Allegheny merger
590

—

Other
(61
)
(8
)
Net cash used for investing activities
(555
)
(1,445
)

Net change in cash and cash equivalents
(728
)
(242
)
Cash and cash equivalents at beginning of period
1,019

874

Cash and cash equivalents at end of period
$
291

$
632

SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: merger with Allegheny, common stock issued
$
4,354

$
—


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


4

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In millions)
2011
2010
2011
2010
STATEMENTS OF INCOME

REVENUES:
Electric sales to non-affiliates
$
1,251

$
951

$
3,348

$
2,348

Electric sales to affiliates
143

600

574

1,746

Other
73

38

229

209

Total revenues
1,467

1,589

4,151

4,303

OPERATING EXPENSES:
Fuel
386

391

1,045

1,062

Purchased power from affiliates
55

116

189

246

Purchased power from non-affiliates
328

446

954

1,206

Other operating expenses
405

308

1,315

916

Provision for depreciation
69

60

205

186

General taxes
31

22

91

71

Impairment of long-lived assets
2

292

22

294

Total operating expenses
1,276

1,635

3,821

3,981

OPERATING INCOME (LOSS)
191

(46
)
330

322

OTHER INCOME (EXPENSE):
Investment income
28

30

50

44

Miscellaneous income (expense)
9

3

17

10

Interest expense — affiliates
(2
)
(2
)
(5
)
(7
)
Interest expense — other
(51
)
(50
)
(156
)
(151
)
Capitalized interest
8

23

28

67

Total other income (expense)
(8
)
4

(66
)
(37
)

INCOME (LOSS) BEFORE INCOME TAXES

183

(42
)
264

285

INCOME TAXES (BENEFITS)
73

(5
)
98

108


NET INCOME (LOSS)
110

(37
)
166

177

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits
1

1

4

(8
)
Unrealized gain (loss) on derivative hedges
(1
)
3

4

7

Change in unrealized gain on available-for-sale securities
(22
)
18

(7
)
29

Other comprehensive income (loss)
(22
)
22

1

28

Income taxes (benefits) on other comprehensive income (loss)
(9
)
8

(1
)
10

Other comprehensive income (loss), net of tax
(13
)
14

2

18


COMPREHENSIVE INCOME (LOSS)
$
97

$
(23
)
$
168

$
195


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


5

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions, except share amounts)
September 30,
2011
December 31,
2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$
6

$
9

Receivables-
Customers, net of allowance for uncollectible accounts of $19 in 2011 and $17 in 2010
452

366

Affiliated companies
478

478

Other, net of allowances for uncollectible accounts of $3 in 2011 and $7 in 2010
61

90

Notes receivable from affiliated companies
340

397

Materials and supplies, at average cost
477

545

Derivatives
170

182

Prepayments and other
61

59

2,045

2,126

PROPERTY, PLANT AND EQUIPMENT:
In service
11,440

11,321

Less — Accumulated provision for depreciation
4,314

4,024

7,126

7,297

Construction work in progress
818

1,063

7,944

8,360

INVESTMENTS:
Nuclear plant decommissioning trusts
1,187

1,146

Other
10

12

1,197

1,158

DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles
126

134

Goodwill
24

24

Property taxes
41

41

Unamortized sale and leaseback costs
68

73

Derivatives
136

98

Other
83

48

478

418

$
11,664

$
12,062

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
877

$
1,132

Short-term borrowings-
Affiliated companies
—

12

Accounts payable-
Affiliated companies
425

467

Other
170

241

Derivatives
175

266

Other
323

322

1,970

2,440

CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding
1,492

1,490

Accumulated other comprehensive loss
(118
)
(120
)
Retained earnings
2,584

2,418

Total common stockholder’s equity
3,958

3,788

Long-term debt and other long-term obligations
2,892

3,181

6,850

6,969

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction
934

959

Accumulated deferred income taxes
303

58

Asset retirement obligations
889

892

Retirement benefits
299

285

Lease market valuation liability
183

217

Derivatives
67

81

Other
169

161

2,844

2,653

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)


$
11,664

$
12,062


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


6

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In millions)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
166

$
177

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
205

186

Nuclear fuel and lease amortization
151

126

Deferred rents and lease market valuation liability
(37
)
(41
)
Deferred income taxes and investment tax credits, net
229

96

Asset impairments
40

315

Accrued compensation and retirement benefits
16

16

Gain on investment securities held in trusts
(48
)
(34
)
Commodity derivative transactions, net
(54
)
(40
)
Cash collateral paid, net
(81
)
(54
)
Decrease (increase) in operating assets-
Receivables
(34
)
(91
)
Materials and supplies
72

(15
)
Prepayments and other current assets
8

36

Increase (decrease) in operating liabilities-
Accounts payable
(113
)
(50
)
Accrued taxes
24

(8
)
Other
(7
)
5

Net cash provided from operating activities
537

624

CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt
247

250

Redemptions and repayments-
Long-term debt
(791
)
(296
)
Short-term borrowings, net
(12
)
—

Other
(10
)
(1
)
Net cash used for financing activities
(566
)
(47
)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(473
)
(801
)
Proceeds from asset sales
519

117

Sales of investment securities held in trusts
1,613

1,478

Purchases of investment securities held in trusts
(1,654
)
(1,511
)
Loans to affiliated companies, net
57

303

Customer acquisition costs
(2
)
(110
)
Leasehold improvement payments to affiliated companies
—

(51
)
Other
(34
)
(2
)
Net cash provided from (used for) investing activities
26

(577
)
Net change in cash and cash equivalents
(3
)
—

Cash and cash equivalents at beginning of period
9

—

Cash and cash equivalents at end of period
$
6

$
—


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


7

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In millions)
2011
2010
2011
2010
STATEMENTS OF INCOME

REVENUES:
Electric sales
$
441

$
457

$
1,165

$
1,352

Excise and gross receipts tax collections
29

30

82

82

Total revenues
470

487

1,247

1,434


OPERATING EXPENSES:
Purchased power from affiliates
57

137

220

425

Purchased power from non-affiliates
80

84

203

257

Other operating expenses
119

95

331

272

Provision for depreciation
23

22

67

66

Amortization of regulatory assets, net
46

10

49

48

General taxes
51

49

146

140

Total operating expenses
376

397

1,016

1,208

OPERATING INCOME
94

90

231

226

OTHER INCOME (EXPENSE):
Investment income
10

5

19

17

Miscellaneous income
1

2

1

2

Interest expense
(22
)
(22
)
(66
)
(66
)
Capitalized interest
—

—

1

1

Total other expense
(11
)
(15
)
(45
)
(46
)
INCOME BEFORE INCOME TAXES
83

75

186

180


INCOME TAXES
33

29

67

61

NET INCOME
50

46

119

119


OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits
2

1

3

5

Change in unrealized gain on available-for-sale securities
(3
)
2

(1
)
3

Other comprehensive income
(1
)
3

2

8

Income taxes (benefits) on other comprehensive income
(1
)
1

(2
)
1

Other comprehensive income, net of tax
—

2

4

7


COMPREHENSIVE INCOME

$
50

$
48

$
123

$
126


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


8

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions, except share amounts)
September 30,
2011
December 31,
2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$
—

$
420

Receivables-
Customers, net of allowance for uncollectible accounts of $4 in 2011 and 2010
177

177

Affiliated companies
76

118

Other
30

12

Notes receivable from affiliated companies
180

17

Prepayments and other
36

7

499

751

UTILITY PLANT:
In service
3,206

3,137

Less — Accumulated provision for depreciation
1,241

1,208

1,965

1,929

Construction work in progress
78

45

2,043

1,974

OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds
178

190

Nuclear plant decommissioning trusts
136

127

Other
91

96

405

413

DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets
343

400

Pension assets
66

29

Property taxes
71

71

Unamortized sale and leaseback costs
26

30

Other
16

18

522

548

$
3,469

$
3,686

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
1

$
1

Short-term borrowings-
Affiliated companies
—

142

Other
—

1

Accounts payable-
Affiliated companies
100

99

Other
36

30

Accrued taxes
79

79

Accrued interest
25

25

Other
112

75

353

452

CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding
785

952

Accumulated other comprehensive loss
(175
)
(179
)
Retained earnings
160

141

Total common stockholder’s equity
770

914

Noncontrolling interest
6

6

Total equity
776

920

Long-term debt and other long-term obligations
1,146

1,152

1,922

2,072

NONCURRENT LIABILITIES:
Accumulated deferred income taxes
751

696

Accumulated deferred investment tax credits
9

10

Retirement benefits
184

184

Asset retirement obligations
70

75

Other
180

197

1,194

1,162

COMMITMENTS AND CONTINGENCIES (Note 10)


$
3,469

$
3,686


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


9

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In millions)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
119

$
119

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
67

66

Amortization of regulatory assets, net
49

48

Purchased power cost recovery reconciliation
(9
)
4

Amortization of lease costs
28

28

Deferred income taxes and investment tax credits, net
67

8

Accrued compensation and retirement benefits
(10
)
(17
)
Cash collateral from suppliers, net
1

23

Pension trust contribution
(27
)
—

Decrease (increase) in operating assets-
Receivables
50

92

Prepayments and other current assets
(30
)
10

Decrease in operating liabilities-
Accounts payable
(23
)
(87
)
Accrued taxes
—

(26
)
Other
2

(7
)
Net cash provided from operating activities
284

261

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt
(1
)
(10
)
Short-term borrowings, net
(142
)
(46
)
Common stock dividend payments
(268
)
(250
)
Other
(2
)
—

Net cash used for financing activities
(413
)
(306
)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(123
)
(111
)
Leasehold improvement payments from affiliated companies
—

18

Sales of investment securities held in trusts
154

79

Purchases of investment securities held in trusts
(161
)
(84
)
Loans to affiliated companies, net
(163
)
102

Cash investments
12

12

Other
(10
)
(7
)
Net cash provided from (used for) investing activities
(291
)
9

Net change in cash and cash equivalents
(420
)
(36
)
Cash and cash equivalents at beginning of period
420

324

Cash and cash equivalents at end of period
$
—

$
288


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


10

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In thousands)
2011
2010
2011
2010
STATEMENTS OF INCOME
REVENUES:
Electric sales
$
225,218

$
309,236

$
634,108

$
901,913

Excise tax collections
18,826

19,480

52,677

52,548

Total revenues
244,044

328,716

686,785

954,461


OPERATING EXPENSES:
Purchased power from affiliates
25,076

89,389

107,284

298,204

Purchased power from non-affiliates
27,303

35,151

68,622

105,200

Other operating expenses
40,330

36,441

106,991

96,613

Provision for depreciation
18,478

18,057

55,392

54,504

Amortization of regulatory assets, net
23,077

45,136

64,613

121,082

General taxes
40,952

39,878

118,118

107,207

Total operating expenses
175,216

264,052

521,020

782,810


OPERATING INCOME
68,828

64,664

165,765

171,651

OTHER INCOME (EXPENSE):
Investment income
5,669

6,604

17,903

20,756

Miscellaneous income
549

533

2,223

1,790

Interest expense
(32,240
)
(33,384
)
(97,453
)
(100,267
)
Capitalized interest
83

10

146

43

Total other expense
(25,939
)
(26,237
)
(77,181
)
(77,678
)
INCOME BEFORE INCOME TAXES
42,889

38,427

88,584

93,973

INCOME TAXES
16,282

13,479

26,927

33,107

NET INCOME
26,607

24,948

61,657

60,866

Income attributable to noncontrolling interest
309

366

984

1,151

EARNINGS AVAILABLE TO PARENT
$
26,298

$
24,582

$
60,673

$
59,715


STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME
$
26,607

$
24,948

$
61,657

$
60,866

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits
2,969

3,228

8,911

(16,129
)
Income taxes (benefits) on other comprehensive income
858

976

1,256

(6,325
)
Other comprehensive income (loss), net of tax
2,111

2,252

7,655

(9,804
)
COMPREHENSIVE INCOME

28,718

27,200

69,312

51,062

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
309

366

984

1,151

COMPREHENSIVE INCOME AVAILABLE TO PARENT
$
28,409

$
26,834

$
68,328

$
49,911


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


11

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(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


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


12

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In thousands)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
61,657

$
60,866

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
55,392

54,504

Amortization of regulatory assets, net
64,613

121,082

Deferred income taxes and investment tax credits, net
13,184

(24,283
)
Accrued compensation and retirement benefits
9,371

10,467

Accrued regulatory obligations
(2,621
)
(1,897
)
Cash collateral from suppliers, net
1,918

19,245

Pension trust contribution
(35,000
)
—

Decrease (increase) in operating assets-
Receivables
158,811

86,725

Prepayments and other current assets
(19,670
)
5,421

Increase (decrease) in operating liabilities-
Accounts payable
(22,119
)
(57,272
)
Accrued taxes
(8,412
)
(23,876
)
Accrued interest
20,698

20,795

Other
791

2,637

Net cash provided from operating activities
298,613

274,414

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt
(116
)
(84
)
Short-term borrowings, net
(104,228
)
(230,132
)
Common stock dividend payments
(64,000
)
(100,000
)
Other
(5,873
)
(4,100
)
Net cash used for financing activities
(174,217
)
(334,316
)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(80,445
)
(70,812
)
Loans to affiliated companies, net
(87,763
)
2,897

Redemption of lessor notes
53,215

48,610

Other
(9,397
)
(6,776
)
Net cash used for investing activities
(124,390
)
(26,081
)

Net change in cash and cash equivalents
6

(85,983
)
Cash and cash equivalents at beginning of period
238

86,230

Cash and cash equivalents at end of period
$
244

$
247


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


13

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In thousands)
2011
2010
2011
2010
STATEMENTS OF INCOME
REVENUES:
Electric sales
$
136,766

$
136,058

$
336,139

$
376,180

Excise tax collections
8,023

7,979

21,595

21,079

Total revenues
144,789

144,037

357,734

397,259

OPERATING EXPENSES:
Purchased power from affiliates
15,834

42,338

68,388

144,062

Purchased power from non-affiliates
22,182

16,663

52,284

50,377

Other operating expenses
35,545

28,746

104,681

79,790

Provision for depreciation
7,969

7,800

23,859

23,763

Amortization of regulatory assets, net
18,143

6,591

(389
)
(3,708
)
General taxes
14,284

14,023

41,174

39,766

Total operating expenses
113,957

116,161

289,997

334,050

OPERATING INCOME
30,832

27,876

67,737

63,209

OTHER INCOME (EXPENSE):
Investment income
2,919

3,018

8,440

11,875

Miscellaneous income (expense)
417

(502
)
(816
)
(2,853
)
Interest expense
(10,520
)
(10,479
)
(31,378
)
(31,421
)
Capitalized interest
161

94

398

252

Total other expense
(7,023
)
(7,869
)
(23,356
)
(22,147
)
INCOME BEFORE INCOME TAXES
23,809

20,007

44,381

41,062

INCOME TAXES
8,971

6,911

12,135

13,241

NET INCOME
14,838

13,096

32,246

27,821

Income (loss) attributable to noncontrolling interest
1

(4
)
5

1

EARNINGS AVAILABLE TO PARENT
$
14,837

$
13,100

$
32,241

$
27,820

STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME
$
14,838

$
13,096

$
32,246

$
27,821

OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits
577

713

1,744

1,723

Increase (decrease) in unrealized gain
on available-for-sale securities
(1,328
)
427

731

466

Other comprehensive income (loss)
(751
)
1,140

2,475

2,189

Income taxes (benefits) on other comprehensive income (loss)
(394
)
330

291

565

Other comprehensive income (loss), net of tax
(357
)
810

2,184

1,624

COMPREHENSIVE INCOME
14,481

13,906

34,430

29,445

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
1

(4
)
5

1

COMPREHENSIVE INCOME AVAILABLE TO PARENT
$
14,480

$
13,910

$
34,425

$
29,444


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


14

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except share amounts)
September 30,
2011
December 31,
2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$
14

$
149,262

Receivables-
Customers, net of allowance for uncollectible accounts of $1,550 in 2011 and $1 in 2010
52,892

29

Affiliated companies
20,694

31,777

Other, net of allowance for uncollectible accounts of $257 in 2011 and $330 in 2010
2,715

18,464

Notes receivable from affiliated companies
187,765

96,765

Prepayments and other
13,849

2,306

277,929

298,603

UTILITY PLANT:
In service
961,324

947,203

Less — Accumulated provision for depreciation
456,655

446,401

504,669

500,802

Construction work in progress
19,150

12,604

523,819

513,406

OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes
82,133

103,872

Nuclear plant decommissioning trusts
78,214

75,558

Other
1,450

1,492

161,797

180,922

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill
500,576

500,576

Regulatory assets
69,720

72,059

Pension assets
24,780

—

Property taxes
24,990

24,990

Other
27,661

23,750

647,727

621,375

$
1,611,272

$
1,614,306

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
—

$
199

Accounts payable-
Affiliated companies
17,045

17,168

Other
9,248

7,351

Accrued taxes
27,822

24,401

Accrued interest
15,983

5,931

Lease market valuation liability
36,900

36,900

Other
23,560

23,145

130,558

115,095

CAPITALIZATION:
Common stockholder’s equity-
Common stock, $5 par value, authorized 60,000,000 shares - 29,402,054 shares outstanding
147,010

147,010

Other paid-in capital
178,138

178,182

Accumulated other comprehensive loss
(47,000
)
(49,183
)
Retained earnings
115,775

117,534

Total common stockholder’s equity
393,923

393,543

Noncontrolling interest
2,594

2,589

Total equity
396,517

396,132

Long-term debt and other long-term obligations
597,609

600,493

994,126

996,625

NONCURRENT LIABILITIES:
Accumulated deferred income taxes
160,515

132,019

Accumulated deferred investment tax credits
5,607

5,930

Retirement benefits
52,585

71,486

Asset retirement obligations
30,237

28,762

Lease market valuation liability
171,625

199,300

Other
66,019

65,089

486,588

502,586

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)


$
1,611,272

$
1,614,306


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


15

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In thousands)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
32,246

$
27,821

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
23,859

23,763

Amortization of regulatory assets, net
(389
)
(3,708
)
Deferred rents and lease market valuation liability
(37,710
)
(36,123
)
Deferred income taxes and investment tax credits, net
32,850

18,927

Accrued compensation and retirement benefits
2,490

4,529

Pension trust contribution
(45,000
)
—

Cash collateral from suppliers, net
1,013

9,874

Decrease (increase) in operating assets-
Receivables
(24,683
)
61,051

Prepayments and other current assets
(11,731
)
2,839

Increase (decrease) in operating liabilities-
Accounts payable
(4,714
)
(69,846
)
Accrued taxes
3,422

(6,172
)
Accrued Interest
10,052

10,050

Other
6,332

(10,931
)
Net cash provided from (used for) operating activities
(11,963
)
32,074

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Short-term borrowings, net
—

(225,975
)
Common stock dividend payments
(34,000
)
(130,000
)
Other
(1,893
)
(279
)
Net cash used for financing activities
(35,893
)
(356,254
)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(27,138
)
(29,592
)
Leasehold improvement payments from affiliated companies
—

32,829

Loans to affiliated companies, net
(91,000
)
3,847

Redemption of lessor notes
21,739

20,509

Sales of investment securities held in trusts
79,703

118,360

Purchases of investment securities held in trusts
(81,878
)
(119,777
)
Other
(2,818
)
(4,550
)
Net cash provided from (used for) investing activities
(101,392
)
21,626

Net change in cash and cash equivalents
(149,248
)
(302,554
)
Cash and cash equivalents at beginning of period
149,262

436,712

Cash and cash equivalents at end of period
$
14

$
134,158


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


16

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In millions)
2011
2010
2011
2010
STATEMENTS OF INCOME
REVENUES:
Electric sales
$
762

$
952

$
1,973

$
2,353

Excise tax collections
15

16

39

39

Total revenues
777

968

2,012

2,392


OPERATING EXPENSES:
Purchased power
429

557

1,127

1,381

Other operating expenses
132

89

297

259

Provision for depreciation
31

27

83

82

Amortization (deferral) of regulatory assets, net
(4
)
100

118

252

General taxes
20

20

53

51

Total operating expenses
608

793

1,678

2,025

OPERATING INCOME
169

175

334

367


OTHER INCOME (EXPENSE):
Miscellaneous income
4

2

8

5

Interest expense
(32
)
(30
)
(93
)
(89
)
Capitalized interest
1

—

2

—

Total other expense
(27
)
(28
)
(83
)
(84
)
INCOME BEFORE INCOME TAXES
142

147

251

283


INCOME TAXES
59

64

107

121

NET INCOME
83

83

144

162

OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits
4

4

13

24

Other comprehensive income
4

4

13

24

Income taxes on other comprehensive income
2

1

5

9

Other comprehensive income, net of tax
2

3

8

15


COMPREHENSIVE INCOME
$
85

$
86

$
152

$
177


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


17

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions, except share amounts)
September 30,
2011
December 31,
2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$
—

$
—

Receivables-
Customers, net of allowance for uncollectible accounts of $4 in 2011 and 2010
296

323

Affiliated companies
14

54

Other
18

26

Notes receivable — affiliated companies
—

177

Prepaid taxes
70

11

Other
19

13

417

604

UTILITY PLANT:
In service
4,615

4,563

Less — Accumulated provision for depreciation
1,697

1,657

2,918

2,906

Construction work in progress
139

63

3,057

2,969

OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust
218

208

Nuclear plant decommissioning trusts
194

182

Other
2

2

414

392

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill
1,811

1,811

Regulatory assets
461

513

Other
35

28

2,307

2,352

$
6,195

$
6,317

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
33

$
32

Short-term borrowings-
Affiliated companies
312

—

Accounts payable-
Affiliated companies
8

29

Other
134

158

Accrued compensation and benefits
36

35

Customer deposits
24

23

Accrued taxes
1

3

Accrued interest
30

18

Other
14

23

592

321

CAPITALIZATION:
Common stockholder’s equity-
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding
136

136

Other paid-in capital
2,011

2,509

Accumulated other comprehensive loss
(245
)
(253
)
Retained earnings
371

227

Total common stockholder’s equity
2,273

2,619

Long-term debt and other long-term obligations
1,746

1,770

4,019

4,389

NONCURRENT LIABILITIES:
Accumulated deferred income taxes
788

716

Power purchase contract liability
222

233

Nuclear fuel disposal costs
197

197

Retirement benefits
73

182

Asset retirement obligations
114

108

Other
190

171

1,584

1,607

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
1



$
6,195

$
6,317


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


18

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In millions)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
144

$
162

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
83

82

Amortization of regulatory assets, net
118

252

Deferred purchased power and other costs
(84
)
(85
)
Deferred income taxes and investment tax credits, net
77

15

Accrued compensation and retirement benefits
6

11

Cash collateral paid, net
—

(23
)
Pension trust contribution
(105
)
—

Decrease (increase) in operating assets-
Receivables
85

(73
)
Prepaid taxes
(59
)
(37
)
Increase (decrease) in operating liabilities-
Accounts payable
(60
)
(38
)
Accrued taxes
(1
)
35

Accrued interest
12

12

Other
11

(14
)
Net cash provided from operating activities
227

299

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net
312

—

Redemptions and Repayments-
Long-term debt
(23
)
(22
)
Common stock dividend payments
—

(165
)
Equity payment to parent
(500
)
—

Other
(2
)
—

Net cash used for financing activities
(213
)
(187
)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(160
)
(130
)
Loans to affiliated companies, net
177

39

Sales of investment securities held in trusts
610

340

Purchases of investment securities held in trusts
(624
)
(353
)
Other
(17
)
(8
)
Net cash used for investing activities
(14
)
(112
)
Net change in cash and cash equivalents
—

—

Cash and cash equivalents at beginning of period
—

—

Cash and cash equivalents at end of period
$
—

$
—


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


19

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In thousands)
2011
2010
2011
2010
STATEMENTS OF INCOME
REVENUES:
Electric sales
$
299,784

$
460,864

$
903,563

$
1,334,454

Gross receipts tax collections
16,589

23,049

49,990

65,245

Total revenues
316,373

483,913

953,553

1,399,699

OPERATING EXPENSES:
Purchased power from affiliates
33,574

166,039

118,398

476,119

Purchased power from non-affiliates
127,765

87,561

381,644

264,765

Other operating expenses
47,490

141,761

144,797

333,895

Provision for depreciation
14,478

12,978

39,667

39,176

Amortization of regulatory assets, net
24,000

15,480

78,261

112,869

General taxes
19,268

25,029

58,570

66,663

Total operating expenses
266,575

448,848

821,337

1,293,487

OPERATING INCOME
49,798

35,065

132,216

106,212

OTHER INCOME (EXPENSE):
Interest income
14

581

120

2,678

Miscellaneous income
1,400

1,539

3,285

5,093

Interest expense
(13,343
)
(13,037
)
(39,530
)
(39,812
)
Capitalized interest
251

176

626

461

Total other expense
(11,678
)
(10,741
)
(35,499
)
(31,580
)
INCOME BEFORE INCOME TAXES
38,120

24,324

96,717

74,632

INCOME TAXES
12,971

10,084

32,203

30,968

NET INCOME
25,149

14,240

64,514

43,664

OTHER COMPREHENSIVE INCOME
Pension and other postretirement benefits
2,163

2,161

6,353

14,032

Unrealized gain on derivative hedges
83

84

251

252

Other comprehensive income
2,246

2,245

6,604

14,284

Income taxes on other comprehensive income
841

723

2,473

5,624

Other comprehensive income, net of tax
1,405

1,522

4,131

8,660

COMPREHENSIVE INCOME
$
26,554

$
15,762

$
68,645

$
52,324


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


20

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except share amounts)
September 30,
2011
December 31,
2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$
157

$
243,220

Receivables-
Customers, net of allowance for uncollectible accounts of $3,191 in 2011 and $3,868 in 2010
143,962

178,522

Affiliated companies
10,130

24,920

Other
19,130

13,007

Notes receivable from affiliated companies
—

11,028

Prepaid taxes
9,981

343

Other
3,658

2,289

187,018

473,329

UTILITY PLANT:
In service
2,277,244

2,247,853

Less — Accumulated provision for depreciation
862,677

846,003

1,414,567

1,401,850

Construction work in progress
50,559

23,663

1,465,126

1,425,513

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts
301,652

289,328

Other
854

884

302,506

290,212

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill
416,499

416,499

Regulatory assets
372,128

295,856

Power purchase contract asset
52,245

111,562

Other
51,389

31,699

892,261

855,616

$
2,846,911

$
3,044,670

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
28,500

$
28,760

Short-term borrowings-
Affiliated companies
282,199

124,079

Accounts payable-
Affiliated companies
20,645

33,942

Other
42,685

29,862

Accrued taxes
7,734

60,856

Accrued interest
11,412

16,114

Other
31,451

29,278

424,626

322,891

CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 900,000 shares -
740,905 and 859,500 shares outstanding, respectively
842,682

1,197,076

Accumulated other comprehensive loss
(138,252
)
(142,383
)
Retained earnings
71,920

32,406

Total common stockholder’s equity
776,350

1,087,099

Long-term debt and other long-term obligations
699,747

718,860

1,476,097

1,805,959

NONCURRENT LIABILITIES:
Accumulated deferred income taxes
487,140

473,009

Nuclear fuel disposal costs
44,474

44,449

Asset retirement obligations
202,498

192,659

Retirement benefits
22,362

29,121

Power purchase contract liability
131,821

116,027

Other
57,893

60,555

946,188

915,820

COMMITMENTS AND CONTINGENCIES (Note 10)




$
2,846,911

$
3,044,670


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


21

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In thousands)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
64,514

$
43,664

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
39,667

39,176

Amortization of regulatory assets, net
78,261

112,869

Deferred costs recoverable as regulatory assets
(65,278
)
(49,646
)
Deferred income taxes and investment tax credits, net
(1,006
)
23,781

Accrued compensation and retirement benefits
276

(282
)
Cash collateral from (to) suppliers, net
283

(17,647
)
Pension trust contribution
(35,000
)
—

Decrease (increase) in operating assets-
Receivables
46,125

(18,444
)
Prepaid taxes
(9,638
)
(12,077
)
Decrease in operating liabilities-
Accounts payable
(4,161
)
(18,763
)
Accrued taxes
(52,430
)
(8,203
)
Accrued interest
(4,702
)
(5,645
)
Other
13,377

6,654

Net cash provided from operating activities
70,288

95,437

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net
158,120

6,296

Redemptions and Repayments-
Common stock
(150,000
)
—

Long-term debt
(14,966
)
(100,000
)
Common stock dividend payments
(80,000
)
—

Equity payment to parent
(150,000
)
—

Net cash used for financing activities
(236,846
)
(93,704
)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(72,830
)
(77,921
)
Sales of investment securities held in trusts
807,405

420,116

Purchases of investment securities held in trusts
(815,489
)
(427,150
)
Loans to affiliated companies, net
11,028

85,949

Other
(6,619
)
(2,723
)
Net cash used for investing activities
(76,505
)
(1,729
)
Net change in cash and cash equivalents
(243,063
)
4

Cash and cash equivalents at beginning of period
243,220

120

Cash and cash equivalents at end of period
$
157

$
124


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


22

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months
Ended September 30
Nine Months
Ended September 30
(In thousands)
2011
2010
2011
2010
STATEMENTS OF INCOME
REVENUES:
Electric sales
$
248,320

$
372,480

$
795,578

$
1,108,751

Gross receipts tax collections
13,212

17,414

42,468

51,100

Total revenues
261,532

389,894

838,046

1,159,851


OPERATING EXPENSES:
Purchased power from affiliates
57,990

165,125

160,109

486,470

Purchased power from non-affiliates
65,407

92,648

271,302

270,900

Other operating expenses
39,007

58,832

124,905

198,296

Provision for depreciation
16,126

14,859

46,469

46,146

Amortization (deferral) of regulatory assets, net
19,164

(1,771
)
44,779

(22,259
)
General taxes
15,912

19,194

51,313

54,375

Total operating expenses
213,606

348,887

698,877

1,033,928


OPERATING INCOME
47,926

41,007

139,169

125,923

OTHER INCOME (EXPENSE):
Miscellaneous income
797

1,508

1,466

4,431

Interest expense
(17,401
)
(17,581
)
(51,996
)
(52,501
)
Capitalized interest
101

193

164

516

Total other expense
(16,503
)
(15,880
)
(50,366
)
(47,554
)

INCOME BEFORE INCOME TAXES

31,423

25,127

88,803

78,369

INCOME TAXES
11,270

5,311

36,626

28,280


NET INCOME
20,153

19,816

52,177

50,089

OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits
1,817

1,830

5,292

12,207

Unrealized gain on derivative hedges
15

16

48

48

Other comprehensive income
1,832

1,846

5,340

12,255

Income taxes on other comprehensive income
645

484

1,878

4,251

Other comprehensive income, net of tax
1,187

1,362

3,462

8,004

COMPREHENSIVE INCOME
$
21,340

$
21,178

$
55,639

$
58,093


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


23

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except share amounts)
September 30,
2011
December 31,
2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$
2

$
5

Receivables-
Customers, net of allowance for uncollectible accounts of $2,263 in 2011 and $3,369 in 2010
119,060

148,864

Affiliated companies
15,479

54,052

Other
13,467

11,314

Notes receivable from affiliated companies
—

14,404

Prepaid taxes
9,044

14,026

Other
3,302

1,592

160,354

244,257

UTILITY PLANT:
In service
2,567,953

2,532,629

Less — Accumulated provision for depreciation
954,104

935,259

1,613,849

1,597,370

Construction work in progress
70,995

30,505

1,684,844

1,627,875

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts
162,946

152,928

Non-utility generation trusts
127,408

80,244

Other
283

297

290,637

233,469

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill
768,628

768,628

Regulatory assets
264,240

163,407

Power purchase contract asset
3,220

5,746

Other
15,212

19,287

1,051,300

957,068

$
3,187,135

$
3,062,669

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt
$
45,000

$
45,000

Short-term borrowings-
Affiliated companies
112,901

101,338

Accounts payable-
Affiliated companies
24,643

35,626

Other
27,831

41,420

Accrued taxes
3,526

5,075

Accrued interest
23,898

17,378

Other
24,699

22,541

262,498

268,378

CAPITALIZATION:
Common stockholder’s equity-
Common stock, $20 par value, authorized 5,400,000 shares - 4,427,577 shares outstanding
88,552

88,552

Other paid-in capital
913,393

913,519

Accumulated other comprehensive loss
(160,064
)
(163,526
)
Retained earnings
43,170

60,993

Total common stockholder’s equity
885,051

899,538

Long-term debt and other long-term obligations
1,072,494

1,072,262

1,957,545

1,971,800

NONCURRENT LIABILITIES:
Accumulated deferred income taxes
431,811

371,877

Retirement benefits
189,311

187,621

Power purchase contract liability
188,432

116,972

Asset retirement obligations
103,139

98,132

Other
54,399

47,889

967,092

822,491

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)




$
3,187,135

$
3,062,669


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


24

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months
Ended September 30
(In thousands)
2011
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$
52,177

$
50,089

Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation
46,469

46,146

Amortization (deferral) of regulatory assets, net
44,779

(22,259
)
Deferred costs recoverable as regulatory assets
(64,872
)
(61,574
)
Deferred income taxes and investment tax credits, net
56,441

94,015

Accrued compensation and retirement benefits
8,272

7,634

Cash collateral paid, net
(1,439
)
(11,760
)
Decrease (increase) in operating assets-
Receivables
70,493

(2,584
)
Prepaid taxes
4,982

(29,318
)
Increase (decrease) in operating liabilities-
Accounts payable
(30,415
)
(12,766
)
Accrued taxes
(14,401
)
(2,245
)
Accrued interest
6,520

6,915

Other
21,654

9,411

Net cash provided from operating activities
200,660

71,704


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt
25,000

—

Short-term borrowings, net
11,563

1,771

Redemptions and Repayments-
Long-term debt
(25,000
)
—

Common stock dividend payments
(70,000
)
—

Other
(1,419
)
(125
)
Net cash provided from (used for) financing activities
(59,856
)
1,646

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions
(93,685
)
(91,924
)
Loans to affiliated companies, net
14,404

—

Sales of investment securities held in trusts
413,584

141,392

Purchases of investment securities held in trusts
(464,940
)
(116,240
)
Other
(10,170
)
(6,584
)
Net cash used for investing activities
(140,807
)
(73,356
)

Net change in cash and cash equivalents
(3
)
(6
)
Cash and cash equivalents at beginning of period
5

14

Cash and cash equivalents at end of period
$
2

$
8


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


25

FIRSTENERGY CORP. AND SUBSIDIARIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



26

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL), FES and its principal subsidiaries (FGCO and NGC), and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FirstEnergy (See Note 2).
FirstEnergy and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the NJBPU. These unaudited interim financial statements and notes were prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.
These unaudited interim financial statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2010 for FirstEnergy, FES and the Utility Registrants, as applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 8). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

2. MERGER
Merger
On February 25, 2011 , the merger between FirstEnergy and AE closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Merger Sub and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
The total consideration in the merger was based on the closing price of a share of FirstEnergy common stock on February 24, 2011 , the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):

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


The allocation of the total consideration transferred in the merger to the assets acquired and liabilities assumed includes adjustments for the fair value of Allegheny coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The preliminary allocation of the purchase price is as follows:



27

(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


The allocation of purchase price in the table above reflects refinements made since the merger date in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This primarily resulted in an increase in other noncurrent assets of approximately $90 million and decreases in current assets, goodwill and noncurrent liabilities of $16 million , $79 million and $7 million , respectively. The impact of the refinements on the amortization of purchase accounting adjustments recorded during the quarters ended March 31, 2011, June 30, 2011 and September 30, 2011, were not significant. Further modifications to the purchase price allocation may occur as a result of continuing review of the assets acquired and liabilities assumed.
The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and unregulated generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The preliminary estimate of goodwill from the merger of $873 million has been assigned to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.
Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:
(In millions)
Regulated Distribution
Competitive
Energy Services
Regulated
Independent Transmission
Other/ Corporate
Consolidated
Balance as of December 31, 2010
$
5,551

$
24

$
—

$
—

$
5,575

Merger with Allegheny
—

873

—

—

873

Balance as of September 30, 2011
$
5,551

$
897

$
—

$
—

$
6,448


The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:



28

(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


The fair value measurements of intangible assets and liabilities were based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.
The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the contract portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.
The fair value of coal supply contracts was determined in a similar manner as the energy, NUG and gas transportation contracts based on the present value of the above/below market cash flows attributable to the contracts. The fair value adjustment for these contracts is being amortized based on expected deliveries under each contract.
As of September 30, 2011 , intangible assets on FirstEnergy’s Consolidated Balance Sheet, including those recorded in connection with the merger, include the following:
(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


Acquired land easements and software with a fair value of $172 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of September 30, 2011 .
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $2 million ( $1 million net of tax) and $14 million ( $11 million net of tax) during the three months ended September 30, 2011 and 2010 , respectively, and approximately $91 million ( $73 million net of tax) and $35 million ( $26 million net of tax) during the first nine months of 2011 and 2010 , respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. Merger transaction costs recognized in the first nine months of 2011 include $56 million ( $47 million net of tax) of change in control and other benefit payments to AE executives.


29

FirstEnergy also recorded approximately $3 million ( $1 million net of tax) and $88 million ( $67 million net of tax) in merger integration costs during the three and nine months ended September 30, 2011 , respectively, including an inventory valuation adjustment. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review, FirstEnergy management determined that the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ( $42 million net of tax) in the first quarter of 2011.
Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statement of Income for the periods subsequent to the February 25, 2011 merger date are as follows:
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 $1 million and $57 million , respectively.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with AE had taken place on January 1, 2010 . The unaudited pro forma information has been calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010 , together with the consequential tax effects.
FirstEnergy and Allegheny both incurred non-recurring costs directly related to the merger that have been included in the pro forma earnings presented below. Combined pre-tax transaction costs incurred were approximately $1 million and $33 million in the three months ended September 30, 2011 and 2010 , respectively, and approximately $91 million and $72 million in the nine months ended September 30, 2011 and 2010 , respectively. In addition, during the nine months ended September 30, 2011 , $88 million of pre-tax merger integration costs and $33 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger been completed on January 1, 2010, or the future consolidated results of operations of the combined company.
Three Months Ended
Nine Months Ended
(Pro forma amounts in millions, except
September 30
September 30
per share amounts)
2011
2010
2011
2010
Revenues
$
4,708

$
5,072

$
13,556

$
14,158

Earnings available to FirstEnergy
$
512

$
300

$
835

$
944

Basic Earnings Per Share
$
1.22

$
0.72

$
2.00

$
2.26

Diluted Earnings Per Share
$
1.22

$
0.71

$
1.99

$
2.25


3. GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. Impairment is indicated and a loss is recognized if the implied fair value of a reporting unit's goodwill is less than the carrying value of its goodwill.

With the completion of the AE merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments (see Note 14). FirstEnergy's goodwill from the merger of $873 million was assigned to the Competitive Energy Services segment based on expected synergies from the merger. FirstEnergy's reporting units are consistent


30

with its operating segments, and consist of Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services. Goodwill is allocated to these operating segments based on the original purchase price allocation for acquisitions, including the AE merger, within the various reporting units. As of September 30, 2011 , goodwill balances for Regulated Distribution and Competitive Energy Services were $ 5,551 million and $ 897 million , respectively. No goodwill has been allocated to the Regulated Independent Transmission segment.

Annual impairment testing is conducted during the third quarter of each year and for 2011 , the analysis indicated no impairment of goodwill. For purposes of annual testing the estimated fair values of Regulated Distribution and Competitive Energy Services were determined using a discounted cash flow approach.

The discounted cash flow model of the Regulated Distribution and Competitive Energy Services segments reporting units is based on the forecasted operating cash flow for the current year, projected operating cash flows (determined using forecasted amounts as well as an estimated growth rate) and a terminal value. Discounted cash flows consist of the operating cash flows for each reporting unit less an estimate for capital expenditures. The key assumptions incorporated in the discounted cash flow approach include growth rates, projected operating income, changes in working capital, projected capital expenditures, planned funding of pension plans, anticipated funding of nuclear decommissioning trusts, expected results of future rate proceedings (applicable to Regulated Distribution segment only) and a discount rate equal to assumed long-term cost of capital. Cash flows may be adjusted to exclude certain non-recurring or unusual items. Reporting unit income, which excludes non-recurring or unusual items, was the starting point for determining operating cash flow and there were no non-recurring or unusual items excluded from the calculations of operating cash flow in any of the periods included in the determination of fair value.

This approach involves management judgment and estimates that are used in relation to changing market conditions and business environment; unanticipated changes in assumptions could have a significant effect on FirstEnergy's evaluation of goodwill. At the time FirstEnergy conducted the annual impairment testing in 2011, fair value would have to have declined in excess of 44% and 53% for Regulated Distribution and Competitive Energy Services, respectively, to indicate a potential goodwill impairment. Fair value would have to have declined more than 20% for CEI, 16% for TE, 38% for JCP&L, 62% for Met-Ed, 58% for Penelec and 62% for FES to indicate a potential goodwill impairment.

4. EARNINGS PER SHARE
Basic earnings per share of common stock are computed using the weighted average of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that would be issued if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
Three Months
Ended September 30
Nine Months
Ended September 30
Reconciliation of Basic and Diluted Earnings per Share
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


(1)
Includes 113 million shares issued to AE shareholders for the periods subsequent to the merger date. (See Note 2)
(2)
The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months and nine months ended September 30, 2011 and 2010 .

5. FAIR VALUE MEASUREMENTS
(A) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption “short-term borrowings.” The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts, as of September 30, 2011 , and


31

December 31, 2010 :

September 30, 2011
December 31, 2010
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
(In millions)
FirstEnergy (1)
$
17,870

$
19,703

$
13,928

$
14,845

FES
3,738

3,975

4,279

4,403

OE
1,158

1,404

1,159

1,321

CEI
1,831

2,096

1,853

2,035

TE
600

720

600

653

JCP&L
1,787

2,074

1,810

1,962

Met-Ed
729

818

742

821

Penelec
1,120

1,245

1,120

1,189

(1)
Includes debt assumed in the AE merger (see Note 2) with a carrying value and a fair value as of September 30, 2011 , of $4,375 million and $4,515 million , respectively, and debt classified as liabilities related to assets pending sale (see Note 15) with a carrying value and a fair value as of September 30, 2011 , of $363 million .
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those obligations based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on debt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and other subsidiaries listed above.
(B) INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities, available-for-sale securities and notes receivable.
FirstEnergy and its subsidiaries periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy and its subsidiaries consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of their cost basis, and the likelihood of recovery of the security’s entire amortized cost basis.
Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting. Net unrealized gains and losses are recorded as regulatory assets or liabilities because the difference between investments held in the trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the nuclear decommissioning trust funds restricts or limits the trusts’ ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust funds’ custodian or managers and their parents or subsidiaries.
Available-For-Sale Securities
FES and the Utility Registrants hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered as available-for-sale at fair market value. FES and the Utility Registrants have no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in NDT, nuclear fuel disposal trusts and NUG trusts as of September 30, 2011 and December 31, 2010 :


32

September 30, 2011 (1)
December 31, 2010 (2)
Cost
Basis
Unrealized
Gains
Unrealized
Losses
Fair
Value
Cost
Basis
Unrealized
Gains
Unrealized
Losses
Fair
Value
(In millions)
Debt securities
FirstEnergy
$
689

$
11

$
—

$
700

$
1,699

$
31

$
—

$
1,730

FES
227

1

—

228

980

13

—

993

OE
—

—

—

—

123

1

—

124

TE
45

—

—

45

42

—

—

42

JCP&L
253

8

—

261

281

9

—

290

Met-Ed
41

—

—

41

127

4

—

131

Penelec
123

2

—

125

145

4

—

149

Equity securities
FirstEnergy
$
174

$
6

$
—

$
180

$
268

$
69

$
—

$
337

FES
83

4

—

87

—

—

—

—

TE
23

1

—

24

—

—

—

—

JCP&L
19

—

—

19

80

17

—

97

Met-Ed
30

1

—

31

125

35

—

160

Penelec
19

—

—

19

63

16

—

79

(1)
Excludes cash investments, receivables, payables, taxes and accrued income: FirstEnergy – $1,526 million ; FES – $872 million ; OE – $136 million ; TE – $9 million ; JCP&L – $133 million ; Met-Ed – $229 million and Penelec – $147 million .
(2)
Excludes cash investments, receivables, payables, taxes and accrued income: FirstEnergy – $193 million ; FES – $153 million ; OE – $3 million ; TE – $34 million ; JCP&L – $3 million ; Met-Ed – $(3) million and Penelec – $4 million .
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded to earnings and interest and dividend income for the three months and nine months ended September 30, 2011 and 2010 were as follows:
Three Months Ended September 30
2011
Sales Proceeds
Realized Gains
Realized Losses
Interest and Dividend Income
(In millions)
FirstEnergy
$
1,974

$
98

$
(38
)
$
20

FES
1,100

52

(19
)
9

OE
134

7

(1
)
1

TE
51

4

(2
)
—

JCP&L
234

11

(4
)
5

Met-Ed
306

15

(8
)
3

Penelec
149

9

(4
)
2

2010
Sales Proceeds
Realized Gains
Realized Losses
Interest and Dividend Income
(In millions)
FirstEnergy
$
662

$
49

$
(32
)
$
19

FES
521

47

(30
)
11

OE
19

—

—

1

TE
12

—

(1
)
—

JCP&L
59

1

(1
)
4

Met-Ed
44

1

—

2

Penelec
7

—

—

1




33

Nine Months Ended September 30
2011
Sales Proceeds
Realized Gains
Realized Losses
Interest and Dividend Income
(In millions)
FirstEnergy
$
3,678

$
220

$
(83
)
$
72

FES
1,613

74

(42
)
41

OE
154

7

(1
)
3

TE
80

5

(4
)
2

JCP&L
610

37

(10
)
13

Met-Ed
807

63

(15
)
8

Penelec
414

34

(11
)
5

2010
Sales Proceeds
Realized Gains
Realized Losses
Interest and Dividend Income
(In millions)
FirstEnergy
$
2,577

$
132

$
(118
)
$
56

FES
1,478

101

(88
)
33

OE
79

2

—

2

TE
118

3

(1
)
1

JCP&L
340

10

(10
)
10

Met-Ed
420

10

(12
)
5

Penelec
141

6

(7
)
5

Held-To-Maturity Securities
The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities as of September 30, 2011 , and December 31, 2010 :
September 30, 2011
December 31, 2010
Cost
Basis
Unrealized
Gains
Unrealized
Losses
Fair
Value
Cost
Basis
Unrealized
Gains
Unrealized
Losses
Fair
Value
(In millions)
Debt Securities
FirstEnergy
$
414

$
45

$
—

$
459

$
476

$
91

$
—

$
567

OE
178

17

—

195

190

51

—

241

CEI
287

27

—

314

340

41

—

381


Investments in emission allowances, employee benefits and cost and equity method investments totaling $312 million as of September 30, 2011 and $259 million as of December 31, 2010 , are not required to be disclosed and are excluded from the amounts reported above.
Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of September 30, 2011 , and December 31, 2010 . The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2013 to 2016.


34

September 30, 2011
December 31, 2010
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
(In millions)
Notes Receivable
FirstEnergy
$
—

$
—

$
7

$
8

TE
82

92

104

118

(C) RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.
The three levels of the fair value hierarchy are as follows:

Level 1
— Quoted prices for identical instruments in active markets.
Level 2
— Quoted prices for similar instruments in active markets;
— quoted prices for identical or similar instruments in markets that are not active; and
— model-derived valuations for which all significant inputs are observable market data.
Level 3
— Valuation inputs are unobservable and significant to the fair value measurement.

The following tables set forth financial assets and liabilities measured at fair value on a recurring basis by level within the fair value hierarchy. There were no significant transfers between levels during the three months and nine months ended September 30, 2011 .
FirstEnergy Corp.
The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of September 30, 2011 , and December 31, 2010 :



35

September 30, 2011
Level 1
Level 2
Level 3
Total
(In millions)
Assets
Corporate debt securities
$
—

$
60

$
—

$
60

Derivative assets — commodity contracts
—

225

—

225

Derivative assets — FTRs
—

—

4

4

Derivative assets — NUG contracts (1)
—

—

59

59

Equity securities (2)
181

—

—

181

Foreign government debt securities
—

2

—

2

U.S. government debt securities
—

331

—

331

U.S. state debt securities
—

310

—

310

Other (4)
—

1,564

—

1,564

Total assets
$
181

$
2,492

$
63

$
2,736

Liabilities
Derivative liabilities — commodity contracts
$
—

$
(257
)
$
—

$
(257
)
Derivative liabilities — FTRs
—

—

(13
)
(13
)
Derivative liabilities — NUG contracts (1)
—

—

(542
)
(542
)
Total liabilities
$
—

$
(257
)
$
(555
)
$
(812
)
Net assets (liabilities) (3)
$
181

$
2,235

$
(492
)
$
1,924

December 31, 2010
Level 1
Level 2
Level 3
Total
(In millions)
Assets
Corporate debt securities
$
—

$
597

$
—

$
597

Derivative assets — commodity contracts
—

250

—

250

Derivative assets — NUG contracts (1)
—

—

122

122

Equity securities (2)
338

—

—

338

Foreign government debt securities
—

149

—

149

U.S. government debt securities
—

595

—

595

U.S. state debt securities
—

379

—

379

Other (4)
—

219

—

219

Total assets
$
338

$
2,189

$
122

$
2,649

Liabilities
Derivative liabilities — commodity contracts
$
—

$
(348
)
$
—

$
(348
)
Derivative liabilities — NUG contracts (1)
—

—

(466
)
(466
)
Total liabilities
$
—

$
(348
)
$
(466
)
$
(814
)
Net assets (liabilities) (3)
$
338

$
1,841

$
(344
)
$
1,835

(1)
NUG contracts are generally subject to regulatory accounting and do not materially 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 $(29) million and $(7) million as of September 30, 2011 and December 31, 2010 , respectively, of receivables, payables, 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 the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy during the periods ending September 30, 2011 and December 31, 2010 :



36

Derivative Asset (1)
Derivative Liability (1)
Net (1)
(In millions)
January 1, 2011 Balance
$
122

$
(466
)
$
(344
)
Realized gain (loss)
—

—

—

Unrealized gain (loss)
(52
)
(285
)
(337
)
Purchases
13

(3
)
10

Issuances
—

—

—

Sales
—

—

—

Settlements
(20
)
211

191

Transfers into  Level 3
—

(12
)
(12
)
September 30, 2011 Balance
$
63

$
(555
)
$
(492
)

January 1, 2010 Balance
$
200

$
(643
)
$
(443
)
Realized gain (loss)
—

—

—

Unrealized gain (loss)
(71
)
(110
)
(181
)
Purchases
—

—

—

Issuances
—

—

—

Sales
—

—

—

Settlements
(7
)
287

280

Transfers into  Level 3
—

—

—

December 31, 2010 Balance
$
122

$
(466
)
$
(344
)
(1)
Changes in the fair value of NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.
FirstEnergy Solutions Corp.
The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of September 30, 2011 and December 31, 2010 :



37

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 $(31) million and $7 million as of September 30, 2011 and December 31, 2010 , respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)
Primarily consists of short-term cash 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 September 30, 2011 :


38

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 September 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, 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 September 30, 2011 and December 31, 2010 :



39

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 $2 million as of December 31, 2010 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)
Primarily consists of short-term cash 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 September 30, 2011 and December 31, 2010 :



40

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 $6 million and $(3) million as of September 30, 2011 and December 31, 2010 , respectively, of receivables, payables, 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 September 30, 2011 and December 31, 2010 :



41

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 September 30, 2011 and December 31, 2010 :



42

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 $(3) million and $(9) million as of September 30, 2011 and December 31, 2010 , respectively, of receivables, payables, 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 September 30, 2011 and December 31, 2010 :



43

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 September 30, 2011 and December 31, 2010 :



44

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 million and $(3) million as of 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 September 30, 2011 and December 31, 2010 :



45

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 ended September 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 .

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 qualified and 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 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 million of assets and $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 $12 million as of September 30, 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 were less than $1 million and $19 million during the three months and nine months ended September 30, 2011 , respectively. Approximately $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


46

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 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 $81 million as of September 30, 2011 . Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCL into interest expense totaled $3 million during the three months ended September 30, 2011 , and 2010 and $9 million during the nine months ended 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 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 $107 million as of September 30, 2011 . Based on current estimates, approximately $21 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $5 million during the three months ended September 30, 2011 and 2010, respectively, and $16 million and $7 million during the nine months ended 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 expired during 2011 with an aggregate notional value of $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 September 30, 2011 , FirstEnergy’s net liability position under commodity derivative contracts was $41 million , which primarily related to FES positions. Under these commodity derivative contracts, FES posted $49 million and AE Supply posted $1 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $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 September 30, 2011 , an adverse 10% change in commodity prices would decrease net income by approximately $14 million 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:



47

Derivatives not designated as hedging instruments:
Derivative Assets
Derivative Liabilities
Fair Value
Fair Value
September 30,
2011
December 31,
2010
September 30,
2011
December 31,
2010
(In millions)
(In millions)
Power Contracts
Power Contracts
Current Assets
$
157

$
96

Current Liabilities
$
190

$
209

Noncurrent Assets
68

40

Noncurrent Liabilities
67

38

FTRs
FTRs
Current Assets
4

—

Current Liabilities
13

—

Noncurrent Assets
—

—

Noncurrent Liabilities
—

—

NUGs
59

122

NUGs
542

467

Interest Rate Swaps
Interest Rate Swaps
Current Assets
—

—

Current Liabilities
—

—

Noncurrent Assets
—

—

Noncurrent Liabilities
—

—

Other
Other
Current Assets
—

10

Current Liabilities
—

—

Noncurrent Assets
—

—

Noncurrent Liabilities
—

—

Total Derivatives Assets
$
288

$
268

Total Derivatives Liabilities
$
812

$
714


The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2011 :
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 nine months ended September 30, 2011 and 2010, are summarized in the following tables:


48

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:
Purchased Power Expense
$
27

$
—

$
—

$
—

$
27

Revenues
3

—

—

—

3

Other Operating Expense

(11
)
(15
)
1

—

(25
)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense
(5
)
—

—

—

(5
)
Revenues
(40
)
30

—

—

(10
)
Other Operating Expense

—

(35
)
—

—

(35
)
2010
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense
$
3

$
—

$
—

$
—

$
3


Realized Gain (Loss) Reclassified to:
Purchased Power Expense
(22
)
—

—

—

(22
)

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

3

92


Realized Gain (Loss) to Derivative Instrument:
53

(3
)
50

Realized Gain (Loss) to Regulatory Assets:
(53
)
3

(50
)

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

$
(146
)
Unrealized Gain (Loss) to Regulatory Assets:

146

—

146

Realized Gain (Loss) to Derivative Instrument:
63

—

63

Realized Gain (Loss) to Regulatory Assets:
(63
)
—

(63
)


49

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 credit to) customers during the three months and nine months ended September 30, 2011 and 2010:


50


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.

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 and nine months ended September 30, 2011 , FirstEnergy made pre-tax contributions to its qualified pension plans of $112 million and $375 million , respectively.
As a result of the merger with AE, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and other postretirement benefit plans 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 at the date of the merger were $954 million and $75 million , respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $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.
The components of the consolidated net periodic cost for pension and OPEB benefits (including amounts capitalized) were as follows:



51

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 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 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



52

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
)

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, 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 secur itize 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 $287 million was outstanding as of September 30, 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 ended September 30, 2011 , is primarily due to equity contributions from owners of $22 million , partially offset by net losses of the noncontrolling interests of $17 million and an equity distribution to owners 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 $28 million as of September 30, 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


53

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 September 30, 2011 , were $44 million , $31 million and $14 million for JCP&L, PE and WP, respectively and $164 million , $89 million and $40 million for the nine months ended 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 and nine months ended September 30, 2010 were $73 million and $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 September 30, 2011 , WP’s reserve for this adverse purchase power commitment was $56 million , including a current liability of $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 September 30, 2011 :
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 .
(2)
CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

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 AE, FirstEnergy’s unrecognized income tax benefits increased by $ 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 million of income tax benefits, including $ 5 million that favorably affected FirstEnergy’s effective tax rate. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first nine months of 2011. After reaching settlements in 2010 on a state tax matter and tax items at appeals with the IRS related to the capitalization of certain costs for tax years 2005-2008 and on gains and losses recognized from the disposition of assets, FirstEnergy recognized approximately $78 million of net income tax benefits, including $21 million that favorably affected FirstEnergy’s effective tax rate for 2010. The remaining portion of the income tax benefit recognized in 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item.
As of September 30, 2011 , it is reasonably possible that approximately $46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $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 million in 2011. There were no other material changes to the amount of accrued interest, except for a $6 million increase in accrued interest as a result of the merger with AE. The reversal of accrued interest associated with the recognized income tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $11 million in the first nine months of 2010. The net amount of interest accrued as of September 30, 2011 was $11 million , compared with $3 million as of December 31, 2010 .
As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by


54

$28 million in the first 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 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. Allegheny has filed its 2010 and 2009 federal returns and such filings are subject to review. State tax returns for tax years 2008 through 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. FirstEnergy's tax returns for all state jurisdictions are open from 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. Tax years 2009-2011 are under review by the 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, results of operations, cash flow or liquidity.

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 September 30, 2011 , outstanding guarantees and other assurances aggregated approximately $3.8 billion , consisting of parental guarantees ( $0.9 billion ), subsidiaries' guarantees ( $2.5 billion ), and surety bonds and LOCs ( $0.4 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' 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 of $0.3 billion (included in the $0.9 billion discussed above) as of 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 September 30, 2011 , FirstEnergy's maximum exposure under these collateral provisions was $594 million , consisting of $495 million due to a below investment grade credit rating (of which $257 million is due to an acceleration of payment or funding obligation) and $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 $662 million .

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $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 September 30, 2011 , and forward prices as of that date, FES and AE Supply have posted collateral of $123 million and $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 $16 million and $1 million of 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


55

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' 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 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 SO 2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO 2 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 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 motion to dismiss New Jersey's and Connecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this 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 SO 2 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 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 PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, 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 PSD and Title V permitting programs. The complaint was also filed against the former co-owner, 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 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 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


56

and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. On October 12 and 13, 2011, the Court dismissed all of 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 refile state law claims in state court, against all of the 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 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 information requests but, at this time, is unable to predict the outcome of this 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 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: Albright, Armstrong, Fort Martin, Harrison, 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 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 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 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 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 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 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 SO 2 and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO 2 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 NOx, SO 2 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 MDE passed alternate NOx and SO 2 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% which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO 2 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 or estimate the possible loss or range of loss.


57

In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny's Pleasants coal-fired plant. In August 2011, Allegheny and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.
National Ambient Air Quality Standards
The EPA's CAIR requires reductions of NOx and SO 2 emissions in two phases (2009/2010 and 2015), ultimately capping SO 2 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 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 CSAPR to replace CAIR, which remains in effect until CSAPR becomes effective ( 60 days after publication in the Federal Register). CSAPR requires reductions of NOx and SO 2 emissions in two phases (2012 and 2014), ultimately capping SO 2 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 SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. 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 SO 2 emissions and proposed to delay restrictions on interstate trading of NOx and SO 2 emission 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 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 SO 2 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 continuing to assess the impact of CSAPR, other environmental proposals and other factors on FirstEnergy's competitive fossil generating facilities, including but not limited to, the impact on its SO 2 emission allowances 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 future cost of compliance with MACT regulations may be substantial and changes to 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 “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 currently requires it to submit 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 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 NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO 2 ) effective January 2, 2011 for existing facilities under the CAA's PSD program.
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 CO 2 , emitted by developed countries


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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 billion over the next three years with a goal of increasing to $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. 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 ruling also failed to answer the question of the extent to which actions for damages may remain viable.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO 2 emissions 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-CO 2 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 plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to 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 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 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 water intake channel to divert fish away from the 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 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 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. 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 to 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 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 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 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 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. A hearing on 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, 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 recommended sulfate impairment designation. PA 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 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 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 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 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 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 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 hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. 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.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the 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 September 30, 2011 , based on estimates of the total costs of cleanup, the Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $103 million (JCP&L - $69 million , TE - $1 million , CEI - $1 million , FGCO - $1 million and FirstEnergy - $31 million ) have been accrued through September 30, 2011 . Included in the total are accrued liabilities of approximately $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 . FirstEnergy recognized an additional expense of $29 million during the second quarter of 2011; $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' 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 decision decertifying the class. In November 2010, the Supreme Court issued an order denying Plaintiffs' motion for leave to appeal. The Court's order effectively ends the attempt to certify the class, and leaves only nine ( 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 have 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 September 30, 2011 , FirstEnergy had approximately $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 NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, 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 . On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.
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 facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to 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 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 ICG, Anker WV, and Anker 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' 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 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $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 million ( $90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. 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 Notice of Appeal and a briefing schedule was issued with oral argument likely in 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 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, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.


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 designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and 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 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 RFC. Moreover, it is clear that the NERC, 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. Any future inability on 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 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 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 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, RFC issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of $650,000 , and for FirstEnergy to 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 RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by 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 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 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 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 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 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 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 million and would be recovered over the following six years. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. Hearings on those plans and the plans of the other utilities were held in mid October 2011.
In March 2009, the MDPSC issued an order temporarily suspending 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 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 compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Comments on the draft rules are due by November 16, and a hearing to consider the rules and comments is scheduled for December 8 and 9, 2011. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, and then approved by the MDPSC as final rules on October 31, 2011. The rules will go into effect after being published again in the Maryland Register.

(C) NEW JERSEY

On September 8, 2011, 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 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 the Morristown underground network. A schedule for the completion of the 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 a result of 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, Rider 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 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 million dependent on the outcome of certain PJM proceedings, agreed to establish a $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 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 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 Ohio Companies to an assessment of a penalty by the 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 decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing.

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' aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC 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. On August 3, 2011, the 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 Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and 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 Ohio Companies' alternative energy recovery rider. Separately, one party has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO has not ruled on 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


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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 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 Ohio Companies to recover deferred costs and associated carrying charges. OCC filed an application for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO did not act on the application for 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 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 March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $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 and 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 . , 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 million ( $189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each of May 2008, 2009 and 2010, the PPUC approved Met-Ed's and 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 approval in May 2010 authorized an increase to the TSC for 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 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 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' 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 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 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 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 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 million , which Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The PPUC approved the SMIP, as modified by the ALJ, in June 2010. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the 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 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 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 OCA filed a Joint Petition for Settlement addressing 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 grace period authorized by the PPUC to continue 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.
Following additional proceedings, 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 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 original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional 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 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 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 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.

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 EGS may not have the same or substantially


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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 EDC before using its trademark or service mark. The Proposed Rulemaking Order calls for comments to be submitted within forty-five days of its publication in the Pennsylvania Bulletin, with no provision for replies. The Order has not been published yet. If implemented these rules could require a significant change in the 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.

(F) WEST VIRGINIA

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 was issued by the WVPSC in September 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. The application was approved and the three facilities are capable of generating renewable credits which 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.

(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 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. 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 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 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 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. 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 all respects.



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PJM Transmission Rate

In April 2007, FERC issued an order (Opinion 494) finding that the PJM transmission 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, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

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 ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500 kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue 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 filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain 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. Other utilities and 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 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 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 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 proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the 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 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 proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit study analysis as part of FERC's evaluation of ATSI's proposed transmission rates. 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 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 move into PJM. These orders approve ATSI's proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect 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 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 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 million to the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.



69

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 as MVPs - are a class of transmission projects that are approved via 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 Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $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 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 MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. 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 tariffs obligate ATSI to pay all charges that attached prior to 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 order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of 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 proposed transmission 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 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 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 CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $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 ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains


70

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 either of the above matters.

PATH Transmission 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 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 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 0.5% 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 and the six intervenors filed with the Chief Administrative Law Judge of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the 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 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 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 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' 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 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 petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.


71


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 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 the studies 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.

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 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 . Performance share awards are currently designated to be 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 September 30, 2011 .
Restricted Stock and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity for the nine months ended September 30, 2011 , was as follows:
Nine Months Ended
September 30, 2011
Restricted stock and stock units outstanding as of January 1, 2011
1,878,022

Granted
907,898

Converted AE restricted stock
645,197

Exercised
(435,358
)
Forfeited
(213,039
)
Restricted stock and stock units outstanding as of September 30, 2011
2,782,720


The 907,898 shares of restricted common stock granted during the nine months ended September 30, 2011 , had a grant-date fair value of $33.8 million and a weighted-average vesting period of 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 nine months ended September 30, 2011 and 2010 , for restricted stock and restricted stock units, net of amounts capitalized, was approximately $43 million and $40 million , respectively.
Stock Options
Stock option activity for the nine months ended September 30, 2011 was as follows:


72

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 nine months ended September 30, 2011 , was $0.5 million . No expense was recognized during the nine months ended September 30, 2010 . Options granted during the nine months ended September 30, 2011 , had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.
Options outstanding by exercise price as of September 30, 2011 , were as follows:
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 nine months ended September 30, 2011 and 2010 , net of amounts capitalized, totaled $2 million and $(8) million , respectively. No performance shares under the FirstEnergy LTIP were settled during the nine months ended September 30, 2011 and 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 nine months ended September 30, 2011 and 2010 , net of amounts capitalized and dividends on common stock, was approximately $34 million and $31 million , respectively.
(C) EDCP
There was no material compensation expense recognized on EDCP stock units during the nine months ended September 30, 2011 , and 2010 .
(D) DCPD
DCPD expenses recognized during the nine months ended September 30, 2011 , and 2010 were approximately $3 million in each period. The net liability recognized for DCPD of approximately $6 million as of 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, 1,075,080 stock units were available for future awards as of September 30, 2011 .

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


73

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 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.

14. SEGMENT INFORMATION
With the completion of the 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” 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 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 and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
•
AE Supply, an operator of generation facilities that was acquired as part of the merger with 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


74

and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from 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 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, Michigan, New Jersey and 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. AE Supply together with its consolidated subsidiary, AGC owns, operates and controls the electric generation capacity of 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 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.
Other/Corporate 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 Utility Registrants do not have separate reportable operating segments.


75

Segment Financial Information
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.



76

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.
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 million to operating income during the quarter ended March 31, 2011 . On July 28, 2011 , FirstEnergy closed the sale of Fremont Energy Center to American Municipal Power, Inc.
Peaking Facilities
During the first 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 $3 million and $23 million during the three and nine months ended 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.

16. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and the associated cost 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 for asbestos remediation.
The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear


77

generating facilities (OE for its leasehold 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 million and $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 .
The revisions to the estimated cash flows had no significant impact on accretion of the obligation during the three months and nine months ended September 30, 2011 , when compared to the same periods of 2010 .

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 months and nine months ended September 30, 2011 and 2010 , consolidating balance sheets as of September 30, 2011 and December 31, 2010 and consolidating statements of cash flows for the nine months ended 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.



78

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(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

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(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

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

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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(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
$
—

$
—

$
—

$
—

$
—



86

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 to FirstEnergy Corp. in the third quarter of 2011 were $511 million , or basic and diluted earnings of $1.22 per share of common stock, compared with $179 million , or basic and diluted earnings of $0.59 per share of common stock in the third quarter of 2010. Earnings Available to FirstEnergy Corp. in the first nine months of 2011 were $742 million or basic earnings of $1.89 ( $1.88 diluted) per share of common stock, compared with $599 million or basic earnings of $1.97 ( $1.96 diluted) per share of common stock in the first nine months of 2010. The principal reasons for the changes in basic earnings per share are summarized below.
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)
Excludes amounts that are shown separately
(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 AE closed. Pursuant to the terms of the Agreement and Plan of Merger between FirstEnergy, Merger Sub and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a 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 merger transaction costs of approximately $2 million ( $1 million net of tax) and $14 million ( $11 million net of tax) during the three months ended September 30, 2011 and 2010 , respectively, and approximately $91 million ( $73 million net of tax) and $35 million ( $26 million net of tax) during the first 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 September 30, 2011, $3 million ( $1 million net of tax) of merger integration costs and $2 million ( $1 million net of tax) of charges from merger settlements approved by regulatory agencies were recognized. In the first nine months of 2011, $88 million ( $67 million net of tax) of merger integration costs and $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


87

material in future periods.
FirstEnergy expects to achieve its 2011 merger benefits target resulting from the merger with AE. Through September 2011, FirstEnergy has taken actions and completed savings initiatives that will allow the company to capture merger benefits of approximately $165 million pre-tax on an annual basis, or 79% of the $210 million annual target.
Operational Matters
Richland and Stryker Peaking Power Plants

On October 18, 2011 , FirstEnergy closed on the sale of 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 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 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 FirstEnergy’s Consolidated Balance Sheet
•
Estimated gain on sale and revaluation of remaining ownership stake will increase equity by an additional $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 reduce delivery from up to 7.5 million tons annually to an obligation to accept up to 2 million tons each year.

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, 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 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 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.
Financial Matters
During the third quarter of 2011, FirstEnergy redeemed or repurchased approximately $425.8 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs associated with such PCRBs were returned for cancellation by the associated LOC providers.


88

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.

During the three months ended September 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 .

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” 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:
•
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with 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 and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with AE. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remained within the Regulated Distribution segment.
•
AE Supply, an operator of generation facilities that was acquired as part of the merger with 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 Utility Registrants do not have separate reportable operating segments.
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. 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


89

transmission-related revenues from 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 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, Michigan, New Jersey and 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. AE Supply together with its consolidated subsidiary, AGC owns, operates and controls the electric generation capacity of 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 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.
Other and Reconciling Adjustments 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 14 to the consolidated financial statements. Earnings available to FirstEnergy by business segment were as follows:

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.


90

Summary of Results of Operations — Third Quarter 2011 Compared with Third Quarter 2010
Financial results for FirstEnergy’s business segments in the third quarter of 2011 and 2010 were as follows:
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



91

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

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 — Third Quarter 2011 Compared with Third Quarter 2010
Net income increased by $86 million in the third quarter of 2011 compared to the 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:


93

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 and increased KWH deliveries. Distribution deliveries (excluding the Allegheny companies) increase d by 2.1% in the third quarter of 2011 from the third quarter of 2010 . The change in distribution deliveries by customer class is summarized in the following table:
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 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 compared to the same period in 2010. While cooling degree days were 29% above normal, they were 2% below 2010 levels. In the industrial sector, KWH deliveries increased to steel and electrical equipment customers by 9% and 11%, respectively, partially offset by decreased deliveries to automotive customers of 3%.
The following table summarizes the price and volume factors contributing to the $388 million decrease in generation revenues for the pre-merger companies in the third quarter of 2011 compared to the third quarter of 2010 :


94

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 third quarter of 2011 , compared with the third quarter of 2010 . Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 78% from 64% for the Ohio Companies and to 54% from 10% 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 $60 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 $768 million to revenues in the third quarter of 2011 , including $184 million for distribution services, $519 million from generation sales and $65 million of transmission revenues.
Operating Expenses —
Total operating expenses increased by $47 million due to the following:

•
Purchased power costs, excluding the Allegheny companies, were $529 million lower in the 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
)


95

•
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.



96

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



97


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


98

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
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 $ 24 million decrease in earnings available to FirstEnergy in the third quarter of 2011 compared to the same period in 2010 . The decrease resulted primarily from decreased capitalized interest ($14 million) resulting from completed construction projects and decreased investment income ($7 million).


99

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



100

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



101

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:



102

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) increase d 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 million decrease in generation revenues in the first nine months of 2011 compared to the same period of 2010 :



103

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 $401 million 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 million lower 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 $828 million to purchased power costs in the first nine 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
$
(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


•
Transmission expenses decreased $254 million primarily due to lower PJM network transmission expenses for Met-Ed and Penelec in the first nine 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 $77 million.
•
The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010 resulted in a comparative cost increase in 2011.
•
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.
•
A provision for excess and obsolete material of $13 million was recognized in the first nine months of 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.
•
Net amortization of regulatory assets decreased $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 and future recovery for Hurricane Irene costs.
•
Merger-related costs increased $56 million in the first nine months of 2011 compared to the same period of 2010 .
•
General taxes increased by $8 million primarily due to 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 $41 million in the first nine months of 2011 primarily due to interest expense on debt of the Allegheny companies and lower investment income on OE's and TE's nuclear decommissioning trusts.
Regulated Independent Transmission — First Nine Months 2011 Compared with First Nine Months 2010
Net income increased by $33 million in the first nine months of 2011 compared to the first nine months of 2010 due to earnings associated with TrAIL and PATH of $52 million, partially offset by decreased earnings for ATSI of $19 million.
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:


105

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 $22 million principally due to TrAIL and PATH operating expenses.
Other Expense —
Other expense increased $16 million in the first nine months of 2011 due to interest expense associated with TrAIL.
Competitive Energy Services — First Nine Months of 2011 Compared to First Nine Months of 2010
Net income increased by $85 million in the first nine months of 2011, compared to the first nine months of 2010, primarily due to higher sales margins, that were partially offset by higher O&M expenses, an inventory reserve adjustment 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 $1,096 million in the first 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:
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



106

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 $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 1.7 million residential and small commercial customers at the end of September 2011 compared to approximately 1.2 million customers at the end of September 2010.
The decrease in POLR revenues of $1,216 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-affiliates and 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 by $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
$
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



107

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 $28 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs declined $12 million in the first nine months of 2011.
Operating Expenses —
Total operating expenses increased by $878 million in the first nine months of 2011 due to the following:
•
Purchased power costs, excluding the Allegheny companies, decreased by $331 million due primarily to lower volumes purchased ($481 million) partially offset by higher unit costs ($150 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 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 $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 $64 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring in 2011. While Davis-Besse had a refueling outage in 2010, the work performed was largely capital-related.
•
Transmission expenses increased by $216 million primarily due to increases in PJM of $332 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $116 million.
•
General taxes increased by $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 $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 $19 million increase in mark-to-market adjustments; a $3 million increase in professional and contractor costs and a $15 million increase in intercompany billings. Intercompany billings increased due to merger-related costs, partially offset by lower intersegment billings for leasehold costs from the Ohio Companies.
The inclusion of the Allegheny companies’ operations added $1,173 million to expenses, including a $36 million mark-to-market adjustment relating primarily to power contracts, as shown in the following table:


108

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 nine months of 2011 was $88 million higher than the first nine months of 2010, primarily due to a $96 million increase in net interest expense, partially offset by an increase in nuclear decommissioning trust investment income ($8 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($54 million) and lower capitalized interest ($39 million) associated with the completion of the Sammis AQC project in 2010.
Other — First Nine Months of 2011 Compared to First 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 a $106 million decrease in earnings available to FirstEnergy in the first nine months 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 and increased depreciation expense resulting from completed construction projects placed into service ($43 million), decreased investment income ($7 million) and an asset impairment charge in the first quarter of 2011 ($11 million).
Regulatory Assets
Regulatory 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 September 30, 2011, and December 31, 2010, and changes during the nine months then ended:
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 $350 million related to the Allegheny companies.
The following tables provide information about the composition of net regulatory assets as of September 30, 2011 and December 31, 2010 and the changes during the nine month period:



109

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 $377 million of net regulatory liabilities as of September 30, 2011, including $367 million of net regulatory liabilities attributable to Allegheny that are primarily related to asset removal costs.
Regulatory assets that do not earn a current return totaled approximately $496 million as of September 30, 2011, of which $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. 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 that are expected to be recovered by 2021.

Regulatory assets not earning a current return for FirstEnergy’s other utility subsidiaries was $119 million and includes certain deferred generation and other costs that are expected to be recovered though 2026.


CAPITAL RESOURCES AND LIQUIDITY
As of September 30, 2011 , FirstEnergy had $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 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 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.
As of September 30, 2011 , FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to currently payable long-term debt, which, as of September 30, 2011 , included the following (in millions):



110

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 no significant short-term borrowings as of September 30, 2011 and approximately $700 million as of December 31, 2010 . FirstEnergy’s available liquidity as of October 28, 2011, is summarized in the following table:
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.
Revolving Credit Facilities
FirstEnergy and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of $4.5 billion (Facilities).
An aggregate amount of $2 billion is available to be borrowed under a syndicated revolving credit facility (FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the 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 (FES/AE Supply Facility).
Commitments under each of the 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 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 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 FES/AE Supply Facility or other indebtedness generally will not cross-default to FirstEnergy under the FirstEnergy Facility.
The following table summarizes the borrowing sub-limits for each borrower under the 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 September 30, 2011 :



111

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 FES/AE Supply Facility and $700 million of the 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 Facilities and against the applicable borrower’s borrowing sub-limit.
Each of the 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 September 30, 2011 , FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the Facilities) were as follows:
Borrower
FirstEnergy
55.1
%
FES
48.2
%
OE
54.7
%
Penn
36.1
%
CEI
55.8
%
TE
57.4
%
JCP&L
41.7
%
Met-Ed
52.5
%
Penelec
54.0
%
ATSI
54.3
%
MP
54.8
%
PE
57.1
%
WP
49.9
%
AE Supply
38.4
%

As of September 30, 2011 , FirstEnergy could issue additional debt of approximately $9.1 billion, or recognize a reduction in equity of approximately $4.9 billion, and remain within the limitations of the financial covenants required by its credit facility.
The 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 are related to the credit ratings of the company borrowing the funds.


112

In addition to the Facilities, FirstEnergy also has established an additional $500 million of revolving credit facilities that are available to TrAIL ($450 million) and AGC ($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 65% of the sum of its debt and equity as of the last day of each calendar quarter through December 31, 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 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 nine months of 2011 was 0.47% per annum for the regulated companies’ money pool and 0.44% per annum for the unregulated companies’ money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have received the appropriate regulatory approvals to become part of the FirstEnergy regulated money pool.
Pollution Control Revenue Bonds
As of September 30, 2011 , FirstEnergy’s currently payable long-term debt included approximately $632 million (FES — $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's variable interest rate PCRBs were issued by the following banks as of September 30, 2011 :
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 $7 million of applicable interest coverage.
(2)
Shorter of 6 months or LOC termination date.
During the third quarter of 2011, FirstEnergy redeemed or repurchased approximately $425.8 million principal amount of PCRBs, as summarized in the following table. Approximately $28.5 million of FGCO FMBs and $98.9 million of NGC FMBs 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

Long-Term Debt Capacity
As of September 30, 2011 , the Ohio Companies and Penn had the aggregate capability to issue approximately $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 $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 $361 million and $352 million, respectively, under provisions of their senior note indentures as of September 30, 2011 . In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of September 30, 2011 , MP, PE and WP had the capability to issue approximately $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 September 30, 2011 , FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as of September 30, 2011 , NGC had the capability to issue $1.9 billion of additional FMBs as of 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 March 21, 2011, S&P affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. On May 27, 2011, Fitch upgraded 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 Baa2 and revised FES' outlook to stable. The following table displays FirstEnergy’s and its subsidiaries’ securities ratings as of October 28, 2011.
Senior Secured
Senior Unsecured
Issuer
S&P
Moody’s
Fitch
S&P
Moody’s
Fitch
FirstEnergy Corp.
—
—
—
BB+
Baa3
BBB
FES
—
—
—
BBB-
Baa3
BBB
AE Supply
—
—
—
BBB-
Baa3
BBB-
AGC
—
—
—
BBB-
Baa3
BBB
ATSI
—
—
—
BBB-
Baa1
A-
CEI
BBB
Baa1
BBB
BBB-
Baa3
BBB-
JCP&L
—
—
—
BBB-
Baa2
BBB+
Met-Ed
BBB
A3
A-
BBB-
Baa2
BBB+
MP
BBB+
Baa1
A-
BBB-
Baa3
BBB+
OE
BBB
A3
BBB+
BBB-
Baa2
BBB
Penelec
BBB
A3
BBB+
BBB-
Baa2
BBB
Penn
BBB+
A3
BBB+
—
—
—
PE
BBB+
Baa1
A-
BBB-
Baa3
BBB+
TE
BBB
Baa1
BBB
—
—
—
TrAIL
—
—
—
BBB-
Baa2
A-
WP
BBB+
A3
A-
BBB-
Baa2
BBB+
Changes in Cash Position
As of September 30, 2011 , FirstEnergy had $291 million of cash and cash equivalents compared to approximately $1 billion as of 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.
During the first nine months of 2011 , FirstEnergy received $1.4 billion from cash dividends and equity repurchases by its subsidiaries and paid $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 businesses (see Results of Operations above). Net cash provided from operating


114

activities increased by $156 million during the first nine months of 2011 compared to the same period in 2010 , as summarized in the following table:
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 resulting from bonus depreciation ( $377 million ) and increased depreciation attributable to the acquired Allegheny 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 ( $205 million ).
The increase in cash flows from working capital and other is primarily due to decreased receivables from higher customer collections ( $311 million ) and decreased materials and supplies from the inventory valuation adjustment in the first quarter of 2011 ( $68 million ), partially offset by decreased payables ( $138 million ).
Cash Flows From Financing Activities
In the first nine months of 2011 , cash used for financing activities was $2,402 million compared to $870 million in the comparable period of 2010 . The following tables summarize new debt financing (net of any discounts) and redemptions:

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 were are follows:
Date
Company
Type of Debt
Issued (Redeemed)
(In millions)
July, 2011
AGC
Unsecured notes
$
100

August, 2011
AGC
Unsecured notes
$
(100
)



115

During the remainder of 2011 FirstEnergy and its subsidiaries may continue to pursue, from time to time, reductions in outstanding long-term debt 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 nine months of 2011 resulted from cash used for property additions, partially offset by the cash acquired in the Allegheny merger and proceeds from asset sales. The following table summarizes investing activities for the first nine months of 2011 and the comparable period of 2010 by business segment:
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 nine months of 2011 decreased by $890 million compared to the same period of 2010 . The decrease was principally due to cash acquired in the Allegheny merger ( $590 million ) and an increase in proceeds from asset sales ( $402 million ), partially offset by an increase in net purchases of investment securities ($90 million) and increased property additions ( $62 million ).
During last quarter of 2011 , capital requirements for property additions and capital leases are estimated to be approximately $638 million, including approximately $35 million for nuclear fuel.

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. Some of the guaranteed contracts contain collateral provisions that are contingent upon either FirstEnergy or its subsidiaries’ credit ratings.
As of September 30, 2011 , FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.8 billion , as summarized below:



116

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 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $33 million for railcar leases.
(3)
Includes $74 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $121 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE, $39 million pledged in connection with the sale and leaseback of Perry by 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 September 30, 2011 , FirstEnergy’s maximum exposure under these collateral provisions was $594 million , as shown below:

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 $204 million and $53 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.
(2)
Includes $29 million that is also considered an acceleration of payment or funding obligation for FES.
Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical increase in prices in the underlying commodity markets would increase the total potential amount to $662 million , as shown below:



117

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 $204 million and $53 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.
(2)
Includes $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 $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 September 30, 2011, and forward prices as of that date, FES and AE Supply have posted collateral of $123 million and $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 $16 million and $1 million of 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' 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 September 30, 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.
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


118

of fair value for financial reporting purposes and for internal management decision making (see Note 6 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of 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)
(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 $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 September 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $14 million during the next 12 months.
Equity Price Risk
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.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of September 30, 2011, the FirstEnergy pension plan was invested in approximately 27% of equity securities, 50% of fixed income securities, 11% of absolute return strategies, 6% of real estate, 4% of private equity and 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 and nine months ended September 30, 2011 , FirstEnergy made pre-tax contributions to its qualified pension plans of $112 million and $375 million , respectively.
NDT funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of September 30, 2011, approximately 19% of the funds were invested in fixed income securities, 9% of the funds were invested in equity securities and 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 $393 million, $180 million and $1,493 million for fixed income securities, equity securities and short-term investments, respectively, as of September 30, 2011, excluding $22 million in a net liability position of receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $18 million reduction in fair value as of 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 nine months of 2011, approximately $1 million, $4 million and $1 million was contributed to the NDTs of JCP&L, OE and TE, respectively. FENOC has submitted a $95 million parental guarantee to the NRC for a short-fall in nuclear decommissioning funding for Beaver Valley Unit 1 and 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.
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

current weighted average risk rating for energy contract counterparties of BBB (S&P). As of 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% for FES, 2% for JCP&L, 2% for Met-Ed, 3% for WP and a combined 2% for the Ohio Companies.

OUTLOOK

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 designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and 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 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 RFC. Moreover, it is clear that the NERC, 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. Any future inability on 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 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 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 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, RFC issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to RFC on September 27, 2010. On July 8, 2011, RFC and Met-Ed signed a settlement agreement to resolve all outstanding issues related to the vegetation encroachment event. The settlement calls for Met-Ed to pay a penalty of $650,000 , and for FirstEnergy to 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 RFC. FirstEnergy was performing the LiDAR work in response to certain other industry directives issued by 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.

MARYLAND

By statute enacted in 2007, the obligation of Maryland utilities to provide 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 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 proceeding.
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 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


120

for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and 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 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 million and would be recovered over the following six years. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. Hearings on those plans and the plans of the other utilities were held in mid October 2011.
In March 2009, the MDPSC issued an order temporarily suspending 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 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 compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC convened a working group of utilities, regulators, and other interested stakeholders to address the topics of the proposed rules. A draft of the rules was filed, along with the report of the working group, on October 27, 2011. Comments on the draft rules are due by November 16, and a hearing to consider the rules and comments is scheduled for December 8 and 9, 2011. Separately, on July 7, 2011, the MDPSC adopted draft rules requiring monitoring and inspections for contact voltage. The draft rules were published in September, and then approved by the MDPSC as final rules on October 31, 2011. The rules will go into effect after being published again in the Maryland Register.

NEW JERSEY

On September 8, 2011, 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 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 the Morristown underground network. A schedule for the completion of the 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, 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 a result of information obtained through this process.



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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, Rider 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 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 million dependent on the outcome of certain PJM proceedings, agreed to establish a $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 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 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 Ohio Companies to an assessment of a penalty by the 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 decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On September 7, 2011, the PUCO denied those applications for rehearing.

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' aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies' 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC 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. On August 3, 2011, the 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 Ohio Companies were short in 2010. On September 2, 2011, the Environmental Law and 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 Ohio Companies' alternative energy recovery rider. Separately, one party has filed a request that the PUCO audit the cost of the Ohio Companies' compliance with the alternative energy requirements and the Ohio Companies' compliance with Ohio law. The PUCO has not ruled on 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


122

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 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 Ohio Companies to recover deferred costs and associated carrying charges. OCC filed an application for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO did not act on the application for 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

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 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 March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $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 and 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 . , 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 million ( $189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In each of May 2008, 2009 and 2010, the PPUC approved Met-Ed's and 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 approval in May 2010 authorized an increase to the TSC for 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 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 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' 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 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 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 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 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.

Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 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 million , which Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The PPUC approved the SMIP, as modified by the ALJ, in June 2010. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the 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 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 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 OCA filed a Joint Petition for Settlement addressing 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 grace period authorized by the PPUC to continue 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.
Following additional proceedings, 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 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 original smart meter implementation plan. A Joint Stipulation with the OSBA was also filed on March 9, 2011. The PPUC approved the Amended Joint Petition for Full Settlement by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional 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 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 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 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.

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 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 EDC before using its trademark or service mark. The Proposed Rulemaking Order calls for comments to be submitted within forty-five days of its publication in the Pennsylvania Bulletin, with no provision for replies. The Order has not been published yet. If implemented these rules could require a significant change in the 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.

WEST VIRGINIA

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 was issued by the WVPSC in September 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. The application was approved and the three facilities are capable of generating renewable credits which 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.

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 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. 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 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 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 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. 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 all respects.

PJM Transmission Rate

In April 2007, FERC issued an order (Opinion 494) finding that the PJM transmission 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


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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, which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

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 ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500 kV and higher voltage facilities on a load ratio share basis and, based on this finding, remanded the rate design issue 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 filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain 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. Other utilities and 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 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 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 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 proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI's proposed treatment of the 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 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 proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC's decision to require a cost-benefit study analysis as part of FERC's evaluation of ATSI's proposed transmission rates. 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 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 move into PJM. These orders approve ATSI's proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect 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 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 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 million to the MISO. This settlement agreement has been submitted for FERC's review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

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 as MVPs - are a class of transmission projects that


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are approved via 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 Board approved the first MVP project -- the “Michigan Thumb Project.” Under MISO's proposal, the costs of MVP projects approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $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 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 MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. 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 tariffs obligate ATSI to pay all charges that attached prior to 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 order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy requested rehearing of 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 proposed transmission 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 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 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 CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $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 ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains 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


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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 either of the above matters.

PATH Transmission 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 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 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 0.5% 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 and the six intervenors filed with the Chief Administrative Law Judge of FERC a joint motion for interim approval and authorization to implement the refund on an interim basis pending issuance of a FERC order acting on the 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 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 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 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' 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 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 petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC.

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”


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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 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 the studies 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
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 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 SO 2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO 2 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 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 motion to dismiss New Jersey's and Connecticut's claims for injunctive relief against Met-Ed, but denied Met-Ed's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed's indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this 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 SO 2 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 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 PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, 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 PSD and Title V permitting programs. The complaint was also filed against the former co-owner, 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 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 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 and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. On October 12 and 13, 2011, the Court dismissed all of 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 refile state law claims in state court, against all of the defendants, including Penelec.


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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 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 information requests but, at this time, is unable to predict the outcome of this 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 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: Albright, Armstrong, Fort Martin, Harrison, 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 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 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 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 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 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 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 SO 2 and NOx, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition's regional efforts to reduce CO 2 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 NOx, SO 2 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 MDE passed alternate NOx and SO 2 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% which began in 2010. The statutory exemption does not extend to R. Paul Smith's CO 2 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 or estimate the possible loss or range of loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny's Pleasants coal-fired plant. In August 2011, Allegheny and WVDEP resolved the NOV through a Consent Order requiring installation of a reagent injection system to reduce opacity by September 2012.
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The EPA's CAIR requires reductions of NOx and SO 2 emissions in two phases (2009/2010 and 2015), ultimately capping SO 2 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 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 CSAPR to replace CAIR, which remains in effect until CSAPR becomes effective ( 60 days after publication in the Federal Register). CSAPR requires reductions of NOx and SO 2 emissions in two phases (2012 and 2014), ultimately capping SO 2 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 SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. 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 SO 2 emissions and proposed to delay restrictions on interstate trading of NOx and SO 2 emission 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 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 SO 2 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 continuing to assess the impact of CSAPR, other environmental proposals and other factors on FirstEnergy's competitive fossil generating facilities, including but not limited to, the impact on its SO 2 emission allowances 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 future cost of compliance with MACT regulations may be substantial and changes to 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 “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 currently requires it to submit 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 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 NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO 2 ) effective January 2, 2011 for existing facilities under the CAA's PSD program.
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 CO 2 , 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 billion over the next three years with a goal of increasing to $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.
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. 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 ruling also failed to answer the question of the extent to which actions for damages may remain viable.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO 2 emissions 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-CO 2 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 plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to 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 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 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 water intake channel to divert fish away from the 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 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 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. 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 to 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 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.
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 Ferry coal-fired plant. These


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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 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 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. A hearing on 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, 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 recommended sulfate impairment designation. PA 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 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 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 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 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 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 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 hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. 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.
LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the 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.
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


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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 September 30, 2011 , based on estimates of the total costs of cleanup, the Utility Registrants' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $103 million (JCP&L - $69 million , TE - $1 million , CEI - $1 million , FGCO - $1 million and FirstEnergy - $31 million ) have been accrued through September 30, 2011 . Included in the total are accrued liabilities of approximately $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 . FirstEnergy recognized an additional expense of $29 million during the second quarter of 2011; $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
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' 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 decision decertifying the class. In November 2010, the Supreme Court issued an order denying Plaintiffs' motion for leave to appeal. The Court's order effectively ends the attempt to certify the class, and leaves only nine ( 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 have 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 September 30, 2011 , FirstEnergy had approximately $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 NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, 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 . On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.
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 facilities as a result of the DOE's failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to 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 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 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


134

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 ICG, Anker WV, and Anker 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' 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 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $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 million ( $90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. 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 Notice of Appeal and a briefing schedule was issued with oral argument likely in 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 normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above 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


135

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, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
See Note 13 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.



136

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, Michigan, New Jersey and 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 $11 million in the first nine months of 2011 compared to the same period of 2010 . The decrease was primarily due to higher operating expenses, an inventory reserve adjustment and the effect of mark-to-market adjustments, partially offset by lower non-core asset impairment charges.
Revenues
Total revenues decreased $152 million , or 3.5% , in the first 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
)

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
)%



137


The increase in direct and governmental aggregation revenues of $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 1.7 million residential and small commercial customers at the end of September 2011 compared to approximately 1.2 million customers at the end of September 2010.
The decrease in POLR revenues of $1,216 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-affiliates and higher unit prices to the Pennsylvania 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 to selectively participate in POLR auctions.
Wholesale revenues increase d by $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
$
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
$
(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 increase d by $28 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs decreased $12 million in the first nine months of 2011.
Operating Expenses
Total operating expenses decreased by $160 million in the first nine months of 2011 , compared with the same period of 2010 .
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2011 compared with the same period last year:



138

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 $17 million in the first 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 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 $252 million in the first 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 that FES no longer has the requirement to serve. Affiliated purchased power costs decreased by $57 million in the first nine months of 2011 , compared to the same period of 2010 , due to lower unit costs and decreased volumes purchased.
Other operating expenses increased by $399 million in the first nine months of 2011 , compared to the same period of 2010 due to the following:

•
Transmission expenses increased by $216 million due primarily to increases in PJM of $332 million from higher congestion, network and line loss expense, partially offset by lower MISO transmission expenses of $116 million.
•
Nuclear operating costs increased by $64 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring in 2011. While Davis-Besse had a refueling outage in 2010, the work performed was largely capital-related.
•
Fossil operating costs increased by $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 and an increase in mark-to-market adjustments of $24 million.
Impairment charges on long-lived assets decreased by $272 million due to a charge related to operational changes at certain 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 nine months of 2011.
General taxes increased by $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.



139

Other Expense
Total other expense increased by $29 million in the first nine months of 2011 , compared to the same period of 2010 , primarily due to a $39 million decrease in capitalized interest associated with the completion of the Sammis AQC project in 2010, partially offset by a $6 million increase in investment income from higher NDT income.



140

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
Net income was unchanged for the first nine months of 2011, compared to the same period of 2010, as decreased revenues and increased other operating expenses were offset by decreased purchased power costs.
Revenues
Revenues decrease d by $187 million , or 13% , in the first 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 $72 million in the first nine months of 2011 , compared to the same period in 2010 , due to increased KWH deliveries 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. 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 nine months of 2011 , compared to the same period in 2010 , are summarized in the following tables:

Distribution KWH Deliveries
Increase
Residential
2.5
%
Commercial
0.9
%
Industrial
7.8
%
Increase in Distribution Deliveries
3.8
%
Distribution Revenues
Increase
(In millions)
Residential
$
37

Commercial
16

Industrial
19

Increase in Distribution Revenues
$
72


Retail generation revenues decreased by $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 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 in the first nine months of 2011 . The increases in customer shopping for residential, commercial and industrial customer classes were 21%, 12% and 7%, respectively.


141

Decreases in retail generation KWH sales and revenues in the first nine months of 2011 , compared to the same period in 2010 , are summarized in the following tables:

Retail Generation KWH Sales
Decrease
Residential
(30.8
)%
Commercial
(36.3
)%
Industrial
(21.4
)%
Decrease in Retail Generation Sales
(29.9
)%
Retail Generation Revenues
Decrease
(In millions)
Residential
$
(171
)
Commercial
(65
)
Industrial
(30
)
Decrease in Retail Generation Revenues
$
(266
)

Wholesale generation revenues increased by $14 million in the first 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 decrease d by $192 million in the first nine months of 2011 , compared to the same period of 2010 . The following table presents changes from the prior period by expense category:

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 nine months of 2011 , compared to the same period of 2010 , due to lower KWH purchases resulting from reduced generation sales requirements coupled with lower unit costs. The increase in other operating expenses for the first 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 . General taxes increased as a result of higher property taxes.



142

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 increased $1 million in the first nine months of 2011, compared to the same period of 2010. The increase in earnings was due to lower purchased power costs and amortization of regulatory assets, partially offset by lower revenues.
Revenues
Revenues decreased by $268 million, or 28%, in the first nine months of 2011, compared to the same period of 2010, due to lower retail generation and distribution revenues.
Distribution revenues decreased by $43 million in the first 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 these customer classes. The lower average unit prices were the result of the absence of transition charges in 2011. 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 sector, KWH deliveries increased primarily as a result of recovering economic conditions in CEI's service territory.
Changes in distribution KWH deliveries and revenues in the first 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
%
Commercial
(0.6
)%
Industrial
1.6
%
Net Increase in Distribution Deliveries
0.8
%
Increase
Distribution Revenues
(Decrease)
(In millions)
Residential
$
(1
)
Commercial
7

Industrial
(49
)
Net Decrease in Distribution Revenues
$
(43
)

Retail generation revenues decreased by $224 million in the first 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. 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. Lower KWH sales were the result of increased customer shopping for residential, commercial and industrial classes of 18%, 10% and 37%, respectively. Lower average unit prices in the residential customer class were the result of generation credits in place for 2011.


143

Decreases in retail generation sales and revenues in the first nine months of 2011, compared to the same period of 2010, are summarized in the following tables:

Retail Generation KWH Sales
Decrease
Residential
(43.0
)%
Commercial
(40.4
)%
Industrial
(71.1
)%
Decrease in Retail Generation Sales
(53.7
)%
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 $262 million in the first nine months of 2011, compared to the same period of 2010. The following table presents the change from the prior year by expense category:
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 due to lower KWH purchases resulting from reduced sales requirements. Other operating expenses increased due to 2011 inventory valuation adjustments. Amortization of regulatory assets decreased primarily due to the completion of transition cost recovery at the end of 2010 and deferred 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 due to increased property taxes as compared to the same period of 2010.



144

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 $4 million in the first nine months of 2011 , compared to the same period of 2010 . The increase primarily resulted from lower purchased power costs from affiliates, partially offset by lower revenues and higher other operating expenses.
Revenues
Revenues decreased by $40 million , or 10% , in the first 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 $20 million in the first nine months of 2011 , compared to the same period of 2010 , due to higher residential, 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 sector, KWH deliveries increased primarily as a result of recovering economic conditions in TE's service territory.
Changes in distribution KWH deliveries and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:
Distribution KWH Deliveries
Increase (Decrease)
Residential
2.8
%
Commercial
(1.7
)%
Industrial
3.2
%
Net Increase in Distribution Deliveries
2.1
%
Distribution Revenues
Increase
(In millions)
Residential
$
11

Commercial
5

Industrial
4

Increase in Distribution Revenues
$
20


Retail generation revenues decreased by $70 million in the first 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.


145

Decreases in retail generation KWH sales and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:

Retail Generation KWH Sales
Decrease
Residential
(28.9
)%
Commercial
(42.1
)%
Industrial
(10.5
)%
Decrease in Retail Generation Sales
(21.6
)%
Retail Generation Revenues
Decrease
(In millions)
Residential
$
(25
)
Commercial
(17
)
Industrial
(28
)
Decrease in Retail Generation Revenues
$
(70
)

Wholesale revenues increased by $11 million in the first 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 $44 million in the first nine months of 2011 , compared to the same period of 2010 . The following table presents changes from the prior period by expense category:

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 decrease d in the first 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 nine months of 2011 coupled with lower unit costs. The increase in other operating costs for the first 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 increase d expenses due to more recovery of costs deferred in prior years during the first nine months of 2011 , compared to the same period of 2010 .
Other Expense
Other expense increase d by $1 million in the first nine months of 2011 , compared to the same period of 2010 , due to lower nuclear decommissioning trust investment income.



146

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.
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 decrease d by $18 million in the first nine months of 2011 , compared to the same period of 2010 . The decrease was primarily due to lower revenues and higher other operating expenses, partially offset by reductions in purchased power costs and amortization of regulatory assets, net.
Revenues
Revenues decrease d by $380 million , or 16% , in the first nine months of 2011 , compared to the same period of 2010 . The decrease in revenues was due to lower distribution, retail generation and wholesale generation revenues, partially offset by an increase in other revenues.
Distribution revenues decreased by $134 million in the first 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, and lower KWH deliveries. The lower KWH deliveries to the residential class were influenced by decreased weather-related usage in the first nine months of 2011 . Lower distribution deliveries to commercial and industrial customers reflected the impact of economic conditions to these sectors.
Decreases in distribution KWH deliveries and revenues in the first nine months of 2011 compared to the same period of 2010 are summarized in the following tables:

Distribution KWH Deliveries
Decrease
Residential
(1.5
)%
Commercial
(2.4
)%
Industrial
(2.4
)%
Decrease in Distribution Deliveries
(2.0
)%
Distribution Revenues
Decrease
(In millions)
Residential
$
(65
)
Commercial
(57
)
Industrial
(12
)
Decrease in Distribution Revenues
$
(134
)

Retail generation revenues decreased by $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 11%, 10% and 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 earnings.


147

Decreases in retail generation KWH sales and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:

Retail Generation KWH Sales
Decrease
Residential
(12.0
)%
Commercial
(23.7
)%
Industrial
(27.9
)%
Decrease in Retail Generation Sales
(15.7
)%
Retail Generation Revenues
Decrease
(In millions)
Residential
$
(136
)
Commercial
(89
)
Industrial
(9
)
Decrease in Retail Generation Revenues
$
(234
)

Wholesale generation revenues decreased by $21 million in the first nine months of 2011 , compared to the same period of 2010 , due to a decrease in PJM spot market energy sales.
Other revenues increased by $9 million in the first 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 $347 million in the first nine months of 2011 , compared to the same period of 2010 . The following table presents changes from the prior period by expense category:

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 decrease d by $254 million in the first nine months of 2011 due to lower requirements from reduced retail generation sales. Other operating expenses increase d by $38 million in the first nine months of 2011 principally from Hurricane Irene storm restoration maintenance costs, partially offset by lower labor costs. Amortization of regulatory assets, net, decrease d by $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 a write-off of nonrecoverable NUG costs.



148

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 who have not elected an alternate power supplier. Met-Ed procures power under its 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 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 increase d by $21 million in the first nine months of 2011 , compared to the same period of 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
Revenues decrease d by $446 million , or 32% , in the first 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 $252 million in the first 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 increased KWH deliveries. 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 sector, KWH deliveries increased primarily as a result of recovering economic conditions in Met-Ed's service territory.

Changes in distribution KWH deliveries and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:
Distribution KWH Deliveries
Increase (Decrease)
Residential
0.5
%
Commercial
(1.1
)%
Industrial
3.1
%
Net Increase in Distribution Deliveries
1.1
%
Distribution Revenues
Decrease
(In millions)
Residential
$
(95
)
Commercial
(71
)
Industrial
(86
)
Decrease in Distribution Revenues
$
(252
)

Retail generation revenues decreased by $27 million in the first 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. 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.


149

Changes in retail generation KWH sales and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:

Retail Generation KWH Sales
Decrease
Residential
(1.1
)%
Commercial
(46.4
)%
Industrial
(90.2
)%
Decrease in Retail Generation Sales
(43.9
)%
Retail Generation Revenues
Increase (Decrease)
(In millions)
Residential
$
133

Commercial
(18
)
Industrial
(142
)
Net Decrease in Retail Generation Revenues
$
(27
)

Wholesale revenues decreased by $157 million in the first nine months of 2011 , compared to the same period of 2010 , reflecting lower RPM revenues for Met-Ed in the PJM market.
Transmission revenues decreased by $10 million in the first 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 deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings in the period.
Operating Expenses
Total operating expenses decrease d $472 million in the first nine months of 2011 compared to the same period of 2010 . The following table presents changes from the prior year by expense category:

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 $241 million in the first 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 $189 million in the first 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 by $35 million in the first nine months of 2011 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $8 million in the first nine months of 2011 primarily due to lower gross receipts taxes.
Other Expense
In the first nine months of 2011 , interest income decreased by $3 million primarily due to reduced CTC stranded asset balances compared to the same period of 2010 .



150

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 who have not elected an alternative power supplier. Penelec procures power under its 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 million in the first nine months of 2011 , compared to the same period of 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 decreased by $322 million , or 28% , in the first nine months of 2011 compared to the same period of 2010 . The decrease in revenue was primarily due to lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $13 million in the first 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 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 nine months of 2010 .
Changes in distribution KWH deliveries and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:

Increase
Distribution KWH Deliveries
(Decrease)
Residential
—
%
Commercial
(3.0
)%
Industrial
4.3
%
Net Increase in Distribution Deliveries
1.0
%
Increase
Distribution Revenues
(Decrease)
(In millions)
Residential
$
3

Commercial
(22
)
Industrial
6

Net Decrease in Distribution Revenues
$
(13
)

Retail generation revenues decreased by $149 million in the first 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 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.


151

Changes in retail generation KWH sales and revenues in the first nine months of 2011 , compared to the same period of 2010 , are summarized in the following tables:
Retail Generation KWH Sales
Decrease
Residential
(3.9
)%
Commercial
(50.7
)%
Industrial
(91.0
)%
Decrease in Retail Generation Sales
(50.7
)%
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 $151 million in the first nine months of 2011 , compared to the same period of 2010 , reflecting lower RPM revenues for Penelec in the PJM market.
Transmission revenues decreased by $9 million in the first 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 deferred the difference between transmission revenues and transmission costs incurred, resulting in no material effect to earnings for the period.
Operating Expenses

Total operating expenses decreased by $335 million in the first nine months of 2011 , as compared with the same period of 2010 . The following table presents changes from the prior year by expense category:

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 $326 million in the first 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 $73 million in the first 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 regulatory assets increased by $67 million in the first nine months of 2011 , primarily due to reduced NUG deferrals as a result of a PPUC-approved increase in Penelec’s NUG cost recovery rider in January 2011.
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.




152

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
(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 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 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.

PART II. OTHER INFORMATION

ITEM 1.        LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A.    RISK FACTORS
For the quarter ended 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
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the third quarter of 2011.
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., Non-Employee Director Stock Plan, Allegheny Energy, Inc., Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.

ITEM 5.     OTHER INFORMATION
Signal Peak Mine Safety
During the third quarter FirstEnergy, through its FEV wholly owned subsidiary, held a 50% interest in Global Mining Group LLC, a


153

joint venture 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
Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended September 30, 2011 :
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
Exhibit Number
FirstEnergy
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 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
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 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
12
Fixed charge ratios


154

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. 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.
CEI
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 Cleveland Electric Illuminating 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.
TE
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 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
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 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 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

the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.


156

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
November 1, 2011
FIRSTENERGY CORP.
Registrant
FIRSTENERGY SOLUTIONS CORP.
Registrant
OHIO EDISON COMPANY
Registrant
THE CLEVELAND ELECTRIC
ILLUMINATING COMPANY
Registrant
THE TOLEDO EDISON COMPANY
Registrant
METROPOLITAN EDISON COMPANY
Registrant
PENNSYLVANIA ELECTRIC COMPANY
Registrant
/s/ Harvey L. Wagner
Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer
JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
/s/ K. Jon Taylor
K. Jon Taylor
Controller
(Principal Accounting Officer)



157
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