instructions for filing ferc form nos. 1 and 3-q · any electronic submission must be created by...

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

I. Purpose

FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others(18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements theannual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial andoperational information from electric utilities, licensees and others subject to the jurisdiction of the Federal EnergyRegulatory Commission. These reports are also considered to be non-confidential public use forms.

II. Who Must Submit

Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of AccountsPrescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101),must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).

Note: Major means having, in each of the three previous calendar years, sales or transmission service thatexceeds one of the following:

(1) one million megawatt hours of total annual sales, (2) 100 megawatt hours of annual sales for resale, (3) 500 megawatt hours of annual power exchanges delivered, or (4) 500 megawatt hours of annual wheeling for others (deliveries plus losses).

III. What and Where to Submit

(a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each reportfor your files. Any electronic submission must be created by using the forms submission software provided free by theCommission at its web site: http://www.ferc.gov/docs-filing/eforms/form-1/elec-subm-soft.asp. The software isused to submit the electronic filing to the Commission via the Internet.

(b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.

(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, thelatest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report tothe Secretary of the Commission at:

Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426

(d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (notapplicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can beeither eFiled or mailed to the Secretary of the Commission at the address above.

FERC FORM 1 & 3-Q (ED. 03-07) i

The CPA Certification Statement should:

a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with theCommission's applicable Uniform System of Accounts (including applicable notes relating thereto and theChief Accountant's published accounting releases), and

b) Be signed by independent certified public accountants or an independent licensed public accountantcertified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18C.F.R. §§ 41.10-41.12 for specific qualifications.)

Reference Schedules Pages

Comparative Balance Sheet 110-113 Statement of Income 114-117 Statement of Retained Earnings 118-119 Statement of Cash Flows 120-121 Notes to Financial Statements 122-123

e) The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions,explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions arereported.

“In connection with our regular examination of the financial statements of for the year ended on which we havereported separately under date of , we have also reviewed schedules

of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, forconformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in itsapplicable Uniform System of Accounts and published accounting releases. Our review for this purpose included suchtests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph(except as noted below) conform in all material respects with the accounting requirements of the Federal EnergyRegulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.”

The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.

(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have beenadded to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on theCommission’s website at http://www.ferc.gov/help/how-to.asp.

(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies ofFERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdf andhttp://www.ferc.gov/docs-filing/eforms.asp#3Q-gas .

IV. When to Submit:

FERC Forms 1 and 3-Q must be filed by the following schedule:

FERC FORM 1 & 3-Q (ED. 03-07) ii

a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and

b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §141.400).

V. Where to Send Comments on Public Reporting Burden.

The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144hours per response, including the time for reviewing instructions, searching existing data sources, gathering andmaintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden forthe FERC Form 3-Q collection of information is estimated to average 150 hours per response.

Send comments regarding these burden estimates or any aspect of these collections of information, includingsuggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office ofManagement and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy RegulatoryCommission). No person shall be subject to any penalty if any collection of information does not display a valid controlnumber (44 U.S.C. § 3512 (a)).

FERC FORM 1 & 3-Q (ED. 03-07) iii

GENERAL INSTRUCTIONS

I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpretall accounting words and phrases in accordance with the USofA.

II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages andfigures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statementswhere rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on thestatements that they support. When applying thresholds to determine significance for reporting purposes, use for balancesheet accounts the balances at the end of the current reporting period, and use for statement of income accounts thecurrent year's year to date amounts.

III Complete each question fully and accurately, even if it has been answered in a previous report. Enter theword "None" where it truly and completely states the fact.

IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "NotApplicable" in column (d) on the List of Schedules, pages 2 and 3.

V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in theheader of each page is to be completed only for resubmissions (see VII. below).

VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, mustbe reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing thenumbers in parentheses.

VII For any resubmissions, submit the electronic filing using the form submission software only. Please explainthe reason for the resubmission in a footnote to the data field.

VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries,except as specifically authorized.

IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be basedupon those shown by the report of the previous period/year, or an appropriate explanation given as to why the differentfigures were used.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasonsand is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service asdescribed in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and isintended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service asdescribed in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm"means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverseconditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open AccessTransmission Tariff. For all transactions identified as LFP, provide in a footnote the

FERC FORM 1 & 3-Q (ED. 03-07) iv

termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to theterms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that servicecannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For alltransactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date eitherbuyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-pointtransmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and isintended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in theabove-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form.Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in priorreporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONSI. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or anyother Commission. Name the commission whose authorization was obtained and give date of the authorization.

II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whosebehalf the report is made.

FERC FORM 1 & 3-Q (ED. 03-07) v

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

(3) ’Corporation' means any corporation, joint-stock company, partnership, association, business trust,organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of theforegoing. It shall not include 'municipalities, as hereinafter defined;

(4) 'Person' means an individual or a corporation;

(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,and any assignee or successor in interest thereof;

(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision oragency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, ordistributing power; ......

(11) "project' means. a complete unit of improvement or development, consisting of a power house, all waterconduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, andall storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power therefrom to the point of junction with the distribution system or with the interconnected primary transmission system, allmiscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights,rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary orappropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

(a) To make investigations and to collect and record data concerning the utilization of the water 'resources of any region tobe developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, andconcerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent theCommission may deem necessary or useful for the purposes of this Act."

"Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic orspecial* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assistthe Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form inwhich such reports salt be made, and require from such persons specific answers to all questions upon which theCommission may need information. The Commission may require that such reports shall include, among other things, fullinformation as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest dueand paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of theproject and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation,generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any suchperson to make adequate provision for currently determining such costs and other facts. Such reports shall be made underoath unless the Commission otherwise specifies*.10

FERC FORM 1 & 3-Q (ED. 03-07) vi

"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind suchorders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among otherthings, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribethe FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission,the information which they shall contain, and the time within which they shall be field..."

General Penalties

The Commission may assess up to $1 million per day per violation of its rules and regulations. SeeFPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM 1 & 3-Q (ED. 03-07) vii

IDENTIFICATION

FERC FORM NO. 1/3-Q:REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Marlene Barwood

76 South Main Street, Akron, Ohio 44308

2014/Q4

76 South Main Street, Akron, Ohio 44308

01 Exact Legal Name of Respondent

(1) An Original (2) A ResubmissionX

02 Year/Period of Report

End ofJersey Central Power & Light Company

03 Previous Name and Date of Change (if name changed during year)

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

05 Name of Contact Person 06 Title of Contact Person

07 Address of Contact Person (Street, City, State, Zip Code)

08 Telephone of Contact Person,IncludingArea Code

09 This Report Is 10 Date of Report(Mo, Da, Yr)

01 Name

02 Title

03 Signature 04 Date Signed

(Mo, Da, Yr)

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States anyfalse, fictitious or fraudulent statements as to any matter within its jurisdiction.

/ /

Jason Petrik Assistant Controller

(330) 761-4049 / /

Marlene Barwood

Controller 03/31/2015

ANNUAL CORPORATE OFFICER CERTIFICATIONThe undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statementsof the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all materialrespects to the Uniform System of Accounts.

FERC FORM No.1/3-Q (REV. 02-04) Page 1

Name of Respondent This Report Is:(1) An Original(2) A Resubmission

Date of Report(Mo, Da, Yr)

Year/Period of Report

End of

LIST OF SCHEDULES (Electric Utility)

Jersey Central Power & Light CompanyX

/ /2014/Q4

Line No.

Title of Schedule ReferencePage No.

Remarks

(c)(b)(a)

Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported forcertain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

101General Information 1

102Control Over Respondent 2

103Corporations Controlled by Respondent 3

104Officers 4

105Directors 5

None106(a)(b)Information on Formula Rates 6

108-109Important Changes During the Year 7

110-113Comparative Balance Sheet 8

114-117Statement of Income for the Year 9

118-119Statement of Retained Earnings for the Year 10

120-121Statement of Cash Flows 11

122-123Notes to Financial Statements 12

122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13

200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14

None202-203Nuclear Fuel Materials 15

204-207Electric Plant in Service 16

None213Electric Plant Leased to Others 17

214Electric Plant Held for Future Use 18

216Construction Work in Progress-Electric 19

219Accumulated Provision for Depreciation of Electric Utility Plant 20

224-225Investment of Subsidiary Companies 21

None227Materials and Supplies 22

None228(ab)-229(ab)Allowances 23

None230Extraordinary Property Losses 24

230Unrecovered Plant and Regulatory Study Costs 25

231Transmission Service and Generation Interconnection Study Costs 26

232Other Regulatory Assets 27

233Miscellaneous Deferred Debits 28

234Accumulated Deferred Income Taxes 29

250-251Capital Stock 30

253Other Paid-in Capital 31

None254Capital Stock Expense 32

256-257Long-Term Debt 33

261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34

262-263Taxes Accrued, Prepaid and Charged During the Year 35

266-267Accumulated Deferred Investment Tax Credits 36

FERC FORM NO. 1 (ED. 12-96) Page 2

LIST OF SCHEDULES (Electric Utility) (continued)




End ofJersey Central Power & Light CompanyX

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Line No.


Remarks

(c)(b)(a)


269Other Deferred Credits 37

None272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38

274-275Accumulated Deferred Income Taxes-Other Property 39

276-277Accumulated Deferred Income Taxes-Other 40

278Other Regulatory Liabilities 41

300-301Electric Operating Revenues 42

None302Regional Transmission Service Revenues (Account 457.1) 43

304Sales of Electricity by Rate Schedules 44

310-311Sales for Resale 45

320-323Electric Operation and Maintenance Expenses 46

326-327Purchased Power 47

328-330Transmission of Electricity for Others 48

331Transmission of Electricity by ISO/RTOs 49

332Transmission of Electricity by Others 50

335Miscellaneous General Expenses-Electric 51

336-337Depreciation and Amortization of Electric Plant 52

350-351Regulatory Commission Expenses 53

352-353Research, Development and Demonstration Activities 54

354-355Distribution of Salaries and Wages 55

None356Common Utility Plant and Expenses 56

397Amounts included in ISO/RTO Settlement Statements 57

398Purchase and Sale of Ancillary Services 58

400Monthly Transmission System Peak Load 59

400aMonthly ISO/RTO Transmission System Peak Load 60

401Electric Energy Account 61

401Monthly Peaks and Output 62

None402-403Steam Electric Generating Plant Statistics 63

None406-407Hydroelectric Generating Plant Statistics 64

408-409Pumped Storage Generating Plant Statistics 65

None410-411Generating Plant Statistics Pages 66


LIST OF SCHEDULES (Electric Utility) (continued)





/ /2014/Q4

Line No.


Remarks

(c)(b)(a)


422-423Transmission Line Statistics Pages 67

None424-425Transmission Lines Added During the Year 68

426-427Substations 69

429Transactions with Associated (Affiliated) Companies 70

450Footnote Data 71

Stockholders' Reports Check appropriate box:Two copies will be submitted

No annual report to stockholders is prepared





End of

GENERAL INFORMATION

Jersey Central Power & Light Company X / / 2014/Q4

New JerseyMarch 27, 1925

Marlene A. Barwood, Controller

76 South Main Street

Akron, Ohio 44308

1. Provide name and title of officer having custody of the general corporate books of account and address ofoffice where the general corporate books are kept, and address of office where any other corporate books of accountare kept, if different from that where the general corporate books are kept.

2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the typeof organization and the date organized.

3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership ortrusteeship was created, and (d) date when possession by receiver or trustee ceased.

4. State the classes or utility and other services furnished by respondent during the year in each State in whichthe respondent operated.

5. Have you engaged as the principal accountant to audit your financial statements an accountant who is notthe principal accountant for your previous year's certified financial statements?

(1) Yes...Enter the date when such independent accountant was initially engaged: (2) NoX

Not Applicable

Electric Service - New Jersey

FERC FORM No.1 (ED. 12-87) PAGE 101




End of

CONTROL OVER RESPONDENT


1. If any corporation, business trust, or similar organization or a combination of such organizations jointly heldcontrol over the repondent at the end of the year, state name of controlling corporation or organization, manner inwhich control was held, and extent of control. If control was in a holding company organization, show the chainof ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.

Jersey Central Power & Light Company is a wholly owned subsidiary of FirstEnergy Corp., a diversified energy company.

Page 102FERC FORM NO. 1 (ED. 12-96)




End of

CORPORATIONS CONTROLLED BY RESPONDENT


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Line No.

Name of Company Controlled Kind of Business Percent VotingStock Owned

(c)(b)(a)

FootnoteRef.(d)

1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondentat any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, namingany intermediaries involved.3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.

Definitions1. See the Uniform System of Accounts for a definition of control.2. Direct control is that which is exercised without interposition of an intermediary.3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where thevoting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutualagreement or understanding between two or more parties who together have control within the meaning of the definition of control in theUniform System of Accounts, regardless of the relative voting rights of each party.

Finance Subsidiary 100% 1 JCP&L Transition Funding LLC

Finance Subsidiary 100% 2 JCP&L Transition Funding II LLC

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Schedule Page: 103 Line No.: 2 Column: dJCP&L Transition Funding, LLC and JCP&L Transition Funding II, LLC are special purpose entities which were established for thepurpose of securitizing JCP&L's bondable transition property and JCP&L's supply of basic generation service, repsectively.

Name of Respondent

Jersey Central Power & Light Company

This Report is:(1) X An Original(2) A Resubmission


/ /


2014/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1




End of

OFFICERS


/ /2014/Q4

Line No.

Title Name of Officer Salaryfor Year

(c)(b)(a)

1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of arespondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function(such as sales, administration or finance), and any other person who performs similar policy making functions.2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previousincumbent, and the date the change in incumbency was made.

President 252,308J.V. Fakult 1

Controller 162,442M.A. Barwood 2

Treasurer 147,966W. Wang 3

Corporate Secretary 151,151E.J. Udovich 4

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End of

DIRECTORS


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Line Name (and Title) of Director Principal Business Address(b)(a)No.

1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviatedtitles of the directors who are officers of the respondent.2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.

300 Madison Avenue, Morristown, New Jersey 07962James V. Fakult 1

President 2

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76 South Main Street, Akron, Ohio 44308Charles E. Jones, Jr. 4

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76 South Main Street, Akron, Ohio 44308Mark A. Julian 6

7

27 Greenfields Drive, Lakewood, New Jersey 08701Gelorma E. Persson 8

9

5 Pheasant Lane, Wild Quail Golf & Country Club, Wyoming,Jesse T. Williams Sr. 10

Delaware 19934 11

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End of

INFORMATION ON FORMULA RATES


/ /2014/Q4

Line No. FERC Rate Schedule or Tariff Number FERC Proceeding

Does the respondent have formula rates? Yes

NoX

1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)accepting the rate(s) or changes in the accepted rate.

FERC Rate Schedule/Tariff Number FERC Proceeding

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FERC FORM NO. 1 (NEW. 12-08) Page 106





/ /2014/Q4

Line No. \ Filed DateAccession No.

DateDocket No. Description

Formula Rate FERC RateSchedule Number orTariff Number


Does the respondent file with the Commission annual (or more frequent) Yes

NoX

2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website

FERC Rate Schedule/Tariff Number FERC Proceeding

filings containing the inputs to the formula rate(s)?

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FERC FORM NO. 1 (NEW. 12-08) Page 106a





/ /2014/Q4

Line No. Page No(s). Schedule Column Line No


1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from

Formula Rate Variances

amounts reported in the Form 1.2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the

Form 1.3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items

impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.

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FERC FORM NO. 1 (NEW. 12-08) Page 106b


Date of Report Year/Period of ReportEnd of

IMPORTANT CHANGES DURING THE QUARTER/YEAR

Jersey Central Power & Light Company X / /

2014/Q4

PAGE 108 INTENTIONALLY LEFT BLANKSEE PAGE 109 FOR REQUIRED INFORMATION.

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them inaccordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. Ifinformation which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom thefranchise rights were acquired. If acquired without the payment of consideration, state that fact.2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names ofcompanies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference toCommission authorization.3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accountswere submitted to the Commission.4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Giveeffective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and givereference to such authorization.5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operationsbegan or ceased and give reference to Commission authorization, if any was required. State also the approximate number ofcustomers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state majornew continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location andapproximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-termdebt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, asappropriate, and the amount of obligation or guarantee.7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.8. State the estimated annual effect and nature of any important wage scale changes during the year.9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any suchproceedings culminated during the year.10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or knownassociate of any of these persons was a party or in which any such person had a material interest.11. (Reserved.)12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders areapplicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may haveoccurred during the reporting period.14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and theextent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through acash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.


1. None.

2. None.

3. None.

4. None.

5. None.

6. The Respondent has authorization from the Federal Energy Regulatory Commission (FERC) to incur short-term debt ofup to $850 million through bank facilities and the utility money pool. The Respondent has the ability to borrow from itsregulated affiliates and FirstEnergy to meet its short-term working capital requirements. FirstEnergy Service Companyadministers this money pool and tracks surplus funds of FirstEnergy and the respective regulated subsidiary, as well asproceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repaythe principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate ofinterest is the same for each company receiving a loan from their respective pool and is based on the average cost offunds available through the pool. The average interest rate for borrowings during the year ended December 31, 2014was 1.45% per annum. In addition, please see pages 256 and 257 of this report for additional information on theRespondent's issuances and redemptions of debt securities.

7. None.

8. None.

9. See Notes 4 and 5 to Financial Statements relating to Regulatory Matters and Commitments, Guarantees andContingencies.

10. For the most recent related disclosure, please refer to the "Certain Relationships and Related Person Transactions"section starting on page 81 of the Company's proxy statement for the May 20, 2014 annual meeting of shareholders.

11. Reserved.

12. None.

13. None.

14. None.

Name of Respondent




/ /


2014/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



X



End of

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

LineNo.

Title of Account(a)

Ref.Page No.

(b)

Current YearEnd of Quarter/Year

Balance(c)

Prior YearEnd Balance

12/31(d)

Jersey Central Power & Light Company / / 2014/Q4

UTILITY PLANT 1

5,747,983,097 5,585,756,460200-201Utility Plant (101-106, 114) 2

172,898,887 121,668,103200-201Construction Work in Progress (107) 3

5,920,881,984 5,707,424,563TOTAL Utility Plant (Enter Total of lines 2 and 3) 4

2,012,688,780 1,975,189,977200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5

3,908,193,204 3,732,234,586Net Utility Plant (Enter Total of line 4 less 5) 6

0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7

0 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8

0 0Nuclear Fuel Assemblies in Reactor (120.3) 9

0 0Spent Nuclear Fuel (120.4) 10

0 0Nuclear Fuel Under Capital Leases (120.6) 11

0 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12

0 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13

3,908,193,204 3,732,234,586Net Utility Plant (Enter Total of lines 6 and 13) 14

0 0Utility Plant Adjustments (116) 15

0 0Gas Stored Underground - Noncurrent (117) 16

OTHER PROPERTY AND INVESTMENTS 17

16,979,653 16,979,653Nonutility Property (121) 18

15,891,546 15,888,925(Less) Accum. Prov. for Depr. and Amort. (122) 19

0 0Investments in Associated Companies (123) 20

2,478,029 2,478,116224-225Investment in Subsidiary Companies (123.1) 21

(For Cost of Account 123.1, See Footnote Page 224, line 42) 22

0 0228-229Noncurrent Portion of Allowances 23

1,008,579 1,007,746Other Investments (124) 24

0 0Sinking Funds (125) 25

0 0Depreciation Fund (126) 26

0 0Amortization Fund - Federal (127) 27

211,683,889 200,886,299Other Special Funds (128) 28

0 0Special Funds (Non Major Only) (129) 29

633,491 888,154Long-Term Portion of Derivative Assets (175) 30

0 0Long-Term Portion of Derivative Assets – Hedges (176) 31

216,892,095 206,351,043TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32

CURRENT AND ACCRUED ASSETS 33

0 0Cash and Working Funds (Non-major Only) (130) 34

0 0Cash (131) 35

239,394,924 228,849,848Special Deposits (132-134) 36

925 925Working Fund (135) 37

0 0Temporary Cash Investments (136) 38

0 0Notes Receivable (141) 39

136,772,557 160,688,029Customer Accounts Receivable (142) 40

24,137,744 32,012,563Other Accounts Receivable (143) 41

5,207,632 5,800,586(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42

0 0Notes Receivable from Associated Companies (145) 43

6,967,862 11,343,677Accounts Receivable from Assoc. Companies (146) 44

0 0227Fuel Stock (151) 45

0 0227Fuel Stock Expenses Undistributed (152) 46

0 0227Residuals (Elec) and Extracted Products (153) 47

0 0227Plant Materials and Operating Supplies (154) 48

0 0227Merchandise (155) 49

0 0227Other Materials and Supplies (156) 50

0 0202-203/227Nuclear Materials Held for Sale (157) 51

0 0228-229Allowances (158.1 and 158.2) 52

FERC FORM NO. 1 (REV. 12-03) Page 110


X



End of

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

LineNo.

Title of Account(a)

Ref.Page No.

(b)


Balance(c)


12/31(d)


(Continued)

0 0(Less) Noncurrent Portion of Allowances 53

0 0227Stores Expense Undistributed (163) 54

0 0Gas Stored Underground - Current (164.1) 55

0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56

26,969,162 36,805,295Prepayments (165) 57

0 0Advances for Gas (166-167) 58

0 0Interest and Dividends Receivable (171) 59

3,245,668 3,652,287Rents Receivable (172) 60

90,171,854 85,454,672Accrued Utility Revenues (173) 61

0 400Miscellaneous Current and Accrued Assets (174) 62

633,491 888,154Derivative Instrument Assets (175) 63

633,491 888,154(Less) Long-Term Portion of Derivative Instrument Assets (175) 64

0 0Derivative Instrument Assets - Hedges (176) 65

0 0(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66

522,453,064 553,007,110Total Current and Accrued Assets (Lines 34 through 66) 67

DEFERRED DEBITS 68

7,191,587 8,235,933Unamortized Debt Expenses (181) 69

0 0230aExtraordinary Property Losses (182.1) 70

4,561,927 4,670,935230bUnrecovered Plant and Regulatory Study Costs (182.2) 71

750,989,865 783,816,658232Other Regulatory Assets (182.3) 72

1,846,375 3,087,574Prelim. Survey and Investigation Charges (Electric) (183) 73

0 0Preliminary Natural Gas Survey and Investigation Charges 183.1) 74

0 0Other Preliminary Survey and Investigation Charges (183.2) 75

18,055 0Clearing Accounts (184) 76

1,637,491 1,577,353Temporary Facilities (185) 77

1,829,117,686 1,830,116,851233Miscellaneous Deferred Debits (186) 78

0 0Def. Losses from Disposition of Utility Plt. (187) 79

364,417 332,654352-353Research, Devel. and Demonstration Expend. (188) 80

13,539,113 15,623,437Unamortized Loss on Reaquired Debt (189) 81

780,015,314 778,648,583234Accumulated Deferred Income Taxes (190) 82

0 0Unrecovered Purchased Gas Costs (191) 83

3,389,281,830 3,426,109,978Total Deferred Debits (lines 69 through 83) 84

8,036,820,193 7,917,702,717TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85


Year/Period of ReportName of Respondent This Report is:(1) An Original(2) A Resubmission

x

Date of Report(mo, da, yr)

end of

LineNo.

Title of Account(a)

Ref.Page No.

(b)


Balance(c)


12/31(d)


COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

PROPRIETARY CAPITAL 1

136,284,470136,284,470Common Stock Issued (201) 2 250-251

00Preferred Stock Issued (204) 3 250-251

00Capital Stock Subscribed (202, 205) 4

00Stock Liability for Conversion (203, 206) 5

2,010,844,2612,012,397,647Premium on Capital Stock (207) 6

575,5113,135,415Other Paid-In Capital (208-211) 7 253

00Installments Received on Capital Stock (212) 8 252

00(Less) Discount on Capital Stock (213) 9 254

00(Less) Capital Stock Expense (214) 10 254b

170,114,143257,237,845Retained Earnings (215, 215.1, 216) 11 118-119

-34,884-34,971Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119

00(Less) Reaquired Capital Stock (217) 13 250-251

00 Noncorporate Proprietorship (Non-major only) (218) 14

14,787,0903,917,292Accumulated Other Comprehensive Income (219) 15 122(a)(b)

2,332,570,5912,412,937,698Total Proprietary Capital (lines 2 through 15) 16

LONG-TERM DEBT 17

00Bonds (221) 18 256-257

00(Less) Reaquired Bonds (222) 19 256-257

00Advances from Associated Companies (223) 20 256-257

2,000,000,0002,000,000,000Other Long-Term Debt (224) 21 256-257

00Unamortized Premium on Long-Term Debt (225) 22

7,988,9917,084,080(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23

1,992,011,0091,992,915,920Total Long-Term Debt (lines 18 through 23) 24

OTHER NONCURRENT LIABILITIES 25

00Obligations Under Capital Leases - Noncurrent (227) 26

00Accumulated Provision for Property Insurance (228.1) 27

5,170,4547,730,409Accumulated Provision for Injuries and Damages (228.2) 28

226,521,910379,796,852Accumulated Provision for Pensions and Benefits (228.3) 29

00Accumulated Miscellaneous Operating Provisions (228.4) 30

00Accumulated Provision for Rate Refunds (229) 31

64,278,03516,751,159Long-Term Portion of Derivative Instrument Liabilities 32

00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33

131,356,404103,062,462Asset Retirement Obligations (230) 34

427,326,803507,340,882Total Other Noncurrent Liabilities (lines 26 through 34) 35

CURRENT AND ACCRUED LIABILITIES 36

200,000,0000Notes Payable (231) 37

136,042,891121,532,029Accounts Payable (232) 38

81,069,623232,535,062Notes Payable to Associated Companies (233) 39

21,088,62914,138,106Accounts Payable to Associated Companies (234) 40

22,583,14223,893,624Customer Deposits (235) 41

4,633,55111,169,264Taxes Accrued (236) 42 262-263

26,371,93222,490,590Interest Accrued (237) 43

00Dividends Declared (238) 44

00Matured Long-Term Debt (239) 45

FERC FORM NO. 1 (rev. 12-03) Page 112

Year/Period of ReportName of Respondent This Report is:(1) An Original(2) A Resubmission

x

Date of Report(mo, da, yr)

end of

LineNo.

Title of Account(a)

Ref.Page No.

(b)


Balance(c)


12/31(d)


(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

00Matured Interest (240) 46

8,856,7222,651,219Tax Collections Payable (241) 47

58,475,96958,130,395Miscellaneous Current and Accrued Liabilities (242) 48

00Obligations Under Capital Leases-Current (243) 49

64,278,03516,751,159Derivative Instrument Liabilities (244) 50

64,278,03516,751,159(Less) Long-Term Portion of Derivative Instrument Liabilities 51

00Derivative Instrument Liabilities - Hedges (245) 52

00(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53

559,122,459486,540,289Total Current and Accrued Liabilities (lines 37 through 53) 54

DEFERRED CREDITS 55

25,553,66627,677,400Customer Advances for Construction (252) 56

2,442,1432,310,944Accumulated Deferred Investment Tax Credits (255) 57 266-267

00Deferred Gains from Disposition of Utility Plant (256) 58

400,549,684496,308,169Other Deferred Credits (253) 59 269

217,743,889266,372,217Other Regulatory Liabilities (254) 60 278

369,634239,556Unamortized Gain on Reaquired Debt (257) 61

00Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277

1,147,796,8941,179,615,690Accum. Deferred Income Taxes-Other Property (282) 63

812,215,945664,561,428Accum. Deferred Income Taxes-Other (283) 64

2,606,671,8552,637,085,404Total Deferred Credits (lines 56 through 64) 65

7,917,702,7178,036,820,193TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66

FERC FORM NO. 1 (rev. 12-03) Page 113




End of

STATEMENT OF INCOME


/ /2014/Q4

Line

(c)(b)(a)Title of Account

No.

TotalCurrent Year to

Date Balance forQuarter/Year

(d)

(Ref.)Page No.

Quarterly1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus thedata in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)the quarter to date amounts for other utility function for the current year quarter.4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l)the quarter to date amounts for other utility function for the prior year quarter.5. If additional columns are needed, place them in a footnote.

Annual or Quarterly if applicable5. Do not report fourth quarter data in columns (e) and (f)6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner toa utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.

Current 3 MonthsEnded

Quarterly OnlyNo 4th Quarter

(e)

Prior 3 MonthsEnded


(f)

TotalPrior Year to

Date Balance forQuarter/Year

UTILITY OPERATING INCOME 1

1,845,731,756 1,868,251,673300-301Operating Revenues (400) 2

Operating Expenses 3

1,375,467,404 1,226,750,921320-323Operation Expenses (401) 4

72,391,866 81,617,512320-323Maintenance Expenses (402) 5

139,427,481 121,305,838336-337Depreciation Expense (403) 6

336-337Depreciation Expense for Asset Retirement Costs (403.1) 7

4,257,960 5,056,194336-337Amort. & Depl. of Utility Plant (404-405) 8

336-337Amort. of Utility Plant Acq. Adj. (406) 9

Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10

Amort. of Conversion Expenses (407) 11

17,561,641 16,867,258Regulatory Debits (407.3) 12

25,317,353 14,959,792(Less) Regulatory Credits (407.4) 13

19,218,099 40,473,053262-263Taxes Other Than Income Taxes (408.1) 14

80,355,069 2,127,797262-263Income Taxes - Federal (409.1) 15

-16,962,629 5,710,624262-263 - Other (409.1) 16

186,187,990 436,121,124234, 272-277Provision for Deferred Income Taxes (410.1) 17

220,154,980 337,564,936234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18

-131,199 -131,199266Investment Tax Credit Adj. - Net (411.4) 19

(Less) Gains from Disp. of Utility Plant (411.6) 20

Losses from Disp. of Utility Plant (411.7) 21

(Less) Gains from Disposition of Allowances (411.8) 22

Losses from Disposition of Allowances (411.9) 23

Accretion Expense (411.10) 24

1,632,301,349 1,583,374,394TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25

213,430,407 284,877,279Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114




End of

STATEMENT OF INCOME FOR THE YEAR (Continued)


/ /2014/Q4

Line Previous Year to Date(in dollars)

(k)(j)(g)

ELECTRIC UTILITY

No.Current Year to Date

(in dollars)

OTHER UTILITY

(l)

GAS UTILITYPrevious Year to Date

(in dollars)Current Year to Date

(in dollars)Previous Year to Date

(in dollars)Current Year to Date

(in dollars)(h) (i)

9. Use page 122 for important notes regarding the statement of income for any account thereof.10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to bemade to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effectedthe gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rightsof the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rateproceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,and expense accounts.12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote tothis schedule.

1

1,845,731,756 1,868,251,673 2

3

1,375,467,404 1,226,750,921 4

72,391,866 81,617,512 5

139,427,481 121,305,838 6

7

4,257,960 5,056,194 8

9

10

11

17,561,641 16,867,258 12

25,317,353 14,959,792 13

19,218,099 40,473,053 14

80,355,069 2,127,797 15

-16,962,629 5,710,624 16

186,187,990 436,121,124 17

220,154,980 337,564,936 18

-131,199 -131,199 19

20

21

22

23

24

1,632,301,349 1,583,374,394 25

213,430,407 284,877,279 26





End of

STATEMENT OF INCOME FOR THE YEAR (continued)


/ /2014/Q4

Line

Previous Year(c)(b)(a)

Title of Account

No.

Current Year

TOTAL

(d)

(Ref.)Page No.

Current 3 MonthsEnded


(e)

Prior 3 MonthsEnded


(f)

213,430,407 284,877,279Net Utility Operating Income (Carried forward from page 114) 27

Other Income and Deductions 28

Other Income 29

Nonutilty Operating Income 30

482,631 472,788Revenues From Merchandising, Jobbing and Contract Work (415) 31

40,149 -3,583(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32

Revenues From Nonutility Operations (417) 33

(Less) Expenses of Nonutility Operations (417.1) 34

-2,621 -2,621Nonoperating Rental Income (418) 35

166 111119Equity in Earnings of Subsidiary Companies (418.1) 36

1,607,178 675,731Interest and Dividend Income (419) 37

-395,309 -13,490Allowance for Other Funds Used During Construction (419.1) 38

2,929,190 11,413,979Miscellaneous Nonoperating Income (421) 39

Gain on Disposition of Property (421.1) 40

4,581,086 12,550,081TOTAL Other Income (Enter Total of lines 31 thru 40) 41

Other Income Deductions 42

Loss on Disposition of Property (421.2) 43

Miscellaneous Amortization (425) 44

121,898 193,431 Donations (426.1) 45

-479,284 -322,755 Life Insurance (426.2) 46

31,429 46,310 Penalties (426.3) 47

106,365 92,682 Exp. for Certain Civic, Political & Related Activities (426.4) 48

-468,128 153,026 Other Deductions (426.5) 49

-687,720 162,694TOTAL Other Income Deductions (Total of lines 43 thru 49) 50

Taxes Applic. to Other Income and Deductions 51

262-263Taxes Other Than Income Taxes (408.2) 52

1,251,767 5,960,445262-263Income Taxes-Federal (409.2) 53

353,647 1,684,270262-263Income Taxes-Other (409.2) 54

260 5,015234, 272-277Provision for Deferred Inc. Taxes (410.2) 55

3,636 2,450234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56

Investment Tax Credit Adj.-Net (411.5) 57

(Less) Investment Tax Credits (420) 58

1,602,038 7,647,280TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59

3,666,768 4,740,107Net Other Income and Deductions (Total of lines 41, 50, 59) 60

Interest Charges 61

115,231,551 100,050,581Interest on Long-Term Debt (427) 62

1,949,258 1,528,549Amort. of Debt Disc. and Expense (428) 63

2,084,325 2,084,325Amortization of Loss on Reaquired Debt (428.1) 64

(Less) Amort. of Premium on Debt-Credit (429) 65

130,078 306,651(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66

6,633,871 6,380,629Interest on Debt to Assoc. Companies (430) 67

6,019,795 4,971,667Other Interest Expense (431) 68

1,815,162 969,790(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69

129,973,560 113,739,310Net Interest Charges (Total of lines 62 thru 69) 70

87,123,615 175,878,076Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71

Extraordinary Items 72

Extraordinary Income (434) 73

(Less) Extraordinary Deductions (435) 74

Net Extraordinary Items (Total of line 73 less line 74) 75

262-263Income Taxes-Federal and Other (409.3) 76

Extraordinary Items After Taxes (line 75 less line 76) 77

87,123,615 175,878,076Net Income (Total of line 71 and 77) 78





End of

STATEMENT OF RETAINED EARNINGS


/ /2014/Q4

Line

CurrentQuarter/YearYear to Date

Balance

(c)(b)(a)

ItemContra Primary

No.

Account Affected

1. Do not report Lines 49-53 on the quarterly version.2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriatedundistributed subsidiary earnings for the year.3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436- 439 inclusive). Show the contra primary account affected in column (b)4. State the purpose and amount of each reservation or appropriation of retained earnings.5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Followby credit, then debit items in that order.6. Show dividends for each class and series of capital stock.7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to berecurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.

PreviousQuarter/YearYear to Date

Balance

(d)

UNAPPROPRIATED RETAINED EARNINGS (Account 216) 64,236,016 170,114,143 1 Balance-Beginning of Period

2 Changes

3 Adjustments to Retained Earnings (Account 439) 162 253 4

5

6

7

8 162 253 9 TOTAL Credits to Retained Earnings (Acct. 439)

10

11

12

13

14

15 TOTAL Debits to Retained Earnings (Acct. 439) 175,877,965 87,123,449 16 Balance Transferred from Income (Account 433 less Account 418.1)

17 Appropriations of Retained Earnings (Acct. 436)

18

19

20

21

22 TOTAL Appropriations of Retained Earnings (Acct. 436)

23 Dividends Declared-Preferred Stock (Account 437)

24

25

26

27

28

29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)

30 Dividends Declared-Common Stock (Account 438)( 70,000,000) 31

32

33

34

35( 70,000,000) 36 TOTAL Dividends Declared-Common Stock (Acct. 438)

37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 170,114,143 257,237,845 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)

APPROPRIATED RETAINED EARNINGS (Account 215)

39

40





End of

STATEMENT OF RETAINED EARNINGS


/ /2014/Q4

Line

CurrentQuarter/YearYear to Date

Balance

(c)(b)(a)

ItemContra Primary

No.

Account Affected

1. Do not report Lines 49-53 on the quarterly version.2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriatedundistributed subsidiary earnings for the year.3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436- 439 inclusive). Show the contra primary account affected in column (b)4. State the purpose and amount of each reservation or appropriation of retained earnings.5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Followby credit, then debit items in that order.6. Show dividends for each class and series of capital stock.7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to berecurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.

PreviousQuarter/YearYear to Date

Balance

(d)

41

42

43

44

45 TOTAL Appropriated Retained Earnings (Account 215)

APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)

46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)

47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 170,114,143 257,237,845 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)

UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account

Report only on an Annual Basis, no Quarterly( 34,833) -34,884 49 Balance-Beginning of Year (Debit or Credit)

111 166 50 Equity in Earnings for Year (Credit) (Account 418.1) 162 253 51 (Less) Dividends Received (Debit)

52( 34,884) -34,971 53 Balance-End of Year (Total lines 49 thru 52)


(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items asinvestments, fixed assets, intangibles, etc.(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and CashEquivalents at End of Period" with related amounts on the Balance Sheet.(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reportedin those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes tothe Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of thedollar amount of leases capitalized with the plant cost.




End of

STATEMENT OF CASH FLOWS


/ /2014/Q4

Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to DateQuarter/Year

(b)(a)No.

Previous Year to DateQuarter/Year

(c) 1 Net Cash Flow from Operating Activities:

175,878,076 87,123,615 2 Net Income (Line 78(c) on page 117)

3 Noncash Charges (Credits) to Income:

126,362,032 130,778,528 4 Depreciation and Depletion

1,907,466 -7,007,697 5 Amortization (Deferral) of Regulatory Assets, Net

-46,245,123 -29,209,124 6 Deferred Purchased Power and Other Costs

11,598,518 4,486,556 7 Prepaid Taxes

98,558,753 -33,970,366 8 Deferred Income Taxes (Net)

-131,199 -131,199 9 Investment Tax Credit Adjustment (Net)

-47,094,287 31,431,578 10 Net (Increase) Decrease in Receivables

11 Net (Increase) Decrease in Inventory

12 Net (Increase) Decrease in Allowances Inventory

29,293,357 -26,999,610 13 Net Increase (Decrease) in Payables and Accrued Expenses

14 Net (Increase) Decrease in Other Regulatory Assets

15 Net Increase (Decrease) in Other Regulatory Liabilities

-13,490 -395,309 16 (Less) Allowance for Other Funds Used During Construction

111 87 17 (Less) Undistributed Earnings from Subsidiary Companies

-33,984,461 35,495,347 18 Other (provide details in footnote):

352,819 -1,934,392 19 Cash Collateral Received, Net

-13,452,268 113,485,766 20 Pension and OPEB Mark-to-Market Adjustment

21

303,057,062 303,944,224 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)

23

24 Cash Flows from Investment Activities:

25 Construction and Acquisition of Plant (including land):

-404,716,299 -224,067,246 26 Gross Additions to Utility Plant (less nuclear fuel)

27 Gross Additions to Nuclear Fuel

28 Gross Additions to Common Utility Plant

29 Gross Additions to Nonutility Plant

13,490 395,309 30 (Less) Allowance for Other Funds Used During Construction

31 Other (provide details in footnote):

32

33

-404,729,789 -224,462,555 34 Cash Outflows for Plant (Total of lines 26 thru 33)

35

36 Acquisition of Other Noncurrent Assets (d)

37 Proceeds from Disposal of Noncurrent Assets (d)

38

39 Investments in and Advances to Assoc. and Subsidiary Companies

40 Contributions and Advances from Assoc. and Subsidiary Companies

41 Disposition of Investments in (and Advances to)

42 Associated and Subsidiary Companies

43

44 Purchase of Investment Securities (a)

45 Proceeds from Sales of Investment Securities (a)


(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items asinvestments, fixed assets, intangibles, etc.(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and CashEquivalents at End of Period" with related amounts on the Balance Sheet.(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reportedin those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes tothe Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of thedollar amount of leases capitalized with the plant cost.




End of

STATEMENT OF CASH FLOWS


/ /2014/Q4

Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to DateQuarter/Year

(b)(a)No.

Previous Year to DateQuarter/Year

(c) 46 Loans Made or Purchased

47 Collections on Loans

-79,663,401 -15,121,761 48 Cost of Removal and Adjustments

49 Net (Increase) Decrease in Receivables

50 Net (Increase ) Decrease in Inventory

51 Net (Increase) Decrease in Allowances Held for Speculation

52 Net Increase (Decrease) in Payables and Accrued Expenses

141,938 1,240,366 53 Other (provide details in footnote):

416,636,550 372,214,589 54 Sale of Investment Securities Held in Trusts

-433,651,406 -388,904,770 55 Purchase of Investment Securities Held in Trusts

56 Net Cash Provided by (Used in) Investing Activities

-501,266,108 -255,034,131 57 Total of lines 34 thru 55)

58

59 Cash Flows from Financing Activities:

60 Proceeds from Issuance of:

500,000,000 61 Long-Term Debt (b)

62 Preferred Stock

63 Common Stock


65

66 Net Increase in Short-Term Debt (c)


-7,516,452 68 Debt Issuance Costs

69

492,483,548 70 Cash Provided by Outside Sources (Total 61 thru 69)

71

72 Payments for Retirement of:

73 Long-term Debt (b)

74 Preferred Stock

75 Common Stock

-51,524 -375,532 76 Other (provide details in footnote):

77

-224,222,978 -48,534,561 78 Net Decrease in Short-Term Debt (c)

79

80 Dividends on Preferred Stock

-70,000,000 81 Dividends on Common Stock

82 Net Cash Provided by (Used in) Financing Activities

198,209,046 -48,910,093 83 (Total of lines 70 thru 81)

84

85 Net Increase (Decrease) in Cash and Cash Equivalents

86 (Total of lines 22,57 and 83)

87

925 925 88 Cash and Cash Equivalents at Beginning of Period

89

925 925 90 Cash and Cash Equivalents at End of period


Schedule Page: 120 Line No.: 18 Column: bOther Operating:

Nuclear Decommissioning and Spent Fuel Trusts Income $16,690,182Stock Based Compensation 4,007,549Customer Deposits 1,310,482Contributions in Aid of Construction 4,603,567Environmental Liability 3,147,000Customer Advances for Construction 2,123,734Injuries and Damages 2,559,955Other 1,052,878 $35,495,347

Schedule Page: 120 Line No.: 18 Column: cOther Operating Activities:

Accrued Compensation and Retirement Benefits $(37,207,728)Other 3,223,267

$(33,984,461)

Name of Respondent




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2014/Q4

FOOTNOTE DATA



Date of Report Year/Period of ReportEnd of

NOTES TO FINANCIAL STATEMENTS


PAGE 122 INTENTIONALLY LEFT BLANKSEE PAGE 123 FOR REQUIRED INFORMATION.

1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of RetainedEarnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,providing a subheading for each statement except where a note is applicable to more than one statement.2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation ofany action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or ofa claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrearson cumulative preferred stock.3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan ofdisposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plantadjustments and requirements as to disposition thereof.4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, givean explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by suchrestrictions.6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders areapplicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information notmisleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may beomitted.8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurredwhich have a material effect on the respondent. Respondent must include in the notes significant changes since the most recentlycompleted year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; andchanges resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of suchmatters shall be provided even though a significant change since year end may not have occurred.9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders areapplicable and furnish the data required by the above instructions, such notes may be included herein.


1. ORGANIZATION AND BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Jersey Central Power & Light Company (JCP&L) is a wholly owned, electric utility subsidiary of FirstEnergy (FE). JCP&L conductsbusiness in New Jersey by providing regulated electric transmission and distribution services in northern, western and east centralNew Jersey. JCP&L procures electric supply to serve its Basic Generation Service (BGS) customers through a statewide auctionprocess approved by the New Jersey Board of Public Utilities (NJBPU). JCP&L is subject to regulation by the NJBPU and the FederalEnergy Regulatory Commission (FERC).

JCP&L follows Generally Accepted Accounting Principles (GAAP) and complies with the regulations, orders, policies and practicesprescribed by the NJBPU and the FERC. The preparation of financial statements in conformity with GAAP requires management tomake periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses anddisclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations arenot indicative of results of operations for any future period. JCP&L has evaluated events and transactions for potential recognition ordisclosure through February 27, 2015, the issuance date of the financial statements.

Certain prior year amounts have been reclassified to conform to the current year presentation. The effect of these adjustments was notmaterial to the current or prior years.

BASIS OF PRESENTATION

The accompanying financial statements have been prepared in accordance with FERC accounting requirements as set forth in theUniform System of Accounts and accounting releases, which differ from Generally Accepted Accounting Principles in the United Statesof America (GAAP). The significant differences between FERC and GAAP related to these financial statements include the following:

− Wholly owned subsidiaries that are consolidated under GAAP are accounted for under the equity method of accounting underFERC. As such investment in subsidiaries are reflected under the equity method of accounting on the FERC income statement,balance sheet and cash flow statement, and on a consolidated basis on the GAAP income statement, balance sheet and cashflow statement.

− The current portion of long-term debt, long-term assets or long-term liabilities is not reported separately on the FERC balancesheet.

− Deferred Income Taxes are recorded on a gross basis on the FERC balance sheet with deferred tax assets and deferred taxliabilities being reported separately.

− Asset removal costs are classified as accumulated depreciation on the FERC balance sheet and as regulatory liabilities on theGAAP balance sheet.

− For income statement purposes, there are differences in items included in Operating Income and Other Income and Deductionsunder GAAP and FERC reporting, including merger costs which are recorded in operating expenses for GAAP and non-operatingexpenses for FERC.

− Notes to Financial Statements related to Regulatory Assets and Liabilities per GAAP differ from Regulatory Assets and Liabilitiesper FERC because Account 189, Unamortized loss on reacquired debt and Account 257, Unamortized gain on reacquired debtare regulatory assets and liabilities for GAAP statements but not for FERC statements.

− Estimated interest and penalties related to uncertain tax positions are recorded as part of interest expense and penaltiesrespectively under FERC and as income tax expense under GAAP.

− Other Comprehensive Income pages 122a-b are not audited per FERC instructions.

ACCOUNTING FOR THE EFFECTS OF REGULATION

JCP&L accounts for the effects of regulation through the application of regulatory accounting since its rates are established by a thirdparty regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers.JCP&L records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded underGAAP for non-regulated entities. These assets and liabilities are amortized in the Statements of Income concurrent with their recoveryor refund through customer rates. JCP&L believes that it is probable that its regulatory assets and liabilities will be recovered andsettled, respectively, through future rates.

REVENUES AND RECEIVABLES

JCP&L's principal business is providing electric service to customers in New Jersey. JCP&L's retail customers are metered on a cyclebasis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilledrevenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimateincludes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shoppingactivity and prices in effect for each class of customer. In each accounting period, JCP&L recognizes the estimated unbilled amount

Name of Respondent




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2014/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)


receivable as revenue and reverses the related prior period estimate.

Receivables from customers include distribution and retail electric sales to residential, commercial and industrial customers. Therewas no material concentration of receivables as of December 31, 2014 and 2013, with respect to any particular segment of JCP&L'scustomers. Billed and unbilled customer receivables were $132 million and $90 million, respectively, as of December 31, 2014, andwere $155 million and $85 million, respectively, as of December 31, 2013.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such astaxes, employee benefits, administrative and general costs, and capitalized interest incurred to place the assets in service. The costsof normal maintenance, repairs and minor replacements are expensed as incurred. JCP&L recognizes liabilities for planned majormaintenance projects as they are incurred.

JCP&L provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant inservice. Depreciation expense was approximately 2.1% and 2.2% of average depreciable property in 2014 and 2013, respectively.

ASSET RETIREMENT OBLIGATIONS (ARO)

JCP&L has recognized applicable legal obligations for AROs and its associated cost primarily for the decommissioning of the ThreeMile Island Unit 2 (TMI-2) nuclear generating facility. JCP&L uses an expected cash flow approach to measure the fair value of itsnuclear decommissioning AROs. In addition, JCP&L has recognized conditional retirement obligations, primarily for asbestosremediation.

JCP&L maintains Nuclear Decommissioning Trusts (NDTs) that are legally restricted for purposes of settling the nucleardecommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2014 and 2013 was $212 million and$201 million, respectively.

Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they areincurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. Whensettlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not in the recognition of theliability.

JCP&L's ending ARO balance as of December 31, 2014 and 2013 was $103 million and $131 million, respectively. JCP&L recordedaccretion in 2014 and 2013 of $9 million and $8 million, respectively.

During 2014, based on studies completed by a third-party to reassess the estimated costs of decommissioning TMI-2, JCP&Ldecreased its ARO by $37 million, of which the total was was credited against a regulatory asset. The reduction in the ARO liability ofJCP&L was primarily the result of an extension in the number of years in which decommissioning activities are estimated to occur.

GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilitiesassumed is recognized as goodwill. JCP&L evaluates goodwill for impairment annually on July 31 and more frequently if indicators ofimpairment arise. In evaluating goodwill for impairment, JCP&L assesses qualitative factors to determine whether it is more likely thannot (that is, likelihood of more than 50 percent) that its fair value is less than its carrying value (including goodwill). If JCP&L concludesthat it is not more likely than not that its fair value is less than its carrying value, then no further testing is required. However, if JCP&Lconcludes that it is more likely than not that its fair value is less than its carrying value or bypasses the qualitative assessment, thenthe two-step quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount ofimpairment to be recognized, if any.

No impairment of goodwill was indicated as a result of testing in 2014 and 2013. In 2014, JCP&L performed a quantitative assessmentusing a discounted cash flow analysis. The fair value of JCP&L exceeded its carrying value by approximately 6%. Key assumptionsincorporated in the discounted cash flow analysis requiring significant management judgment included: a discount rate, growth rates,projected operating income, changes in working capital, projected capital expenditures, projected funding of pension plans, expectedresults of future rate proceedings, and a terminal value growth rate. The July 31, 2014 assessment included a discount rate of 5.75%and a terminal value growth rate of 1.61%. Lower than forecasted revenue growth could have a negative impact on future goodwillassessments. Annual goodwill impairment testing for 2013 was performed using a qualitative assessment.

INVESTMENTS

Name of Respondent




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2014/Q4



All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on theBalance Sheets at cost, which approximates their fair market value. Investments other than cash include notes receivable.

NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements not yet effective are not expected to have a material effect on JCP&L's financial statement.

2. PENSION AND OTHER POSTEMPLOYMENT BENEFITS

FE provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualifiedpension plans that cover certain employees, including employees of JCP&L. The plans provide defined benefits based on years ofservice and compensation levels. In addition, FE provides a minimum amount of noncontributory life insurance to retired employees inaddition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles andco-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, theirsurvivors. JCP&L recognizes its allocated portion of the expected cost of providing pensions and Other Post-Employement Benefits(OPEB) to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible toreceive those benefits. JCP&L also recognized its allocated portion of obligations to former or inactive employees after employment,but before retirement, for disability-related benefits. On August 25, 2014, the qualified pension plan was amended authorizing avoluntary cashout window program for certain eligible terminated participants with vested benefits. Eligible terminated participantswere able to elect an immediate lump sum cash payment of their vested benefits. Additionally, annuity options were offered and couldbe elected instead of the lump sum cash payment. The election period was September 15, 2014 to October 31, 2014. Payment ofbenefits for participants that elected an immediate lump sum cash payment or an annuity commenced on December 1, 2014 whichresulted in a $40 million reduction to the underfunded status of the pension plan. Additionally, during 2014, certain unions ratified theirlabor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately$97 million. There was no reduction to JCP&L's share of its OPEB net liability resulting from the 2014 amendments.

FE recognizes as a pension and OPEB mark-to-market adjustment the change in the fair value of plan assets and net actuarial gainsand losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. Theremaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets andprior service costs, are recorded on a monthly basis. JCP&L's mark-to-market adjustment for the years ended December 31, 2014 and2013 were $198 million ($113 million net of amounts capitalized) and $(16) million ($(13) million net of amounts capitalized),respectively. In 2014, the pension and OPEB mark-to-market adjustment primarily reflects a 75 basis points decline in the discountrates, a lower mortality rate as further described below, lower than expected asset returns, and changes in other demographicassumptions.

FE’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the yearended December 31, 2014, FE did not make any contributions to its qualified pension plan. FE expects to contribute $143 million to itsqualified pension plan in 2015. Pension and OPEB costs are affected by employee demographics (including age, compensation levelsand employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs mayalso be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and healthcare trend rates used in determining the projected benefit obligations for pension and OPEB costs. FE uses a December 31measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of themeasurement date.

FE’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types ofinvestments held by the pension trusts. In 2014, FE’s qualified pension and OPEB plan assets earned $387 million or 6.2% comparedto losses of $(22) million, or (0.3)% in 2013 and assumed a 7.75% rate of return for both years on plan assets which generated $496million and $535 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is basedon the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or lossesgenerated as a result of the difference between expected and actual returns on plan assets will increase or decrease future netperiodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan isdetermined to qualify for remeasurement.

During 2014 the Society of Actuaries published new mortality tables and improvement scales reflecting improved life expectancies andan expectation that the trend will continue. An analysis of FE pension and OPEB plan mortality data indicated the use of the RP2000mortality table with projection scale BB2D was most appropriate. As such, the RP2000 mortality table with projection scale BB2D wasutilized to determine the 2014 benefit cost and obligation as of December 31, 2014 for the FE pension and OPEB plans.

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JCP&L’s allocated share of pension and OPEB costs (credits) and JCP&L’s share of net liability, including the mark-to-marketadjustment was as follows:

Pension OPEB

As of December 31, 2014 2013 2014 2013

(in millions)JCP&L's share of net liability $ 255 $ 122 $ 123 $ 103JCP&L's share of net periodic costs (credits)(1) 137 (9) 8 (29)

(1) Includes annual pension and OPEB mark-to-market adjustment

In selecting an assumed discount rate, FE considers currently available rates of return on high-quality fixed income investmentsexpected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on planassets consider historical market returns and economic forecasts for the types of investments held by FE’s pension trusts. Thelong-term rate of return is developed considering the portfolio’s asset allocation strategy.

3. LEASES

JCP&L leases certain office space and other property and equipment under cancelable and noncancelable leases.

Operating lease expense which includes rent expense for the use of office space and other property and equipment owned by affiliatedcompanies for the years ended December 31, 2014 and 2013 was $23 million and $20 million, respectively. JCP&L's estimated futureminimum lease payments for operating leases as of December 31, 2014 with initial or remaining lease terms in excess of one year areas follows:

(In millions) 2015 2016 2017 2018 2019 Thereafter Total

Less: amountrepresentinginterest and

fees

Presentvalue of net

minimumcapital lease

payments

Operating leases $ 12 $ 12 $ 11 $ 13 $ 5 $ 58 $ 111 N/A N/A

JCP&L's estimated future minimum lease payments for capital leases are immaterial.

4. REGULATORY MATTERS

NEW JERSEY

JCP&L currently provides BGS for retail customers who do not choose a third party Electric Generation Supplier (EGS) and forcustomers of third party EGSs that fail to provide the contracted service. The supply for BGS, which is comprised of two components,is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approvedby the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial andindustrial customers. The other BGS component and auction, providing a fixed price service, is intended for smaller commercial andresidential customers. All New Jersey Electric Distribution Companies (EDCs) participate in this competitive BGS procurement processand recover BGS costs directly from customers as a charge separate from base rates.

In an order issued July 31, 2012, the NJBPU ordered JCP&L to file a base rate case using a historical 2011 test year. The rate casepetition was filed on November 30, 2012 by JCP&L requesting approval to increase revenues by approximately $31 million, whichincluded the recovery of 2011 storm restoration costs but excluded approximately $603 million of costs incurred in 2012 associatedwith the impact of Hurricane Sandy. In the initial briefs of the parties, the Division of Rate Counsel recommended that base raterevenues be reduced by $214.9 million while the NJBPU Staff recommended a $207.4 million reduction (such amounts do not addressthe revenue requirements associated with the major storm events of 2011 and 2012). On May 5, 2014, JCP&L submitted updatedschedules to reflect the result of the generic storm cost proceeding, discussed below, to revise the debt rate to 5.93%, and to requestthat base rate revenues be increased by $9.1 million, including the recovery of 2011 storm costs. The record in the case was closed asof June 30, 2014. The Administrative Law Judge (ALJ) provided his initial decision on January 8, 2015, which recommended an annualrevenue reduction of $107.5 million and did not include the recovery of 2012 storm costs or any Consolidated Tax Adjustments (CTA).

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On February 11, 2015, the NJBPU approved a 45-day extension to render a final decision, by April 8, 2015. On March 26, 2015, theNJBPU entered a final written Order, directing an annual revenue reduction of $114.9 million. The NJBPU largely approved the ALJ’sinitial decision with the following adjustments: (i) a decrease in annual base rate revenues of $5.36 million associated with the BPU’srecently modified CTA policy that was approved in the Generic CTA proceeding; and (ii) a carrying cost of 2.52% on the unamortizedbalance of the 2011 storm costs, which results in a decrease in annual base rate revenues of approximately $2 million. On the sameday, the NJBPU entered a final written Order in the generic proceeding established to review JCP&L’s major storm events of 2011 and2012 and directed that JCP&L be allowed to recover the NJBPU approved 2012 storm costs at the same time implementing its baserate reduction, which resulted in an increase in annual revenues of approximately $81 million. The overall result of these final writtenOrders is a reduction in JCP&L annual base rate revenues of $34.3 million. The NJBPU also directed JCP&L to complete certainstudies, including one related to reliability.

On January 23, 2013, the NJBPU opened a generic proceeding to review its policies with respect to the use of a CTA in base ratecases. The NJBPU and its Staff solicited, and were provided, input from interested stakeholders, including utilities and the Division ofRate Counsel. On June 18, 2014, the NJBPU Staff proposed to amend current CTA policy by: 1) calculating savings using a 5 yearlook back from the beginning of the test year; 2) allocating savings with 75% retained by the company and 25% allocated to ratepayers; and 3) excluding transmission assets of electric distribution companies in the savings calculation. JCP&L and otherstakeholders filed written comments on the Staff proposal. In its Order issued October 22, 2014, the NJBPU stated it would continue toapply its current CTA policy in base rate cases, subject to incorporating the staff proposed modifications (as discussed above). Forpending base rate cases in which the record had closed, such as JCP&L’s, the NJBPU would, following an initial decision of the ALJ,reopen the record for the limited purpose of adding a CTA calculation reflecting the modified policy and allow parties the opportunity tocomment. FE expects the application of the modified policy in the pending JCP&L base rate case to reduce annual revenues byapproximately $5 million. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order to the New Jersey SuperiorCourt. JCP&L has filed to participate as a respondent in that proceeding.

On March 20, 2013, the NJBPU ordered that a generic proceeding be established to investigate the prudence of costs incurred by allNew Jersey utilities for service restoration efforts associated with the major storm events of 2011 and 2012. The Order provided that ifany utility had already filed a proceeding for recovery of such storm costs, to the extent the amount of approved recovery had not yetbeen determined, the prudence of such costs would be reviewed in the generic proceeding. On May 31, 2013, the NJBPU clarified itsearlier order to indicate that the 2011 major storm costs would be reviewed expeditiously in the generic proceeding, with the goal ofmaintaining the base rate case schedule established by the ALJ where recovery of such costs would be addressed. The NJBPUfurther indicated that it would review the 2012 major storm costs in the generic proceeding and the recovery of such costs would beconsidered through a Phase II in the existing base rate case or through another appropriate method to be determined at theconclusion of the generic proceeding. On June 21, 2013, JCP&L filed a detailed report in support of recovery of major storm costs withthe NJBPU. On February 24, 2014, a Stipulation was filed with the NJBPU by JCP&L, the Division of Rate Counsel and NJBPU Staffwhich will allow recovery of $736 million of JCP&L’s $744 million of costs related to the significant weather events of 2011 and 2012.As a result, FE recorded a regulatory asset impairment charge of approximately $8 million (pre-tax) as of December 31, 2013. By itsOrder of March 19, 2014, the NJBPU approved the Stipulation of Settlement. Although the settlement permits recovery of 2011 and2012 storm costs, the recovery of the 2011 costs will be addressed in the pending base rate case; whereas the manner and timing ofrecovery of the 2012 storm costs totaling $580 million will be determined by the NJBPU. On March 26, 2015, the NJBPU entered afinal written Order directing JCP&L to recover the NJBPU approved 2012 storm costs at the same time it’s implementing its base ratereduction. Specifically, NJBPU directed that the 2012 major storm capital costs will be incorporated into base rates established in the2012 base rate case, while the deferred operations and maintenance expenses will be amortized over six years, collected througha rider, and subject to a carrying cost of 2.52%.

FEDERAL REGULATION

With respect to its wholesale services and rates, JCP&L is subject to regulation by FERC. Under the Federal Power Act (FPA), FERCregulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters. FERC regulations requireJCP&L to provide open access transmission service at FERC-approved rates, terms and conditions. JCP&L's transmission facilitiesare subject to functional control by PJM and transmission service using JCP&L's transmission facilities is provided by PJMInterconnection, L.L.C. (PJM) under the PJM Open Access Transmission Tariff (PJM Tariff). See FERC Matters below.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesalepower at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers toentry into markets. JCP&L has been authorized by FERC to sell wholesale power in interstate commerce and have a market-basedrate tariff on file with FERC; although major wholesale purchases remain subject to regulation by the relevant state commissions. As acondition to selling electricity on a wholesale basis at market-based rates, JCP&L, like other entities granted market-based rateauthority, must file electronic quarterly reports with FERC listing its sales transactions for the prior quarter.

Reliability Matters

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Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keepingand reporting requirements on JCP&L. North American Electric Reliability Corporation (NERC) is the Electric Reliability Organization(ERO) designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-dayimplementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirst Corporation (RFC). Allof FE's facilities, including those of JCP&L, are located within the RFC region. FE actively participates in the NERC and RFCstakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementationand enforcement of the reliability standards implemented and enforced by RFC.

FE believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course ofoperating its extensive electric utility systems and facilities, FE occasionally learns of isolated facts or circumstances that could beinterpreted as excursions from the reliability standards. If and when such occurrences are found, FE develops information about theoccurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” anoccurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as todevelop and adopt new reliability standards. Any inability on FE’s part to comply with the reliability standards for its bulk electric systemcould result in the imposition of financial penalties that could have a material adverse effect on JCP&L's financial condition, results ofoperations and cash flows.

FERC MATTERS

PJM Transmission Rates

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FE and otherparties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on aload-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question hasbeen the subject of extensive litigation before FERC and the appellate courts, including most recently before the United States Court ofAppeals for the Seventh Circuit (Seventh Circuit). On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled thatFERC had not quantified the benefits that western PJM utilities would derive from certain new 500 Kilovolt (kV) or higher lines and thushad not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are theprimary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiariesshould pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not onload-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocationfor hearing and settlement proceedings. Settlement discussions under a FERC-appointed settlement judge are ongoing.

Order No. 1000, issued by FERC on July 21, 2011, announced new policies regarding transmission planning and transmission costallocation, requiring the submission of a compliance filing by PJM and the PJM transmission owners demonstrating that the costallocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in theorder. On August 15, 2014 the United States Court of Appeals for the District of Columbia Circuit (U.S. Court of Appeals for the D.C.Circuit) affirmed Order No. 1000, including its termination of certain "right of first refusal" privileges discussed in more detail below. Thecourt subsequently denied a request for rehearing of its decision.

In series of orders, including certain of the orders related to the Order No. 1000 proceedings, FERC has asserted that the PJMtransmission owners do not hold an incumbent “right of first refusal” to construct, own and operate transmission projects within theirrespective footprints that are approved as part of PJM’s Regional Transmission Expansion Plan (RTEP) process. FE and other PJMtransmission owners have appealed these rulings, and those appeals are pending before the U.S. Court of Appeals for the D.C.Circuit.

To demonstrate compliance with the regional cost allocation principles of Order No. 1000, the PJM transmission owners, including FE,proposed a hybrid allocation of 50% beneficiary pays and 50% socialized to be effective for RTEP projects approved by the PJM Boardof Managers on, and after, the requested February 1, 2013 effective date of the compliance filing. FERC has accepted that approach.

Separately, the PJM transmission owners, including JCP&L, submitted filings to FERC setting forth the cost allocation method forprojects that cross the borders between the PJM Region and: (1) the New York Independent System Operator (NYISO) region; (2) theMidcontinent Independent System Operator, Inc. (MISO) region; and (3) the FERC-jurisdictional members of the SoutheasternRegional Transmission Planning (SERTP) region. These filings propose to allocate the cost of these interregional transmissionprojects based on the costs of projects that otherwise would have been constructed separately in each region, or, in the case of MISO,indicate that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement betweenPJM and MISO comply with the requirements of Order No. 1000. FERC accepted the PJM/MISO and PJM/SERTP filing, subject torefund and further compliance requirements. The PJM/NYISO cross-border project cost allocation filing remains pending before FERC.

The outcome of these proceedings and their impact, if any, on JCP&L cannot be predicted at this time.

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Market-Based Rate Authority, Triennial Update

JCP&L has authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every threeyears JCP&L must file an update with the FERC that demonstrates JCP&L continues to meet FERC’s requirements for holdingmarket-based rate authority. On December 20, 2013, FirstEnergy Service Company (FESC), on behalf of its affiliates withmarket-based rate authority, submitted to FERC the most recent triennial market power analysis filing for each market-based rateholder, including JCP&L, for the current cycle of this filing requirement. On August 13, 2014, FERC accepted the triennial filing assubmitted.

5. COMMITMENTS AND CONTINGENCIES

NUCLEAR INSURANCE

JCP&L maintains property damage insurance provided by Nuclear Electric Insurance Limited (NEIL) for its interest in the Three MileIsland Unit 2 (TMI-2) nuclear plant, a permanently shutdown and defueled facility. Under these arrangements, up to $150 million ofcoverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided.JCP&L pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $0.3 million during apolicy year.

JCP&L intends to maintain insurance against nuclear risks as long as it is available. To the extent that property damage,decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any ofJCP&L’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident isdetermined not to be covered by JCP&L’s insurance policies, or to the extent such insurance becomes unavailable in the future,JCP&L would remain at risk for such costs.

The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&Lcarries the required American Nuclear Insurers (ANI) third party liability coverage and also has coverage under a Price Andersonindemnity agreement issued by the United States Nuclear Regulatory Commission (NRC). The total available coverage in the event ofa nuclear incident is $560 million, which is also the limit of public liability for any nuclear incident involving TMI-2.

ENVIRONMENTAL MATTERS

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

Regulation of Waste Disposal

FE and certain of its subsidiaries, including JCP&L, have been named as potentially responsible parties at waste disposal sites, whichmay require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA).Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject todispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and severalbasis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as ofDecember 31, 2014 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for suchcosts and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $93 million have been accrued byJCP&L through December 31, 2014. Included in the total are accrued liabilities for environmental remediation of former manufacturedgas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable Societal BenefitsCharge (SBC). FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possiblelosses or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to JCP&L's normal businessoperations pending against JCP&L and its subsidiaries. The loss or range of loss in these matters is not expected to be material toJCP&L or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, RegulatoryMatters of the Notes to Consolidated Financial Statements.

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2014/Q4



JCP&L accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonablyestimate the amount of such costs. In cases where JCP&L determines that it is not probable, but reasonably possible that it has amaterial obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it wereultimately determined that JCP&L or its subsidiaries have legal liability or are otherwise made subject to liability, it could have amaterial adverse effect on JCP&L's or its subsidiaries' financial condition, results of operations and cash flows.

6. TRANSACTIONS WITH AFFILIATED COMPANIES

JCP&L’s operating expenses and interest expenses include transactions with affiliated companies. These affiliated companytransactions include affiliated company power sales agreements between FE’s competitive and regulated companies, support servicebillings, interest on affiliated company notes including the money pools and other transactions.

FE's competitive companies at times provide power through affiliated company power sales to meet a portion of the Utilities' Providerof Last Resort (POLR) and default service requirements. The primary affiliated company transactions for JCP&L during the yearsended December 31, 2014 and 2013 are as follows:

2014 2013

(In millions)Support services $ 84 $ 91Interest Expense 7 6

FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated from FESC, a subsidiary of FE. Themajority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalfof more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. Thecurrent allocation or assignment formulas used and their bases include multiple factor formulas: each company's proportionate amountof FE's aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specificdepartmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FEand its other subsidiaries are generally settled under commercial terms within thirty days.

7. STATEMENT OF CASH FLOWS – Per Instructions on Page 121

As of December 31, 2014 2013Cash (Account 131) $ - $ -Working Fund (Account 135) $ 925 $ 925Cash and Cash Equivalents at End of Year $ 925 $ 925

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:Cash paid during the year:

Interest Paid (net of amount capitalized) $ 129,951,397 $ 102,796,805Income Tax Payments $ 62,087,300 $ 15,291,090

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End of

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES


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Line No.

1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.4. Report data on a year-to-date basis.

OtherAdjustments

(e)

Foreign CurrencyHedges

(d)

Minimum PensionLiability adjustment

(net amount)(c)

Unrealized Gains andLosses on Available-for-Sale Securities

(b)

Item

(a)

32,894,753

Balance of Account 219 at Beginning of

Preceding Year

1

( 17,608,555)

Preceding Qtr/Yr to Date Reclassifications

from Acct 219 to Net Income

2

222,778

Preceding Quarter/Year to Date Changes in

Fair Value

3

( 17,385,777)Total (lines 2 and 3) 4

15,508,976

Balance of Account 219 at End of

Preceding Quarter/Year

5

15,508,976

Balance of Account 219 at Beginning of

Current Year

6

( 11,033,055)

Current Qtr/Yr to Date Reclassifications

from Acct 219 to Net Income

7

( 199)

Current Quarter/Year to Date Changes in

Fair Value

8

( 11,033,254)Total (lines 7 and 8) 9

4,475,722

Balance of Account 219 at End of Current

Quarter/Year

10

FERC FORM NO. 1 (NEW 06-02) Page 122a

Other Cash FlowHedges[Specify]

(g)

Other Cash FlowHedges

Interest Rate Swaps

(f)




End of

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES


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Line No.

TotalComprehensive

Income

(j)

Net Income (CarriedForward from

Page 117, Line 78)

(i)

Totals for eachcategory of items

recorded in Account 219

(h)

32,009,414( 885,339) 1

( 17,445,102) 163,453 2

222,778 3

175,878,076 158,655,752( 17,222,324) 163,453 4

14,787,090( 721,886) 5

14,787,090( 721,886) 6

( 10,869,599) 163,456 7

( 199) 8

87,123,615 76,253,817( 10,869,798) 163,456 9

3,917,292( 558,430) 10

FERC FORM NO. 1 (NEW 06-02) Page 122b




End of

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS


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Line No.

(b)(a)

Classification Electric

(c)

FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Total Company for the Current Year/Quarter Ended

Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and incolumn (h) common function.

Utility Plant 1

In Service 2

5,560,117,717 5,560,117,717Plant in Service (Classified) 3

Property Under Capital Leases 4

Plant Purchased or Sold 5

174,149,166 174,149,166Completed Construction not Classified 6

Experimental Plant Unclassified 7

5,734,266,883 5,734,266,883Total (3 thru 7) 8

Leased to Others 9

13,716,214 13,716,214Held for Future Use 10

172,898,887 172,898,887Construction Work in Progress 11

Acquisition Adjustments 12

5,920,881,984 5,920,881,984Total Utility Plant (8 thru 12) 13

2,012,688,780 2,012,688,780Accum Prov for Depr, Amort, & Depl 14

3,908,193,204 3,908,193,204Net Utility Plant (13 less 14) 15

Detail of Accum Prov for Depr, Amort & Depl 16

In Service: 17

1,952,492,284 1,952,492,284Depreciation 18

Amort & Depl of Producing Nat Gas Land/Land Right 19

Amort of Underground Storage Land/Land Rights 20

60,196,496 60,196,496Amort of Other Utility Plant 21

2,012,688,780 2,012,688,780Total In Service (18 thru 21) 22

Leased to Others 23

Depreciation 24

Amortization and Depletion 25

Total Leased to Others (24 & 25) 26

Held for Future Use 27

Depreciation 28

Amortization 29

Total Held for Future Use (28 & 29) 30

Abandonment of Leases (Natural Gas) 31

Amort of Plant Acquisition Adj 32

2,012,688,780 2,012,688,780Total Accum Prov (equals 14) (22,26,30,31,32) 33


(g)

Common

(h)




End of

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS


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Line No.

FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Gas Other (Specify)

(d) (e) (f)

Other (Specify)Other (Specify)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33





End of

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)


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Line No.

Description of item Balance

(c)(b)(a)

Changes during YearBeginning of Year Additions

1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by therespondent.2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, thequantity used and quantity on hand, and the costs incurred under such leasing arrangements.

Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 1

Fabrication 2

Nuclear Materials 3

Allowance for Funds Used during Construction 4

(Other Overhead Construction Costs, provide details in footnote) 5

SUBTOTAL (Total 2 thru 5) 6

Nuclear Fuel Materials and Assemblies 7

In Stock (120.2) 8

In Reactor (120.3) 9

SUBTOTAL (Total 8 & 9) 10

Spent Nuclear Fuel (120.4) 11

Nuclear Fuel Under Capital Leases (120.6) 12

(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 13

TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 14

Estimated net Salvage Value of Nuclear Materials in line 9 15

Estimated net Salvage Value of Nuclear Materials in line 11 16

Est Net Salvage Value of Nuclear Materials in Chemical Processing 17

Nuclear Materials held for Sale (157) 18

Uranium 19

Plutonium 20

Other (provide details in footnote): 21

TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) 22





End of

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)


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Line No.

Balance

(f)(e)(d)

Changes during YearEnd of YearAmortization Other Reductions (Explain in a footnote)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22





End of

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)


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Line No.

Account Balance Additions

(c)(b)(a)Beginning of Year

1. Report below the original cost of electric plant in service according to the prescribed accounts.2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions andreductions in column (e) adjustments.5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be includedin column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amountof plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of suchretirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)

1. INTANGIBLE PLANT 1(301) Organization 51,057 2(302) Franchises and Consents 16,447 3(303) Miscellaneous Intangible Plant 69,616,323 8,841,927 4TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 69,683,827 8,841,927 52. PRODUCTION PLANT 6A. Steam Production Plant 7(310) Land and Land Rights 8(311) Structures and Improvements 9(312) Boiler Plant Equipment 10(313) Engines and Engine-Driven Generators 11(314) Turbogenerator Units 12(315) Accessory Electric Equipment 13(316) Misc. Power Plant Equipment 14(317) Asset Retirement Costs for Steam Production 15TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 16B. Nuclear Production Plant 17(320) Land and Land Rights 18(321) Structures and Improvements 19(322) Reactor Plant Equipment 20(323) Turbogenerator Units 21(324) Accessory Electric Equipment 22(325) Misc. Power Plant Equipment 23(326) Asset Retirement Costs for Nuclear Production 55,157,343 24TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 55,157,343 25C. Hydraulic Production Plant 26(330) Land and Land Rights 284,198 27(331) Structures and Improvements 3,614,843 28(332) Reservoirs, Dams, and Waterways 13,574,474 4,377,849 29(333) Water Wheels, Turbines, and Generators 16,927,617 30(334) Accessory Electric Equipment 3,964,461 31(335) Misc. Power PLant Equipment 1,659,815 32(336) Roads, Railroads, and Bridges 33(337) Asset Retirement Costs for Hydraulic Production 34TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 40,025,408 4,377,849 35D. Other Production Plant 36(340) Land and Land Rights 37(341) Structures and Improvements 38(342) Fuel Holders, Products, and Accessories 39(343) Prime Movers 40(344) Generators 41(345) Accessory Electric Equipment 42(346) Misc. Power Plant Equipment 43(347) Asset Retirement Costs for Other Production 44TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 45TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 95,182,751 4,377,849 46

Page 204FERC FORM NO. 1 (REV. 12-05)

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)





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Line No.

Account Balance Additions

(c)(b)(a)Beginning of Year

3. TRANSMISSION PLANT 47(350) Land and Land Rights 42,887,144 48(352) Structures and Improvements 27,168,054 1,016,765 49(353) Station Equipment 492,733,037 34,210,427 50(354) Towers and Fixtures 37,043,336 51(355) Poles and Fixtures 163,685,544 7,780,553 52(356) Overhead Conductors and Devices 263,797,633 26,461,995 53(357) Underground Conduit 1,948,411 1,705 54(358) Underground Conductors and Devices 16,563,650 1,584,190 55(359) Roads and Trails 2,135,523 56(359.1) Asset Retirement Costs for Transmission Plant 3,410 57TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 1,047,965,742 71,055,635 584. DISTRIBUTION PLANT 59(360) Land and Land Rights 33,018,688 60(361) Structures and Improvements 23,325,058 2,342,181 61(362) Station Equipment 475,217,795 8,416,320 62(363) Storage Battery Equipment 63(364) Poles, Towers, and Fixtures 621,375,087 24,022,605 64(365) Overhead Conductors and Devices 889,646,964 44,166,730 65(366) Underground Conduit 113,897,730 485,598 66(367) Underground Conductors and Devices 445,992,548 29,867,110 67(368) Line Transformers 737,759,715 22,657,583 68(369) Services 435,782,003 7,861,869 69(370) Meters 96,380,404 22,764,218 70(371) Installations on Customer Premises 24,345,239 507,355 71(372) Leased Property on Customer Premises 72(373) Street Lighting and Signal Systems 179,253,123 10,650,492 73(374) Asset Retirement Costs for Distribution Plant 45,656 74TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 4,076,040,010 173,742,061 755. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76(380) Land and Land Rights 77(381) Structures and Improvements 78(382) Computer Hardware 79(383) Computer Software 80(384) Communication Equipment 81(385) Miscellaneous Regional Transmission and Market Operation Plant 82(386) Asset Retirement Costs for Regional Transmission and Market Oper 83TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 846. GENERAL PLANT 85(389) Land and Land Rights 2,008,907 86(390) Structures and Improvements 101,219,684 839,656 87(391) Office Furniture and Equipment 39,231,194 798,798 88(392) Transportation Equipment 3,728,388 20,708 89(393) Stores Equipment 3,510,877 90(394) Tools, Shop and Garage Equipment 24,417,820 2,476,705 91(395) Laboratory Equipment 5,229,308 386 92(396) Power Operated Equipment 3,593,613 447,037 93(397) Communication Equipment 95,382,374 1,146,799 94(398) Miscellaneous Equipment 4,293,761 95,571 95SUBTOTAL (Enter Total of lines 86 thru 95) 282,615,926 5,825,660 96(399) Other Tangible Property 97(399.1) Asset Retirement Costs for General Plant 551,990 285,647 98TOTAL General Plant (Enter Total of lines 96, 97 and 98) 283,167,916 6,111,307 99TOTAL (Accounts 101 and 106) 5,572,040,246 264,128,779 100(102) Electric Plant Purchased (See Instr. 8) 101(Less) (102) Electric Plant Sold (See Instr. 8) 102(103) Experimental Plant Unclassified 103TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 5,572,040,246 264,128,779 104


(f)

Transfers Balance atEnd of Year





/ /2014/Q4

Line No.(g)

Adjustments

(e)

Retirements

(d)


distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of theseamounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount ofrespondent’s plant actually in service at end of year.7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary accountclassifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulatedprovision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primaryaccount classifications.8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showingsubaccount classification of such plant conforming to the requirement of these pages.9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date

1 49,294 -1,763 2 16,447 3

73,017,865 -5,440,385 4 73,083,606 -5,442,148 5

6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

17,839,392 -37,317,951 24 17,839,392 -37,317,951 25

26 284,198 27 3,614,843 28 17,952,323 29 16,927,617 30 3,964,461 31 1,659,815 32

33 34

44,403,257 35 36 37 38 39 40 41 42 43 44 45

62,242,649 -37,317,951 46


(f)

Transfers Balance atEnd of Year





/ /2014/Q4

Line No.(g)

Adjustments

(e)

Retirements

(d)


47 42,842,914 -44,230 48 28,245,932 67,565 6,452 49 523,723,623 832,448 -1,262,533 2,789,756 50 37,182,515 139,179 51 170,121,747 -855,403 2,468,939 2,957,886 52 290,734,132 2,005,625 1,531,121 53 1,962,291 12,175 54 18,219,283 71,443 55 2,135,523 56

3,410 57 1,115,171,370 -22,955 3,458,163 7,285,215 58

59 32,954,774 -63,914 60 26,025,184 1,356,023 998,078 61 478,725,932 47,138 -802,760 4,152,561 62

63 629,346,836 -15,590,754 460,102 64 917,929,164 -1,588,641 14,295,889 65 114,189,646 -134,845 58,837 66 474,575,167 1,486,573 2,771,064 67 752,278,140 -2,070,906 6,068,252 68 442,544,850 91,689 1,190,711 69 114,971,489 -1,515,544 2,657,589 70 24,515,565 -19,474 317,555 71

72 187,676,551 -207,347 2,019,717 73

45,656 74 4,195,778,954 47,138 -19,059,900 34,990,355 75

76 77 78 79 80 81 82 83 84 85

2,008,907 86 101,967,385 6,577 98,532 87 42,480,354 4,580,848 2,130,486 88 3,800,420 51,324 89 3,434,907 75,970 90 24,700,365 -47,138 -1,523,460 623,562 91 5,061,212 168,482 92 4,008,849 49,927 -81,728 93 95,479,372 277 1,050,078 94 4,210,896 -20,295 158,141 95

287,152,667 54,113 2,962,219 4,305,251 96 97

837,637 98 287,990,304 54,113 2,962,219 4,305,251 99 5,734,266,883 78,296 -55,399,617 46,580,821 100

101 102 103

5,734,266,883 78,296 -55,399,617 46,580,821 104





End of

ELECTRIC PLANT LEASED TO OTHERS (Account 104)


/ /2014/Q4

Line No.

Name of LesseeDescription of

(b)(a)

(Designate associated companieswith a double asterisk) Property Leased

CommissionAuthorization

(c)

ExpirationDate ofLease

(d)

Balance atEnd of Year

(e) 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46


47 TOTAL




End of

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)


/ /2014/Q4

Line Description and Location Date Originally Included Balance atEnd of Year

(c)(b)(a)Of Property in This Account

Date Expected to be usedin Utility Service

(d)No.

1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property heldfor future use.2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition toother required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.

Land and Rights: 1

Transmission Line Right of Way 2

12/31/57Gilbert - Smithburg 500KV 282,449 3

12/31/80New Freedom - Forked River 500KV 3,987,729 4

12/31/83Whippany - Kinnelon 755,502 5

12/31/80Future 230KV Line 6,693,039 6

7

12/31/66Miscellaneous Substation Sites 1,030,657 8

9

10

11

12

13

14

15

16

17

18

19

Items Under $250,000 966,838 20

Other Property: 21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46


47 Total 13,716,214

Schedule Page: 214 Line No.: 3 Column: cDate not presently determinable for all items not specifically noted in column C.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)


/ /2014/Q4

Line No.

Description of Project Construction work in progress -

(b)(a)Electric (Account 107)

1. Report below descriptions and balances at end of year of projects in process of construction (107)2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (seeAccount 107 of the Uniform System of Accounts)3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.

18,190,106JC-001672 - Englishtown - Wycoff Street 115 kV line 1

14,670,279JC-001267 - Rocktown 230-34.5 kV Substation 2

10,348,389JC-001671 - Eaton Crest 230/34.5 kV Substation 3

5,040,520JC-900381 - Substation Condition TX Blanket 4

5,036,147JC-900380 - This JC Substation Condition DX Blanket 5

5,012,473JC-002172 - West Wharton-Inst (2) 230Kv Reactors 6

4,479,196JC-001848 - Wyckoff Street add 115 kV - 34.5 kV Txmr 7

3,094,775JC-900059 - N-Repair-OH Facility- Reliability Other 8

3,050,418JC-900048 - N-New Business- Residential Underground 9

2,894,966JC-001463 - Whippany - Roseland 230 kV DCT Line Reconductor 10

2,703,596JC-900051 - N-Maintain UnSched. Repair-Repl OH Facilities 11

2,362,713JC-001065 - Leisure Village - Drum Point build a 34. 12

2,300,331JC-M70023 - ITS - Merger: Trans EMS Standardization 13

2,242,107JC-001459 - Sussex REA Transf Load off of the Q745 14

2,020,546JC-004000 - Smart Grid Modernization Initiative DOE 15

1,983,567JC-001853 - Atlantic Sub Add 230kV Backup Relays 16

1,960,496JC-001217 - Red Bank Thrid 230kV Line Reinforcement 17

1,938,310JC-002233 - JC Major Storm November 26, 2014 - CATO 18

1,866,395JC-001852 - Red Bank Sub Repl 9 34.5kV BD Bus Bkrs 19

1,829,774JC-001475 - Atlantic - Oceanview Relay and Control Modifications 20

1,820,093JC-001847 - Oceanview Area Project Third 230kV line 21

1,804,972JC-001008 - MOD-Costco Sub - Add 2nd Bank, 14MVA (34 22

1,771,198JC-001427 - Gilbert - Flanders-W Wharton 115 kV Cond 23

1,760,543JC-002144 - Montville Area Reinforcement Project 24

1,598,494JC-900073 - N-Highway Relocation-OH Facility 25

1,526,107JC-001073 - Farmingdale - Howell build new 115 kV line 26

1,498,871JC-900150 - N-Network & Ducted Reliability Project 27

1,487,483JC-900047 - N-New Business- Residential Overhead 28

1,426,213JC-001458 - Riverdale-Butler 34.5 kV Line 29

1,392,876JC-001803 - Morristown S St. Network Capital Repairs 30

1,391,384JC-001850 - Oceanview Sub Replace 15 34.5kV Bkrs 31

1,338,627JC-900149 - N-New Service-Commercial UG 32

1,336,100GF-0001806 - YCCO-NO1RPL-FERC Relicensing 33

1,267,179JC-001954 - Deep Run - Loop the B2 and C3 115 kV Lin 34

1,266,988JC-700286 - ITS - WMI - Corporate 2013 35

1,181,289JC-001855 - Larrabee Sub Repl 5 Overdutied 34.5 Bkrs 36

1,118,340JC-002131 - Post Hurricane Sandy Work- Nondeferrable 37

1,110,724JC-900042 - N-Engr-OH internally initiated 38

1,108,407JC-700319 - IT Customer SAP & Web Enhancements 39

1,101,110JC-001744 - LIDAR 100kv Trans Line Mapping 40

1,042,538JC-002166 - Windsor Substation Flooding Mitigation 41

1,036,357JC-002127 - Emergent: Collinsville Bank 1 Repair 42


43 TOTAL 172,898,887




End of

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)


/ /2014/Q4

Line No.

Description of Project Construction work in progress -

(b)(a)Electric (Account 107)

1. Report below descriptions and balances at end of year of projects in process of construction (107)2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (seeAccount 107 of the Uniform System of Accounts)3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.

49,487,890Projects Under $1,000,000 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42


43 TOTAL 172,898,887




End of

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)


/ /2014/Q4

Line No.

Item Total

(c)(b)(a) (d)

Section A. Balances and Changes During Year

(c+d+e)Electric Plant in

ServiceElectric Plant Held

for Future UseElectric Plant

Leased to Others(e)

1. Explain in a footnote any important adjustments during year.2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported forelectric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded whensuch plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recordedand/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the bookcost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functionalclassifications.4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.

Balance Beginning of Year 1 1,919,220,668 1,919,220,668

Depreciation Provisions for Year, Charged to 2

(403) Depreciation Expense 3 139,427,480 139,427,480

(403.1) Depreciation Expense for Asset

Retirement Costs

4

(413) Exp. of Elec. Plt. Leas. to Others 5

Transportation Expenses-Clearing 6

Other Clearing Accounts 7

Other Accounts (Specify, details in footnote): 8

9

TOTAL Deprec. Prov for Year (Enter Total of

lines 3 thru 9)

10 139,427,480 139,427,480

Net Charges for Plant Retired: 11

Book Cost of Plant Retired 12 46,550,048 46,550,048

Cost of Removal 13 23,522,003 23,522,003

Salvage (Credit) 14 565,732 565,732

TOTAL Net Chrgs. for Plant Ret. (Enter Total

of lines 12 thru 14)

15 69,506,319 69,506,319

Other Debit or Cr. Items (Describe, details in

footnote):

16 -36,649,545 -36,649,545

17

Book Cost or Asset Retirement Costs Retired 18

Balance End of Year (Enter Totals of lines 1,

10, 15, 16, and 18)

19 1,952,492,284 1,952,492,284

Steam Production 20

Section B. Balances at End of Year According to Functional Classification

Nuclear Production 21 17,839,392 17,839,392

Hydraulic Production-Conventional 22

Hydraulic Production-Pumped Storage 23 17,977,922 17,977,922

Other Production 24

Transmission 25 347,515,744 347,515,744

Distribution 26 1,380,104,115 1,380,104,115

Regional Transmission and Market Operation 27

General 28 189,055,111 189,055,111

TOTAL (Enter Total of lines 20 thru 28) 29 1,952,492,284 1,952,492,284


Schedule Page: 219 Line No.: 16 Column: b

Other debits and credits are the result of the following:

Update to Asset Retirement Obligation (ARO) for TMI-2 Decommissioning $ (37,317,951)Other transfers and adjustments 632,493 Asset retirement cost deferred 35,913

$ (36,649,545)

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)


/ /2014/Q4

Line No.

Description of Investment Date Acquired

(c)(b)(a)

Amount of Investment atBeginning of Year

Date Of Maturity

(d)

1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL incolumns (e),(f),(g) and (h)(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject tocurrent settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturitydate, and specifying whether note is a renewal.3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered forAccount 418.1.

JCP&L Transition Funding LLC 1

1,601,0006/11/2002 Capital Contributions 2

-23,363 Equity in Undistributed Subsidiary Earnings 3

1,577,637Subtotal 4

5

JCP&L Transition Funding II LLC 6

912,0008/10/2006 Capital Contributions 7

-11,521 Equity in Undistributed Subsidiary Earnings 8

900,479Subtotal 9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41


42 Total Cost of Account 123.1 $ TOTAL 2,478,116 2,513,000




End of

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)


/ / 2014/Q4

Line No.

Equity in Subsidiary Earnings of Year

Revenues for Year Amount of Investment atEnd of Year

Gain or Loss from InvestmentDisposed of

(e) (f) (g) (h)

4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgeeand purpose of the pledge.5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,date of authorization, and case or docket number.6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (orthe other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includiblein column (f).8. Report on Line 42, column (a) the TOTAL cost of Account 123.1

1

1,601,000 2

-23,418 -161 106 3

1,577,582 -161 106 4

5

6

912,000 7

-11,553 -92 60 8

900,447 -92 60 9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41


42 166 -253 2,478,029




End of

MATERIALS AND SUPPLIES


/ / 2014/Q4

Line No.

Account Balance Balance

(c)(b)(a)

Department orDepartments which

(d)

Beginning of Year End of YearUse Material

1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and thevarious accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expenseclearing, if applicable.

1 Fuel Stock (Account 151)

2 Fuel Stock Expenses Undistributed (Account 152)

3 Residuals and Extracted Products (Account 153)

4 Plant Materials and Operating Supplies (Account 154)

5 Assigned to - Construction (Estimated)

6 Assigned to - Operations and Maintenance

7 Production Plant (Estimated)

8 Transmission Plant (Estimated)

9 Distribution Plant (Estimated)

10 Regional Transmission and Market Operation Plant

(Estimated)

11 Assigned to - Other (provide details in footnote)

12 TOTAL Account 154 (Enter Total of lines 5 thru 11)

13 Merchandise (Account 155)

14 Other Materials and Supplies (Account 156)

15 Nuclear Materials Held for Sale (Account 157) (Not

applic to Gas Util)

16 Stores Expense Undistributed (Account 163)

17

18

19

20 TOTAL Materials and Supplies (Per Balance Sheet)





End of

Allowances (Accounts 158.1 and 158.2)


/ / 2014/Q4

Line No.

SO2 Allowances Inventory Current Year

(b)(a)(Account 158.1) No. Amt.

(c)No.(d)

Amt.(e)

1. Report below the particulars (details) called for concerning allowances.2. Report all acquisitions of allowances at cost.3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by GeneralInstruction No. 21 in the Uniform System of Accounts.4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c),allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remainingsucceeding years in columns (j)-(k).5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.

2015

Balance-Beginning of Year 1

2

Acquired During Year: 3

Issued (Less Withheld Allow) 4

Returned by EPA 5

6

7

Purchases/Transfers: 8

9

10

11

12

13

14

Total 15

16

Relinquished During Year: 17

Charges to Account 509 18

Other: 19

20

Cost of Sales/Transfers: 21

22

23

24

25

26

27

Total 28

Balance-End of Year 29

30

Sales: 31

Net Sales Proceeds(Assoc. Co.) 32

Net Sales Proceeds (Other) 33

Gains 34

Losses 35

Allowances Withheld (Acct 158.2)


Add: Withheld by EPA 37

Deduct: Returned by EPA 38

Cost of Sales 39


41

Sales: 42

Net Sales Proceeds (Assoc. Co.) 43


Gains 45

Losses 46

FERC FORM NO. 1 (ED. 12-95) Page 228a




End of



/ / 2014/Q4

Line No.

(f) (j)No. Amt.

(g)No.(h)

Amt.(i)

No. Amt. No. Amt.(k) (l) (m)

Future Years Totals

(Continued)

6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associatedcompany" under "Definitions" in the Uniform System of Accounts).8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.

2016 2017

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46





End of



/ / 2014/Q4

Line No.

NOx Allowances Inventory Current Year

(b)(a)(Account 158.1) No. Amt.

(c)No.(d)

Amt.(e)

1. Report below the particulars (details) called for concerning allowances.2. Report all acquisitions of allowances at cost.3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by GeneralInstruction No. 21 in the Uniform System of Accounts.4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c),allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remainingsucceeding years in columns (j)-(k).5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.

2015


2

Acquired During Year: 3

Issued (Less Withheld Allow) 4

Returned by EPA 5

6

7

Purchases/Transfers: 8

9

10

11

12

13

14

Total 15

16

Relinquished During Year: 17

Charges to Account 509 18

Other: 19

20

Cost of Sales/Transfers: 21

22

23

24

25

26

27

Total 28


30

Sales: 31

Net Sales Proceeds(Assoc. Co.) 32


Gains 34

Losses 35

Allowances Withheld (Acct 158.2)


Add: Withheld by EPA 37

Deduct: Returned by EPA 38

Cost of Sales 39


41

Sales: 42

Net Sales Proceeds (Assoc. Co.) 43


Gains 45

Losses 46

FERC FORM NO. 1 (ED. 12-95) Page 228b




End of



/ / 2014/Q4

Line No.

(f) (j)No. Amt.

(g)No.(h)

Amt.(i)

No. Amt. No. Amt.(k) (l) (m)

Future Years Totals

(Continued)

6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associatedcompany" under "Definitions" in the Uniform System of Accounts).8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.

2016 2017

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46





End of

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)


/ /2014/Q4

Line No.

(c)(b)(a) (d)

Description of Extraordinary Loss[Include in the description the date of

Commission Authorization to use Acc 182.1and period of amortization (mo, yr to mo, yr).]

Total Amount of Loss

LossesRecognisedDuring Year

WRITTEN OFF DURING YEAR

AccountCharged Amount

Balance at

End of Year

(f)(e)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19


20 TOTAL




End of

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)


/ /2014/Q4

Line No.

(c)(b)(a) (d)

Description of Unrecovered Plant Total Amount

of Charges

CostsRecognisedDuring Year

WRITTEN OFF DURING YEAR

AccountCharged Amount

Balance at

End of Year

(f)(e)

and Regulatory Study Costs [Includein the description of costs, the date of

Commission Authorization to use Acc 182.2and period of amortization (mo, yr to mo, yr)]

Oyster Creek Design Basis Doc.21

Authorization 8/03.22

(Amortized as Costs are Recovered23

from Customers)24

Period 42 Years, Ending 12/52. 3,241,183 407.3 -83,004 3,158,17925

26

TMI-1 Design Basis Documentation27

Authorization 9/90.28

(Amortized as Costs are Recovered29

from Customers)30

Period 58 Years, Ending 12/68 1,429,752 407.3 -26,004 1,403,74831

32

Werner Station. Amortization33

Period 17 Years, Ending 04/13.34

35

36

37

38

39

40

41

42

43

44

45

46

47

48


49 TOTAL 4,670,935 -109,008 4,561,927




End of

Transmission Service and Generation Interconnection Study Costs


/ /2014/Q4

Line No. Description

Costs Incurred During

(b)(a)Period Account Charged

(c)

ReimbursementsReceived During

(d)

Account CreditedWith Reimbursement

(e)

1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service andgenerator interconnection studies.2. List each study separately.3. In column (a) provide the name of the study.4. In column (b) report the cost incurred to perform the study at the end of period.5. In column (c) report the account charged with the cost of the study.6. In column (d) report the amounts received for reimbursement of the study costs at end of period.7. In column (e) report the account credited with the reimbursement received for performing the study.

the Period

Transmission Studies 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Generation Studies 21

22

( 138,695)Total Generation Interconnection 561.7 176,743 561.7 23

Studies 24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231

Schedule Page: 231 Line No.: 23 Column: aCosts Account Reimbursements Account

Description Incurred Charged Received Credited

During During With Period the Period Reimbursement

(a) (b) (c) (d) (e)Allenwood-Larabee 34.5kV-Pre Construction Study W3-079 $ 1,560 561.7 $ 1,877 561.7Andover 34.5kV-System Impact Study X3-083 181 561.7Andover-Kittatinny #2 34kV-Pre Construction Study W3-136 (189) 561.7Applegarth 12.5kV-System Impact Study W2-078 181 561.7Argonne-New Lisbon 34.5kV-JC-System Impact Study Z2-102 1,309 561.7 2,069 561.7Asbury-Broadway #2 34.5kV-Pre Construction Study W3-139 (1,775) 561.7Atlantic-South River 230kV-Facility Study W4-021 1,910 561.7 1,978 561.7Belvidere-Gilbert 115kV-Feasibility Study Y3-105 (1,088) 561.7Bennett-Farmingdale 34.5kV-Feasibility Study Z2-092 9,119 561.7 12,341 561.7Bernards 34.5kV-System Impact Study X1-095 86 561.7Blairstown-Kittatinny 34.5kV-Pre Construction Study W3-138 (189) 561.7Branchville-Holiday Lakes 34kV-Pre-Construction Study W3-126 (706) 561.7Branchville-Sussex 34kV-Feasibility Study Z2-095 2,919 561.7 7,125 561.7Broadway-Stewartsville 34.5kV-Pre Construction Study W3-077 (171) 561.7Budd Lake 34.5kV-Facility Study X1-094 181 561.7Clifton-Athenia 230kV-Feasibility Study Z2-069 3,741 561.7 4,374 561.7Cookstown 34.5kV-Facility Study W1-129 (116) 561.7Cookstown-Great Adventure 34.5kV Pre-Construction Study W3-120 (6) 561.7Coventa/Warren 34.5kV-Feasibility Study NQ-1046 1,026 561.7 1,839 561.7Crossmans-Werner 34.5kV-Feasibility Study Z2-056 1,251 561.7 2,643 561.7East Newton–Blairstown 34.5kV-System Impact Study Y1-084 (2,298) 561.7East Windsor 34.5kV-Pre Construction Study W3-078 (1,361) 561.7Englishtown 34.5kV-Pre Construction Study W4-072 (377) 561.7Englishtown 34kV-Pre Construction Study W3-156 (189) 561.7Fairfield 12kV-System Impact Study W3-045 181 561.7Flemington #2 34.5kV-Pre Construction Study W2-080 85 561.7 109 561.7Forked River 230kV-Feasibility Study AA1-097 223 561.7 345 561.7Frankford 34.5kV-System Impact Study X1-046 86 561.7Franklin 34.5kV-System Impact Study X2-054 86 561.7 4,573 561.7Freehold #2 34.5kV-System Impact Study X2-059 181 561.7Freehold 34.5kV-System Impact Study X1-085 (5,374) 561.7Frelinghuysen 34.5kV-Pre Construction Study W3-146 (861) 561.7Frenchtown 34.5kV-Pre Construction Study W4-093 85 561.7 110 561.7Frenchtown-Rosemont 34.5kV Pre-Construction Study W3-149 85 561.7 110 561.7Glen Garnder 12kV-Feasibility StudyY 1-072 85 561.7Great Adventure 34.5kV-Feasibility Study AA1-060 773 561.7 1,264 561.7Great Adventure-Tap 34.5kV-System Impact Study W3-158/W4-045 842 561.7 1,264 561.7Hampton 12.5kV-Pre Construction Study W4-064 1,684 561.7 2,102 561.7Hawks 12kV-Feasibility Study Z2-093 391 561.7 575 561.7Holland 12.5kV-Pre Construction Study W4-097 2,635 561.7 3,256 561.7Homerstown-Winder 34kV-Pre Construction Study W4-045 470 561.7 575 561.7Hornerstown-Windsor 34kV-Facility Study W3-159 (82) 561.7Howell 34.5kV-System Impact Study X1-037 239 561.7Kearny 138kV-Feasibility Study W2-024 (3,665) 561.7Kittatinny 230kV-Feasibility Study Z1-050 5,410 561.7 7,681 561.7Lake Nelson-Middlesex-Feasibility/System Impact Study Z1-031 1,557 561.7 6,351 561.7Lakewood #1 230kV-System Impact Study Y2-078 1,880 561.7 3,231 561.7Lakewood #2 230kV-System Impact Study Y2-079 1,153 561.7 5,434 561.7Lambertville 34.5kV-System Impact Study W2-076 3,186 561.7 2,190 561.7Manalapan #2 12.5kV-Pre Construction Study W4-094 (47) 561.7Mansfield 34.5kV Facility Study X1-008 (175) 561.7Middlesex-Bridgewater 230kV-Feasibility Study Z2-053 1,424 561.7 2,183 561.7

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


Milford 34.5kV-Pre Construction Study W1-082 (487) 561.7Monroe 34.5kV-System Impact Study X1-049 85 561.7Monroe-Feasibility Study AA1-124 1,601 561.7 2,413 561.7Morris Park-Stewartsville 34.5kV Facility Study W3-076 (47) 561.7Newton 34.5kV-Facility Study W3-145 85 561.7 109 561.7Pemberton 32.5kV-Feasibility Study Z2-102 6,815 561.7 10,458 561.7Pequest River 34.5kV-Feasibility Study Y2-018 1,518 561.7Perryville 12.5kV-Pre Construction Study W4-031 171 561.7 218 561.7Phillipsburg 12.47kV-Pre Construction Study W1-127 (47) 561.7Phillipsburg 12.5kV-Pre Construction Study W4-073 (943) 561.7Phillipsburg-Washington 34.5kV-Pre Construction Study W3-095 (593) 561.7Pittstown 12kV-Pre Construction Study W1-132 (342) 561.7Pohatcong-Washington 34.5kV-Pre Construction Study W4-046 575 561.7 838 561.7Raritan River 230kV-Facility Study W4-009 (272,962) 561.7 40,599 561.7Raritan River 230kV-Facility Study X4-005 181 561.7 230 561.7Raritan River 230kV-System Impact Study X4-005 (1,020) 561.7Raritan River-Deep Run 115kV-Feasibility Study AA1-098 1,480 561.7 2,988 561.7Ringoes #1-34.5kV-Pre Construction Study W3-107 (236) 561.7Ringoes 34.5kV Pre-Construction Study W3-029 513 561.7 631 561.7Ringoes 34.5kV-Pre Construction Study W2-064 (1,500) 561.7Salem Unit 1 to PSEG Zone-Feasibility Study Z1-083 4,159 561.7 5,173 561.7South River 230kV-Feasibility Study Z2-109 3,414 561.7 15,055 561.7South River 230kV-System Impact Study Z2-109 85 561.7 264 561.7Stewartville 34.5kV-Pre Construction Study W3-032 (141) 561.7Sussex-System Impact Study W3-110 (2,151) 561.7Wall 12.47kV-Pre Construction Study W2-074 (728) 561.7Washington#2 34.5kV-Pre Construction Study W3-154 (585) 561.7Washington-Mobile Chemical 34kV-Feasibility Study Z2-094 2,363 561.7 4,482 561.7Werner 230kV-System Impact Study X1-078 (590) 561.7Misc. costs to be transferred from 561.7 25,239 561.7Miscellaneous allocated costs 924 561.7Order charges to be transferred from 561.7 39,093 561.7 45,526 561.7Total Generation Interconnection Studies $ (138,695) $ 176,743

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

OTHER REGULATORY ASSETS (Account 182.3)


/ /2014/Q4

Line No.

Description and Purpose of Debits CREDITSWritten off Duringthe Quarter/YearAccount Charged

(d)(c)(a)

Balance at end ofCurrent Quarter/Year

(e)

Other Regulatory Assets Written off Duringthe Period

Amount

(f)

1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may begrouped by classes.3. For Regulatory Assets being amortized, show period of amortization.

Balance atBeginning of

CurrentQuarter/Year

(b)

63,497,557 16,117,668 47,379,889253Non-utility Generation Charge: Operating NUGS 1

2

58,926,690 40,765,107 18,161,583407.3Market Transition Charge Tax - Oyster Creek Sc 3

(amortized through 2016) 4

5

74,607,759 66,423,509 8,184,250407.3Market Transition Charge Tax - MTC Sec 6

(amortized through 2021) 7

8

11,573,025 11,425,528 147,497431MTC Deferred Balance - Interest 9

10

3,073,997 3,720,637 646,640Environmental Cleanup Costs 11

12

3,416,904 3,416,904Divestiture Activities 13

14

( 2,000,000) -2,000,000Oyster Creek: Sales Price Adjustment 15

16

95,938 52,042 43,896407.3Merrill Creek 17

18

37,513,511 41,363,154 3,849,643Basic Generation Service Rider 19

20

1,544,915 2,458,406 913,491FAS 109 - Accounting for Income Taxes 21

22

3,471,440 3,742,642 271,202Asset Removal Costs 23

24

370,467,662 372,103,955 1,636,293Storm Damages 25

26

Societal Benefits Charge: 27

110,495,869 123,467,257 12,971,388Manufactured Gas Site Investigation & Cleanup 28

14,130,573 19,253,151 5,122,578Manufactured Gas Site Insurance Recovery 29

30

13,050,060 19,256,670 6,206,610Regional Greenhouse Gas Initiative 31

32

79,972 79,972407.3BPU Management Audit Fees 33

34

285,772 287,504 1,732LT Capacity Agreement Pilot Program 35

36

16,507,495 15,676,236 831,259variousDemand Side Management Rider 37

38

1,899,633 2,113,993 214,360NJ BPU Rate Case Expenditures 39

40

6,648,938 6,648,938MTC Deferred Balance effective 8/2003 41

42

1,177,886 4,696,564 50,868407.3 3,569,546Vegetation Management - Transmission 43


44 TOTAL 783,816,658 74,879,214 750,989,865 42,052,421




End of

MISCELLANEOUS DEFFERED DEBITS (Account 186)


/ /2014/Q4

Line No.

Description of Miscellaneous Debits CREDITSAccount

(c)(b)(a)


(d)

Deferred Debits Amount(e)

Balance at Beginning of Year

(f)Charged

1. Report below the particulars (details) called for concerning miscellaneous deferred debits.2. For any deferred debit being amortized, show period of amortization in column (a)3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped byclasses.

11,979 10,705 1,274253/242Merrill Cr Lease Improv - Sithe 1 2

7,978 7,407 571253/242Merrill Cr Lse Imp - Northamptn 3 4

1,810,936,125 1,810,936,125Goodwill 5 6

1,235,003 1,342,007 107,004 254LT Overcollateralization Rec JC 7 8

306,367 146,893 159,474234Reimbursable BGS Consult. Fees 9 10

135,000 135,000Collateral - Margin Paid Regul. 11 12

13,222,200 13,222,200Sprint Nextel - Prepayment 13 14

1,529,447 1,511,862 17,585431Credit Facilities-Revolvers 15 16

982,893 -70,700 1,053,593Smart Grid Stimulus 17 18 19 20

318,445 409,451 91,006Minor Items 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

1,431,414 1,466,736


49 TOTAL

47 Misc. Work in Progress

48Deferred Regulatory Comm.Expenses (See pages 350 - 351)

1,830,116,851 1,829,117,686




End of

ACCUMULATED DEFERRED INCOME TAXES (Account 190)


/ /2014/Q4

Line No.

Description and Location Balance of Begining

(c)(b)(a)

Balance at Endof Year of Year

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.2. At Other (Specify), include deferrals relating to other income and deductions.

Electric 1

2

3

4

5

6

780,015,314 778,648,583Other 7

780,015,314 778,648,583TOTAL Electric (Enter Total of lines 2 thru 7) 8

Gas 9

10

11

12

13

14

Other 15

TOTAL Gas (Enter Total of lines 10 thru 15 16

Other (Specify) 17

780,015,314 778,648,583TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18

Notes


Schedule Page: 234 Line No.: 7 Column: b Balance at Balance at

Other Electric: Beginning of Year End of Year (a) (b) (c)

Above Market NUG Liability $ 26,257,577 $ 10,344,074 Accrued Taxes: FICA on Vacation Accrual 310,027 300,461 Accumulated Provision Injuries and Damage-General Liability 497,146 1,542,847 Accumulated Provision Injuries and Damage-Workers Compensation 1,614,985 1,614,943 Asset Retirement Obligation Liability 1,545,520 1,545,481 Asset Retirement Obligation Liability Decommissioning TMI2 Rad 0 40,349,441 Bad Debt Expense 2,369,539 2,127,262 Bond Issuance Expense 581,949 415,667 Charitable Contribution Carryforward 163,290 271,808 Company Debt - Issuance Discount 383,894 348,460 Current Liability: Acquisition of Property-MGP 34,137,528 35,266,778 Current Liability: Lease Expense Merrill Creek 9,330,618 9,321,882 Customer Advances for Construction Refundable 10,438,673 11,305,923 Customer Collection Nuclear Fuel Disposal Fee 35,142,221 35,782,224 Decommissioning ARO Liability: TMI2 Non Rad 744,905 0 Decommissioning ARO Liability: TMI2 Rad 51,368,664 0 Decommissioning Tax Exempt/Regulatory Liability 0 21,300,214 Decommissioning TMI2 21,663,231 0 Decommissioning TMI2 Non-Qualified Trust Tax Exempt Interest 36,982,074 0 Decommissioning TMI2 Non-Rad 2,445,729 3,484,057 Decommissioning TMI2 Non-Rad Salvage 7,325 7,325 Decommissioning TMI2 Rad 0 72,825,847 Decommissioning TMI2 Unrealized Gain-Loss 7,568,210 0 Deferred Compensation Expense 536,743 563,793 DOE SNF Unrealized Gain-Loss 331,528 1,028,230 DOE Spent Nuclear Fuel Disposal 6,629,076 4,166,459 DOE Spent Nuclear Fuel Disposal Interest - OC 52,063,044 52,091,692 DOE Spent Nuclear Fuel Disposal Interest Customer Funds 3,341,868 3,341,781 DOE Spent Nuclear Fuel Stranded Cost Amortization 707,410 0 EDCP OCI Offset 117,678 87,384 Environmental Liability 107,454 107,451 FAS 109 Federal Reclass 12 0 FAS 109 State Reclass 78 0 FAS 112 - Medical Benefit Accrual 4,579,409 4,579,289 FAS 123R - APIC 252,784 201,799 FAS 123R - Performance Shares 19,503 12,406 FAS 123R - Restricted Stock 71,239 0 FAS 123R - Restricted Stock Units 1,158,721 168,834 FAS 123R - Stock Options 21,382 0 FAS 133 - Hedging Transactions OCI 498,548 385,655 FAS 158 Pension OCI Offset 462,136 363,433 Federal Long Term - NOL 132,354,596 130,851,650 Federal Short Term - NOL 0 1,712,746 Gas Site Investigation and Cleanup-OC Spill 13,334 0 General Business Credit Carryforward 0 $401,376 GPU SERP Offset 736 0 GR&F Tax Audit 541,489 541,475 Incentive Compensation 0 1,623,415 Interest Accrued Customer Deposits 484 479 ITC FAS 109 1,686,586 1,595,907 JCP&L Arbitration 449,350 449,338 Long Term Disability Accrual 0 628,126 Merrill Creek Lease 781,298 703,771 Miscellaneous Current Liability 0 89,475

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


Miscellaneous Schedule M 0 4,301 NGC APB11 17,500,544 0 NGC MTC 12,111,007 0 NJ Corporate Business Tax 265,913 0 NJ Surcharge Non Depreciation State 559,654 0 NJ Universal Service Fund 6,855,087 5,793,886 NOL Deferred Tax Asset LT NJ 0 565,668 NOL Deferred Tax Asset NJ 24,245,343 13,573,988 NOL Deferred Tax Asset PA 8,770 0 Normalize Post 72 Taxes 12,086,175 0 Nuclear Fuel Stranded Cost Amortization 0 707,392 Ocean Peaking Power 666,816 666,798 Other Deferred Credit-NJCEP/Rider DSF Trans 0 168,376 Other Regulatory Asset CRA Future PC Spending 0 4,347,578 Oyster Creek Investment 817,000 816,979 Pension EDCP-SERP Payments 54,750 97,238 Pension/OPEB : Other Def Cr. or Dr. 0 70,548,425 Pensions and Benefits in Excess of Max 679,183 1,283,585 Pensions Expense 222,143,646 102,372,107 Post Retirement Benefits SFAS 106 Accrual 0 93,990,192 Purchase Power-Unbilled 18,530,517 19,961,825 Refinancing Costs 504,499 548,196 RGGI Recovery-Unbilled Deferral 52,018 53,928 Sale of Property - Tax Gain or (Loss) 859,455 859,433 SERP OCI Offset 15 19 Smart Grid Ruling 4,250 0 Tax Basis Step-Up 19,587 0 TMI2 Post Defueling Monitoring 2,705,451 2,753,917 Transition-Unbilled Deferred 739,871 238,168 Unamortized Gain on Reacquired Debt 401,529 97,856 Unbilled Distribution Deferrals 2,928,750 3,187,300 Universal Service Fund 0 0 Vacation Pay Accrual 3,629,162 3,527,501 Total Other (line 7 above) $ 778,648,583 $ 780,015,314

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

CAPITAL STOCKS (Account 201 and 204)


/ /2014/Q4

Line No.

Class and Series of Stock and Number of shares

(c)(b)(a)

Call Price at End of Year

Par or StatedValue per share

(d)

Name of Stock Series Authorized by Charter

1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separateseries of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reportingrequirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year andcompany title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.

10.00 16,000,000Common Stock (Account 201) 1

2

16,000,000 Total - Common Stock 3

4

Preferred Stock (Account 204) 5

6

15,600,000 Undesignated as to series 7

8

15,600,000 Total Preferred Stock 9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42


AS REACQUIRED STOCK (Account 217)




End of

CAPITAL STOCKS (Account 201 and 204) (Continued)


/ /2014/Q4

Line No.

OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT

IN SINKING AND OTHER FUNDS

Shares(g)

Cost(h)

Shares SharesAmount

(Total amount outstanding without reductionfor amounts held by respondent)

Amount(e) (f) (i) (j)

3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commissionwhich have not yet been issued.4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative ornon-cumulative.5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds whichis pledged, stating name of pledgee and purposes of pledge.

136,284,470 13,628,447 1

2

136,284,470 13,628,447 3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42






/ /2014/Q4

Line Item Amount(b)(a)

OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)

No.

Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide asubheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add morecolumns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting suchchange.(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise toamounts reported under this caption including identification with the class and series of stock to which related.(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at endof year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,disclose the general nature of the transactions which gave rise to the reported amounts.

Donations Received from Stockholders (Account 208) 1

2

Reductions in Par on Stated Value of Capital Stock (Account 209) 3

4

Gain on Resale or Cancellation of Reacquired Cap Stock (Account 210) 5

6

Miscellaneous Paid-in Capital (Account 211) 7

8

575,511 Balance at Beginning of Year 9

156,720 Performance and Discretionary Restricted Stock issued/payouts 10

2,493,914 ESOP Compensation 11

2,647 EDCP Compensation 12

-93,377 Restricted Stock Units - Excess Tax Loss SFAS 123 (R) 13

3,135,415 Subtotal - Balance at End of Year 14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39


40 TOTAL 3,135,415




End of

CAPITAL STOCK EXPENSE (Account 214)


/ /2014/Q4

Line No.

Class and Series of Stock Balance at End of Year(b)(a)

1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21


22 TOTAL




End of

LONG-TERM DEBT (Account 221, 222, 223 and 224)


/ /2014/Q4

Line No.

Class and Series of Obligation, Coupon Rate

(c)(b)(a)

Total expense, Premium or Discount

Principal AmountOf Debt issued(For new issue, give commission Authorization numbers and dates)

1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.2. In column (a), for new issues, give Commission authorization numbers and dates.3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designatedemand notes as such. Include in column (a) names of associated companies from which advances were received.5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates wereissued.6. In column (b) show the principal amount of bonds or other long-term debt originally issued.7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated withissues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than asspecified by the Uniform System of Accounts.

ACCOUNT 221 - BONDS 1

2

3

4

5

SUBTOTAL - ACCOUNT 221 6

7

ACCOUNT 222 - REACQUIRED BONDS 8

9

ACCOUNT 223 - ADVANCES FROM ASSOCIATED COMPANIES 10

11

ACCOUNT 224 - OTHER LONG TERM DEBT 12

2,268,861 300,000,0007.35% Senior Note 13

381,000 14 D

1,358,816 150,000,0004.80% Senior Note 15

1,149,000 16 D

2,414,720 300,000,0005.625% Senior Note 17

1,608,000 18 D

2,346,873 200,000,0006.40% Senior Note 19

1,216,000 20 D

358,552 250,000,0005.65% Senior Note 21

2,500,000 22 D

327,221 300,000,0006.15% Senior Note 23

3,693,000 24 D

4,207,350 500,000,0004.70% Senior Note 25

2,595,000 26 D

26,424,393 2,000,000,000SUBTOTAL - ACCOUNT 224 27

28

29

30

Note to Instruction 15 31

Note to Instruction 16 32


33 TOTAL 2,000,000,000 26,424,393




End of

LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)


/ /2014/Q4

Line No.Nominal Date

of IssueDate ofMaturity

AMORTIZATION PERIOD

Date From Date To

Outstanding(Total amount outstanding without

reduction for amounts held byrespondent)

Interest for YearAmount

(d) (e) (f) (g) (h) (i)

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premiumon Debt - Credit.12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-termadvances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaidduring year. Give Commission authorization numbers and dates.13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgeeand purpose of the pledge.14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end ofyear, describe such securities in a footnote.15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interestexpense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest onLong-Term Debt and Account 430, Interest on Debt to Associated Companies.16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.

1

2

3

4

5

6

7

8

9

10

11

12

300,000,000 22,050,00002/01/201901/27/200902/01/201901/27/2009 13

14

150,000,000 7,200,00006/15/201805/19/200306/15/201805/19/2003 15

16

300,000,000 16,875,00005/01/201604/20/200405/01/201604/20/2004 17

18

200,000,000 12,800,00005/15/203605/19/200605/15/203605/19/2006 19

20

250,000,000 14,125,0006/1/20175/21/20076/1/20175/21/2007 21

22

300,000,000 18,450,0006/1/20375/21/20076/1/20375/21/2007 23

24

500,000,000 23,500,0004/1/20248/21/20134/1/20248/21/2013 25

26

2,000,000,000 115,000,000 27

28

29

30

31

32


33 2,000,000,000 115,000,000

Schedule Page: 256 Line No.: 31 Column: aReconciliation of Column (i) to accounts 427 & 430

Account 427 Interest $115,231,551Account 430 Interest 6,633,871Total Interest in accounts 427 & 430 $121,865,422

Total interest Form 1 Page 257 Column (i) $115,000,000Other Interest - Treasury Lock Hedge 276,336Other Interest - EDCP/SERP loans (44,785)Interest on short term money pool borrowings 1,231,448Carrying Charges on SC00 Assets 5,402,423 $121,865,422

Schedule Page: 256 Line No.: 32 Column: aPursuant to BPU order at Docket #EF12111053 dated 2/20/2013, Jersey Central Power & Light received authorization to issueadditional long-term debt in the amount of $750,000,000. To date $500,000,000 has been issued, with authorization to issueadditional long-term debt in the amount of $250,000,000 remaining. Authorization expires 12/31/2015.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES


/ /2014/Q4

Particulars (Details)(b)(a)

Amount LineNo.

1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and showcomputation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return forthe year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if aseparate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of groupmember, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements ofthe above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.

87,123,615Net Income for the Year (Page 117) 1

2

3

Taxable Income Not Reported on Books 4

23,448,735 5

6

7

8

Deductions Recorded on Books Not Deducted for Return 9

602,461,809 10

11

12

13

Income Recorded on Books Not Included in Return 14

-2,216,332 15

16

17

18

Deductions on Return Not Charged Against Book Income 19

-511,732,974 20

21

22

23

24

25

26

199,084,853Federal Tax Net Income 27

Show Computation of Tax: 28

69,679,699Net Liability @ 35% 29

30

31

Basis of Allocation 32

See Footnote 33

34

35

36

37

38

39

40

41

42

43

44



TAXABLE INCOME NOT REPORTED ON BOOKS

AFUDC Equity - Incurred $ 395,309 CIAC - Incurred 18,301,928 DOE Spent Nuclear Fuel Disposal Interest - OC 73,455 Tax Capitalized Interest - Incurred 4,669,780 Universal Service Fund (Interest) 8,263

$ 23,448,735

Schedule Page: 261 Line No.: 10 Column: bDEDUCTIONS RECORDED ON BOOKS NOT DEDUCTED FOR RETURN

263A Mixed Service Costs $ 16,594,182 Accumulated Provision For Injured and Damage-General Liability 2,559,955 Bond Transition Collateral (Subs Books) 21,858,234 Bond Transition Property 8,917,172 Book Depreciation 143,924,541 Book Gain/Loss 197,553 Casualty Loss 481(a) 34,116,154 Cost of Removal Adjustment (Non-Repairs) 2,997,268 Current Liability: Acquisition of Property-MGP 2,665,000 Current Income Taxes 64,997,854 Customer Advances for Construction Refundable 2,123,734 Customer Collection Nuclear Fuel Disposal Fee 1,569,000 Decommissioning ARO Liability: TMI2 Non Rad 898,590 Decommissioning-FAS 143 Accretion- 29,694,375 Decommissioning TMI2 7,328,753 Deferred Compensation Expense 66,254 Deferred MTC Tax (Oyster Creek) 18,161,583 Deferred MTC Tax II 8,184,250 Demand Side Management Costs 831,259 DOE Spent Nuc Fuel Disposal 9,353 ESOP Dividends - Capitalized 894,113 FAS 123R - Performance Shares 16,115 FAS 123R - Restricted Stock Units - Incurred 57,630 FAS 133 - Mark to Market - Asset 107,676 FE Service Permanent M Allocation 260,972 FE Service Timing Allocation 183,719 Incentive Compensation 87,669 Life Insurance 309,665 Lobbying 106,365 Long Term Disability Accrual 1,537,680 Management Audit Fees 79,972 Meals and Entertainment - 50% Disallowance 89,295 Merrill Creek Lease Improvement 1,844 Miscellaneous Current Liability 219,038 NJ Universal Service Fund 801,073 Operating NUGS 38,824,312 Penalties 31,429 Pension EDCP-SERP Payments 210,643 Pension/OPEB : Other Deferred Credit or Debit 42,976,140 Pensions and Benefits in Excess of Max 82,647 Pensions Expense 133,178,500 Post Retirement Benefits SFAS 106 Accrual 8,147,438 Purchase Power-Unbilled 3,505,088 Refinancing Costs 107,004

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


RGGI Recovery-Unbilled Deferral 4,678 TMI2 Post Defueling Monitoring 118,819 Unamortized Loss on Reacquired Debt 2,084,324 Unbilled Distribution Deferrals 633,129 Universal Service Fund 761 Unrecovered Plant and Reg Study 109,007

$ 602,461,809


INCOME RECORDED ON BOOKS NOT INCLUDED IN RETURN

AFUDC Debt - Incurred $ (1,815,162)Equity Earnings (166)Interest on RRC Deferred (42,412)LT Capacity Agreement Interest (1,732)Manufactured Gas Plant - Interest (356,860)

$ (2,216,332)


DEDUCTIONS ON RETURN NOT CHARGED AGAINST BOOK INCOME

Above Market NUG Liability $ (38,955,284)Accrued Taxes: FICA on Vacation Accrual (23,401)Accrued Taxes: Tax Audit Reserves (77,112)Asset Removal Costs (235,289)Bad Debt Expense (592,954)Bond Issuance Expense (407,028)Capitalized Pensions - Incurred (103,446,627)Capitalized Vertical Tree Trimming (6,744,488)Casualty Loss (1,334,037)Company Debt - Issuance Discount (86,721)Cost of Removal (15,581,237)Current Liability: Lease Expense Merrill Creek (125,752)Decommissioning ARO Liability: TMI2 Rad (29,694,375)Decommissioning TMI2 Non-Qualified Investment (160,915)Decommissioning TMI2 Non-Rad (180,075)Decommissioning TMI2 Qualified Investment (7,886,353)Deferred Charge-EIB (91,006)Deferred Income Taxes (33,970,366)ESOP Dividends (1,517,190)FAS 123R - Performance Shares - Capitalized (9,497)FAS 123R - Restricted Stock Units (97,790)Gas Site Invest and Cleanup-OC Spill (91102) (32,641)Gas Site Investigation and Cleanup (17,737,105)Interest Due DOE Nuclear Waste OC (73,455)Interest Due DOE Nuclear Waste TMI (9,353)Investment Tax Credit (131,199)Life Insurance (525,460)Merrill Creek Lease (88,104)MTC Deferred Balance (36,592,739)NJ Universal Service Fund Arrears (764,668)NJBPU Rate Case Expenditure (214,360)Pension EDCP-SERP - Capitalized (124,137)Pension/OPEB - Capitalized (587,383)Post Retirement Benefits SFAS 106 Payments (7,079,327)RRC (Over)-Under Recovery (6,164,199)Smart Growth CIAC (1,044,764)State Taxes (2,054)

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


Storm Damage (1,636,293)Tax Basis Step Up Depreciation/Amortization (10,924)Tax Depreciation (134,956,329)Tax Gain/Loss (Includes Salvage) (6,396,905)Tax Repairs - Incurred (54,679,968)Transition-Unbilled Deferred (1,228,142)Unamortized Gain on Reacquired Debt (130,077)Vacation Pay Accrual (305,891)

$ (511,732,974)

Schedule Page: 261 Line No.: 33 Column: a

Basis of Allocation: Respondent is included in the consolidated Federal Income Tax Return filed by FirstEnergy Corp., which includes its wholly owned subsidiaries. Federal income tax liability is allocated on the basis of each member's United States Federal tax liability. The total Federal Income Tax liability of each member will be no more than if it were to file an individual tax return. This is in accordance with IRC Section 1552 and Treasury Regulation 1.1502-33(d)(3) and 1.1552-1(a)(2).

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR


/ /2014/Q4

Line No.

Kind of Tax(See instruction 5)

BALANCE AT BEGINNING OF YEARTaxes Accrued(Account 236)

Prepaid Taxes(Include in Account 165)

TaxesChargedDuringYear

TaxesPaid

DuringAdjust-ments

Year(a) (b) (c) (d) (e) (f)

1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts duringthe year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If theactual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts otherthan accrued and prepaid tax accounts.4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.

Federal: 1

14,150 11,650 2,500Federal Excise tax 2

8,970 8,970Heavy Highway Vehicle Use 3

63,852,533 -1,987,816 70,632,528 3,362,648Income Tax 4

5

10,076,532 10,053,131 758,942FICA 6

7

61,033 61,033Unemployment Insurance 8

9

74,013,218 -1,987,816 80,767,312 4,124,090SUBTOTAL: Federal 10

11

State: New Jersey 12

-4,183,629 15,284,508 -11,769,672 33,443,938NJ Corp. Business Tax 13

14

464,172 1,278,379 464,179NJ Trans Energy Fac Assess 15

16

6,209,767 7,172,966 6,000Local Real Estate 17

18

208,717 123,579 39,282NJ State Other/Sales and 19

20

587,263 587,263NJ Unemployment 21

22

3,286,290 15,284,508 -2,607,485 33,443,938 509,461SUBTOTAL: New Jersey 23

24

State: Pennsylvania 25

26

13,852Public Utility Realty 27

28

-8,065 -1,131 8,957PA Franchise Tax 29

30

-20,049 -504 19,746PA Corp. Net Income 31

32

245 245PA Unemployment Tax 33

34

-27,869 -1,390 42,555SUBTOTAL: Pennsylvania 35

36

37

38

39

40

33,486,493


TOTAL41 78,158,437 77,271,639 13,296,692 4,633,551




End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)


/ /2014/Q4

Line No.(Taxes accrued

BALANCE AT END OF YEARPrepaid Taxes Electric

(Account 408.1, 409.1)Extraordinary Items

(Account 409.3)Adjustments to Ret. OtherEarnings (Account 439)

(g) (h) (i) (j) (k) (l)Account 236) (Incl. in Account 165)

DISTRIBUTION OF TAXES CHARGED

5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,identifying the year in column (a).6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a footnote. Designate debit adjustmentsby parentheses.7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pendingtransmittal of such taxes to the taxing authority.8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments andamounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.

1

5,996 5,654 2

8,970 3

-9,722,541 80,355,069 8,154,827 4

5

37,384 10,015,747 735,541 6

7

-63 61,096 8

9

-9,670,254 90,437,566 8,890,368 10

11

12

5,192,453 -16,962,125 25,745,527 54 13

14

1,278,379 1,278,386 15

16

75,667 7,097,299 969,199 17

18

-71,140 194,719 77,112 31,257 19

20

21,172 566,091 21

22

5,218,152 -7,825,637 25,822,639 2,278,896 23

24

25

26

13,852 27

28

-1,131 2,023 29

30

-504 201 31

32

245 33

34

-1,390 16,076 35

36

37

38

39

40


41 25,838,715 82,610,539 -4,452,102 11,169,264

Schedule Page: 262 Line No.: 4 Column: fReverse 2013 FIN 48 and "Revenue Agent's Report" reclass. No "Revenue Agent's Report" Interest reclass for 2014.

Schedule Page: 262 Line No.: 4 Column: l$1,251,767 offset to Account 409.2 ; $1,048,039 offset to Account 146 ; ($10,502,025) offset to Account 234 ; $42,406 offset toAccount 211 ; ($1,553,386) offset to Account 207 ; ($9,342) offset to Account 409.1(NJ).

Schedule Page: 262 Line No.: 13 Column: fReverse 2013 NOL.

Schedule Page: 262 Line No.: 13 Column: l$353,647 offset to Account 409.2 ; $42,396 offset to Account 211 ; $4,829,471 offset to Account 253 ; ($33,061) offset to Account409.1 (Federal).

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)


/ /2014/Q4

Line No.

Account Balance at Beginning

(c)(b)(a)

of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's Income

Account No. Amount Account No. Amount(d) (e) (f) (g)

Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility andnonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)the average period over which the tax credits are amortized.

Electric Utility 1

3% 2

4% 2,442,143 411.4 131,199 3

7% 4

10% 5

6

7

TOTAL 2,442,143 131,199 8

Other (List separatelyand show 3%, 4%, 7%,10% and TOTAL)

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48


Balance at End

(i)(h)

of Year




End of

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)


/ /2014/Q4

Line No.

ADJUSTMENT EXPLANATIONAverage Periodof Allocation

to Income

1

2

2,310,944 17.6 3

4

5

6

7

2,310,944 8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48


Schedule Page: 266 Line No.: 3 Column: iInvestment Tax Credit - 4%

The Respondent is amortizing the previously created deferred credit by a ratable flow-through amount to income over the useful life ofthe property. On March 9, 1972, General Public Utilities Corporation (former parent company of respondent) filed with the DistrictDirector of Internal Revenue, Manhattan District, on behalf of its affiliated companies (the Respondent being one of the affiliates), anelection under paragraph (2) of Section 46(e) of the Internal Revenue Code of 1954, as amended, for allowance, with respect to publicutility property, of the credit allowed by Section 38 of the code. Such an election provides (a) to reduce the cost of service forratemaking purposes or in its regulated books of account by no more than ratable portion of the credit allowable by Section 38, and (b)not to reduce the base to which its rate of return is applied for ratemaking purposes by any portion of the credit allowable by Section38.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

OTHER DEFFERED CREDITS (Account 253)


/ /2014/Q4

Line No.

Description and Other DEBITS Credits

Account(c)(b)(a)


(d)

Deferred Credits Amount

(e)

Balance at Beginning of Year Contra

(f)

1. Report below the particulars (details) called for concerning other deferred credits.

2. For any deferred credit being amortized, show the period of amortization.

3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.

6,622,891TMI-2 PDMS Costs 6,741,711 118,820Various 1

2

5,019,239Accrued Site Cleanup Reserve 5,501,239 482,000Various 3

4

Mfg Gas Plant Site Investigation & 5

81,903,000 Cleanup 84,568,000 2,665,000Various 6

7

19,781,480Acc'd Lease Exp. Merrill Creek 19,666,410 115,070242 8

9

Ocean Peaking Power 10

1,632,352(Amort. through 2028) 1,568,706 63,646415 11

12

Contributions in Aid 13

-2,387,653to Construction 2,215,913 4,603,566Various 14

15

197,131,812Nuclear Fuel Disposal 197,214,620 82,808Various 16

17

2,103,929Gain on Sale of Assets 2,103,929 18

19

412,191DSF Transition Period Interest 412,191 20

21

2,975Proceeds for Forked River Sale 2,975 22

23

TEC Surcharge Liability 24

25

263,045Environmental Liability 263,045 26

27

Affiliated Company Pension and 28

85,198,893OPEB Valuation Adjustment 172,705,666 87,506,773Various 29

30

3,145,377Other Deferred Credits - Long TerJ 3,145,377 31

32

-279,847Minor Items 3,343,764 3,623,611 33

34

35

36

37

38

39

40

41

42

43

44

45

46


47 TOTAL 99,082,578 3,324,093 496,308,169 400,549,684




End of

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)


/ /2014/Q4

Line No.

Account

(a) (b) (c) (d)

Balance atBeginning of Year

CHANGES DURING YEAR

Amounts Debited Amounts Credited to Account 410.1 to Account 411.1

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizableproperty.2. For other (Specify),include deferrals relating to other income and deductions.

1 Accelerated Amortization (Account 281)

2 Electric

3 Defense Facilities

4 Pollution Control Facilities


6

7

8 TOTAL Electric (Enter Total of lines 3 thru 7)

9 Gas

10 Defense Facilities

11 Pollution Control Facilities


13

14

15 TOTAL Gas (Enter Total of lines 10 thru 14)

16

17 TOTAL (Acct 281) (Total of 8, 15 and 16)

18 Classification of TOTAL

19 Federal Income Tax

20 State Income Tax

21 Local Income Tax


NOTES




End of

ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)


/ /2014/Q4

Line No.

CHANGES DURING YEAR ADJUSTMENTSBalance at

End of YearDebits CreditsAmounts Debited

to Account 410.2Amounts Credited to Account 411.2 Account

CreditedAmount

DebitedAccount Amount

(e) (f) (h) (j) (k)(g) (i)

3. Use footnotes as required.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21


NOTES (Continued)




End of

ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)


/ /2014/Q4

Line No.

Account

(a) (b) (c) (d)


CHANGES DURING YEAR

Amounts Debited Amounts Credited to Account 410.1 to Account 411.1

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property notsubject to accelerated amortization2. For other (Specify),include deferrals relating to other income and deductions.

Account 282 1

Electric 1,147,796,894 52,803,225 19,999,011 2

Gas 3

4

TOTAL (Enter Total of lines 2 thru 4) 1,147,796,894 52,803,225 19,999,011 5

6

7

8

TOTAL Account 282 (Enter Total of lines 5 thru 1,147,796,894 52,803,225 19,999,011 9

Classification of TOTAL 10

Federal Income Tax 1,017,868,049 39,212,218 15,592,864 11

State Income Tax 129,928,845 13,591,007 4,406,147 12

Local Income Tax 13


NOTES




End of

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)


/ /2014/Q4

Line No.




CreditedAmount


(e) (f) (h) (j) (k)(g) (i)

3. Use footnotes as required.

1

Various 1,179,615,690 1,653,754Various 668,336 2

3

4

1,179,615,690 1,653,754 668,336 5

6

7

8

1,179,615,690 1,653,754 668,336 9

10

1,040,719,090 1,289,402 521,089 11

138,896,600 364,352 147,247 12

13


NOTES (Continued)

Schedule Page: 274 Line No.: 2 Column: h

DebitsAccount DebitCredited Amount

(g) Description (h)

283 Vegetation Management $ 1,437,380 182 FAS109 Regulatory Asset 216,374

$ 1,653,754

Schedule Page: 274 Line No.: 2 Column: j

CreditsAccount CreditDebited Amount

(i) Description (j)

146 Intercompany $ 21 182 FAS109 Regulatory Asset 668,315

$ 668,336

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)


/ /2014/Q4

Line No.

Account

(a) (b) (c) (d)


CHANGES DURING YEARAmounts Debited Amounts Credited to Account 410.1 to Account 411.1

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amountsrecorded in Account 283.2. For other (Specify),include deferrals relating to other income and deductions.

Account 283 1

Electric 2

3

4

5

6

7

419,384,187 281,413,160 812,215,945 8

419,384,187 281,413,160 812,215,945TOTAL Electric (Total of lines 3 thru 8) 9

Gas 10

11

12

13

14

15

16

TOTAL Gas (Total of lines 11 thru 16) 17

18

419,384,187 281,413,160 812,215,945TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19

Classification of TOTAL 20

345,666,285 230,083,545 714,755,378Federal Income Tax 21

73,717,902 51,329,615 97,460,567State Income Tax 22

Local Income Tax 23


NOTES




End of

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)


/ /2014/Q4

Line No.




CreditedAmount


(e) (f) (h) (j) (k)(g) (i)

3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.4. Use footnotes as required.

1

2

3

4

5

6

7

664,561,428 103,964,605VariousVarious 3,635 260 113,644,720 8

664,561,428 103,964,605 3,635 260 113,644,720 9

10

11

12

13

14

15

16

17

18

664,561,428 103,964,605 3,635 260 113,644,720 19

20

592,098,122 83,085,790 2,891 260 90,157,675 21

72,463,306 20,878,815 744 23,487,045 22

23


NOTES (Continued)

Schedule Page: 276 Line No.: 8 Column: b Balance at Amounts Amounts Amounts Amounts Beginning Debited to Credited to Debited to Credited to Acct Debits Acct Credits Balance at

Account Subdivisions of Year Acct 410.1 Acct 411.1 Acct 410.2 Acct 411.2 Credit Amount Debit Amount End of Year (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

Accounts Receivable - Deferred Revenue 0 154,021 11,032 0 0 0 0 142,989 Accrued Taxes: Tax Audit Reserves 0 0 0 0 0 190 2,428 190 33,928 31,500 Asset Removal Costs 1,375,160 52,879,387 54,254,547 0 0 0 0 0 Bond Transition Collateral 33,927,266 688,885 9,618,625 0 0 0 0 24,997,526 Bond Transition Property 38,757,265 281,384 3,924,964 0 0 0 0 35,113,685 Capital Loss Carryover 42,730 5,135 0 0 0 0 0 47,865 Decommissioning FAS 143 Accretion 0 61,064,155 20,714,714 0 0 0 0 40,349,441 Decommissioning Tax Exempt Offset 0 13,570,702 971,398 0 0 0 0 12,599,304 Decommissioning TMI2 Non-Qualified Investment 0 5,068 70,800 0 0 190 5,068 190 70,800 0 Decommissioning TMI2 Non-Qualified Tax Exempt Interest 0 426,804 5,962,573 0 0 190 426,804 190 5,962,573 0 Decommissioning TMI2 Qualified Investment 66,569,508 8,851,495 75,421,003 0 0 0 0 0 Decommissioning TMI2 Qualified Principal 14,880,452 1,147,452 16,027,904 0 0 0 0 0 Decommissioning TMI2 Rad 16,717 2,747 68,536,653 0 0 190 5,282,632 190 73,799,821 0 Decommissioning TMI2 Radiological 0 18,006 1,289 0 0 0 0 16,717 Decommissioning Trust - Contribution Deduction 12,850,096 0 12,850,096 0 0 0 0 0 Decommissioning Trust - Pour Over Deduction 29,667,722 0 29,667,722 0 0 0 0 0 Decommissioning Qualified Plan 0 74,408,415 5,326,195 0 0 0 0 69,082,220 Decommissioning Unrealized Gain-Loss 7,568,211 2,715,043 1,591,764 0 0 0 0 8,691,490 Deferred Charge-EIB 110,271 40,043 2,870 0 0 0 0 147,444 Deferred MTC Tax (Oyster Creek) 24,071,553 572,323 7,991,764 0 0 0 0 16,652,112 Deferred MTC Tax II 30,477,270 258,184 3,602,158 0 0 0 0 27,133,296 Demand Side Management Costs 6,743,311 5,966,821 1,958,979 0 0 0 0 10,751,153 Divestiture Activities Generation 1,395,805 19 56 0 0 0 0 1,395,768 DOE SNF Unrealized Gain/Loss - Special Deposit 331,529 0 331,529 0 0 0 0 0 DOE Spent Nuclear Fuel Disposal 2,466,328 0 0 0 0 190 2,466,328 0 0 FAS 123R - Restricted Stock 61,356 0 0 0 0 190 61,356 0 0 FAS 123R - Restricted Stock Units 702,007 0 0 0 0 190 702,007 0 0 FAS 123R - Stock Options 302,280 4 10 0 0 190/146 343,420 190/146 293,924 252,778 FAS 133 - Mark to Market - Asset 43,986 3,392 47,378 0 0 0 0 0 FAS 158 OPEB OCI Offset 14,269,775 0 0 0 0 190 14,269,775 190 5,628,534 5,628,534 FE Service RSU 162(m) Val. Allow Allocation 757,170 99,475 280,568 0 0 0 0 576,077 FE Service Tax Interest Allocation 10,492 0 0 0 0 0 0 10,492 FE Service Timing Allocation 13,614,425 370,248 5,170,340 0 0 0 0 8,814,333 Gas Site Investigation and Cleanup 50,405,656 7,804,742 625,742 0 0 0 0 57,584,656 Incentive Compensation 210,549 1,922,367 3,756,331 0 0 190 125,164 190 1,748,579 0 Income from U.S. Partnerships 0 3,043 218 0 0 0 0 2,825 Interest Due DOE Nuclear Waste OC 52,063,042 33,049 4,401 0 0 0 0 52,091,690 Interest Due DOE Nuclear Waste TMI 6,629,075 4,208 560 0 0 0 0 6,632,723 Interest on RRC Deferred 22,216 18,661 1,337 0 0 0 0 39,540 Inventory: Reserve for Obsolescence 761,456 386,893 27,742 0 0 0 0 1,120,607 LT Capacity Agreement Interest 1,550 762 54 0 0 0 0 2,258 LT Capacity Agreement Pilot 115,188 1 5 0 0 0 0 115,184 LT Overcollateralization Rec 504,498 7 20 0 0 0 0 504,485 Management Audit Fees 32,669 2,519 35,188 0 0 0 0 0 Manufactured Gas Plant - Interest 504,248 343,743 197,983 0 0 0 0 650,008 Merrill Creek Lease Imp 8,152 123 877 0 0 0 0 7,398 MTC Balance Reclass 27,304,926 0 27,304,926 0 0 0 0 0 MTC Deferred Balance 23,556,554 16,100,336 15,377,255 0 0 0 0 24,279,635 NJ Surcharge-Non Depreciation-Federal 195,879 0 195,879 0 0 0 0 0 NJ Universal Service Fund Arrears 4,958,145 450,811 32,469 0 0 0 0 5,376,487 NJBPU Rate Case Expenditure 776,001 103,987 16,444 0 0 0 0 863,544 OPEB Adjustment - Health Reform Act 2,793,732 0 0 0 0 146 3,009,160 146 215,428 0 Operating NUGS 25,938,752 1,223,107 17,083,101 0 0 0 0 10,078,758 Other Regulatory Liability - Asset Removal Costs 0 1,624,579 116,288 0 0 0 0 1,508,291 Pension EDCP-SERP Payments 0 695,745 223,168 0 0 190/146 617,029 190/146 144,452 0 Pensions Expense 85,438,697 0 0 0 0 190 85,438,697 0 0 Post Retirement Benefits SFAS 106 Payments 23,532,417 3,115,281 224,366 0 0 146 893,644 146 12,482,645 38,012,333 Property ADIT Fas109 GU State 0 0 0 0 0 0 182 461,550 461,550 RAC Deferral 0 65,106 3 0 0 0 0 65,103 Reverse Capital Gain 1,028 0 1,028 0 0 0 0 0 RRC (Over)-Under Recovery 5,308,734 2,722,586 204,715 0 0 0 0 7,826,605 SFAS 109 Property 631,214 0 631,214 0 0 0 0 0 Smart Growth CIAC 2,638,659 459,716 33,010 0 0 0 0 3,065,365 Special Deposit: SNF Unreal Gain(Loss) 0 1,490,229 461,999 0 0 0 0 1,028,230 Spent Fuel Disposal Interest 19,369,899 272 777 0 0 0 0 19,369,394 State Income Tax - Fed Deferred Only 16,503,361 0 16,503,361 0 0 0 0 0 State Income Tax - RAR - Federal 878,603 0 878,603 0 0 0 190 1,684,094 1,684,094 State Income Tax Deductible 0 18,520,820 10,085,227 0 0 0 0 8,435,593 Storm Damage 151,336,039 722,065 57,602 0 0 0 0 152,000,502 Unamortized Loss on Reacquired Debt 6,382,174 65,734 917,325 0 0 0 0 5,530,583 Universal Service Fund 1,144 0 0 0 0 190 1,208 190 897 833 Universal Service Fund (Interest) 9,759 0 0 260 3,635 0 0 6,384 Unrecovered Plant and Regulatory Study 1,908,077 3,460 48,038 0 0 0 0 1,863,499 Vegetation Management 481,167 0 0 0 0 0 282 1,437,380 1,918,547

812,215,945 281,413,160 419,384,187 260 3,635 113,644,720 103,964,605 664,561,428

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

OTHER REGULATORY LIABILITIES (Account 254)


/ /2014/Q4

Line No.

Description and Purpose of DEBITS

CreditsAccount

(d)(c)(a)

Balance at Endof Current

Quarter/Year

(e)

Other Regulatory Liabilities Amount

(f)Credited

1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be groupedby classes.3. For Regulatory Liabilities being amortized, show period of amortization.

Balance at Beginingof Current

Quarter/Year

(b)

Non-utility Generation Charge: 1

26,241,655 26,241,655 MTC Deferred Balance - effective 8/2003 various 2

3

1,235,003 1,342,007 107,004 OC Securitization Overcollateralization 4

5

55,780,221 66,119,296 10,339,075DOE Spent Nuclear Fuel High Level Waste Disposal 6

7

811,575 2,517,152 1,705,577Spent Nuclear Fuel Unrealized Gains 8

9

1,686,565 90,679 1,595,886FAS 109 - Accounting for Income Taxes various 10

11

1,325,554 1,325,554Gross Receipts and Franchise Tax Audit 12

13

TMI-2 Decommissioning 14

45,161,734 82,184,862 37,023,128 Radiological 15

6,005,028 180,074 5,824,954 Non-Radiological various 16

18,526,831 21,277,153 2,750,322 Unrealized Gain / Loss 17

18

21,300,214 21,300,214Customer Payable for Future Income Taxes 19

20

Unbilled Revenue: 21

45,362,342 48,867,429 3,505,087 Purchase Power Deferral 22

1,811,188 1,228,143 583,045 Transition Deferral 407.4 23

127,340 132,018 4,678 Regional Greenhouse Gas Initiative Deferral 24

7,169,522 7,802,652 633,130 Distribution Unbilled Deferrals 25

26

5,540,615 1,044,764 4,495,851Smart Growth Refund various 27

28

958,716 1,004,144 45,428Universal Services Fund Rider 29

30

31

32

33

34

35

36

37

38

39

40

FERC FORM NO. 1/3-Q (REV 02-04) Page 278

41 TOTAL 77,413,643 28,785,315 266,372,217 217,743,889




End of

ELECTRIC OPERATING REVENUES (Account 400)


/ /2014/Q4

Line No.

Title of Account

(c)(b)(a)

Operating Revenues Yearto Date Quarterly/Annual

1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWHrelated to unbilled revenues need not be reported separately as required in the annual version of these pages.2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are addedfor billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close ofeach month.4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.

Operating RevenuesPrevious year (no Quarterly)

Sales of Electricity 1

1,134,327,973(440) Residential Sales 1,071,702,218 2

(442) Commercial and Industrial Sales 3

534,270,572Small (or Comm.) (See Instr. 4) 541,209,316 4

79,715,499Large (or Ind.) (See Instr. 4) 81,158,048 5

18,696,290(444) Public Street and Highway Lighting 17,823,745 6

-51,551,000(445) Other Sales to Public Authorities -48,146,422 7

(446) Sales to Railroads and Railways 8

(448) Interdepartmental Sales 9

1,715,459,334TOTAL Sales to Ultimate Consumers 1,663,746,905 10

87,047,920(447) Sales for Resale 112,884,944 11

1,802,507,254TOTAL Sales of Electricity 1,776,631,849 12

(Less) (449.1) Provision for Rate Refunds 13

1,802,507,254TOTAL Revenues Net of Prov. for Refunds 1,776,631,849 14

Other Operating Revenues 15

2,334,970(450) Forfeited Discounts 2,416,092 16

4,650,558(451) Miscellaneous Service Revenues 4,295,733 17

(453) Sales of Water and Water Power 18

8,405,943(454) Rent from Electric Property 8,750,892 19

(455) Interdepartmental Rents 20

2,848,206(456) Other Electric Revenues 2,767,572 21

47,504,742(456.1) Revenues from Transmission of Electricity of Others 50,869,618 22

(457.1) Regional Control Service Revenues 23

(457.2) Miscellaneous Revenues 24

25

65,744,419TOTAL Other Operating Revenues 69,099,907 26

1,868,251,673TOTAL Electric Operating Revenues 1,845,731,756 27

Page 300FERC FORM NO. 1/3-Q (REV. 12-05)




End of

ELECTRIC OPERATING REVENUES (Account 400)


/ /2014/Q4

Line No.

MEGAWATT HOURS SOLD

Previous Year (no Quarterly)Current Year (no Quarterly)

AVG.NO. CUSTOMERS PER MONTH

Year to Date Quarterly/Annual Amount Previous year (no Quarterly)

(d) (e) (f) (g)

6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by therespondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classificationin a footnote.)7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.9. Include unmetered sales. Provide details of such Sales in a footnote.

1

9,460,482 969,980 972,485 9,335,762 2

3

9,024,931 122,815 124,019 9,095,196 4

2,320,810 2,415 2,383 2,294,616 5

87,135 1,740 1,743 87,312 6

7

8

9

20,893,358 1,096,950 1,100,630 20,812,886 10

943,448 1,033,372 11

21,836,806 1,096,950 1,100,630 21,846,258 12

13

21,836,806 1,096,950 1,100,630 21,846,258 14

Page 301

Line 12, column (b) includes $ of unbilled revenues.

Line 12, column (d) includes MWH relating to unbilled revenues

4,717,182

63,034

FERC FORM NO. 1/3-Q (REV. 12-05)

Schedule Page: 300 Line No.: 7 Column: bThese revenues include an adjustment for Jersey Central Power & Light Company Transition Funding revenues which are included inthe customer revenue lines (Lines 2-6) above.

Schedule Page: 300 Line No.: 7 Column: cThese revenues include an adjustment for Jersey Central Power & Light Company Transition Funding revenues which are included inthe customer revenue lines (Lines 2-6) above.

Schedule Page: 300 Line No.: 17 Column: bThe dollars represent the following:

Disconnect/Reconnect Charges $ 738,346Facilities Maintenance Charges 326,882 Field Collection Charges 1,455,417Forfeited Discounts Older Than 10 Years 259,396 Service Charges 1,725,279Temporary Service Charges (882,784)Other - Numerous Items under $250,000 each 673,197Total $ 4,295,733

Schedule Page: 300 Line No.: 17 Column: cThe dollars represent the following:

Disconnect/Reconnect Charges $ 722,042Facilities Maintenance Charges 373,701 Field Collection Charges 1,492,992Forfeited Discounts Older Than 10 Years 407,310 Service Charges 1,670,298Temporary Service Charges (276,970)Other - Numerous Items under $250,000 each 261,185Total $ 4,650,558

Schedule Page: 300 Line No.: 21 Column: bThe dollars represent the following:

System Control and Dispatch Services $ 2,281,626Consumer Electronics Protection Service 387,761 Other - Numerous Items under $250,000 each 98,185Total $ 2,767,572

Schedule Page: 300 Line No.: 21 Column: cThe dollars represent the following:

System Control and Dispatch Services $ 2,300,172Consumer Electronics Protection Service 416,467 Other - Numerous Items under $250,000 each 131,567Total $ 2,848,206

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA






/ /2014/Q4

Line No. Description of Service

(a)

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)

1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration,etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.

Balance at End of

(c)(b)

Balance at End ofQuarter 1 Quarter 2

Balance at End ofQuarter 3

(d) (e)

Balance at End ofYear

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302

46 TOTAL




End of

SALES OF ELECTRICITY BY RATE SCHEDULES


/ /2014/Q4

Line No.

Number and Title of Rate schedule MWh Sold

(b)(a)

Revenue

(c)

Average Numberof Customers

(d)

KWh of SalesPer Customer

(e)

Revenue PerKWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh percustomer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under eachapplicable revenue account subheading.3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residentialschedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reportedcustomers.4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12if all billings are made monthly).5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

1

2 RESIDENTIAL SALES

9,048,735 953,313 9,492 0.1126 1,019,136,416 3 Rate RS

253,966 18,387 13,812 0.1083 27,516,317 4 Rate RT

17,125 581 29,475 0.1017 1,741,718 5 Rate RGT

1,263 107 11,804 0.1857 234,537 6 Rate OL

232 97 2,392 0.1683 39,047 7 Other

9,321,321 972,485 9,585 0.1125 1,048,668,035 8 Subtotal Residential Sales

9

14,441 0.0995 1,437,566 10 Unbilled

9,335,762 972,485 9,600 0.1125 1,050,105,601 11 TOTAL RESIDENTIAL SALES

12

13

14 COMMERCIAL SALES

6,445,314 122,405 52,656 0.0652 419,994,653 15 Rate GS

570,539 186 3,067,414 0.0383 21,845,655 16 Rate GST

1,131,623 270 4,191,196 0.0407 46,025,235 17 Rate GP

889,586 71 12,529,380 0.0265 23,543,032 18 Rate GT

24,386 906 26,916 0.2125 5,182,997 19 Rate OL

2,529 181 13,972 0.3010 761,161 20 Other

9,063,977 124,019 73,085 0.0571 517,352,733 21 Subtotal Commercial Sales

22

31,219 0.0901 2,813,296 23 Unbilled

9,095,196 124,019 73,337 0.0572 520,166,029 24 TOTAL COMMERCIAL SALES

25

26

27 INDUSTRIAL SALES

352,891 2,120 166,458 0.0606 21,398,748 28 Rate GS

86,672 24 3,611,333 0.0396 3,428,208 29 Rate GST

663,805 140 4,741,464 0.0334 22,198,405 30 Rate GP

1,190,983 84 14,178,369 0.0239 28,522,301 31 Rate GT

685 14 48,929 0.2136 146,318 32 Rate OL

-18,330 1 -18,330,000 0.0192 -351,990 33 Other

2,276,706 2,383 955,395 0.0331 75,341,990 34 Subtotal Industrial Sales

35

17,910 0.0286 511,681 36 Unbilled

2,294,616 2,383 962,911 0.0331 75,853,671 37 TOTAL INDUSTRIAL SALES

38

39

40

20,812,886 1,663,746,905 1,100,630 18,910 0.0799

63,034 4,717,182 0 0 0.0748 20,749,852 1,659,029,723 1,100,630 18,853 0.0800


41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)43 TOTAL




End of

SALES OF ELECTRICITY BY RATE SCHEDULES


/ /2014/Q4

Line No.

Number and Title of Rate schedule MWh Sold

(b)(a)

Revenue

(c)

Average Numberof Customers

(d)

KWh of SalesPer Customer

(e)

Revenue PerKWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh percustomer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under eachapplicable revenue account subheading.3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residentialschedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reportedcustomers.4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12if all billings are made monthly).5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

1

2 PUBLIC ST. & HIGHWAY LIGHTING

4,931 129 38,225 0.1107 545,615 3 Rate ISL

22,750 294 77,381 0.1657 3,769,470 4 Rate MVL

60,167 1,309 45,964 0.2215 13,325,189 5 Rate SVL

11 26,691 6 Other

87,848 1,743 50,400 0.2011 17,666,965 7 Subtotal St. & Highway Lighting

8

-536 0.0846 -45,361 9 Unbilled - Accounting Period

87,312 1,743 50,093 0.2018 17,621,604 10 TOTAL ST. & HIGHWAY LIGHTING

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

20,812,886 1,663,746,905 1,100,630 18,910 0.0799

63,034 4,717,182 0 0 0.0748 20,749,852 1,659,029,723 1,100,630 18,853 0.0800


41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)43 TOTAL




End of

SALES FOR RESALE (Account 447)


/ /2014/Q4

Line No.

Name of Company or Public Authority

(c)(b)(a)

FERC RateMonthly Billing

Average

(d)

Statistical

cationClassifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)Average Average

Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other thanpower exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and creditsfor energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on thePurchased Power schedule (Page 326-327).2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote anyownership interest or affiliation the respondent has with the purchaser.3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., thesupplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service mustbe the same as, or second only to, the supplier's service to its own ultimate consumers.LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economicreasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energyfrom third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets thedefinition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as theearliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Lessthan five years.SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service isone year or less.LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability ofservice, aside from transmission constraints, must match the availability and reliability of designated unit.IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" meansLonger than one year but Less than five years.

PJM Power Agreement NANANAOS 1

2

Solar Renewable Energy Credits NANANAOS 3

4

5

6

7

8

9

10

11

12

13

14


0

0

0

Subtotal RQ

Subtotal non-RQ

Total

0 0

0

0

0

0




End of

SALES FOR RESALE (Account 447) (Continued)


/ /2014/Q4

Line No.

MegaWatt Hours

(i)(h)(g) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)Total ($)

REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof the service in a footnote.AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. Provide an explanation in a footnote for each adjustment.4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs underwhich service, as identified in column (b), is provided.6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter theaverage monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP)demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximummetered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteintegration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.Footnote any demand not stated on a megawatt basis and explain.7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, includingout-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)the total charge shown on bills rendered to the purchaser.9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled onthe Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page401,iine 24.10. Footnote entries as required and provide explanations following all required data.

75,607,450 28,715,392 104,322,842 1,033,372 1

2

8,562,102 8,562,102 3

4

5

6

7

8

9

10

11

12

13

14


0

75,607,450

75,607,450

0

1,033,372

1,033,372

0 0

37,277,494

37,277,494

112,884,944

112,884,944

0

0

0

Schedule Page: 310 Line No.: 1 Column: aRepresents power sold through the PJM Interconnection.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


ELECTRIC OPERATION AND MAINTENANCE EXPENSES





/ /2014/Q4

Line No.

Account Amount for

(c)(b)(a)Current Year Previous Year

Amount forIf the amount for previous year is not derived from previously reported figures, explain in footnote.

1. POWER PRODUCTION EXPENSES 1A. Steam Power Generation 2Operation 3(500) Operation Supervision and Engineering 4(501) Fuel 5(502) Steam Expenses 6(503) Steam from Other Sources 7(Less) (504) Steam Transferred-Cr. 8(505) Electric Expenses 9(506) Miscellaneous Steam Power Expenses 10(507) Rents 11(509) Allowances 12 -3,904TOTAL Operation (Enter Total of Lines 4 thru 12) 13 -3,904Maintenance 14(510) Maintenance Supervision and Engineering 15(511) Maintenance of Structures 16(512) Maintenance of Boiler Plant 17(513) Maintenance of Electric Plant 18(514) Maintenance of Miscellaneous Steam Plant 19TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 -3,904B. Nuclear Power Generation 22Operation 23(517) Operation Supervision and Engineering 24(518) Fuel 25 1,569,000 1,569,000(519) Coolants and Water 26(520) Steam Expenses 27(521) Steam from Other Sources 28(Less) (522) Steam Transferred-Cr. 29(523) Electric Expenses 30(524) Miscellaneous Nuclear Power Expenses 31(525) Rents 32TOTAL Operation (Enter Total of lines 24 thru 32) 33 1,569,000 1,569,000Maintenance 34(528) Maintenance Supervision and Engineering 35(529) Maintenance of Structures 36(530) Maintenance of Reactor Plant Equipment 37(531) Maintenance of Electric Plant 38(532) Maintenance of Miscellaneous Nuclear Plant 39TOTAL Maintenance (Enter Total of lines 35 thru 39) 40TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41 1,569,000 1,569,000C. Hydraulic Power Generation 42Operation 43(535) Operation Supervision and Engineering 44 820 10,715(536) Water for Power 45(537) Hydraulic Expenses 46(538) Electric Expenses 47(539) Miscellaneous Hydraulic Power Generation Expenses 48 412,962 436,362(540) Rents 49TOTAL Operation (Enter Total of Lines 44 thru 49) 50 413,782 447,077C. Hydraulic Power Generation (Continued) 51Maintenance 52(541) Mainentance Supervision and Engineering 53 60,679 62,537(542) Maintenance of Structures 54 17,147 19,390(543) Maintenance of Reservoirs, Dams, and Waterways 55 528,824 303,275(544) Maintenance of Electric Plant 56 210,964 623,677(545) Maintenance of Miscellaneous Hydraulic Plant 57 289,458 111,523TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 1,107,072 1,120,402TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 1,520,854 1,567,479


ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)





/ /2014/Q4

Line No.

Account Amount for



D. Other Power Generation 60Operation 61(546) Operation Supervision and Engineering 62(547) Fuel 63(548) Generation Expenses 64(549) Miscellaneous Other Power Generation Expenses 65 111 211(550) Rents 66TOTAL Operation (Enter Total of lines 62 thru 66) 67 111 211Maintenance 68(551) Maintenance Supervision and Engineering 69(552) Maintenance of Structures 70(553) Maintenance of Generating and Electric Plant 71(554) Maintenance of Miscellaneous Other Power Generation Plant 72TOTAL Maintenance (Enter Total of lines 69 thru 72) 73TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 111 211E. Other Power Supply Expenses 75(555) Purchased Power 76 1,046,277,723 1,032,926,473(556) System Control and Load Dispatching 77(557) Other Expenses 78 -46,131,248 -29,104,410TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 1,000,146,475 1,003,822,063TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 1,003,232,536 1,006,958,7532. TRANSMISSION EXPENSES 81Operation 82(560) Operation Supervision and Engineering 83 26,745 51,548

84(561.1) Load Dispatch-Reliability 85 1,301,180 1,078,923(561.2) Load Dispatch-Monitor and Operate Transmission System 86(561.3) Load Dispatch-Transmission Service and Scheduling 87(561.4) Scheduling, System Control and Dispatch Services 88 42,128 204,760(561.5) Reliability, Planning and Standards Development 89 30,752(561.6) Transmission Service Studies 90 19,617 41,808(561.7) Generation Interconnection Studies 91 256,536 -315,438(561.8) Reliability, Planning and Standards Development Services 92 25,016 23,278(562) Station Expenses 93 11,825 16,265(563) Overhead Lines Expenses 94 390,329 411,278(564) Underground Lines Expenses 95(565) Transmission of Electricity by Others 96 1,014,012 1,034,251(566) Miscellaneous Transmission Expenses 97 918,438 1,648,723(567) Rents 98 9,168,147 10,125,016TOTAL Operation (Enter Total of lines 83 thru 98) 99 13,173,973 14,351,164Maintenance 100(568) Maintenance Supervision and Engineering 101 1,332,011 2,302,134(569) Maintenance of Structures 102(569.1) Maintenance of Computer Hardware 103 25,201 20,581(569.2) Maintenance of Computer Software 104 162,331 135,608(569.3) Maintenance of Communication Equipment 105 382,911 366,687(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106(570) Maintenance of Station Equipment 107 3,017,484 3,784,072(571) Maintenance of Overhead Lines 108 3,487,130 7,750,832(572) Maintenance of Underground Lines 109 5,831 2,168(573) Maintenance of Miscellaneous Transmission Plant 110 285,644 229,257TOTAL Maintenance (Total of lines 101 thru 110) 111 8,698,543 14,591,339TOTAL Transmission Expenses (Total of lines 99 and 111) 112 21,872,516 28,942,503







/ /2014/Q4

Line No.

Account Amount for



3. REGIONAL MARKET EXPENSES 113Operation 114(575.1) Operation Supervision 115(575.2) Day-Ahead and Real-Time Market Facilitation 116(575.3) Transmission Rights Market Facilitation 117(575.4) Capacity Market Facilitation 118(575.5) Ancillary Services Market Facilitation 119(575.6) Market Monitoring and Compliance 120(575.7) Market Facilitation, Monitoring and Compliance Services 121 29,057 31,298(575.8) Rents 122Total Operation (Lines 115 thru 122) 123 29,057 31,298Maintenance 124(576.1) Maintenance of Structures and Improvements 125(576.2) Maintenance of Computer Hardware 126(576.3) Maintenance of Computer Software 127(576.4) Maintenance of Communication Equipment 128(576.5) Maintenance of Miscellaneous Market Operation Plant 129Total Maintenance (Lines 125 thru 129) 130TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131 29,057 31,2984. DISTRIBUTION EXPENSES 132Operation 133(580) Operation Supervision and Engineering 134 388,773 568,617(581) Load Dispatching 135 1,294,234 1,071,903(582) Station Expenses 136 517,632 444,372(583) Overhead Line Expenses 137 389,353 305,468(584) Underground Line Expenses 138 2,409,829 2,197,150(585) Street Lighting and Signal System Expenses 139 2,722 5,468(586) Meter Expenses 140 926,329 942,556(587) Customer Installations Expenses 141(588) Miscellaneous Expenses 142 23,073,566 22,345,697(589) Rents 143 3,505,308 3,551,961TOTAL Operation (Enter Total of lines 134 thru 143) 144 32,507,746 31,433,192Maintenance 145(590) Maintenance Supervision and Engineering 146 917,904 654,536(591) Maintenance of Structures 147 53,273 52,142(592) Maintenance of Station Equipment 148 7,758,333 9,766,523(593) Maintenance of Overhead Lines 149 46,831,037 33,168,696(594) Maintenance of Underground Lines 150 3,154,189 3,242,206(595) Maintenance of Line Transformers 151 7,958(596) Maintenance of Street Lighting and Signal Systems 152 3,709,665 2,889,618(597) Maintenance of Meters 153 4,290,252 3,050,098(598) Maintenance of Miscellaneous Distribution Plant 154 3,151,464 2,849,742TOTAL Maintenance (Total of lines 146 thru 154) 155 69,866,117 55,681,519TOTAL Distribution Expenses (Total of lines 144 and 155) 156 102,373,863 87,114,7115. CUSTOMER ACCOUNTS EXPENSES 157Operation 158(901) Supervision 159 10,523 1,990(902) Meter Reading Expenses 160 12,037,847 11,339,583(903) Customer Records and Collection Expenses 161 14,204,347 14,260,119(904) Uncollectible Accounts 162 9,921,372 7,595,441(905) Miscellaneous Customer Accounts Expenses 163 454,949 443,209TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 36,629,038 33,640,342







/ /2014/Q4

Line No.

Account Amount for



6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165Operation 166(907) Supervision 167 711,941 617,971(908) Customer Assistance Expenses 168 122,421,144 124,553,214(909) Informational and Instructional Expenses 169 189,647 19,610(910) Miscellaneous Customer Service and Informational Expenses 170 8,803,318 9,284,356TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 132,126,050 134,475,1517. SALES EXPENSES 172Operation 173(911) Supervision 174(912) Demonstrating and Selling Expenses 175(913) Advertising Expenses 176 3 44(916) Miscellaneous Sales Expenses 177TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178 3 448. ADMINISTRATIVE AND GENERAL EXPENSES 179Operation 180(920) Administrative and General Salaries 181 5,585,808 3,494,858(921) Office Supplies and Expenses 182 603,092 1,056,329(Less) (922) Administrative Expenses Transferred-Credit 183 10,453,005 9,618,932(923) Outside Services Employed 184 38,957,019 46,686,195(924) Property Insurance 185 370,272 380,922(925) Injuries and Damages 186 1,904,528 4,527,488(926) Employee Pensions and Benefits 187 -35,359,784 100,834,618(927) Franchise Requirements 188(928) Regulatory Commission Expenses 189 4,896,190 4,678,878(929) (Less) Duplicate Charges-Cr. 190(930.1) General Advertising Expenses 191 139,826 538,186(930.2) Miscellaneous General Expenses 192 2,912,857 2,572,785(931) Rents 193 602,787 546,535TOTAL Operation (Enter Total of lines 181 thru 193) 194 10,159,590 155,697,862Maintenance 195(935) Maintenance of General Plant 196 1,945,780 998,606TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 12,105,370 156,696,468TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 1,308,368,433 1,447,859,270





End of

PURCHASED POWER (Account 555)


/ /2014/Q4

Line No.


(c)(b)(a)


Average

(d)

Statistical


Tariff Number Demand (MW)(e) (f)




(Including power exchanges)

1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing ofdebits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or useacronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., thesupplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service mustbe the same as, or second only to, the supplier’s service to its own ultimate consumers.

LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted foreconomic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergencyenergy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm servicewhich meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contractdefined as the earliest date that either buyer or seller can unilaterally get out of the contract.

IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but lessthan five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is oneyear or less.

LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability ofservice, aside from transmission constraints, must match the availability and reliability of the designated unit.

IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" meanslonger than one year but less than five years.

EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.and any settlements for imbalanced exchanges.

OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the natureof the service in a footnote for each adjustment.

NANANAWheelabrator Gloucester OS 1

NANANAHunterdon Cogeneration OS 2

NANANALakewood Cogeneration OS 3

NANANAManchester Renewal Power OS 4

NANANAM&M Mars OS 5

NANANAWarren Energy Resource OS 6

NANANAPA, NJ, MD Power Agreement (PJM) OS 7

NANANAAllegheny Electric Cooperative OS 8

NANANABroker's Fees OS 9

NANANAAdministrative Expense OS 10

NANANABP Energy Company OS 11

NANANACitigroup Energy OS 12

NANANAConocoPhillips Company OS 13

NANANADominion Retail OS 14


Total




End of



/ /2014/Q4

Line No.


(c)(b)(a)


Average

(d)

Statistical
















NANANADTE Energy Trading OS 1

NANANAEnergy America LLC OS 2

NANANAExelon Generation Company OS 3

NANANAJP Morgan Ventures Energy OS 4

NANANAMacquarie Energy OS 5

NANANAMorgan Stanley & Company (Parlin) OS 6

NANANANextEra Energy Power Marketing OS 7

NANANANoble Americas Gas & Power OS 8

NANANANRG Power Marketing OS 9

NANANAPP&L Energy Plus OS 10

NANANAPSEG Energy Resource OS 11

NANANAPublic Power Association of New Jersey RQ 12

NANANATranscanada Power Marketing OS 13

NANANABorough of Butler LF 14


Total




End of



/ /2014/Q4

Line No.


(c)(b)(a)


Average

(d)

Statistical
















NANANABorough of Madison LF 1

NANANANITS Adjustment for BGS OS 2

NANANARenewable Energy Credits OS 3

NANANARenewable Auction Expense OS 4

NANANACustomer Net Metering Credits OS 5

6

7

8

9

10

11

12

13

14


Total




End of

PURCHASED POWER(Account 555) (Continued)


/ /2014/Q4

Line No.

MegaWatt Hours

(i)(h)(g) (j)


(k)

Purchased (j+k+l)Total

COST/SETTLEMENT OF POWER

($) ($) ($)


POWER EXCHANGES

MegaWatt HoursReceived

MegaWatt HoursDelivered

(l) (m)of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportingyears. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriatedesignation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, asidentified in column (b), is provided.5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enterthe monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and theaverage monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). MonthlyNCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demandduring the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthoursof power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, includingout-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlementamount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by theagreement, provide an explanatory footnote.8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must bereported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.9. Footnote entries as required and provide explanations following all required data.

6,836,447 6,836,447 1 78,710

5,432 5,432 2 46

72,070,515 72,070,515 3 586,499

2,394,259 2,394,259 4 39,690

346,477 346,477 5 7,627

2,441,354 2,441,354 6 22,606

18,528,589 17,215 18,545,804 7 421,210

180,445 180,445 8

49,054 49,054 9

578,400 578,400 10

93,852,062 93,852,062 11 1,091,537

33,456,407 33,456,407 12 398,608

16,728,203 16,728,203 13 199,304

2,537,236 2,537,236 14 26,806


12,146,599 1,013,997,313 18,929,160 1,032,926,473




End of



/ /2014/Q4

Line No.

MegaWatt Hours

(i)(h)(g) (j)


(k)



($) ($) ($)


POWER EXCHANGES






14,096,348 14,096,348 1 163,325

27,439,257 27,439,257 2 325,186

169,253,715 169,253,715 3 1,929,044

80,899,275 80,899,275 4 963,903

51,335,098 51,335,098 5 610,247

19,254,436 19,254,436 6

68,506,635 68,506,635 7 806,221

34,579,859 34,579,859 8 397,224

17,166,114 17,166,114 9 193,384

23,605,371 23,605,371 10 246,354

174,836,520 174,836,520 11 2,015,118

2,048,160 335,636 2,383,796 12 60,008

134,363,437 134,363,437 13 1,551,370

7,376 7,376 14 13


12,146,599 1,013,997,313 18,929,160 1,032,926,473




End of



/ /2014/Q4

Line No.

MegaWatt Hours

(i)(h)(g) (j)


(k)



($) ($) ($)


POWER EXCHANGES






19,202 5,291 24,493 1 38

-53,396,534 -53,396,534 2

17,761,273 17,761,273 3

1,846 1,846 4

786,063 786,063 5 12,521

6

7

8

9

10

11

12

13

14


12,146,599 1,013,997,313 18,929,160 1,032,926,473

Schedule Page: 326 Line No.: 1 Column: aPage 326, lines 1 through 6.Represents power purchased for Non-Utility Generation (NUG).

Schedule Page: 326 Line No.: 7 Column: aRepresents power purchased from PJM Interconnections.

Schedule Page: 326 Line No.: 11 Column: aPage 326, Lines 11 through 14.Page 326.1, Lines 1 through 14.Page 326.2, Line 1.Represents power purchased from Basic Generation Suppliers (BGS).

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)





/ /2014/Q4

Line No.

Payment By

(c)(b)(a) (d)

Statistical

cationClassifi-

(Footnote Affiliation)

(Including transactions referred to as 'wheeling')

(Company of Public Authority)(Footnote Affiliation)

(Company of Public Authority)(Footnote Affiliation)

(Company of Public Authority)Energy Received From Energy Delivered To

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company orpublic authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnoteany ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to PointTransmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point TransmissionReservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this codefor any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote foreach adjustment. See General Instruction for definitions of codes.

Allegheny Electric Cooperative, Inc. Susquehanna Steam Electric Sta. Allegheny Electric Cooperative LFP 1

PJM - Network Integrated Transmission PJM Network PJM Network FNO 2

PJM - Point to Point Various Various OS 3

PJM - Transmission Ancillaries Various Various OS 4

PJM - Financial Transmission Rights Auction Various Various OS 5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34


TOTAL




End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)


/ /2014/Q4

Line No.

(Including transactions reffered to as 'wheeling')

FERC RateSchedule of

Tariff Number(e)

Point of Receipt(Subsatation or Other

Designation)(f)

Point of Delivery(Substation or Other

(g)

BillingDemand(MW)

(h)

TRANSFER OF ENERGY


(i)Delivered

(j)

MegaWatt HoursDesignation)

5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contractdesignations under which service, as identified in column (d), is provided.6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report thedesignation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in thecontract.7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demandreported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.8. Report in column (i) and (j) the total megawatthours received and delivered.

Not Specified90 Allegheny Elec. Coop 238 144,054 144,054 1

PJM Network42 PJM Network 2

Various42 Various 3

Various42 Various 4

Various42 Various 5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34


238 144,054 144,054




End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)


/ /2014/Q4

Line No.

(m)(l)(k) (n)(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)Energy Charges

($)(Other Charges)Demand Charges

($)

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demandcharges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to theamount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, includingout of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the totalcharge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or servicerendered.10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual reportpurposes only on Page 401, Lines 16 and 17, respectively.11. Footnote entries and provide explanations following all required data.

1,006,737 1,006,737 1

41,345,769 41,345,769 2

1,242,275 1,242,275 3

7,253,779 7,253,779 4

21,058 21,058 5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34


43,594,781 50,869,618 7,274,837 0

Schedule Page: 328 Line No.: 2 Column: iMWH will be reported for Jersey Central Power & Light by PJM Interconnection in the FERC Form 582.

Schedule Page: 328 Line No.: 2 Column: jMWH will be reported for Jersey Central Power & Light by PJM Interconnection in the FERC Form 582.

Schedule Page: 328 Line No.: 2 Column: kIncludes credit adjustment to Purchase Power (FERC Account 555) for Network Integrated Transmission Service (NITS) since chargesfor the same are built into overall BGS rates. This offsets charges of $53,396,534 in FERC Account 555.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

TRANSMISSION OF ELECTRICITY BY ISO/RTOs


/ /2014/Q4

Line No.

Payment Received by Statistical

(b)(a)(Transmission Owner Name) Classification

FERC Rate Scheduleor Tariff Number

(c)

Total Revenue by RateSchedule or Tarirff

(d)

Total Revenue

(e)

1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – FirmNetwork Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – OtherLong-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS –Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in priorreporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under whichservice, as identified in column (b) was provided.5. In column (d) report the revenue amounts as shown on bills or vouchers.6. Report in column (e) the total revenues distributed to the entity listed in column (a).

Jersey Central Power & Light Company 1

2

21,058 21,05842OSFinancial Transmission Rights Auction 3

41,345,769 41,345,76942FNONetwork Integrated Transmission 4

1,242,275 1,242,27542OSPoint to Point Transmission 5

7,253,779 7,253,77942OSTransmission Ancillaries 6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

49,862,881 49,862,881

Page 331

40 TOTAL

FERC FORM NO. 1/3-Q (REV 03-07)

Schedule Page: 331 Line No.: 4 Column: aIncludes credit adjustment to Purchase Power (FERC Account 555) for Network Integrated Transmission Service (NITS) since chargesfor the same are built into overall BGS rates. This offsets charges of $53,396,534 in FERC Account 555.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)


/ /2014/Q4

Line No. Name of Company or Public

(d)(c)(a)Authority (Footnote Affiliations)

TRANSFER OF ENERGYMagawatt-

hoursReceived

Magawatt-

Deliveredhours

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERSDemandCharges

($)(e)

EnergyCharges

(f)($)

OtherCharges

($)(g)

($)

Total Cost ofTransmission

(h)

(Including transactions referred to as "wheeling")

1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other publicauthorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with thetransmission service provider. Use additional columns as necessary to report all companies or public authorities that providedtransmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - OtherLong-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm TransmissionService, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report thedemand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of allother charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote allcomponents of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If nomonetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,including the amount and type of energy or service rendered.6. Enter "TOTAL" in column (a) as the last line.7. Footnote entries and provide explanations following all required data.

StatisticalClassification

(b)

OS 1,034,251 1,034,251PJM - Interconnection 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16


1,034,251 1,034,251TOTAL

Schedule Page: 332 Line No.: 1 Column: gThe Respondent is a member of the PJM Interconnection.

The dollars represent the following:

1. Ancillary Services $ 906,0702. Congestion Charges 132,9063. Transmission Loss Expense (4,725) Total $ 1,034,251

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)

Jersey Central Power & Light Company X / /

2014/Q4

Line Description Amount(b)(a)No.

18,256Industry Association Dues 1

Nuclear Power Research Expenses 2

Other Experimental and General Research Expenses 3

Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4

Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5

8,784Administrative Fees 6

1,000,479Bank Fees 7

123,609Financing Administration Fees 8

43,808Licenses, Permits and Regulations 9

47,694Membership Dues - Civic 10

252,328Membership Dues - Trade 11

1,090,269Miscellaneous Regulatory Expenses 12

-17,164Other - EDC Base 13

11,788Payroll Benefits - FENOC 14

-11,215Smart Grid True-up 15

4,149All Other (12 Items) 16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

2,572,785


46 TOTAL




End of

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)


/ /2014/Q4

Line No. Functional Classification

Depreciation

(d)(b)(a)

Amortization of

Total

(Except amortization of aquisition adjustments)

A. Summary of Depreciation and Amortization Charges

Expense(Account 403)

Limited TermElectric Plant

Amortization ofOther Electric

Plant (Acc 405)(e) (f)

1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for AssetRetirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other ElectricPlant (Account 405).2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used tocompute charges and whether any changes have been made in the basis or rates used from the preceding report year.3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changesto columns (c) through (g) from the complete report of the preceding year.Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plantincluded in any sub-account used.In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showingcomposite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state themethod of averaging used.For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curveselected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. Ifcomposite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state atthe bottom of section C the amounts and nature of the provisions and the plant items to which related.

(Account 404)(c)

DepreciationExpense for AssetRetirement Costs(Account 403.1)

3,983,135 3,983,135 1 Intangible Plant

2 Steam Production Plant

3 Nuclear Production Plant

4 Hydraulic Production Plant-Conventional

1,077,174 1,077,174 5 Hydraulic Production Plant-Pumped Storage

6 Other Production Plant

17,122,509 17,122,509 7 Transmission Plant

110,338,121 110,338,121 8 Distribution Plant

9 Regional Transmission and Market Operation

11,164,502 10,889,677 274,825 10 General Plant

11 Common Plant-Electric

143,685,441 139,427,481 4,257,960 12 TOTAL

Column (d) represents amortization of the following:Software - - - - - - - - - - - - - - - - - - - - - 14.29% (amortized over 7 years)Leasehold Improvements (Red Bank) - - 9.09%


B. Basis for Amortization Charges




End of

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)


/ /2014/Q4

Line No. Account No.

(c)(b)(a) (d) (e)

C. Factors Used in Estimating Depreciation Charges

DepreciablePlant Base

(In Thousands)

EstimatedAvg. Service

Life

NetSalvage(Percent)

AppliedDepr. rates

MortalityCurveType

AverageRemaining

Life(f) (g)

(Percent)

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50





End of

REGULATORY COMMISSION EXPENSES


/ /2014/Q4

Line No.

Description Assessed by

(c)(b)(a)

Total Expense for

Expenses of

(d)

(Furnish name of regulatory commission or body the Regulatorydocket or case number and a description of the case) Commission Utility

Current Year(b) + (c)

Deferredin Account182.3 at

Beginning of Year(e)

1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, ifbeing amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amountsdeferred in previous years.

Federal Energy Regulatory Commission 1

Annual Assessment - Yards Creek 244,584 244,584 2

3

New Jersey Board of Public Utilities 4

Annual Assessment 4,434,294 4,434,294 5

6

7

1,899,633NJBPU Rate Case 2012 8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45


46 TOTAL 4,678,878 4,678,878 1,899,633




End of

REGULATORY COMMISSION EXPENSES (Continued)


/ /2014/Q4

Line No.

(j)(i)(f) (k) (l)

EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR

CURRENTLY CHARGED TODepartment Account

No.(g)

Amount

(h)

Deferred toAccount 182.3

ContraAccount

Amount Deferred in Account 182.3

End of Year

3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.5. Minor items (less than $25,000) may be grouped.

1

Electric 2 244,584928

3

4

Electric 5 4,434,294928

6

7

2,113,993 294,000407.4 508,360 8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45


46 4,678,878 508,360 294,000 2,113,993




End of

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES


/ /2014/Q4

Line No.

Description

(b)(a)Classification

1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identifyrecipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable toothers (See definition of research, development, and demonstration in Uniform System of Accounts).2. Indicate in column (a) the applicable classification, as shown below:

Classifications:A. Electric R, D & D Performed Internally: a. Overhead (1) Generation b. Underground a. hydroelectric (3) Distribution i. Recreation fish and wildlife (4) Regional Transmission and Market Operation ii Other hydroelectric (5) Environment (other than equipment) b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.) c. Internal combustion or gas turbine (7) Total Cost Incurred d. Nuclear B. Electric, R, D & D Performed Externally: e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric f. Siting and heat rejection Power Research Institute (2) Transmission

Peak Load Shift Smart GridA(4) 1

ED Transmission Line ResearchA(3) 2

CEATI Transmission Line ResearchB(3) 3

Peak Load Shift Smart Grid EPRIB(4) 4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38





End of

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)


/ /2014/Q4

Line No.

AMOUNTS CHARGED IN CURRENT YEAR

(e)(c)

Costs Incurred InternallyCurrent Year

Costs Incurred ExternallyCurrent Year

(d)Account Amount

(f)

Unamortized Accumulation

(g)

(2) Research Support to Edison Electric Institute (3) Research Support to Nuclear Power Groups (4) Research Support to Others (Classify) (5) Total Cost Incurred3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &D activity.4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,Development, and Demonstration Expenditures, Outstanding at the end of the year.6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by"Est."7. Report separately research and related testing facilities operated by the respondent.

1 60,910

16,271 2188 16,271 68,572

3 15,492 188 15,492 144,318

4 90,617

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38





End of

DISTRIBUTION OF SALARIES AND WAGES


/ /2014/Q4

Line No.

Classification

(c)(b)(a)

Direct Payroll Allocation ofTotal

(d)Distribution Payroll charged for

Clearing Accounts

Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts toUtility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columnsprovided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximationgiving substantially correct results may be used.

Electric 1

Operation 2

122Production 3

1,096,790Transmission 4

Regional Market 5

7,447,356Distribution 6

12,434,091Customer Accounts 7

1,447,100Customer Service and Informational 8

Sales 9

987,234Administrative and General 10

23,412,693TOTAL Operation (Enter Total of lines 3 thru 10) 11

Maintenance 12

3,881Production 13

3,257,010Transmission 14

Regional Market 15

26,659,521Distribution 16

14,532Administrative and General 17

29,934,944TOTAL Maintenance (Total of lines 13 thru 17) 18

Total Operation and Maintenance 19

4,003Production (Enter Total of lines 3 and 13) 20

4,353,800Transmission (Enter Total of lines 4 and 14) 21

Regional Market (Enter Total of Lines 5 and 15) 22

34,106,877Distribution (Enter Total of lines 6 and 16) 23

12,434,091Customer Accounts (Transcribe from line 7) 24

1,447,100Customer Service and Informational (Transcribe from line 8) 25

Sales (Transcribe from line 9) 26

1,001,766Administrative and General (Enter Total of lines 10 and 17) 27

53,347,637 53,347,637TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28

Gas 29

Operation 30

Production-Manufactured Gas 31

Production-Nat. Gas (Including Expl. and Dev.) 32

Other Gas Supply 33

Storage, LNG Terminaling and Processing 34

Transmission 35

Distribution 36

Customer Accounts 37

Customer Service and Informational 38

Sales 39

Administrative and General 40

TOTAL Operation (Enter Total of lines 31 thru 40) 41

Maintenance 42

Production-Manufactured Gas 43

Production-Natural Gas (Including Exploration and Development) 44

Other Gas Supply 45

Storage, LNG Terminaling and Processing 46

Transmission 47






/ /2014/Q4

Line No.

Classification

(c)(b)(a)

Direct Payroll Allocation ofTotal

(d)Distribution Payroll charged for

Clearing Accounts

DISTRIBUTION OF SALARIES AND WAGES (Continued)

Distribution 48

Administrative and General 49

TOTAL Maint. (Enter Total of lines 43 thru 49) 50

Total Operation and Maintenance 51

Production-Manufactured Gas (Enter Total of lines 31 and 43) 52

Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53

Other Gas Supply (Enter Total of lines 33 and 45) 54

Storage, LNG Terminaling and Processing (Total of lines 31 thru 55

Transmission (Lines 35 and 47) 56

Distribution (Lines 36 and 48) 57

Customer Accounts (Line 37) 58

Customer Service and Informational (Line 38) 59

Sales (Line 39) 60

Administrative and General (Lines 40 and 49) 61

TOTAL Operation and Maint. (Total of lines 52 thru 61) 62

Other Utility Departments 63

Operation and Maintenance 64

53,347,637 53,347,637TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65

Utility Plant 66

Construction (By Utility Departments) 67

67,932,296 67,932,296Electric Plant 68

Gas Plant 69


67,932,296 67,932,296TOTAL Construction (Total of lines 68 thru 70) 71

Plant Removal (By Utility Departments) 72

8,157,905 8,157,905Electric Plant 73

Gas Plant 74


8,157,905 8,157,905TOTAL Plant Removal (Total of lines 73 thru 75) 76

Other Accounts (Specify, provide details in footnote): 77

30,906 30,906Jobbing Contract 78

3,985 3,985Other Income 79

5,075 5,075Preliminary Survey & Investigation 80

625,245 625,245Temporary Facilities 81

359 359Research & Development 82

9,860 9,860PowerPlant Reconciliation of Settlements 83

104,211 104,211Other 84

1,847,924 1,847,924Work Performed for Associated Companies 85

86

87

88

89

90

91

92

93

94

2,627,565 2,627,565TOTAL Other Accounts 95

132,065,403 132,065,403TOTAL SALARIES AND WAGES 96





End of

COMMON UTILITY PLANT AND EXPENSES


1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified byaccounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs tothe respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulatedprovisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, includingexplanation of basis of allocation and factors used.3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts asprovided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which suchexpenses are related. Explain the basis of allocation used and give the factors of allocation.4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or otherauthorization.






/ /2014/Q4

Line No.

Description of Item(s) Balance at End of

(c)(b)(a)

Balance at End of

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

Quarter 1 Quarter 2Balance at End of

Quarter 3(d) (e)

1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales forResale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy marketfor purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determiningwhether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated andseparately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.

Balance at End ofYear

Energy 1

Net Purchases (Account 555) 2

Net Sales (Account 447) 3

Transmission Rights 4

Ancillary Services 5

Other Items (list separately) 6

7

Purchases (Account 555) 8

Day Ahead (DA) 9 1,044,887 649,849 829,544 940,560

Real Time (RT) 10 3,927,013 3,753,978 3,851,718 3,895,925

11

Sales (Account 447) 12

Day Ahead (DA) 13 ( 45,615,488)( 23,463,376) ( 31,462,679) ( 42,021,674)

Real Time (RT) 14 ( 5,858,293)( 3,990,871) ( 4,752,282) ( 5,517,187)

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

( 46,501,881)( 23,050,420) ( 31,533,699) ( 42,702,376)


46 TOTAL

Schedule Page: 397 Line No.: 8 Column: aThis schedule reflects reporting requirements of FERC Order 668.

Schedule Page: 397 Line No.: 12 Column: aThis schedule reflects reporting requirements of FERC Order 668.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

PURCHASES AND SALES OF ANCILLARY SERVICES


/ /2014/Q4

Line No.

Type of Ancillary Service

(a)

Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in therespondents Open Access Transmission Tariff.

In columns for usage, report usage-related billing determinant and the unit of measure.

(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.

(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and soldduring the year.

(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and soldduring the year.

(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.

(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement servicespurchased and sold during the period.

(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold duringthe year. Include in a footnote and specify the amount for each type of other ancillary service provided.

Number of UnitsUnit of

Measure Dollars

(b) (c) (d)

Number of UnitsUnit of

Measure Dollars

(e) (f) (g)

Usage - Related Billing Determinant Usage - Related Billing Determinant

Amount Purchased for the Year Amount Sold for the Year

-1,974,771 80,105MWH 87,600Scheduling, System Control and Dispatch 1

-177,909 6,840MWD 3,650Reactive Supply and Voltage 2

-3,872,977MWH 120,140 26,099MWH 537Regulation and Frequency Response 3

Energy Imbalance 4

-850,185 23,877Operating Reserve - Spinning 5

-2,212,908 415,450Operating Reserve - Supplement 6

-446,656 362,393Other 7

-9,535,406 120,140 914,764 91,787Total (Lines 1 thru 7) 8

FERC FORM NO. 1 (New 2-04) Page 398

Schedule Page: 398 Line No.: 7 Column: dBlack Start Service Charges $ (378)Lost Opportunity Cost (1,336) Emergency Load Response 284,033Market Monitor 336Ramapo Par Phase Angle Regulation Charges 79,738Total $ 362,393

Schedule Page: 398 Line No.: 7 Column: gBlack Start Service Charges $ (139,800)Other Supporting Facilities Credits (306,856) Total $ (446,656)

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

MONTHLY TRANSMISSION SYSTEM PEAK LOAD


/ /2014/Q4

Line No.

Monthly PeakMW - Total

(c)(b)(a)

Month

NAME OF SYSTEM:

Day ofMonthly

Peak

(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physicallyintegrated, furnish the required information for each non-integrated system.(2) Report on Column (b) by month the transmission system's peak load.(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction forthe definition of each statistical classification.

(d)

Hour ofMonthly Peak

(e)

Firm NetworkService for Self

(f)

Firm NetworkService for

Others

(g)

Long-Term FirmPoint-to-pointReservations

(h)

Other Long-Term Firm

Service

(i)

Short-Term FirmPoint-to-pointReservation

(j)

OtherService

6,369 101900 7 4,079January 1

6,369 10190011 3,575February 2

6,369 101900 3 3,609March 3

19,107 30 11,263Total for Quarter 1 4

6,369 102000 4 2,928April 5

6,369 10170027 3,892May 6

6,369 10180018 5,221June 7


6,369 101700 2 5,637July 9

6,369 10180027 4,970August 10

6,369 101700 2 5,482September 11


6,369 10200015 3,173October 13

6,369 10190019 3,395November 14

6,369 101900 8 3,528December 15


76,428 120 49,489Total Year to

Date/Year

17


Schedule Page: 400 Line No.: 1 Column: eThe amounts in column (e) exclude wholesale suppliers and alternative retail suppliers.

Schedule Page: 400 Line No.: 1 Column: fThe amounts in column (f) include wholesale suppliers and alternative retail suppliers.

Schedule Page: 400 Line No.: 1 Column: gFor column (g) the service was provided by PJM as the transmission provider.

Schedule Page: 400 Line No.: 1 Column: hFor column (h) the service was provided by PJM as the transmission provider.

Schedule Page: 400 Line No.: 1 Column: iFor column (i) the service was provided by PJM as the transmission provider.

Schedule Page: 400 Line No.: 1 Column: jFor column (j) the service was provided by PJM as the transmission provider.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD


/ /2014/Q4

Line No.

Monthly PeakMW - Total

(c)(b)(a)

Month

NAME OF SYSTEM:

Day ofMonthly

Peak

(1) Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physicallyintegrated, furnish the required information for each non-integrated system.(2) Report on Column (b) by month the transmission system's peak load.(3) Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).(4) Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service inColumn (g) are to be excluded from those amounts reported in Columns (e) and (f).(5) Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).

(d)

Hour ofMonthly Peak

(e)

Imports intoISO/RTO

(f)

Exports fromISO/RTO

(g)

Through andOut Service

(h)

NetworkService Usage

(i)

Point-to-PointService Usage

(j)

Total Usage

7 1900 6,379 4,079January 1

11 1900 6,379 3,575February 2

3 1900 6,379 3,609March 3

19,137 11,263Total for Quarter 1 4

4 2000 6,379 2,928April 5

27 1700 6,379 3,892May 6

18 1800 6,379 5,221June 7


2 1700 6,379 5,637July 9

27 1800 6,379 4,970August 10

2 1700 6,379 5,482September 11


15 2000 6,379 3,173October 13

19 1900 6,379 3,395November 14

8 1900 6,379 3,528December 15


76,548 49,489Total Year to

Date/Year

17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a




End of

ELECTRIC ENERGY ACCOUNT


/ /2014/Q4

Line No.

Item

(a)(b)(a) (b)

Line No.

MegaWatt Hours Item MegaWatt Hours

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

SOURCES OF ENERGY1

Generation (Excluding Station Use):2

Steam3

Nuclear4

Hydro-Conventional5

291,491Hydro-Pumped Storage6

Other7

400,825Less Energy for Pumping8

-109,334Net Generation (Enter Total of lines 3

through 8)

9

12,146,599Purchases10

Power Exchanges:11

Received12

Delivered13

Net Exchanges (Line 12 minus line 13)14

Transmission For Other (Wheeling)15

144,054Received16

144,054Delivered17

Net Transmission for Other (Line 16 minus

line 17)

18

Transmission By Others Losses19

12,037,265TOTAL (Enter Total of lines 9, 10, 14, 18

and 19)

20

DISPOSITION OF ENERGY21

20,812,886Sales to Ultimate Consumers (Including

Interdepartmental Sales)

22

Requirements Sales for Resale (See

instruction 4, page 311.)

23

1,033,372Non-Requirements Sales for Resale (See

instruction 4, page 311.)

24

-10,855,369Energy Furnished Without Charge25

45,428Energy Used by the Company (Electric

Dept Only, Excluding Station Use)

26

1,000,948Total Energy Losses27

12,037,265TOTAL (Enter Total of Lines 22 Through

27) (MUST EQUAL LINE 20)

28


(d)

Day of Month




End of

MONTHLY PEAKS AND OUTPUT


/ /2014/Q4

Line No. Total Monthly Energy Megawatts

(c)(b)(a)

Hour

(e)

MONTHLY PEAK

Month

NAME OF SYSTEM:

Monthly Non-RequirmentsSales for Resale &Associated Losses (See Instr. 4)

1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the requiredinformation for each non- integrated system. 2. Report in column (b) by month the system’s output in Megawatt hours for each month.3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).

(f)

January 29 7 4,079 94,864 1900 1,145,583

February 30 11 3,575 63,360 1900 956,664

March 31 3 3,609 98,311 1900 1,000,205

April 32 4 2,928 46,677 2000 769,810

May 33 27 3,892 78,016 1700 812,001

June 34 18 5,221 112,453 1800 1,088,303

July 35 2 5,637 149,137 1700 1,371,903

August 36 27 4,970 109,186 1800 1,169,981

September 37 2 5,482 101,606 1700 1,056,632

October 38 15 3,173 86,243 2000 871,633

November 39 19 3,395 58,369 1900 858,906

December 40 8 3,528 35,150 1900 935,644


41 TOTAL 12,037,265 1,033,372

Schedule Page: 401 Line No.: 16 Column: bDoes not include Network Integrated Transmission Services MWH, which will be reported for Jersey Central Power & Light Companyby PJM Interconnection in FERC Form 582.

Schedule Page: 401 Line No.: 17 Column: bDoes not include Network Integrated Transmission Services MWH, which will be reported for Jersey Central Power & Light Companyby PJM Interconnection in FERC Form 582.

Schedule Page: 401 Line No.: 25 Column: bRepresents Megawatt Hours included in Line 22, Sales to Ultimate Consumers, that were delivered and billed to shopping customersand provided by external suppliers.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA






/ / 2014/Q4

Line No.

Item

(b)(a) (c)

PlantName:

PlantName:

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report inthis page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operatedas a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attendmore than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on atherm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average costper unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than onefuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear

2 Type of Constr (Conventional, Outdoor, Boiler, etc)

3 Year Originally Constructed

4 Year Last Unit was Installed

5 Total Installed Cap (Max Gen Name Plate Ratings-MW)

6 Net Peak Demand on Plant - MW (60 minutes)

7 Plant Hours Connected to Load

8 Net Continuous Plant Capability (Megawatts)

9 When Not Limited by Condenser Water

10 When Limited by Condenser Water

11 Average Number of Employees

12 Net Generation, Exclusive of Plant Use - KWh

13 Cost of Plant: Land and Land Rights

14 Structures and Improvements

15 Equipment Costs

16 Asset Retirement Costs

00 17 Total Cost

00 18 Cost per KW of Installed Capacity (line 17/5) Including

19 Production Expenses: Oper, Supv, & Engr

20 Fuel

21 Coolants and Water (Nuclear Plants Only)

22 Steam Expenses

23 Steam From Other Sources

24 Steam Transferred (Cr)

25 Electric Expenses

26 Misc Steam (or Nuclear) Power Expenses

27 Rents

28 Allowances

29 Maintenance Supervision and Engineering

30 Maintenance of Structures

31 Maintenance of Boiler (or reactor) Plant

32 Maintenance of Electric Plant

33 Maintenance of Misc Steam (or Nuclear) Plant

34 Total Production Expenses

35 Expenses per Net KWh

36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

38 Quantity (Units) of Fuel Burned

39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)

40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year

41 Average Cost of Fuel per Unit Burned

42 Average Cost of Fuel Burned per Million BTU

43 Average Cost of Fuel Burned per KWh Net Gen

44 Average BTU per KWh Net Generation


9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and LoadDispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plantsdesigned for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclearsteam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combinedcycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain byfootnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost unitsused for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for thereport period and other physical and operating characteristics of plant.




End of

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)


/ / 2014/Q4

Line No.

(e) (f)

PlantName:

PlantName:

(d)

PlantName:

(Continued)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

00 0 17

00 0 18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44


0 0




End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)


/ / 2014/Q4

Line No.

Item FERC Licensed Project No.

(b)(a) (c)Plant Name:

FERC Licensed Project No.Plant Name:

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts ina footnote. If licensed project, give project number.3. If net peak demand for 60 minutes is not available, give that which is available specifying period.4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to eachplant.

Kind of Plant (Run-of-River or Storage) 1

Plant Construction type (Conventional or Outdoor) 2

Year Originally Constructed 3

Year Last Unit was Installed 4

Total installed cap (Gen name plate Rating in MW) 5 0.00 0.00

Net Peak Demand on Plant-Megawatts (60 minutes) 6 0 0

Plant Hours Connect to Load 7 0 0

Net Plant Capability (in megawatts) 8

(a) Under Most Favorable Oper Conditions 9 0 0

(b) Under the Most Adverse Oper Conditions 10 0 0

Average Number of Employees 11 0 0

Net Generation, Exclusive of Plant Use - Kwh 12 0 0

Cost of Plant 13

Land and Land Rights 14 0 0

Structures and Improvements 15 0 0

Reservoirs, Dams, and Waterways 16 0 0

Equipment Costs 17 0 0

Roads, Railroads, and Bridges 18 0 0

Asset Retirement Costs 19 0 0

TOTAL cost (Total of 14 thru 19) 20 0 0

Cost per KW of Installed Capacity (line 20 / 5) 21 0.0000 0.0000

Production Expenses 22

Operation Supervision and Engineering 23 0 0

Water for Power 24 0 0

Hydraulic Expenses 25 0 0

Electric Expenses 26 0 0

Misc Hydraulic Power Generation Expenses 27 0 0

Rents 28 0 0

Maintenance Supervision and Engineering 29 0 0

Maintenance of Structures 30 0 0

Maintenance of Reservoirs, Dams, and Waterways 31 0 0

Maintenance of Electric Plant 32 0 0

Maintenance of Misc Hydraulic Plant 33 0 0

Total Production Expenses (total 23 thru 33) 34 0 0

Expenses per net KWh 35 0.0000 0.0000


0 0 0




End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)


/ / 2014/Q4

FERC Licensed Project No.

(e)(d) (f)Plant Name:



Line No.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expensesdo not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

1

2

3

4

0.00 0.000.00 5

0 00 6

0 00 7

8

0 00 9

0 00 10

0 00 11

0 00 12

13

0 00 14

0 00 15

0 00 16

0 00 17

0 00 18

0 00 19

0 00 20

0.0000 0.00000.0000 21

22

0 00 23

0 00 24

0 00 25

0 00 26

0 00 27

0 00 28

0 00 29

0 00 30

0 00 31

0 00 32

0 00 33

0 00 34

0.0000 0.00000.0000 35


2309Yards Creek


(b)




End of

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)


/ / 2014/Q4

Line No.

Item

(a)

1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings)2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts ina footnote. Give project number.3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to eachplant.5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expensesdo not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."

1 Type of Plant Construction (Conventional or Outdoor) Semi-outdoor

2 Year Originally Constructed 1965

3 Year Last Unit was Installed 1965

4 Total installed cap (Gen name plate Rating in MW) 226

5 Net Peak Demaind on Plant-Megawatts (60 minutes)

6 Plant Hours Connect to Load While Generating

7 Net Plant Capability (in megawatts) 200

8 Average Number of Employees 8

9 Generation, Exclusive of Plant Use - Kwh

10 Energy Used for Pumping

11 Net Output for Load (line 9 - line 10) - Kwh

12 Cost of Plant

13 Land and Land Rights 284,198

14 Structures and Improvements 3,437,662

15 Reservoirs, Dams, and Waterways 17,294,221

16 Water Wheels, Turbines, and Generators 16,168,269

17 Accessory Electric Equipment 3,889,448

18 Miscellaneous Powerplant Equipment 1,609,806

19 Roads, Railroads, and Bridges

20 Asset Retirement Costs

21 Total cost (total 13 thru 20) 42,683,604

22 Cost per KW of installed cap (line 21 / 4) 188.4486

23 Production Expenses

24 Operation Supervision and Engineering

25 Water for Power

26 Pumped Storage Expenses

27 Electric Expenses

28 Misc Pumped Storage Power generation Expenses

29 Rents

30 Maintenance Supervision and Engineering

31 Maintenance of Structures

32 Maintenance of Reservoirs, Dams, and Waterways

33 Maintenance of Electric Plant

34 Maintenance of Misc Pumped Storage Plant

35 Production Exp Before Pumping Exp (24 thru 34)

36 Pumping Expenses

37 Total Production Exp (total 35 and 36)

38 Expenses per KWh (line 37 / 9)


0 0 0FERC Licensed Project No.Plant Name:


(d)




End of

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)


/ / 2014/Q4

Line No.


(e)(c)

6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from eachstation or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH asreported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumpingenergy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38





End of

GENERATING PLANT STATISTICS (Small Plants)


/ /2014/Q4

Line No.

Name of PlantInstalled Capacity

(c)(b)(a)

Cost of PlantNet PeakDemand

(d)

YearOrig.

Const.Name Plate Rating

(In MW) MW(60 min.)

Net GenerationExcludingPlant Use

(e) (f)

1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumpedstorage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license fromthe Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,give project number in footnote.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46





End of

GENERATING PLANT STATISTICS (Small Plants) (Continued)


/ /2014/Q4

Line No.

(i)(h)(g) (j) (k) (l)

OperationExc'l. Fuel

Production Expenses

Fuel Maintenance Kind of FuelFuel Costs (in cents

(per Million Btu)

3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped withcombinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gasturbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.

Plant Cost (Incl AssetRetire. Costs) Per MW

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46





End of

TRANSMISSION LINE STATISTICS


/ /2014/Q4

Line No.

(c)(b)(a) (d) (e)

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles)(In the case of

underground linesreport circuit miles)

On Structureof Line

Designated

On Structuresof Another

Line

NumberOf

Circuits

(h)

1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not reportsubstation costs and expenses on this page.3. Report data by individual lines for all voltages if so required by a State commission.4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of constructionby the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from theremainder of the line.6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which isreported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Reportpole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses withrespect to such structures are included in the expenses reported for the line designated.

Steel H Frame 500.00 500.00 17.91 1 1 Smithburg Deans

2 17.91 1 3 Total 500 KV Lines

4 230.00 230.00 13.15 1 5 Atlantic Freneau

Steel Tower 230.00 230.00 11.60 2 6 Atlantic LarrabeeWood H Frame 230.00 230.00 4.61 2 7 Atlantic Ocean View #1Wood H Frame 230.00 230.00 4.61 2 8 Atlantic Ocean View #2Steel Tower 230.00 230.00 7.06 2 9 Atlantic Red Bank #1Steel Tower 230.00 230.00 7.45 2 10 Atlantic Red Bank #2

230.00 230.00 23.66 1 11 Atlantic Smithburg 230.00 230.00 18.85 1 12 Atlantic South River 230.00 230.00 9.75 1 13 Bridgewater Gillette-Lake Nelson 230.00 230.00 3.17 1 14 Branchburg East Femington

Steel Tower 230.00 230.00 10.39 1 15 Chester West Wharton 230.00 230.00 15.34 1 16 Chester Glen Gardner 230.00 230.00 0.08 1 17 Cedar Oyster Creek 230.00 230.00 7.44 1 18 Clarksville (PSE&G) Windsor 230.00 230.00 4.19 1 19 Clarksville Lawrence

Steel Tower 230.00 230.00 10.93 1 20 Cookstown Lumbertown (PSE&G) 230.00 230.00 39.75 1 21 Cookstown Larrabee-Whitings 230.00 230.00 3.18 1 22 East Flemington Pleasant Valley (PSG&E) 230.00 230.00 2.53 1 23 East Windsor Windsor 230.00 230.00 8.99 1 24 Englishtown Smithburg

Steel Tower 230.00 230.00 5.24 1 25 Freneau ParlinSteel Tower 230.00 230.00 16.28 1 26 Gilbert Glen GardnerSteel Tower 230.00 230.00 18.65 1 27 Gilbert Martins CreekSteel Tower 230.00 230.00 51.61 1 28 Gilbert Morristown

230.00 230.00 0.22 1 29 Gilbert Springfield 230.00 230.00 5.93 1 30 Gillette DOT Summit, Traynor #1 230.00 230.00 5.91 1 31 Gillette DOT Summit, Traynor #2 230.00 230.00 9.76 1 32 Gillette Lake Nelson

Steel Tower 230.00 230.00 15.34 1 33 Glen Gardner Chester 230.00 230.00 7.84 1 34 Greystone Whippany #1 230.00 230.00 7.86 1 35 Greystone Whippany #2


36 TOTAL 3,699.79 18.02 81




End of



/ /2014/Q4

Line No.

(c)(b)(a) (d) (e)

DESIGNATION

From To

(f) (g)


Operating Designed

Type of

Supporting

Structure



On Structureof Line

Designated


Line

NumberOf

Circuits

(h)


230.00 230.00 32.91 1 1 Greystone Portland 230.00 230.00 8.03 1 2 Greystone West Wharton 230.00 230.00 0.09 1 3 Kittany Yards Creek

Steel Tower 230.00 230.00 17.73 1 4 Kittatinny Tap Pohatcong 230.00 230.00 2.09 1 5 Kittatinny Newton 230.00 230.00 7.56 1 6 Kittqtinny Portland 230.00 230.00 8.04 1 7 Lake Nelson Raritan River #1 230.00 230.00 7.75 1 8 Lake Nelson Raritan River #2

Steel Tower 230.00 230.00 13.11 1 9 Lakewood Larrabee #1 230.00 230.00 5.25 1 10 Lakewood Larrabee #2

Steel Tower 230.00 230.00 2.39 1 11 Lakewood Leisure Village #1 230.00 230.00 2.37 1 12 Lakewood Leisure Village #2 230.00 230.00 12.05 1 13 Larrabee Smithburg #1 230.00 230.00 12.01 1 14 Larrabee Smithburg #2 230.00 230.00 12.29 1 15 Lawrence Pleasant Valley 230.00 230.00 7.17 1 16 Leisure Village Manitou #1 230.00 230.00 7.15 1 17 Leisure Village Manitou #2

Steel Tower 230.00 230.00 11.08 1 18 Manitou Oyster Creek #1 230.00 230.00 11.06 1 19 Manitou Oyster Creek #2 230.00 230.00 8.77 1 20 Manitou Whitings

Steel Pole 230.00 230.00 6.73 1 21 Morristown Whippany 230.00 230.00 2.10 1 22 Montville Newton 230.00 230.00 4.53 1 23 Parlin Raritan River 230.00 230.00 12.29 1 24 Pleasant Valley Lawrence 230.00 230.00 18.81 1 25 Pohatcong DOT West Wharton 230.00 230.00 33.34 2 26 Portland Greystone

Steel Tower 230.00 230.00 7.56 2 27 Portland KittatinnySteel Tower 230.00 230.00 4.23 2 28 Raritan River Werner

230.00 230.00 3.82 1 29 Raritan River South River 230.00 230.00 0.43 1 30 Red Bank NJ Transi Red Bank 230.00 230.00 8.99 1 31 Smithburg East Windsor

Steel Tower 230.00 230.00 12.14 1 32 Smithburg Larrabee #1 230.00 230.00 12.01 1 33 Smithburg Larrebee #2 230.00 230.00 0.22 1 34 Springfield Gilbert 230.00 230.00 4.23 1 35 Werner Raritan River


36 TOTAL 3,699.79 18.02 81




End of



/ /2014/Q4

Line No.

(c)(b)(a) (d) (e)

DESIGNATION

From To

(f) (g)


Operating Designed

Type of

Supporting

Structure



On Structureof Line

Designated


Line

NumberOf

Circuits

(h)


230.00 230.00 8.12 1 1 West Wharton GreystoneSteel Tower 230.00 230.00 9.41 2 2 Whippany Traynor #1Steel Tower 230.00 230.00 2.67 1 3 Whippany RoselandSteel Tower 230.00 230.00 9.38 1 4 Whippany Traynor #2

230.00 230.00 2.53 1 5 Windsor East Windsor

6 703.81 80 7 Total 230 KV Lines

8Various 115.00 115.00 1,492.80 9 115 kv Lines

10Various 34.50 34.50 18.02 1,485.27 11 34.5 KV Lines

12

13

14 Operation and Maintenance

15 Expense

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35


36 TOTAL 3,699.79 18.02 81




End of

TRANSMISSION LINE STATISTICS (Continued)


/ /2014/Q4

Line No.

COST OF LINE (Include in Column (j) Land,

Size ofConductor

and Material

Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES

OperationExpenses

Maintenance Rents TotalLand Construction andOther Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p)Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote ifyou do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report thepole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, forwhich the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining thearrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharingexpenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, orother party is an associated company.9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and howdetermined. Specify whether lessee is an associated company.10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.

2493 ACAR 1

24,325,443 15,613,412 8,712,031 2

24,325,443 15,613,412 8,712,031 3

4

5

1590 ACSR 6

1590 ACSR 7

1590 ACSR 8

1590 ACSR 9

1590 ACSR 10

11

12

13

14

1590 ACSR 15

16

17

18

19

1590 ACSR 20

21

22

23

24

1590 ACSR 25

1590 ACSR 26

1590 ACSR 27

1590 ACSR 28

29

30

31

32

1590 ACSR 33

34

35


36 39,803,583 520,355,491 560,159,074 411,278 7,750,832 10,125,016 18,287,126




End of



/ /2014/Q4

Line No.


Size ofConductor

and Material


OperationExpenses


Total Cost



1

2

3

1590 ACSR 4

5

6

7

8

1590 ACSR 9

10

1590 ACSR 11

1590 ASCR 12

13

14

15

16

17

1590 ACSR 18

19

20

1590 ACSR 21

22

23

1590 ACSR 24

25

1590 ACSR 26

1590 ACSR 27

1590 ACSR 28

29

30

31

1590 ACSR 32

33

34

35


36 39,803,583 520,355,491 560,159,074 411,278 7,750,832 10,125,016 18,287,126




End of



/ /2014/Q4

Line No.


Size ofConductor

and Material


OperationExpenses


Total Cost



1590 ACSR 1

1590 ACSR 2

1033.5 ACSR 3

1590 ACSR 4

5

164,150,571 148,897,820 15,252,751 6

164,150,571 148,897,820 15,252,751 7

8

15,618,113 14,198,982 1,419,131 9

10

356,064,947 341,645,277 14,419,670 11

12

13

18,287,126 10,125,016 7,750,832 411,278 14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35


36 39,803,583 520,355,491 560,159,074 411,278 7,750,832 10,125,016 18,287,126




End of

TRANSMISSION LINES ADDED DURING YEAR


/ /2014/Q4

Line No.

(c)(b)(a) (d) (e)

LINE DESIGNATION

From To

LineLength

inMiles

SUPPORTING STRUCTURE

TypeAverage

Number perMiles

CIRCUITS PER STRUCTURE

Present Ultimate

(f) (g)

1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to reportminor revisions of lines.2. Provide separate subheadings for overhead and underground construction and show each transmission line separately. If actualcosts of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the

1 No new lines added for 2014

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43


44 TOTAL

Total




End of

TRANSMISSION LINES ADDED DURING YEAR (Continued)


/ /2014/Q4

Line No.

(k)(j)(h) (l) (m)

CONDUCTORS

Size ConfigurationVoltage

KV

LINE COST

Land and Poles, Towersand Fixtures

Conductors

(n) (p)

Specificationand Spacing (Operating) Land Rights and Devices

(i)

costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads andTrails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,indicate such other characteristic.

Asset

(o)Retire. Costs

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43


44




End of

SUBSTATIONS


/ /2014/Q4

Line No. Name and Location of Substation

Primary(c)(b)(a)

Tertiary(d)

Character of Substation

(e)Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.2. Substations which serve only one industrial or street railway customer should not be listed below.3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped accordingto functional character, but the number of such substations must be shown.4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whetherattended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations incolumn (f).

Yards Creek, Blairstown Township, NJ 0.23 0.01T-U-G 1

Forked River, Lacey Township, NJ 0.03T-U-G 2

Subtotal 0.23 0.04 3

Atlantic, Colts Neck Township, NJ 0.04 0.23T-U 4



Chester, Chester Township, NJ 0.04 0.23T-U 7

Cookstown, North Hanover Township, NJ 0.04 0.23T-U 8

Deep Run, Old Bridge Township, NJ 0.04 0.23T-U 9

East Flemington, Raritan Township, NJ 0.04 0.23T-U 10

East Windsor, East Windsor Township, NJ 0.23 0.50T-U 11

Eaton Crest 0.04 0.23T-U 12

Englishtown, Manalapan Township, NJ 0.04 0.23T-U 13

Englishtown, Manalapan Township, NJ 0.04 0.12T-U 14

Englishtown 0.12 0.23T-U 15

Englishtown, Manalapan Township, NJ 0.23T-U 16

Flanders, Mt. Olive Township, NJ 0.04 0.12T-U 17

Franklin, Franklin Township, NJ 0.04 0.12T-U 18

Freneau, Matawan Borough, NJ 0.04 0.23T-U 19

Freneau, Matawan Borough, NJ 0.01 0.23T-U 20

Gilbert Station, Holland Township, NJ 0.04 0.23T-U 21



Gillette, Long Hill Township, NJ 0.04 0.23T-U 24

Glen Gardner, Lebanon Township, NJ 0.04 0.23T-U 25

Greystone, Denville Township, NJ 0.04 0.23T-U 26

Kittatinny, Blairstown Township, NJ 0.03 0.23T-U 27

Kittatinny, Blairstown Township, NJ 0.03 0.23T-U 28

Larrabee, Howell Township, NJ 0.07 0.23T-U 29



Lakewood Co Gen, Lakewood, NJ 0.03 0.23T-U 32

Leisure Village, Dover Township, NJ 0.03 0.23T-U 33

Manalapan, Manalapan Township, NJ 0.01 0.23T-U 34

Manchester, Manchester Township, NJ 0.03 0.23T-U 35

Manitou, Berkeley Township, NJ 0.03 0.23T-U 36

Montville, Montville, NJ 0.03 0.23T-U 37

Morris Park, Lopatcong Township, NJ 0.03 0.12T-U 38

Morris Park, Lopatcong Township, NJ 0.23T-U 39

Morristown, Morristown, NJ 0.03 0.23T-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


NEJESCO, Sayreville Borough, NJ 0.03 0.23T-U 1

Newton, Newton, NJ 0.03 0.23T-U 2

Oceanview, Neptune Township, NJ 0.03 0.23T-U 3

Oyster Creek, Lacey Township, NJ 0.03 0.23T-U 4

Pequest River, Belvidere Township, NJ 0.03 0.12T-U 5

Pohatcong Mountain, Mansfield Township, NJ 0.03 0.23T-U 6

Raritan River, Sayreville Borough, NJ 0.12 0.23 0.01T-U 7

Raritan River, Sayreville Borough, NJ 0.03 0.12T-U 8

Raritan River, Sayreville Borough, NJ 0.03 0.12T-U 9

Readington, Bridgewater Township, NJ 0.04 0.23T-U 10

Red Bank, Red Bank, NJ 0.04 0.23T-U 11

Smithburg, Freehold Township, NJ 0.23 0.50T-U 12

Smithburg, Freehold Township, NJ 0.03 0.23T-U 13

Stoney Brook, Hanover Township, NJ 0.01 0.23T-U 14

Stoney Brook, Hanover Township, NJ 0.01 0.12T-U 15

Tewksbury 0.01 0.23T-U 16

Traynor, City of Summit, NJ 0.04 0.23T-U 17

Vernon, Vernon, NJ 0.04 0.12T-U 18

Werner, City of South Amboy, NJ 0.23T-U 19

Werner, City of South Amboy, NJ 0.04 0.12T-U 20

West Wharton, Jefferson Township, NJ 0.01 0.23T-U 21



Whippany, East Hanover Township, NJ 0.12 0.23 0.01T-U 24

Whippany, East Hanover Township, NJ 0.03 0.23T-U 25

Whitings 0.03 0.23T-U 26

Whitings, Manchester Township, NJ 0.01 0.03T-U 27

Wyckoff Street 0.04 0.12T-U 28

Windsor 0.03 0.23T-U 29

Windsor, Washington Township, NJ 0.01 0.03T-U 30

Subtotal 2.61 14.23 0.02 31

Atlantic 0.01 0.03D-U 32

Academy, Livingston Township NJ 0.01 0.03D-U 33

Air Reduction, New Providence Borough, NJ 0.01 0.03D-U 34

Alderney, Parsippany-Troy Hills Township, NJ 0.01 0.03D-U 35

Allenhurst, Allenhurst, NJ 0.03D-U 36

Allenwood, Wall Township, NJ 0.03D-U 37

Alpha, Alpha Borough, NJ 0.01 0.03D-U 38

Alpha, Alpha Borough, NJ 0.03D-U 39

Andover, Andover, NJ 0.01 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


Andover, Andover, NJ 0.03D-U 1

Applegarth, Applegarth, NJ 0.01 0.03D-U 2

Asbury Park, Asbury Park, NJ 0.01 0.03D-U 3

Asbury Park, Asbury Park, NJ 0.03D-U 4

Atlantic Highlands, Atlantic Highlands, NJ 0.03D-U 5

Avon, Avon by Sea, NJ 0.03D-U 6

Azoplate 0.01 0.03D-U 7

Azoplate 0.01 0.03D-U 8

Baptistown 0.01 0.03D-U 9

Bath Avenue, Long Branch, NJ 0.01 0.03D-U 10

Bath Avenue, City of Long Branch, NJ 0.03D-U 11

Bay, Union Beach Borough, NJ 0.01 0.03D-U 12

Bay, Union Beach Borough, NJ 0.03D-U 13

Beach Glen, Rockaway Township, NJ 0.01 0.03D-U 14

Beach Glen, Rockaway Township, NJ 0.03D-U 15

Belford, Middletown Township, NJ 0.03D-U 16

Belford, Middletown Township, NJ 0.01 0.03D-U 17

Belmar, Wall Township, NJ 0.03D-U 18

Bernardsville, Bernardsville, NJ 0.01 0.03D-U 19

Bennett, Wall Township, NJ 0.01 0.03D-U 20

Berkeley Heights, Berkeley Heights, NJ 0.03D-U 21

Blairstown, Frelinghuysen Township, NJ 0.01 0.03D-U 22

Bradevelt, Marlboro Township, NJ 0.01 0.03D-U 23

Bradley Beach, Bradley Beach, NJ 0.03D-U 24

Branchport, City of Long Branch, NJ 0.03D-U 25

Branchville, Frankford Township, NJ 0.01 0.03D-U 26

Briant Park, Summit, NJ 0.03D-U 27

Brielle, Wall Township, NJ 0.03D-U 28

Brielle, Wall Township, NJ 0.01 0.03D-U 29

Browntown, Old Bridge Township, NJ 0.01 0.03D-U 30

Buckeye, Raritan Township, NJ 0.03D-U 31

Buckeye, Raritan Township, NJ 0.03D-U 32

Campus Drive, Florham Park Borough, NJ 0.01 0.03D-U 33

Canoe Brook, Millburn Township, NJ 0.03D-U 34

Cedar Bridge, Brick Township, NJ 0.01 0.03D-U 35

Cedar Knolls, Hanover Township, NJ 0.01 0.03D-U 36

Chambers Brook, Bridgewater Township, NJ 0.01 0.03D-U 37

Change Bridge, Montville Township, NJ 0.01 0.03D-U 38

Change Bridge, Montville Township, NJ 0.03D-U 39

Chapin Road, Montville Township, NJ 0.01 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


Cheesequake, Old Bridge Township, NJ 0.01 0.03D-U 1

Cherryville, Hunterdon County, NJ 0.01 0.03D-U 2

Cherryville, Hunterdon County, NJ 0.03D-U 3

Chester, Chester Township, NJ 0.01 0.03D-U 4

Clark Street, Keyport, NJ 0.03D-U 5

Clinton, Clinton, NJ 0.01 0.03D-U 6

Clinton, Clinton, NJ 0.03D-U 7

Collinsville, Morris Township & Morristown, NJ 0.01 0.03D-U 8

Colonial Oaks, East Brunswick, NJ 0.01 0.03D-U 9

Colonial Oaks, East Brunswick, NJ 0.01D-U 10

Colts Neck, Colts Neck, NJ 0.01 0.03D-U 11

Convent, Morris Township, NJ 0.01 0.03D-U 12

Convent, Morris Township, NJ 0.03D-U 13

Corlies Avenue, Neptune, NJ 0.03D-U 14

Costco, Monrow, NJ 0.01 0.03D-U 15

Cozy Lake, Jefferson Township, NJ 0.01 0.03D-U 16

Cranbury, Monroe Township, NJ 0.01 0.03D-U 17

Crawfords Corner, Holmdel Township, NJ 0.01 0.03D-U 18

Crossman's, Sayreville Borough, NJ 0.03D-U 19

Crossman's, Sayreville Borough, NJ 0.01 0.03D-U 20

CSC, Berkeley Heights Township, NJ 0.01 0.03D-U 21

Dead River, Warren Township, NJ 0.01 0.03D-U 22

Denville, Denville, NJ 0.03D-U 23

Deep Run, Old Bridge Twp NJ 0.01 0.03D-U 24

Depot, Red Bank Borough, NJ 0.01 0.03D-U 25

Dickerson, Randolph Township, NJ 0.03D-U 26

Dover, Dover, NJ 0.03D-U 27

Drakestown 0.01 0.12D-U 28

Drew, Boonton, NJ 0.03D-U 29

Drum Point, Brick Township, NJ 0.01 0.03D-U 30

East Dover, Rockaway Township, NJ 0.01 0.03D-U 31

East Flemington, Raritan Township, NJ 0.01 0.03D-U 32

East Flemington, Raritan Township, NJ 0.03D-U 33

East Newton, Newton, NJ 0.03D-U 34

Eaton Crest, Eatontown Borough, NJ 0.01 0.03D-U 35

Eaton Crest, Eatontown Borough, NJ 0.03D-U 36

Elberon, Deal Borough, NJ 0.03D-U 37

Englishtown, Manalapan Township, NJ 0.01 0.03D-U 38

Ernston, Sayreville Borough, NJ 0.03D-U 39

Fadem Road, Springfield Township, NJ 0.01 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


Fair Haven, Fair Haven, NJ 0.01 0.03D-U 1

Fair Haven, Fair Haven, NJ 0.03D-U 2

Fairview, Middletown Township, NJ 0.01 0.03D-U 3

Farmingdale, Howell Township, NJ 0.01 0.03D-U 4

Feltus Street, Sayreville Borough, NJ 0.01 0.03D-U 5

Feltus Street, Sayreville Borough, NJ 0.03D-U 6

Flanders, Mt. Olive Township, NJ 0.01 0.03D-U 7

Fleetwood, Rockaway Township, NJ 0.01 0.03D-U 8

Fleetwood, Rockaway Township, NJ 0.03D-U 9

Florham Park, Florham Park, NJ 0.01 0.03D-U 10

Fox Hill, Mountain Lakes Borough, NJ 0.01 0.03D-U 11

Forkdriver2 0.03D-U 12

Franklin, Franklin, NJ 0.03D-U 13

Freehold, Freehold, NJ 0.01 0.03D-U 14

Freehold, Freehold, NJ 0.03D-U 15

Furnace Brook, White Township, NJ 0.01 0.03D-U 16

Gilbert Station, Long Hill Township, NJ 0.03D-U 17

Gillette, Long Hill Township, NJ 0.01 0.03D-U 18

Glen Gardner, Lebanon Township, NJ 0.01 0.03D-U 19

Glendola, Wall Township, NJ 0.01 0.03D-U 20

Gordons Corner, Manalapan Township, NJ 0.01 0.03D-U 21

Grandin, Union Township, NJ 0.01 0.03D-U 22

Great Adventure, Jackson Township, NJ 0.01 0.03D-U 23

Greater Cross Road, Bedminister Township, NJ 0.01 0.03D-U 24

Green Grove, Ocean Township, NJ 0.01 0.03D-U 25

Green Village, Chatham Township, NJ 0.01 0.03D-U 26

Greystone, Denville Township, NJ 0.01 0.03D-U 27

Hackettstown, Hackettstown, NJ 0.03D-U 28

Halsey, Parsippany-Troy Hills Township, NJ 0.01 0.03D-U 29

Hamburg,Hamburg Boro,NJ 0.01 0.03D-U 30

Hamilton, Neptune, NJ 0.03D-U 31

Haskell, Wanaque Township, NJ 0.01 0.03D-U 32

Hawks, Holland Township, NJ 0.01 0.03D-U 33

Hazlet, Hazlet, NJ 0.01 0.03D-U 34

Herbertsville, Brick Township, NJ 0.01 0.03D-U 35

Herbertsville, Brick Township, NJ 0.01 0.03D-U 36

Highlands, Highlands, NJ 0.03D-U 37

Hooper Avenue, Dover Township, NJ 0.01 0.03D-U 38

Hornerstown, Upper Freehold Township, NJ 0.01 0.03D-U 39

Howell, Howell, NJ 0.01 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


Hurdtown, Jefferson Township, NJ 0.03D-U 1

Hurdtown, Jefferson Township, NJ 0.03D-U 2

Hyson, Jackson Township, NJ 0.01 0.03D-U 3

Island Heights, Dover Township, NJ 0.01 0.03D-U 4

Jamesburg, Jamesburg, NJ 0.03D-U 5

Jernee Mill, Sayreville, NJ 0.03D-U 6

Jerseyville, Freehold Township, NJ 0.01 0.03D-U 7

Jerseyville, Freehold Township, NJ 0.03D-U 8

Keansburg, Keansburg, NJ 0.01 0.03D-U 9

Keansburg, Keansburg, NJ 0.03D-U 10

Kenvil, Roxbury Township, NJ 0.01 0.03D-U 11

Kenvil, Roxbury Township, NJ 0.03D-U 12

Keyport, Union Beach Borough, NJ 0.01 0.03D-U 13

Keyport, Union Beach Borough, NJ 0.03D-U 14

Kittatiny 0.01 0.03D-U 15

King George, Bernards Township, NJ 0.01 0.03D-U 16

Lacey, Lacey, NJ 0.01 0.03D-U 17

Lakehurst, Manchester, NJ 0.01 0.03D-U 18

Lakewood, Lakewood, NJ 0.03D-U 19

Landing, Roxbury Township, NJ 0.01 0.03D-U 20

Lanes Mill, Brick Township, NJ 0.01 0.03D-U 21

Larrabee, Howell, NJ 0.01 0.03D-U 22

Laurelton, Brick Township, NJ 0.01 0.03D-U 23

Laurence Harbor, Old Bridge Township, NJ 0.01 0.03D-U 24

Lavallette, Lavallette, NJ 0.03D-U 25

Lebanon, Clinton Township, NJ 0.01 0.03D-U 26

Leisure Village 0.01 0.03D-U 27

Leisure Village, Dover Township, NJ 0.01 0.23D-U 28

Lincoln Park, Lincoln Park, NJ 0.03D-U 29

Lincroft, Middletown Township, NJ 0.01 0.03D-U 30

Little Silver, Little Silver, NJ 0.03D-U 31

Little Silver, Little Silver, NJ 0.01 0.03D-U 32

Locust Grove, Eatontown Borough, NJ 0.03D-U 33

Long Branch, Long Branch, NJ 0.03D-U 34

Lyons, Lyons, NJ 0.01 0.03D-U 35

Manasquan, Manasquan, NJ 0.03D-U 36

Manitou, Berkeley Township, NJ 0.01 0.03D-U 37

Mantoloking, Mantoloking, NJ 0.03D-U 38

Matawan, Matawan, NJ 0.03D-U 39

McGraw-Hill, East Windsor Township, NJ 0.01 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


McGraw-Hill, East Windsor Township, NJ 0.03D-U 1

McGuire, New Hanover Township, NJ 0.01 0.03D-U 2

Mendham, Mendham, NJ 0.01 0.03D-U 3

Metedeconk, Lakewood Township, NJ 0.01 0.03D-U 4

Middletown, Middletown, NJ 0.01 0.03D-U 5

Mid-Monmouth, Tinton Falls Borough, NJ 0.01 0.03D-U 6

Millburn, Milburn, NJ 0.03D-U 7

Millhurst, Manalapan Township, NJ 0.01 0.03D-U 8

Mon Consol Water, Middletown Township, NJ 0.01 0.03D-U 9

Monmouth Beach, Monmouth Beach, NJ 0.01 0.03D-U 10

Monmouth Beach, Monmouth Beach, NJ 0.03D-U 11

Monroe, Monroe, NJ 0.01 0.03D-U 12

Montville, Montville, NJ 0.01 0.03D-U 13

Morris Park 0.01 0.03D-U 14

Morris Park,Lopatcong Township,NJ 0.03D-U 15

Morris Plains, Morris Plains, NJ 0.03D-U 16

Morristown, Morristown, NJ 0.01 0.03D-U 17

Motts Corner, Berkeley Township, NJ 0.01 0.03D-U 18

Mountain, Warren Township, NJ 0.01 0.03D-U 19

Mt. Arlington, Mt. Arlington, NJ 0.01 0.03D-U 20

Mt. Arlington, Mt. Arlington, NJ 0.03D-U 21

Mt. Fern, Randolph Township, NJ 0.01 0.03D-U 22

Mt. Pleasant, East Hanover Township, NJ 0.01 0.03D-U 23

Neptune, Neptune City Borough, NJ 0.03D-U 24

Neshanic, Branchburg Township, NJ 0.01 0.03D-U 25

Neshanic, Branchburg Township, NJ 0.03D-U 26

Netcong, Netcong, NJ 0.01 0.03D-U 27

Netcong, Netcong, NJ 0.01 0.03D-U 28

New Canton, Washington Township, NJ 0.01 0.03D-U 29

New Lisbon, Pemberton Township, NJ 0.01 0.03D-U 30

New Prospect, Jackson, NJ 0.01 0.03D-U 31

New Prospect, Jackson, NJ 0.01 0.03D-U 32

New Providence, New Providence, NJ 0.03D-U 33

Newburgh, Washington Township, NJ 0.01 0.03D-U 34

North Branch, Readington Township, NJ 0.01 0.03D-U 35

North Newton, Newtown, NJ 0.03D-U 36

Ocean Beach, Dover Township, NJ 0.03D-U 37

Okner, Livingston Township, NJ 0.01 0.03D-U 38

Old Bridge, East Brunswick Township, NJ 0.03D-U 39

Old Bridge, East Brunswick Township, NJ 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


Old York, Branchburg Township, NJ 0.01 0.03D-U 1

Ortley Beach, Dover Township, NJ 0.01 0.03D-U 2

Ortley Beach, Dover Township,NJ 0.03D-U 3

Parsippany-Troy Hills Township, NJ 0.01 0.03D-U 4

Peapack, Peapack, NJ 0.01 0.03D-U 5

Pequannock, Pequannock, NJ 0.01 0.03D-U 6

Pequannock, Pequannock, NJ 0.03D-U 7

Pequest River, Belvidere Township, NJ 0.01 0.03D-U 8

Perryville, Union Township, NJ 0.01 0.03D-U 9

Phillipsburg, Phillipsburg, NJ 0.03D-U 10

Pine Beach, Pine Beach, NJ 0.01 0.03D-U 11

Pine Beach, Pine Beach, NJ 0.03D-U 12

Pinewald, Berkeley Township, NJ 0.03D-U 13

Pinewald, Berkeley Township, NJ 0.01 0.03D-U 14

Pleasant Plains, Dover Township, NJ 0.01 0.03D-U 15

Point Pleasant, Point Pleasant, NJ 0.01 0.03D-U 16

Point Pleasant, Point Pleasant, NJ 0.03D-U 17

Pompton Lakes, Pompton Lakes, NJ 0.03D-U 18

Pompton Plains, Pequannock Township, NJ 0.03D-U 19

Poplar, Ocean Township, NJ 0.01 0.03D-U 20

Princeton Road, East Windsor, NJ 0.03D-U 21

Raceway Mall, Freehold Township, NJ 0.01 0.03D-U 22

Readington, Bridgewater Township, NJ 0.01 0.03D-U 23

Reclamation, Shrewsbury, NJ 0.03D-U 24

Red Bank, Red Bank, NJ 0.03D-U 25

Ridge, Bernards Township, NJ 0.01 0.03D-U 26

Ringoes, East Amwell, NJ 0.01 0.03D-U 27

Ringoes, East Amwell, NJ 0.01 0.03D-U 28

Riverdale, Riverdale, NJ 0.01 0.03D-U 29

Riverdale, Riverdale, NJ 0.03D-U 30

Rockaway, Rockaway Borough, NJ 0.03D-U 31

Rocktown Road, West Amwell, NJ 0.03D-U 32

Rumson, Rumson, NJ 0.03D-U 33

Sayrewoods, Old Bridge, NJ 0.01 0.03D-U 34

Sayreville, Sayreville, NJ 0.01 0.03D-U 35

Sayreville, Sayreville, NJ 0.01 0.03D-U 36

Sea Bright, Sea Bright Borough, NJ 0.03D-U 37

Seaside Heights, Seaside Heights, NJ 0.03D-U 38

Seaside Park, Seaside Park Borough, NJ 0.03D-U 39

Short Hills, Millburn Township, NJ 0.01 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


Short Hills, Milburn Township, NJ 0.03D-U 1

Silverton, Brick Township, NJ 0.01 0.03D-U 2

Somerset, Bridgewater Township, NJ 0.01 0.03D-U 3

South Amboy, South Amboy, NJ 0.03D-U 4

South Lakewood, Lakewood Township, NJ 0.01 0.03D-U 5

Sparta, Sparta, NJ 0.01 0.03D-U 6

Spotswood, Spotswood, NJ 0.01 0.03D-U 7

Spring Lake Heights, Spring Lake Heights, NJ 0.01 0.03D-U 8

Spring Lake Heights, Spring Lake Heights, NJ 0.03D-U 9

Stanton, Readington Township, NJ 0.01 0.03D-U 10

Stanton, Readington Township, NJ 0.03D-U 11

Stirling, Long Hill Township, NJ 0.03D-U 12

Stewartsville, Greenwich Township, NJ 0.01 0.03D-U 13

Stewartsville, Greenwich Township, NJ 0.03D-U 14

Stockton, Seagirt Boroough, NJ 0.03D-U 15

Stone Church, Middletown Township, NJ 0.01 0.03D-U 16

Summit, Summit, NJ 0.03D-U 17

Sussex 0.01 0.03D-U 18

Taylor Lane, Middletown Township, NJ 0.01 0.03D-U 19

Taylortown, Montville Township, NJ 0.01 0.03D-U 20

Texas Road, Old Bridge Township, NJ 0.01 0.03D-U 21

Thatcher, Wharton Borough, NJ 0.03D-U 22

Toms River, Dover Township, NJ 0.03D-U 23

Traynor, Summit, NJ 0.01 0.03D-U 24

Traynor, Summit, NJ 0.03D-U 25

Troy Hills, Parsippany-Troy Hills Township, NJ 0.03D-U 26

Twin Rivers, East Windsor Township, NJ 0.01 0.03D-U 27

Upton, Pemberton Township, NJ 0.01 0.03D-U 28

Valley View, New Providence Borough, NJ 0.03D-U 29

Van Hiseville, Jackson Township, NJ 0.01 0.03D-U 30

Vermont Avenue, Lakewood Township, NJ 0.03D-U 31

Vernon, Vernon, NJ 0.01 0.03D-U 32

Waretown, Ocean Township, NJ 0.01 0.03D-U 33

Wall Church, Wall Township, NJ 0.03D-U 34

Warton 0.01 0.03D-U 35

Washington, Washington Borough, NJ 0.03D-U 36

Waverly, Springfield Township, NJ 0.01 0.03D-U 37

West End, Long Branch, NJ 0.03D-U 38

West Flemington, Raritan Township, NJ 0.01 0.03D-U 39

West Flemington, Raritan Township, NJ 0.03D-U 40





End of

SUBSTATIONS


/ /2014/Q4


Primary(c)(b)(a)

Tertiary(d)


(e)Secondary

VOLTAGE (In MVa)


West Wharton, Jefferson Township, NJ 0.01 0.03D-U 1

Whippany, East Hanover Township, NJ 0.01 0.03D-U 2

Whitesville, Neptune Township, NJ 0.03D-U 3

Whitney, Morris Township, NJ 0.01 0.03D-U 4

Windsor, Washington Township, NJ 0.03D-U 5

Windsor, Washington Township, NJ 0.01 0.03D-U 6

Woodbine, West Long Branch Borough, NJ 0.01 0.03D-U 7

Woodbine, West Long Branch Borough, NJ 0.03D-U 8

Woodland, Point Pleasant Borough, NJ 0.01 0.03D-U 9

Woodland, Point Pleasant Borough, NJ 0.03D-U 10

Woodruffs Gap, Sparta Township, NJ 0.01 0.03D-U 11

Woodruffs Gap, Sparta Township, NJ 0.03D-U 12

Wyckoff Street, Wyckoff Street, NJ 0.03D-U 13

Wyckoff Street, Wyckoff Street, NJ 0.01 0.03D-U 14

Subtotal 1.84 9.36 15

16

Total 4.68 23.63 0.02 17

18

Quantities listed below by functional character 19

2-Stepup - Unattended (T-U-G) 20

67-Transmission-Unattended (T-U) 21

238-Distribution-Unattended (D-U) 22

65 < 10 MVA 23

372 TOT. SYSTEM 24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40





End of

SUBSTATIONS


/ /2014/Q4

Line No.Number of Units

(g)(f) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

(Continued)

Capacity of Substation(In Service) (In MVa)

Number ofTransformers

In ServiceSpare

Type of Equipment

Number of

Transformers (In MVa)(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment forincreasing capacity.6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than byreason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date andperiod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give nameof co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accountsaffected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

216 3 1

20 1 2

236 4 3

125 1 4

130 1 5

90 1 6

148 2 7

250 2 8

180 2 9

128 2 10

1740 2 11

125 1 12

250 2 13

50 1 14

224 1 15

50 1 16

114 2 17

114 2 18

375 3 2 19

110 2 20

125 1 21

1 22

100 2 23

250 2 1 24

270 3 25

293 2 26

500 1 27

75 1 28

224 1 29

375 3 30

110 2 3 31

125 1 32

250 2 1 33

28 2 34

125 1 35

503 5 36

470 4 37

50 1 38

125 1 39

250 2 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



155 3 1

275 4 2

293 2 3

351 4 4

114 2 5

125 1 6

448 2 7

50 1 8

90 1 9

250 2 10

500 4 1 11

870 1 12

125 1 13

55 1 14

55 1 15

14 1 16

500 4 17

128 2 18

88 1 19

224 1 20

375 3 21

168 1 22

14 1 23

200 1 24

336 2 25

250 2 26

50 2 27

90 3 28

255 2 29

29 2 30

14928 123 9 31

25 1 32

40 2 33

40 2 34

40 2 35

40 2 36

20 1 37

20 1 38

9 1 39

9 1 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



9 1 1

20 1 2

20 1 3

40 2 4

6 1 5

8 1 6

20 1 7

9 1 8

9 1 9

26 2 10

9 1 11

20 1 12

13 2 13

20 1 14

19 2 15

9 1 16

20 1 17

28 3 18

40 2 19

20 1 20

19 2 21

19 2 22

40 2 23

33 3 24

19 2 25

20 2 26

19 2 27

9 1 28

20 1 29

40 2 30

5 1 31

4 1 32

12 1 33

19 2 34

40 2 35

40 2 36

20 1 37

25 1 38

28 2 39

40 2 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



40 2 1

14 1 2

2 1 3

40 2 4

8 1 5

20 1 6

6 1 7

40 2 8

25 1 9

2 3 10

40 2 11

40 2 12

6 1 13

9 1 14

39 2 15

45 2 16

40 2 17

40 2 18

20 1 19

8 1 20

28 2 21

40 2 22

19 2 23

20 1 24

20 1 25

29 2 26

19 2 27

11 1 28

19 2 29

50 2 30

19 2 31

40 2 32

19 2 33

19 2 34

20 1 35

9 1 36

19 3 37

20 1 38

19 2 39

40 2 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



20 1 1

9 1 2

34 2 3

20 1 4

20 1 5

9 1 6

40 2 7

12 1 8

10 1 9

65 3 10

40 2 11

20 1 12

19 2 13

40 1 14

9 1 15

23 2 16

12 2 1 17

26 2 18

40 2 19

40 2 20

80 2 21

20 1 22

40 2 23

20 1 24

40 2 25

23 2 26

110 2 1 27

19 2 28

40 2 29

14 1 30

5 1 31

29 2 32

19 2 33

40 2 34

20 1 35

25 1 36

6 1 37

40 2 38

20 1 39

60 3 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



9 1 1

14 1 2

60 3 3

40 2 4

6 1 5

6 1 6

20 1 7

8 1 8

20 1 9

9 1 10

40 2 11

9 1 12

20 1 13

13 2 14

14 1 15

20 1 16

40 2 17

9 1 18

40 2 19

29 2 20

20 1 21

10 1 2 22

40 2 23

14 2 24

18 2 25

20 1 26

20 1 27

70 2 28

29 2 29

40 2 30

9 1 31

25 1 32

28 3 33

18 2 34

25 1 35

19 2 36

40 2 37

8 1 38

13 2 39

9 1 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



9 1 1

40 2 2

40 2 3

40 2 4

40 2 5

40 2 6

40 2 7

40 2 8

20 1 9

8 1 10

8 1 11

60 3 12

9 1 13

20 1 14

9 1 15

12 2 16

125 4 17

19 2 18

34 2 19

20 1 20

9 1 21

39 2 22

45 2 23

30 3 24

20 1 25

6 1 26

40 2 27

9 1 28

14 1 29

40 2 30

22 1 31

14 1 32

19 2 33

40 2 34

40 2 35

23 2 36

29 2 37

40 2 38

20 1 39

18 2 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



20 1 1

20 1 2

6 1 3

60 2 4

25 1 5

20 1 6

9 1 7

23 2 8

20 1 9

28 3 10

20 1 11

9 1 12

9 1 13

14 1 14

40 2 15

29 2 16

40 2 17

29 2 18

19 2 19

40 2 20

9 1 21

20 2 22

12 1 23

6 1 24

42 2 25

30 2 26

20 1 27

9 1 28

24 2 29

9 1 30

19 2 31

19 2 32

18 2 33

6 1 34

13 2 35

12 1 36

6 1 37

20 1 38

22 2 39

10 1 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



9 1 1

40 2 2

40 2 3

9 1 4

80 2 5

40 2 6

40 2 1 7

20 1 8

13 2 9

9 1 10

6 1 11

21 2 12

14 1 13

9 1 14

14 2 15

18 1 16

30 2 17

14 1 18

20 2 19

20 1 20

60 2 21

19 2 22

30 2 23

15 1 24

17 2 25

35 2 26

25 2 27

20 2 28

19 2 29

19 2 30

14 1 31

35 2 32

35 3 33

14 1 34

20 1 35

30 2 36

35 1 37

19 1 38

25 1 39

9 1 40





End of

SUBSTATIONS


/ /2014/Q4


(g)(f) (h)


(k)

Total Capacity

(Continued)



In ServiceSpare

Type of Equipment

Number of



5 1

25 1 2

10 1 3

20 1 4

9 1 5

20 1 6

20 1 7

9 1 8

20 1 9

9 1 10

15 1 11

5 1 12

9 1 13

20 1 14

7229 467 10 15

16

22393 594 19 17

18

19

236 4 20

14928 123 9 21

6972 405 10 22

493 66 23

22629 598 19 24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40


Schedule Page: 426 Line No.: 1 Column: aJersey Central Power & Light Company shares ownership of certain substation structures and equipment at Yards Creek GeneratingStation with Public Service Electric & Gas on a 50% basis. Line No. 1, Column (f), Capacity of Substation, represents the respondents50% share.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA





End of

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES


/ /2014/Q4

Line No. Description of the Non-Power Good or Service

Name of

(c)(b)(a) (d)

Associated/AffiliatedCompany

AccountCharged or

Credited

Amount

Credited

1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to

an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt to include or aggregate amounts in a nonspecific category such as "general".

3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.

Charged or

1 Non-power Goods or Services Provided by Affiliated

2 Provide Chairman of the Board Support 221FirstEnergy Service Co. Various

3 Provide Chief Executive Officer Support 286,381FirstEnergy Service Co. Various

4 Provide President of FirstEnergy Utilities Support 604,738FirstEnergy Service Co. Various

5 Provide Transmission & Distribution Support 18,482,709FirstEnergy Service Co. Various

6 Provide Utility Operations Support 178,557FirstEnergy Service Co. Various

7 Provide Compliance & Regulated Services Support 1,166,321FirstEnergy Service Co. Various

8 Provide Customer Service Support 14,454,926FirstEnergy Service Co. Various

9 Provide Energy Efficiency Support 431,273FirstEnergy Service Co. Various

10 Provide Environmental Support 2,274,853FirstEnergy Service Co. Various

11 Provide Finance, Strategic Planning &

12 Operations Support 8,165FirstEnergy Service Co. Various

13 Provide Corporate Services &

14 Chief Information Officer Support 18,892,682FirstEnergy Service Co. Various

15 Provide Supply Chain Support 526,809FirstEnergy Service Co. Various

16 Provide Accounting Support 6,999,327FirstEnergy Service Co. Various

17 Provide Treasury Support 437,150FirstEnergy Service Co. Various

18 Provide Business Development &

19 Integrated System Planning Support 124,917FirstEnergy Service Co. Various

20 Non-power Goods or Services Provided for Affiliate

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42


2 Provide Corporate Risk Support 835,176FirstEnergy Service Co. Various

FERC FORM NO. 1 (New) Page 429FERC FORM NO. 1-F (New)




End of



/ /2014/Q4


Name of

(c)(b)(a) (d)


AccountCharged or

Credited

Amount

Credited




Charged or

3 Provide Internal Audit Support 509,106FirstEnergy Service Co. Various

4 Provide Legal Department Support 4,853,241FirstEnergy Service Co. Various

5 Provide Rates & Regulatory Affairs Support 1,507,063FirstEnergy Service Co. Various

6 Provide Corp/Real Estate Record Management Support 2,822,104FirstEnergy Service Co. Various

7 Provide Corporate Affairs Support 1,667,301FirstEnergy Service Co. Various

8 Provide External Affairs & Communication Support 1,592,600FirstEnergy Service Co. Various

9 Provide Federal, State & Local Affairs &

10 Energy Policy & Economic Development Support 520,267FirstEnergy Service Co. Various

11 Provide Human Resources Support 7,244,730FirstEnergy Service Co. Various

12 Interest Income - Carrying Charges on

13 Service Company Assets -5,402,423FirstEnergy Service Co. 419

14 Interest Expense - Regulated Money Pool 1,231,448FirstEnergy Corp. 430

15 Rent - Wadsworth Facility 660,189ATSI 567

16 Rent - Akron Control Facility 675,825ATSI 567

17 Rent - Pottsville Pike 860,246Metropolitan Edison 588

18 Rent - Fairmont Call Center 456,348Monongahela Power 588

19 Rent - Greensburg Corporate Center 776,518West Penn Power 588


21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42


2 Transmission Charge -TMI Unit 1 1,998,563Metropolitan Edison 567

3 Transmission Investment Power Pool Agreement 1,762,524Metropolitan Edison 567

4 TMI Charges for Miscellaneous General and

FERC FORM NO. 1 (New) Page 429.1FERC FORM NO. 1-F (New)




End of



/ /2014/Q4


Name of

(c)(b)(a) (d)


AccountCharged or

Credited

Amount

Credited




Charged or

5 Outside Services 387,831GPU Nuclear, Inc. 253

6

7 Allocation Factors

8

9

10

11

12

13

14

15

16

17

18

19


21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

FERC FORM NO. 1 (New) Page 429.2FERC FORM NO. 1-F (New)

Schedule Page: 429 Line No.: 2 Column: cAccount Amount

Provide Chairman of the Board Support 593 $ 4 Cost Allocation Factors Used - Direct, MA 923 102

107 105 108 8 143 1 185 1

$ 221


Provide Chief Executive Officer Support 593 $ 5,728 Cost Allocation Factors Used - Direct, MA 923 126,007

107 142,274 108 10,825 143 1,547

$ 286,381


Provide President of FirstEnergy Utilities Support 593 $ 12,095 Cost Allocation Factors Used - MU 923 260,037

107 305,998 108 23,282 185 3,326

$ 604,738


Provide Transmission & Distribution Support 566 $ 184,827 Cost Allocation Factors Used - Direct, MU, ST, TX 568 2,033,098

570 184,827 571 184,828 580 (554,481)586 739,308 588 3,142,061 590 554,481 592 369,654 593 554,481 905 369,654 923 184,827 107 9,797,684 108 632,109 186 105,351

$ 18,482,709


Provide Utility Operations Support 588 $ 141,060 Cost Allocation Factors Used - Direct, MU 905 35,711

107 1,786 $ 178,557

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA



Provide Compliance & Regulated Services Support 557 $ 81,642 Cost Allocation Factors Used - Direct, MT, MU, TX 561.7 11,663

566 443,202 568 268,254 571 23,326 923 139,959 107 188,361 108 7,931 143 1,983

$ 1,166,321


Provide Customer Service Support 593 $ 144,549 Cost Allocation Factors Used - Direct, CR, MU 902 144,549

903 3,324,633 908 144,549 910 9,106,603 923 144,550 107 1,300,944 108 144,549

$ 14,454,926


Provide Energy Efficiency Support 416 $ 38,815 Cost Allocation Factors Used - CR, MU 903 306,204

908 8,625 923 25,876 107 11,903 108 (1,553)186 41,403

$ 431,273


Provide Environmental Support 571 $ 45,497 Cost Allocation Factors Used - Direct, ENV, MT, MU 588 250,234

593 90,994 923 932,690 107 850,340 108 57,326 143 38,218 185 9,554

$ 2,274,853


Provide Finance, Strategic Planning & Operations Support 923 $ 3,593 Cost Allocation Factors Used - MA 107 4,298

108 183 143 91

$ 8,165

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA



Provide Corporate Services & Chief Information Officer Support 569.2 $ 188,927 Cost Allocation Factors Used - Direct, CR, DW, GUS, 569.3 377,854 MA, MN, MT, MU, NIS, NS 593 188,927 PV, SSC, WS1, WS2 598 2,644,975

903 1,322,488 923 5,667,805 107 7,991,604 108 340,068 143 170,034

$ 18,892,682


Provide Supply Chain Support 543 $ 5,268 Cost Allocation Factors Used - Direct, MA, MN, MT, MU 593 10,536

923 194,920 107 278,155 108 22,126 143 15,804

$ 526,809


Provide Accounting Support 593 $ 69,993 Cost Allocation Factors Used - Direct, HC, MA, MN, MT, MU, PE 923 5,109,509

107 1,637,843 108 127,388 143 54,594

$ 6,999,327


Provide Treasury Support 593 $ 4,372 Cost Allocation Factors Used - Direct, MA, MN, MU, PE 923 192,345

107 223,603 108 14,426 143 2,404

$ 437,150


Provide Business Development & Integrated System Planning Support 593 $ 1,249 Cost Allocation Factors Used -MA, MN, MU 923 77,449

107 39,748 108 2,311 143 4,160

$ 124,917

Schedule Page: 429.1 Line No.: 2 Column: cAccount Amount

Provide Corporate Risk Support 593 $ 16,704 Cost Allocation Factors Used - MA, MN, MT, MU 923 367,477

107 414,915 108 31,570 143 4,510

$ 835,176

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA



Provide Internal Audit Support 588 $ 5,091 Cost Allocation Factors Used - Direct, MA, MN, MU 593 10,182

923 244,371 107 229,505 108 17,462 143 2,495

$ 509,106


Provide Legal Department Support 566 $ 48,532 Cost Allocation Factors Used - Direct, MA, MN, MU 923 3,931,126

107 812,432 108 52,415 143 8,736

$ 4,853,241


Provide Rates & Regulatory Affairs Support 566 $ 15,071 Cost Allocation Factors Used - Direct, CR, MU 593 15,070

923 708,320 107 722,486 108 46,116

$ 1,507,063


Provide Corp/Real Estate, Record Management Support 593 $ 56,442 Cost Allocation Factors Used - Direct, MA, MN, MT, MU, SF 923 1,072,400

107 1,443,506 108 93,129 143 15,522 935 141,105

$ 2,822,104


Provide Corporate Affairs Support 923 $ 1,633,955 Cost Allocation Factors Used - Direct, MA, MU 107 19,341

108 1,334 143 12,671

$ 1,667,301


Provide External Affairs & Communication Support 593 $ 15,926 Cost Allocation Factors Used - Direct, MA, MN, MT, MU 923 1,178,524

107 358,335 108 27,871 143 11,944

$ 1,592,600

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA



Provide Federal, State & Local Affairs & 593 $ 5,203 Energy Policy Support & Economic Development Support 923 327,768 Cost Allocation Factors Used - Direct, DW MT, MU, SH 107 172,312

108 13,111 185 1,873

$ 520,267


Provide Human Resources Support 593 $ 72,447 Cost Allocation Factors Used - Direct, HC, MA, MN, MU 923 5,361,100

107 1,630,065 108 126,783 143 54,335

$ 7,244,730


Inventory Carrying Charges 419 $ (5,402,423)Cost Allocation Factors Used - Direct

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


Schedule Page: 429.2 Line No.: 7 Column: aFactor Abbreviations

MA Multiple Factor – AllMN Multiple Factor Non-UtilityMT Multiple Factor Utility & Non-UtilityMU Multiple Factor UtilityTX Multiple Factor Utility - TransmissionCR Customer RatioDW Development WorkENV Environmental FactorGS Gigabytes SAPGUS Gigabytes UnixHC Head CountIS Inserting ServiceNIS Number of Intel ServicesNS Network Services PE Participating Employees PV Print VolumeSF Square FootageSH Shopping CustomersSSC Server Support CompositeST Stores FactorWS1 Workstation SupportWS2 Number of Work Stations

‘Direct’ indicates that 100% of the costs assess to one legal entity

MA – Each Subsidiary benefiting from receiving the product or service will be charged a proportion of the Indirect Costs. TheFirstEnergy Holding Co bears 5% of the product or service costs being allocated. The remaining 95% of the costs will be allocatedbetween the Utility and Non-Utility Subsidiaries based on FirstEnergy’s equity investment in the respective groups. A subsequent stepthen allocates among the Utility Subsidiaries based upon the “Multiple Factor - Utility” (MU) method and among the Non-UtilitySubsidiaries based upon the “Multiple Factor - Non-Utility” (MN) method, both explained below.

MN – Each Non-Utility Subsidiary benefiting from receiving the product or service will be charged a proportion of the Indirect Costsbased upon the total assets of each Non-Utility Subsidiary, including the generating assets under operating leases to the UtilitySubsidiaries.

MT – The product or service costs being charged are allocated 100% between Utility and Non-Utility Subsidiaries in the same manneras MA above. Unlike MA, FirstEnergy Holding Co does not bear any of the allocation.

MU – Each Utility Subsidiary benefiting from receiving the product or service will be charged a proportion of the Indirect Costs basedupon the sum of the weighted averages of (1) Gross transmission and/or distribution plant; (2) Operating and maintenance expenseexcluding purchase power and fuel costs: and (3) Transmission and/or distribution revenues, excluding transactions with affiliates. Each of the 3 components is weighted equally.

TX – Each Utility Subsidiary benefiting from receiving the product or service will be charged a proportion of the Indirect Costs basedupon the sum of the weighted averages of (1) Gross transmission plant; (2) Operating and maintenance expense excluding purchasepower and fuel costs: and (3) Transmission revenues, excluding transactions with affiliates. Each of the 3 components is weightedequally.

Name of Respondent




/ /


2014/Q4

FOOTNOTE DATA


INDEX

Schedule Page No.

Accrued and prepaid taxes ........................................................................ 262-263

Accumulated Deferred Income Taxes .................................................................... 234

272-277

Accumulated provisions for depreciation of

common utility plant ............................................................................. 356

utility plant .................................................................................... 219

utility plant (summary) ...................................................................... 200-201

Advances

from associated companies .................................................................... 256-257

Allowances ....................................................................................... 228-229

Amortization

miscellaneous .................................................................................... 340

of nuclear fuel .............................................................................. 202-203

Appropriations of Retained Earnings .............................................................. 118-119

Associated Companies

advances from ................................................................................ 256-257

corporations controlled by respondent ............................................................ 103

control over respondent .......................................................................... 102

interest on debt to .......................................................................... 256-257

Attestation ............................................................................................ i

Balance sheet

comparative .................................................................................. 110-113

notes to ..................................................................................... 122-123

Bonds ............................................................................................ 256-257

Capital Stock ........................................................................................ 251

expense .......................................................................................... 254

premiums ......................................................................................... 252

reacquired ....................................................................................... 251

subscribed ....................................................................................... 252

Cash flows, statement of ......................................................................... 120-121

Changes

important during year ........................................................................ 108-109

Construction

work in progress - common utility plant .......................................................... 356

work in progress - electric ...................................................................... 216

work in progress - other utility departments ................................................. 200-201

Control

corporations controlled by respondent ............................................................ 103

over respondent .................................................................................. 102

Corporation

controlled by .................................................................................... 103

incorporated ..................................................................................... 101

CPA, background information on ....................................................................... 101

CPA Certification, this report form ................................................................. i-ii

FERC FORM NO. 1 (ED. 12-93) Index 1

INDEX (continued)

Schedule Page No.Deferred

credits, other ................................................................................... 269

debits, miscellaneous ............................................................................ 233

income taxes accumulated - accelerated

amortization property ........................................................................ 272-273

income taxes accumulated - other property .................................................... 274-275

income taxes accumulated - other ............................................................. 276-277

income taxes accumulated - pollution control facilities .......................................... 234

Definitions, this report form ........................................................................ iii

Depreciation and amortization

of common utility plant .......................................................................... 356

of electric plant ................................................................................ 219

336-337

Directors ............................................................................................ 105

Discount - premium on long-term debt ............................................................. 256-257

Distribution of salaries and wages ............................................................... 354-355

Dividend appropriations .......................................................................... 118-119

Earnings, Retained ............................................................................... 118-119

Electric energy account .............................................................................. 401

Expenses

electric operation and maintenance ........................................................... 320-323

electric operation and maintenance, summary ...................................................... 323

unamortized debt ................................................................................. 256

Extraordinary property losses ........................................................................ 230

Filing requirements, this report form

General information .................................................................................. 101

Instructions for filing the FERC Form 1 ............................................................. i-iv

Generating plant statistics

hydroelectric (large) ........................................................................ 406-407

pumped storage (large) ....................................................................... 408-409

small plants ................................................................................. 410-411

steam-electric (large) ....................................................................... 402-403

Hydro-electric generating plant statistics ....................................................... 406-407

Identification ....................................................................................... 101

Important changes during year .................................................................... 108-109

Income

statement of, by departments ................................................................. 114-117

statement of, for the year (see also revenues) ............................................... 114-117

deductions, miscellaneous amortization ........................................................... 340

deductions, other income deduction ............................................................... 340

deductions, other interest charges ............................................................... 340

Incorporation information ............................................................................ 101

Index 2FERC FORM NO. 1 (ED. 12-95)

INDEX (continued)

Schedule Page No.

Interest

charges, paid on long-term debt, advances, etc ............................................... 256-257

Investments

nonutility property .............................................................................. 221

subsidiary companies ......................................................................... 224-225

Investment tax credits, accumulated deferred ..................................................... 266-267

Law, excerpts applicable to this report form .......................................................... iv

List of schedules, this report form .................................................................. 2-4

Long-term debt ................................................................................... 256-257

Losses-Extraordinary property ........................................................................ 230

Materials and supplies ............................................................................... 227

Miscellaneous general expenses ....................................................................... 335

Notes

to balance sheet ............................................................................. 122-123

to statement of changes in financial position ................................................ 122-123

to statement of income ....................................................................... 122-123

to statement of retained earnings ............................................................ 122-123

Nonutility property .................................................................................. 221

Nuclear fuel materials ........................................................................... 202-203

Nuclear generating plant, statistics ............................................................. 402-403

Officers and officers' salaries ...................................................................... 104

Operating

expenses-electric ............................................................................ 320-323

expenses-electric (summary) ...................................................................... 323

Other

paid-in capital .................................................................................. 253

donations received from stockholders ............................................................. 253

gains on resale or cancellation of reacquired

capital stock .................................................................................... 253

miscellaneous paid-in capital .................................................................... 253

reduction in par or stated value of capital stock ................................................ 253

regulatory assets ................................................................................ 232

regulatory liabilities ........................................................................... 278

Peaks, monthly, and output ........................................................................... 401

Plant, Common utility

accumulated provision for depreciation ........................................................... 356

acquisition adjustments .......................................................................... 356

allocated to utility departments ................................................................. 356

completed construction not classified ............................................................ 356

construction work in progress .................................................................... 356

expenses ......................................................................................... 356

held for future use .............................................................................. 356

in service ....................................................................................... 356

leased to others ................................................................................. 356

Plant data ...................................................................................336-337

401-429


INDEX (continued)

Schedule Page No.Plant - electric

accumulated provision for depreciation ........................................................... 219

construction work in progress .................................................................... 216

held for future use .............................................................................. 214

in service ................................................................................... 204-207

leased to others ................................................................................. 213

Plant - utility and accumulated provisions for depreciation

amortization and depletion (summary) ............................................................. 201

Pollution control facilities, accumulated deferred

income taxes ..................................................................................... 234

Power Exchanges .................................................................................. 326-327

Premium and discount on long-term debt ............................................................... 256

Premium on capital stock ............................................................................. 251

Prepaid taxes .................................................................................... 262-263

Property - losses, extraordinary ..................................................................... 230

Pumped storage generating plant statistics ....................................................... 408-409

Purchased power (including power exchanges) ...................................................... 326-327

Reacquired capital stock ............................................................................. 250

Reacquired long-term debt ........................................................................ 256-257

Receivers' certificates .......................................................................... 256-257

Reconciliation of reported net income with taxable income

from Federal income taxes ...................................................................... 261

Regulatory commission expenses deferred .............................................................. 233

Regulatory commission expenses for year .......................................................... 350-351

Research, development and demonstration activities ............................................... 352-353

Retained Earnings

amortization reserve Federal ..................................................................... 119

appropriated ................................................................................. 118-119

statement of, for the year ................................................................... 118-119

unappropriated ............................................................................... 118-119

Revenues - electric operating .................................................................... 300-301

Salaries and wages

directors fees ................................................................................... 105

distribution of .............................................................................. 354-355

officers' ........................................................................................ 104

Sales of electricity by rate schedules ............................................................... 304

Sales - for resale ............................................................................... 310-311

Salvage - nuclear fuel ........................................................................... 202-203

Schedules, this report form .......................................................................... 2-4

Securities

exchange registration ........................................................................ 250-251

Statement of Cash Flows .......................................................................... 120-121

Statement of income for the year ................................................................. 114-117

Statement of retained earnings for the year ...................................................... 118-119

Steam-electric generating plant statistics ....................................................... 402-403

Substations .......................................................................................... 426

Supplies - materials and ............................................................................. 227


INDEX (continued)

Schedule Page No.Taxes

accrued and prepaid ......................................................................... 262-263

charged during year ......................................................................... 262-263

on income, deferred and accumulated ............................................................. 234

272-277

reconciliation of net income with taxable income for ............................................ 261

Transformers, line - electric ....................................................................... 429

Transmission

lines added during year ..................................................................... 424-425

lines statistics ............................................................................ 422-423

of electricity for others ................................................................... 328-330

of electricity by others ........................................................................ 332

Unamortized

debt discount ............................................................................... 256-257

debt expense ................................................................................ 256-257

premium on debt ............................................................................. 256-257

Unrecovered Plant and Regulatory Study Costs ........................................................ 230


ANNUAL REPORT

OF


NAME OF RESPONDENT

300 Madison Ave., Morrisotown, New Jersey 07962

ADDRESS OF RESPONDENT

TO THE

STATE OF NEW JERSEY

BOARD OF PUBLIC UTILITIES

44 SOUTH CLINTON AVENUE, 9TH FLOOR,

POST OFFICE BOX 350

TRENTON, NEW JERSEY 07102

FOR THE YEAR ENDED DECEMBER 31, 2014

Name of Officer in charge of correspondence

with the Board regarding this report _M_ a_r _le_n_e _A_._B_a_��o _o _d��

Official Title Controller Office Address 76 South Main St., Akron, OH 44308

Name and Address of Registered Agent

State of New Jersey

Board of Public Utilities

44 South Clinton Avenue, 9th Floor,

Post Office Box 350

Trenton, New Jersey 08625

IDENTIFICATION

01 Exact Legal Name of Respondent: 02 Year of Report:

Jersey Centeral Power & Light Company December 31, 2014

03 Previous Name and Date of Change (If name changed during year):

04 Address of Principal Office at End of Year (Street, City, State, Zip Code):

76 South Main St., Akron, OH 44308

05 Web Address of the Company:

www.firstenergycorp.com

07 Name of Contact Person:

Marlene A. Barwood

06 Federal ID# of Respondent:

21-0485010

08 Title of Contact Person:

Controller

09 Address of Contact Person (Street, City, State, Zip Code): 76 South Main St., Akron, OH 44308

10 Telephone # of Contact Person:

330-384-4596

12 E-Address Address of Contact Person

11 Fax Number of Contact Person:

330-384-7986

[email protected]

13 This Original Report is due on March 31, 2014; It is Filed on April 24, 2015 .

14 This is a Resubmission Report. Date Filed on (Month, Date, Year)

CORPORATE OFFICER CERTIFICATION

The undersigned officer certifies that:

I have read this New Jersey Board of Public Utilities ("Board") Annual Financial Report which is prescribed

by the Federal Energy Regulatory Commission ("FERC") and adopted by the Board. Based on my knowledge

this report does not contain any untrue statement of material fact or omit to state a material fact necessary to

make the statements made, in light of the circumstances such statements were made, not misleading with

respect to the period covered by this report.

Based on my knowledge the financial statements, and other financial information (Comparative Balance

Sheet, Statement of Income for the Year, Statement of Retained Earnings for the Year, Statement of Cash

Flows, Statement of Accumulated Comprehensive Income and Hedging Activities, and Notes to the Financial

Statements) included in this report conform in all material respects with the FERC's Uniform System of

Accounts, as of, and for, the periods presented in this report.

I am responsible for establishing and maintaining internal accounting controls as defined by the FERC. I

have designed such internal accounting controls to ensure that material information relating to the respondent

and its subsidiaries, to the extent that the respondent has subsidiaries, is made known to me by others within

those entities, particularly during the period in which this report is being prepared. I have evaluated the

effectiveness of internal accounting controls as of a date within 90 days prior to the period in which this report

(evaluation date). I have presented in this report my conclusions about the effectiveness of the internal

accounting controls based on my evaluation as of the evaluation date.

I have disclosed, based on my most recent evaluation, to the respondent's auditors and the audit

committee or persons performing similar functions, to the extent that respondent has an audit committee or

persons performing similar functions, that all significant deficiencies in the design or operation of internal

accounting control which could adversely affect the respondent's ability to record, process, summarize and

report financial data and have identified for the respondent's auditors any material weaknesses in disclosure

controls and procedures and any fraud, whether or not material, that involves management or other

employees who have a significant role in the respondent's internal accounting controls.

I have indicated in this report whether or not there were significant changes in internal accounting control

and procedures or in other factors that could significantly affect internal accounting controls and procedures

subsequent to the date of my most recent evaluation, including any corrective actions with regard to

significant deficiencies and material weaknesses.

In addition, I have examined the remaining schedules contained in this report; to the best of my knowledge,

information, and belief all statements of fact contained in this report are correct statements of the business

affairs of the respondent and the financial statements, and other financial information contained in this report,

conform in all material respect to the Uniform System of Accounts.

15 Name: 16 Title:

Marlene A. Barwood Controller

18 Date Signed:

April 24, 2015

Name of Respondent:


This Report is: [ X ] An Original [ ] A Resubmission


Annual Report for the Year ended

December 31, 2014.

Enter in Remarks column the term "none", "not applicable", or "NA" as appropriate, where no information or amounts have been reported for certain pages. Please do not omit

pages the responses are "none", "not applicable" or "NA".

I Line #I ._I ________ T_ i _tl _e _o_f _S_c_h_e_d_u_le _______ ----11 I Reference Page No. I I Revised on I I Remarks

GENERAL CORPORATE INFORMATION AND FINANCIAL STATEMENTS: General Information

2 Control over Respondent 3 Corporation Controlled by Respondent 4 Officers 5 Directors

Information on Formula Rates: 6 -FERC Rate Schedule/Tariff Number & Proceeding 7 -Formula Rate Variances 8 Security Holders and Voting Powers 9 Important Changes During the Year

Comparative Balance Sheet: 10 -Assets and Other Debits 11 -Liabilities and Other Credits 12 Statement of Income for the Year 13 Statement of Retained Earnings 14 Statement of Cash Flows 15 Notes to Financial Statements

Statement of Accumulated Comprehensive Income, 16 Comprehensive Income, & Hedging Activites

BALANCE SHEET SUPPORTING SCHEDULES -ASSETS AND OTHER DEBITS

17 Summary of Utility Plant and Accumulated Provision for Depreciation, Amortizatin, and Depletion

18 19 20 21 22 23

Nuclear Fuel Materials (Acct. 120.1 to 120.6 & 157) Electric Plant in Service (Acct. 101, 102, 103, and 106) Electric Plant Leased to Others (Acct. 104) Electric Plant Held for Future Use (Acct. 105) Construction Work in Progress (Acct. 107) Construction Overheads - Electric

24 General Description of Construction Overhead Procedure

25

26

27 28 29 30 31 32 33 34

35 36 37

Computation of Ailowence for Funds Used During Construction Rates Accumulated Provision for Depreciation of Electric Utility Plant (Acct. 108) Non utility Property (Acct. 121) Investments (Acct. 123, 124 and 136) Investments in Subsidiary Companies (Acct. 123.1) Materials and Supplies Allowances (Acct. 158.1 and 158.2) Extraordinary Property Losses (Acct. 182.1) Unrecovered Plant & Regulatory Study Costs (182.2) Transmission Service and Generation Interconnection Study Costs Other Regulatory Assets (Acct. 182.3) Miscellaneous Deferred Debits (Acct. 186) Accumulated Deferred Income Taxes (Acct. 190)

1of3

101 102 103 104 105

106-106a 106b 107

108-109.1

110-111 112-113 114-117 118-119 120-121

122-123.1

122a-122b

200-201

202-203 204-207

213 214 216 217 218

218

219

221 222-223 224-225

227 228a-229b

230a 230b 231

232 233 234

Ed. 12-87 Ed. 12-96 Ed. 12-96 Ed. 12-96 Ed. 12-95

New 12-08 New 12-08 Ed. 12-96 Ed. 12-96

Rev. 12-03 Rev. 12-03 Rev. 02-04 Rev. 02-04 Ed. 12-96

Ed. 12-96/12-88

New 06-02

Ed. 12-89

Ed. 12-89 Rev. 12-05 Ed. 12-95 Ed. 12-96 Ed. 12-87 Ed. 12-89 Ed. 12-88

Ed. 12-88

Rev. 12-05

Ed. 12-95 Ed. 12-96 Ed. 12-89

Rev. 12-05 Ed. 12-95 Ed. 12-88 Ed. 12-88

New 03-07

Rev. 02-04 Ed. 12-94 Ed. 12-88

NA NA

NA

NA

NA NA NA

Name of Respondent: This Report is: [ X] An Original


December 31, 2014. Jersey Central Power & Light Company [ ] A Resubmission




I Line #l ._I ________ T_i_tl _e _o_f _S_c_h_e_d _u _le _______ _..11 Reference Page No. 11 Revised on 11 Remarks

BALANCE SHEET SUPPORTING SCHEDULES:

LIABILITIES AND OTHER CREDITS:

38 Capital Stock (Acct. 201 and 204) 250-251 Ed. 12-91/12-88

39 Capital Stock Subscribed, Capital Stock Liability for 252 Ed. 12-95

Coversion, Premium on Capital Stock and Installments Received on Capital Stock

40 Other Paid-In Capital (Acct. 208-211 inc.) 253 Ed. 12-87

41 Discount on Capital Stock (Acct. 213) 254a Ed. 12-87

42 Capital Stock Expense (Acct. 214) 254b Ed. 12-87 NA

43 Securities Issued or Assumed and Securities 255 Ed. 12-96

Refunded or Retired During the Year 44 Long-Term Debt (Acct. 221, 222, 223 and 224) 256-257 Ed. 12-96 45 Unamortized Debt Expense, Premium & Discount 258-259 Ed. 12-96

on Long-Term Debt (Acct. 181, 225, 226) 46 Unamortized Loss and Gain on Reacquired Debt 260 Ed. 12-96

47 Reconciliation of Reported Net Income With 261 Ed. 12-96

Taxable Income for Federal Income Taxes 48 Taxes Accrued, Prepaid, and Charged During Year 262-263 Ed. 12-96

49 Investment Tax Credits Generated and Utilized 264-265 Ed. 12-88

50 Accumulated Deferred Investment Tax Credits 266-267 Ed. 12-89

51 Miscellaneous Current and Accrued Liabilities 268 Ed. 12-96

52 Other Deferred Credits (Acct.253) 269 Ed. 12-94

Accumulated Deferred Income Taxes: 53 -Accelerated Amortization Property (Acct. 281) 272-273 Ed. 12-96 NA

54 -Other Property (Acct. 282) 274-275 Ed. 12-96

55 -Other (Acct. 283) 276-277 Ed. 12-96

56 Other Regulatory Liabilities (Acct. 254) 278 Rev. 02-04

INCOME ACCOUNT SUPPORTING SCHEDULE:

57 Electric Operating Revenues (Acct. 400) 300-301A Rev. 12-05/12-96

58 Regional Transmission Service Revenues (Acct. 457.1) 302 New 12-05 NA

59 Sales of Electricity by Rate Schedules 304 Ed. 12-95

60 Saled for Resale-Electricity (Acct. 447) 310-311 Ed. 12-90

61 Electric Operation and Maintenance Expenses 320-323 Ed. 12-93

62 Number of Electric Department Employees 323 Ed. 12-93

63 Purchased Power (including power exchanges) (555) 326-327 Ed. 12-90

64 Transmission of Electricity for Others (Acct. 456.1) 328-330 Ed. 12-90

65 Transmission of Electricity by ISO/RTOs 331 Rev. 03-07

66 Transmission of Electricity by Others (Acct. 565) 332 Rev. 02-04 67 Miscellaneous General Expenses (Acct. 930.2) 335 Ed. 12-94

68 Depreciation & Amortization of Electric Plant 336-337 Rev. 12-03

69 Income From Utility Plant Leased to Others 339 Ed. 12-86

70 Particulars Concerning Certain Income 340 Ed. 12-87

Deductions and Interest Charges Accounts

2 of 3

Name of Respondent: This Report is: [ X ] An Original


December 31, 2014. Jersey Central Power & Light Company [ ] A Resubmission




I Line #I ._I _______ _ T_itl_e_ o_ f _ S_ c_ h_ e_d_u_le _______ ___,I I Reference Page No. I I Revised on I I Remarks

COMMON SECTION:

71 Regulatory Commission Expenses 72 Research, Development, & Demonstration Activities 73 Distribution of Salaries and Wages 74 Common Utility Plant and Expenses 75 Charges for Outside Professional

And Other Consultative Services 76 Amounts included in ISO/RTO Settlement Statements 77 Purchase and Sales of Ancillary Services

ELECTRIC PLANT STATISTICAL DAT A

78 Monthly Transmission System Peak Load 79 Monthly ISO/RTO Transmission System Peak Load 80 Electric Energy Account 81 Monthly Peak and Output 82 Steam-Electric Generating Plants (Large Plants) 83 Hydroelectric Generating Plants (Large Plants) 84 Pumped Storage Generating Plants (Large Plants) 85 Generating Plants Statistics (Small Plants) 86 Transmission Line Statistics 87 Transmission Lines Added During Year 88 Substations 89 Electric Distribution Meters and Line Transformers 90 Transactions with Associated (Affiliated) Companies 91 Environmental Protection Facilities 92 Environmental Protection Expenses 93 Underground Transmission & Distribution System:

-Conduit, Underground Cable & Submarine Cable 94 Overhead Distribution System:

-Overhead Transmission & Distribution Systems 95 Street Lighting and Signal Systems 96 Footnote Data 97 Index

Stockholders' Annual Reports Check Apprpriate Box:

[ ] Four Copies will be submitted. [ ] No Annual Report to Stockholder

is prepared.

3 of 3

350-351 352-353 354-355

356 357

397 398

400 400a 401a 401b

402-403 406-407 408-409 410-411 422-423 424-425 426-427

429 429-1-F

430 431

E440

E441 E442 450

Index 1 to Index 5

Ed. 12-96 Ed. 12-87 Ed. 12-88 Ed. 12-87 Ed. 12-96

New 12-05 New 02-04

New 07-04 New 07-04 Ed. 12-90 Ed. 12-90

Rev. 12-03 Rev. 12-03 Rev. 12-03 Rev. 12-03 Ed. 12-87

Rev. 12-03 Ed. 12-96 Ed. 12-88 New 1-F

Ed. 12-88 Ed. 12-88

Ed. 12-87 Ed. 12-90/95

NA NA

NA

NA

Name of Respondent This Report is: Date of Report Year of Report (1) [ x] An Original (Mo, Da, Yr )

Jersey Central Power & Light Company (2) r 1 A Resubmission Dec. 31, 2014

ELECTRIC OPERATING REVENUES (Account 400) (Continued) 1. Report by New Jersey Gross Reciepts and Franchise and provide the taxable megawatts of electricity and the Tax Class, the taxable megawatts of electricity and corresponding operating revenues for each tariff the corresponding operating operating revenues. schedule.

2. Where there is more than one tariff schedule 3. Provide a reconciliation of the total amounts designated in a tax class, identify the names of the on line 14 and the amounts shown on line 12 of page individual tariff schedules above the tax class name 301 in the area provided for notes.

Megawatts of Electricity Sold Operating Revenues Line Quantity Quantity For Amount Amount For No. Tax Class For Year Previous Year For Year Previous Year

(a) (b) (c) (d) (e) ER-1 Standard Residential 475,484 8,721,358

1 Service 2 ER-2 Time - of - Day Service 19,174 259,361 3 ER-3 Water Heatinq Service 660 11,779 4 ENR-1 Transmission Service 128,233 1,923,736 5 ENR-2 Primary Service 89,124 1,694,505

ENR-3 Secondary Time - of - Day 34,649 622,736 6 Service

ENR-4 Secondary Non - Time - of - Day 344, 127 6,324,112 7 Service

ENR-5 Primary I Secondary 8 Combination Service 9 ENR-6 Hotel Casino Service

ENR-7 Street & Private Lighting 5,295 109,149 10 Service

ENR-8 Experimental Transmission 11 Service

IDGC (Indigenous Refinery Gas 12 Conversion)

EHEP (Experimental Hourly Energy 13 Pricing Service) 14 Total 1,096,746 19,666,736 * *

NOTES * Not readily available. See FERC page 304 for a breakdown of total revenues by rate class.

Reconciliation 12er item 3 above MWH MWH

Line number 14 above 1,096,746 19,666,736 Exemptions I Adjustments:

Sales for Resale 1,033,372 943,448 Other [1] 19,716, 140 1,226,622

Page 301 Line number 12 21,846,258 21,836,806

[1] Represents Megawatts not subject to NJ Gross Receipts/TEFA Taxes. TEFA was phased out at the end of 2013. This activity relates to prior years.

Page 301 -A

JERSEY CENTRAL POWER & LIGHT COMPANY An Original Dec. 3 1, 2014

UNDERGROUND TRANSMISSION SYSTEMS AND UNDERGROUND DISTRIBUTION SYSTEMS

CONDUIT, UNDERGROUND CABLE, AND SUBMARINE CABLE (Distribution System)

1 . Report below the information called for

concerning conduit, underground cable, and

submarine cable at end of year.

2. Show separately the underground distribution

system plant serving each large metropolitan area.

Report in total by operating divisions the under

ground distribution systems not required to be

reported separately.

Line I Designation of underground distribution system

No.

(a)

1 UNDERGROUND DISTRIBUTION

2

3 Burlington County

4 Essex County

5 Hunterdon County

6 Mercer County

7 Middlesex County

8 Monmouth County

9 Morris County

10 Ocean County

1 1 Passaic County

12 Somerset County

13 Sussex County

14 Union County

15 Warren County

16

17 Total Underground Distribution

3. Designate underground systems, or

important portions thereof, leased from others,

jointly owned with others, or operated other

wise than by reason of sole ownership by the

respondent. For any underground system

operated under lease, give name of lessor,

date, and period of lease, and annual rent.

For any system operated other than by reason

of sole ownership or lease, give name of co-owner

or other party, explain basis of sharing expenses

or other accounting between the parties, and state

amounts and accounts affected in respondent's

books of account. Specify in each case whether

lessor, co-owner, or other party is an associated

company.

Underground Cable Submarine Cable

Miles of conduit bank 1--��-.-��1---��-.-��------1

( all sizes and types) Miles*

(c) Various (b)

Not Available

NJBRC

Page E440

157.60

55.75

1,106.16

234.95

787.60

2,678.23

1,959.90

2,548.64

67. 13

737.28

439.0 1

103.05

502.47

1 1,377.77

Operating voltage

(d)

Various

Various

Various

Various

Various

Various

Various

Various

Various

Various

Various

Various

Various

Feet*

(e) 3/C

Not Available

Operating voltage

(f)

Not Available

JERSEY CENTRAL POWER & LIGHT COMPANY An Original Dec. 31, 2014

OVERHEAD DISTRIBUTION SYSTEMS

OVERHEAD TRANSMISSION SYSTEMS AND OVERHEAD DISTRIBUTION SYSTEMS

1. Report below the information called for as at end of the year, for each municipality or tax district. 2. Municipalities are to be grouped under operating or commercial districts. 3. Designate any overhead distribution system plant held under any title other than full ownership and in a footnote state the name of owner or co-owner of such plant, the nature of respondent's title, and percent ownership.

LINE NO.

1 2 3 4 5 6 7 8 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

MUNICIPALITY MILES OF POLE LINE OR

TAX DISTRICT

(a) Burlington County

Essex County

Hunterdon County

Mercer County

Middlesex County

Monmouth County

Morris County

Ocean County

Passaic County

Somerset County

Sussex County

Union County

Warren County

Total

* Represents circuit miles

TOTAL*

(b) 370.63

134.93

1,495.55

194.26

510.57

2,505.39

2,076.54

1,753.18

174.43

514.49

1,207.31

234.98

1,097.56

12,269.82

ON PUBLIC WAYS

(c)

Not Available

Page E441

ON PRIVATE R/W

(d)

Not Available

WIRE CABLE MILES MILES

(e) (f) 1,071.37

411.24

4,649.11

648.62 Not Available

1,578.55

7,039.71

5,642.27

5,728.07

461.47

1,664.92

2,492.48

687.20

2,972.22

35,047.23

JERSEY CENTRAL POWER & LIGHT COMPANY An Original Dec. 31, 2014

STREET LIGHTING AND SIGNAL SYSTEMS

1. Report below the information called for concerning street lighting and signal systems owned or leased at end of year.

2. Designate any street lighting and signal system plant held under any title other than full ownership and in a footnote state the names of owner or co-owner of such plant, the nature of respondent's title and percent ownership.

STREET LIGHT SYSTEM

LINE NO.

ITEM (a)

21 Number of Lamps: 3 11 Total first of year 4 Added during year

51 Total 61 (Less) Retired during year 7l Total end of year 8 Inactive end of year 9

10 11 12 Number of Poles: 13, Total first of year 141 Added during year 1 sl Total 16 (Less) Retired during year 17 Total end of year 18 Inactive end of year 19 20 21 22 Note: 23 Fluorescent - 122

TOTAL (b)

0 0

197,251 0

197,251

NIA NIA

NIA 0

29,295

FILAMENT (c)

NIA NIA

5,871 NIA

5,871

MERCURY (d)

NIA NIA 30, 129

NIA 30, 129

SODIUM (e)

NIA NIA 161,251 NIA 161,251

24 Line 5 - Street Light System Lamp No. Totals do not include LED lamps of 509 2s I I I I 26 The Pole number reported is based strictly on Street Light Standards - 16 ft. 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49!

I

501

Page E442

SIGNAL SYSTEMS

(f)

None

None

None

None

TRAFFIC SYSTEMS

(g)

None

None

None

None

instructions for filing ferc form nos. 1 and 3-q · any electronic submission must be created by...

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