2008 FERC Form 1 and 2008 CPUC Annual Report - Edison ...

2008 FERC Form No. 1 

ANNUAL REPORT OF 

MAJOR ELECTRIC 

UTILITIES, LICENSEES AND 

OTHERS 

 

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2008 ANNUAL REPORT 

TO THE 

CALIFORNIA PUBLIC 

UTILITIES COMMISSION 

 

If you have any questions or comments, please 

contact Walter Wong, Financial Reporting and 

Research at (626) 302-1371.

Item 1: 

X 

An Initial (Original) 

Submission 

THIS FILING IS 

OR 

Resubmission No. ____ 

Form 1 Approved 

OMB No. 1902-0021 

(Expires 2/29/2009) 

Form 1-F Approved 

OMB No. 1902-0029 

(Expires 2/28/2009) 

Form 3-Q Approved 

OMB No. 1902-0205 

(Expires 2/28/2009) 

FERC FINANCIAL REPORT 

FERC FORM No. 1: Annual Report of 

Major Electric Utilities, Licensees 

and Others and Supplemental 

Form 3-Q: Quarterly Financial Report 

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 

18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and 

other sanctions as provided by law. The Federal Energy Regulatory Commission does not 

consider these reports to be of confidential nature 

Exact Legal Name of Respondent (Company) 

Southern California Edison Company 

Year/Period of Report 

End of 2008/Q4 

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

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 the 

annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and 

operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy 

Regulatory 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 Accounts 

Prescribed 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 that 

exceeds 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 report 

for your files. Any electronic submission must be created by using the forms submission software provided free by the 

Commission at its web site: http://www.ferc.gov/docs-filing/eforms/form-1/elec-subm-soft.asp. The software is 

used 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, the 

latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to 

the 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 (not 

applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be 

either 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 the 

Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the 

Chief Accountant's published accounting releases), and 

b) Be signed by independent certified public accountants or an independent licensed public accountant 

certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 

C.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 are 

reported. 

for the year ended on which we have 

, we have also reviewed schedules 

of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for 

“In connection with our regular examination of the financial statements of 

reported separately under date of 

conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its 

applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such 

tests 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 Energy 

Regulatory 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 been 

added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the 

Commission’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 of 

FERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdf and 

http://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: 


ii

a) FERC Form 1 for each year ending December 31 must be filed by April 18 th 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 1,144 

hours per response, including the time for reviewing instructions, searching existing data sources, gathering and 

maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for 

the 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, including 

suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 

20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of 

Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory 

Commission). No person shall be subject to any penalty if any collection of information does not display a valid control 

number (44 U.S.C. § 3512 (a)). 


iii

GENERAL INSTRUCTIONS 

I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret 

all 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 and 

figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements 

where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the 

statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance 

sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the 

current year's year to date amounts. 

III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the 

word "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 "Not 

Applicable" 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 the 

header 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, must 

be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the 

numbers in parentheses. 

VII For any resubmissions, submit the electronic filing using the form submission software only. Please explain 

the 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 based 

upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different 

figures 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 reasons 

and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as 

described 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 is 

intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as 

described 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 adverse 

conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access 

Transmission Tariff. For all transactions identified as LFP, provide in a footnote the 


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 the 

terms of the Open Access Transmission Tariff. "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 adverse conditions. For all 

transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either 

buyer 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-point 

transmission 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 is 

intended to remain reliable even under adverse conditions. 

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the 

above-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 prior 

reporting periods. Provide an explanation in a footnote for each adjustment. 

DEFINITIONS 

I. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any 

other 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 whose 

behalf the report is made. 


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 the 

foregoing. 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 or 

agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or 

distributing power; ...... 

(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water 

conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and 

all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there 

from to the point of junction with the distribution system or with the interconnected primary transmission system, all 

miscellaneous 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 or 

appropriate 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 to 

be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and 

concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the 

Commission 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 or 

special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist 

the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in 

which such reports salt be made, and require from such persons specific answers to all questions upon which the 

Commission may need information. The Commission may require that such reports shall include, among other things, full 

information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due 

and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the 

project 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 such 

person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under 

oath unless the Commission otherwise specifies*.10 


vi

"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such 

orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other 

things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe 

the 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. See 

FPA § 316(a) (2005), 16 U.S.C. § 825o(a). 


vii

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

FERC FORM NO. 1/3-Q: 

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER 

01 Exact Legal Name of Respondent 


IDENTIFICATION 

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) 

2244 Walnut Grove Avenue, Rosemead, California 91770 

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

2244 Walnut Grove Avenue, Rosemead, California 91770 

02 Year/Period of Report 


05 Name of Contact Person 06 Title of Contact Person 

Linda G. Sullivan 

Vice President & Controller 

08 Telephone of Contact Person,Including 09 This Report Is 10 Date of Report 

Area Code 

(1) X An Original (2) A Resubmission 

(Mo, Da, Yr) 

(626) 302-1502 04/18/2009 

The undersigned officer certifies that: 

ANNUAL CORPORATE OFFICER CERTIFICATION 

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 statements 

of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material 

respects to the Uniform System of Accounts. 

/ / 

01 Name 

03 Signature 04 Date Signed 

/s/ Thomas M. Noonan 

(Mo, Da, Yr) 

02 Title 

Sr. VP & CFO /s/ Thomas M. Noonan 

04/18/2009 

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 any 

false, fictitious or fraudulent statements as to any matter within its jurisdiction.

Name of Respondent 


This Report Is: 

Date of Report 

(1) X An Original 

(Mo, Da, Yr) 

(2) A Resubmission 

04/18/2009 

LIST OF SCHEDULES (Electric Utility) 



Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for 

certain pages. Omit pages where the respondents are "none," "not applicable," or "NA". 

Line 

No. 

Title of Schedule 

(a) 

Reference 

Page No. 

(b) 

Remarks 

(c) 

1 

General Information 

101 

2 

Control Over Respondent 

102 

3 

Corporations Controlled by Respondent 

103 

4 

Officers 

104 

5 

Directors 

105 

6 

Important Changes During the Year 

108-109 

7 

Comparative Balance Sheet 

110-113 

8 

Statement of Income for the Year 

114-117 

9 

Statement of Retained Earnings for the Year 

118-119 

10 

Statement of Cash Flows 

120-121 

11 

Notes to Financial Statements 

122-123 

12 

Statement of Accum Comp Income, Comp Income, and Hedging Activities 

122(a)(b) 

13 

Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 

200-201 

14 

Nuclear Fuel Materials 

202-203 

15 

Electric Plant in Service 

204-207 

16 

Electric Plant Leased to Others 

213 

17 

Electric Plant Held for Future Use 

214 

18 

Construction Work in Progress-Electric 

216 

19 

Accumulated Provision for Depreciation of Electric Utility Plant 

219 

20 

Investment of Subsidiary Companies 

224-225 

21 

Materials and Supplies 

227 

22 

Allowances 

228-229 

23 

Extraordinary Property Losses 

230 

24 

Unrecovered Plant and Regulatory Study Costs 

230 

25 

Transmission Service and Generation Interconnection Study Costs 

231 

26 

Other Regulatory Assets 

232 

27 

Miscellaneous Deferred Debits 

233 

28 

Accumulated Deferred Income Taxes 

234 

29 

Capital Stock 

250-251 

30 

Other Paid-in Capital 

253 

31 

Capital Stock Expense 

254 

32 

Long-Term Debt 

256-257 

33 

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

261 

34 

Taxes Accrued, Prepaid and Charged During the Year 

262-263 

35 

Accumulated Deferred Investment Tax Credits 

266-267 

36 

Other Deferred Credits 

269 

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






(Mo, Da, Yr) 


04/18/2009 

LIST OF SCHEDULES (Electric Utility) (continued) 





Line 

No. 


(a) 

Reference 

Page No. 

(b) 

Remarks 

(c) 

37 

Accumulated Deferred Income Taxes-Accelerated Amortization Property 

272-273 

38 

Accumulated Deferred Income Taxes-Other Property 

274-275 

39 

Accumulated Deferred Income Taxes-Other 

276-277 

40 

Other Regulatory Liabilities 

278 

41 

Electric Operating Revenues 

300-301 

42 

Sales of Electricity by Rate Schedules 

304 

43 

Sales for Resale 

310-311 

44 

Electric Operation and Maintenance Expenses 

320-323 

45 

Purchased Power 

326-327 

46 

Transmission of Electricity for Others 

328-330 

47 

Transmission of Electricity by ISO/RTOs 

331 

48 

Transmission of Electricity by Others 

332 

49 

Miscellaneous General Expenses-Electric 

335 

50 

Depreciation and Amortization of Electric Plant 

336-337 

51 

Regulatory Commission Expenses 

350-351 

52 

Research, Development and Demonstration Activities 

352-353 

53 

Distribution of Salaries and Wages 

354-355 

54 

Common Utility Plant and Expenses 

356 

55 

Amounts included in ISO/RTO Settlement Statements 

397 

56 

Purchase and Sale of Ancillary Services 

398 

57 

Monthly Transmission System Peak Load 

400 

58 

Monthly ISO/RTO Transmission System Peak Load 

400a 

59 

Electric Energy Account 

401 

60 

Monthly Peaks and Output 

401 

61 

Steam Electric Generating Plant Statistics 

402-403 

62 

Hydroelectric Generating Plant Statistics 

406-407 

63 

Pumped Storage Generating Plant Statistics 

408-409 

64 

Generating Plant Statistics Pages 

410-411 

65 

Transmission Line Statistics Pages 

422-423 

66 

Transmission Lines Added During the Year 

424-425 







(Mo, Da, Yr) 


04/18/2009 

LIST OF SCHEDULES (Electric Utility) (continued) 





Line 

No. 


(a) 

Reference 

Page No. 

(b) 

Remarks 

(c) 

67 

Substations 

426-427 

68 

Footnote Data 

450 

Stockholders' Reports Check appropriate box: 

Four copies will be submitted 

No annual report to stockholders is prepared 








(Mo, Da, Yr) 

04/18/2009 


End of 

2008/Q4 

GENERAL INFORMATION 

1. Provide name and title of officer having custody of the general corporate books of account and address of 

office where the general corporate books are kept, and address of office where any other corporate books of account 

are kept, if different from that where the general corporate books are kept. 

Linda G. Sullivan, Vice President and Controller 

Location: 2244 Walnut Grove Avenue, Rosemead, CA 91770 

Mailing Address: P.O. Box 800, Rosemead, CA 91770 

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 type 

of organization and the date organized. 

California, July 6, 1909 

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 or 

trusteeship was created, and (d) date when possession by receiver or trustee ceased. 

Not in receivership. 

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

the respondent operated. 

Primarily engaged in electric utility service in the State 

of California and gas and water service on Santa Catalina 

Island in the State of California. 

5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not 

the principal accountant for your previous year's certified financial statements? 

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

(2) X No 

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







(Mo, Da, Yr) 

04/18/2009 


End of 


CONTROL OVER RESPONDENT 

1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held 

control over the repondent at the end of the year, state name of controlling corporation or organization, manner in 

which control was held, and extent of control. If control was in a holding company organization, show the chain 

of 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. 

Edison International holds control over respondent by 

way of 100% ownership of respondent's common stock which was acquired 

pursuant to a holding company reorganization effective July 1, 1988. 

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

Page 102






(Mo, Da, Yr) 


04/18/2009 

CORPORATIONS CONTROLLED BY RESPONDENT 



1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent 

at 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, naming 

any 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. 

Definitions 

1. 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 the 

voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by 

mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of 

control in the Uniform System of Accounts, regardless of the relative voting rights of each party. 

Line 

No. 

Name of Company Controlled Kind of Business Percent Voting 

Stock Owned 

(a) 

(b) 

(c) 

1 Bear Creek Uranium Company 

2 a Partnership 

3 

4 Conservation Financing Corporation, 

5 a California Corporation 

6 

7 

8 

9 Edison ESI (Formerly Energy Service, Inc.) 


11 

12 

13 

14 

15 Edison Material Supply LLC 

16 a Delaware Limited Liability Company 

17 

18 

19 Mono Power Company 

20 a California Company 

21 

22 

23 Mountainview Power Company LLC 


25 

26 

27 

Inactive. - 

Non-public utility engaged 87% 

in remediation and mitigation 

of environmental liabilities 


primarily in the business of 

furnishing energy services to 

commercial customers. 

Non-public utility engaged in 100% 

providing procurement, inven- 

tory and warehousing services 

Inactive. 100% 

Non-public Utility engaged in 100% 

operating an electric 

generating plant in 

Redlands, CA. 

Footnote 

Ref. 

(d) 







(Mo, Da, Yr) 


04/18/2009 

CORPORATIONS CONTROLLED BY RESPONDENT 



1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent 

at 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, naming 

any 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. 

Definitions 

1. 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 the 

voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by 

mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of 

control in the Uniform System of Accounts, regardless of the relative voting rights of each party. 

Line 

No. 

1 

2 SCE Capital Company 

Name of Company Controlled Kind of Business Percent Voting 

Stock Owned 

(a) 

(b) 

(c) 

3 a Delaware Corporation 

4 

5 Southern States Realty (Formerly Southern 

6 Surplus Realty Co.) 


8 

9 SCE Funding LLC 


11 

12 

13 SCE Trust I 

14 

15 

16 

17 SCE Trust II 

18 

19 

20 

21 SCE Trust III 

22 

23 

24 

25 

26 

27 



in holding real estate 

interests. 


Delaware business trust - 

organized to act as a 

financing vehicle. 







Footnote 

Ref. 

(d) 

FERC FORM NO. 1 (ED. 12-96) Page 103.1



This Report is: 



FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 103 Line No.: 1 Column: d 

Bear Creek Uranium Company 

----------------- 

Mono Power owns a 50% partnership interest in the Bear Creek Uranium Company; the remaining interest is owned by 

RME Holding Company (formerly Union Pacific Resources Group, Inc.) 


Conservation Financing Corporation 

Remaining Interest owned as of December 31, 2007 by CH2M Hill. Conservation Financing Corporation was dissolved on 

March 3, 2008. 


Respondent is the only member of Edison Material Supply LLC. 


Respondent is the only member of Mountainview Power Company LLC. 

Schedule Page: 103.1 Line No.: 9 Column: d 

Respondent is the only member of SCE Funding LLC. 

SCE Funding LLC. was dissolved on August 15, 2008. 


Respondent is the depositor. 








Line 

No. 




OFFICERS 


(Mo, Da, Yr) 

04/18/2009 



1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a 

respondent 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 previous 

incumbent, and the date the change in incumbency was made. 

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 

Title Name of Officer Salary 

for Year 

(a) 

(b) 

(c) 

Chairman of the Board & Alan J. Fohrer 

1,483,433 

Chief Executive Officer 

President John R. Fielder 

855,865 

Executive Vice President (Until September 29, 2008) Polly L. Gault 

676,985 

Executive Vice President (Effective April 1, 2008); Pedro J. Pizarro 

730,821 

Senior Vice President (Until Aprl 1, 2008) 

Senior Vice President (Until April 1, 2008) Ronald L. Litzinger 

792,208 

Senior Vice President & Chief Information Officer Mahvash Yazdi 

698,287 

Senior Vice President & Chief Financial Officer Thomas M. Noonan 

621,661 

Pursuant to Item 402 of Regulation S-K, the 

informaton provided above was reported as "Salary," 

"Bonus," "Non-Equity Incentive Plan Compensation" 

and "All Other Compensation" in the Summary 

Compensation Table of the Company's Proxy 

Statement filed with the Securities and Exchange 

Commission on March 13, 2009. For additional 

information required by Regulation S-K, Item 402, 

please see the Company's Proxy Statement. 







DIRECTORS 


(Mo, Da, Yr) 

04/18/2009 



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), abbreviated 

titles 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. 

Line 

No. 

Name (and Title) of Director 

(a) 

Principal Business Address 

(b) 

1 John E. Bryson 

2244 Walnut Grove Avenue 

2 

3 

4 Theodore F. Craver, Jr. *** 

P.O. Box 976, Rosemead, California 91770 


5 

6 

7 Alan J. Fohrer** 



8 

9 

10 

Chairman of the Board and Chief Executive Officer 

Vanessa C.L. Chang 


136 North Irving Boulevard 

11 

12 

13 France A. Cordova 

Los Angeles, California 90004 

Hovde Hall, 610 Purdue Mall 

14 

15 

16 

17 Charles B. Curtis 

West Lafayette, Indiana 47907-2040 

1747 Pennsylvania Avenue, N.W., 7th Floor 

18 

19 

20 

21 Bradford M. Freeman *** 

Washington, DC 20006 

11100 Santa Monica Blvd., Suite 1900 

22 

23 

24 

25 Luis G. Nogales 


9229 West Sunset Boulevard, Suite 900 

26 

27 

28 

29 Ronald L. Olson*** 


355 South Grand Avenue, 35th Floor 

30 

31 

32 

33 James M. Rosser*** 


5151 State University Drive 

34 

35 

36 

37 Richard T. Schlosberg, III 


800 E. Sonterra Boulevard, Suite 140 

38 

39 

40 

41 Robert H. Smith 

San Antonio, Texas 78258 

750 East Green Street, Room 203 

42 

43 

44 

45 Thomas C. Sutton*** 

Pasadena, California 91101 

700 Newport Center Drive 

46 

47 

48 

Newport Beach, California 92660 







DIRECTORS 


(Mo, Da, Yr) 

04/18/2009 



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), abbreviated 

titles 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. 

Line 

No. 

Name (and Title) of Director 

(a) 

Principal Business Address 

(b) 

1 Brett White 

11150 Santa Monice Boulevard, Suite 1600 

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 

48 








FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 105 Line No.: 1 Column: a 

Mr. Bryson served as a member of the Executive Committee and as a director until his retirement on July 31, 2008. 


Mr. Craver became a director on August 1, 2008. 


Mr. Smith retired as a director on April 24, 2009. 




This 

(1) 

Report 

X 

Is: 

An Original 



04/18/2009 



IMPORTANT CHANGES DURING THE QUARTER/YEAR 

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in 

accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If 

information 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 the 

franchise 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 of 

companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to 

Commission 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 Accounts 

were submitted to the Commission. 

4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give 

effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give 

reference to such authorization. 

5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations 

began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of 

customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major 

new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and 

approximate 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-term 

debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as 

appropriate, 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 such 

proceedings 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 106, voting trustee, associated company or known associate 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 are 

applicable 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 have 

occurred 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 30 

percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the 

extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a 

cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio. 

PAGE 108 INTENTIONALLY LEFT BLANK 

SEE PAGE 109 FOR REQUIRED INFORMATION. 







(Mo, Da, Yr) 

04/18/2009 


IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued) 



Question 1. Franchises 

These are the Franchises changes in 2008: 

Menifee Electric Franchise 

Menifee City Ordinance No. 2008-06, granting SCE an indefinite franchise to use and construct and use for 

transmitting and distributing electricity within the City of Menifee. 

Terms and Conditions: 

Type of Franchise: 1937 Franchise Act 

Term: Indeterminate 

Effective date: October 7, 2008 

Franchise fee formula: Based on the greater of 1% of gross annual receipts derived from the sale of electricity 

within City limits or 2% of gross annual receipts arising from use, operation or possession of franchise. 

Franchise fee for 2008: may be paid under Broughton Act. We do not have franchise fees yet. 

City of Wildomar 

This City was incorporated on July 1, 2008. We have not yet negotiated an agreement with the City. For 2008, 

the City will be paid under the County of Riverside Agreement, Ordinance No. 684. 

Terms and Conditions: 

Type of Franchise: 1937 Franchise Act 

Term: 50 years 

Effective date: 10/17/89 

Franchise fee formula: Based on the greater of 1% of gross annual receipts derived from the sale of electricity 

within City limits or 2% of gross annual receopts arising from use, operation or possession of franchise. 

Franchise fee for 2008: We do not have franchise fees yet. 

Question 2. Acquisition of ownership in other companies 

None 

Question 3. Purchase or sale of an operating unit or system 

None 







(Mo, Da, Yr) 

04/18/2009 





Question 4. Important leaseholds acquired or given 

The following leasehold executed during 2008: 

Lessee Name: Molokai Property, LLC (previously Hawaii Properties) 

Initial Term: 12/1/2008 – 11/30/2053 

Length (yrs): 45 years, initial term of 45 years with option to extend for 2 additional 10 year periods (total of 

65 years) 

Annual Rent: Yr 1: $10,000; Yr 2: $15,000; Yr 3: $20,000; Yrs 4-5: $25,000; 

Yrs 6-10: $30,000 

Reappraisal every 10 th years 

Application: 07-08-001 

Decision Date: 11/18/2005 

Decision: 01-10-029 

Approver: CPUC 

Also see notes to financial statements on page 123.4 

Question 5: Important extension or reduction of transmission or distribution system 

There were no major/significant extensions or reduction of SCE service territory in 2008. 

Question 6: Obligations 

Long-Term Debt: 

SERIES NAME 

ISSUE 

DATE 

AMOUNT 

(MILLIONS) 

INTEREST 

RATE 

MATURITY 

DATE 

SERIES 2008A 1/22/08 $600 5.95% 2/1/38 

Series 2008B Bonds 08/18/08 $400 5.5% 08/15/18 

Series 2008C Bonds 10/15/08 $500 5.75% 03/15/14 

AUTHORIZING CPUC 

DECISION 

No. 05-08-008 dated 

August 25, 2005 

No. 07-08-012 dated 

August 23, 2007 

07-08-012 

dated Aug. 23, 2007 

07-08-012 

dated Aug. 23, 2007 









(Mo, Da, Yr) 

04/18/2009 



Short-Term Obligations: 

There was no commercial paper outstanding on 12/31/08. However, there was a $1.893 billion bank loan 

outstanding on 12/31/2008. 

Security Issuances: 

SERIES NAME 

None 

ISSUE 

DATE 

AMOUNT 

(MILLIONS) 

INTEREST 

RATE 

AUTHORIZING 

CPUC 

DECISION 

Indemnities: 

Indemnity Provided as Part of the Acquisition of Mountainview: 

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific 

environmental claims related to SCE’s previously owned San Bernardino Generating Station, divested by SCE 

in 1998 and reacquired as part of the Mountain acquisition. SCE retained certain responsibilities with respect 

to environmental claims as part of the original divestiture of the station. The aggregate liability for either party 

to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification 

for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to 

this indemnity. 

Other Indemnities: 

SCE provides other indemnifications through contracts entered into in the normal course of business. These 

are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, 

and specified environmental indemnities and income taxes with respect to assets sold. SCE’s obligations 

under these agreements may be limited in terms of time and/or amount, and in some instances SCE may have 

recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often 

are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications 

cannot be reasonably estimated. SCE has not recorded a liability related to these indemnities. 

Question 7. Changes in articles of incorporation or amendments to charter 

None 

Question 8. Wage Scale Changes 







(Mo, Da, Yr) 

04/18/2009 





The following wage scale changes have occurred in 2008: 

• Annual merit increase for non-represented employees implemented on 3/3/08. Average increase was 

3.8% 

• Salary structure for non-represented employees updated as of 3/3/08. Average structure adjustment 

(changes to market reference points) was 2.8% 

• Increases to IBEW and Teamsters was 3.5% effective 12/22/08 

Question 9. Materially important legal matters 

Navajo Nation Litigation 

The Navajo Nation filed a complaint in June 1999 in the District Court against SCE, among other defendants, 

arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, 

violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent 

misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the 

defendants’ actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal 

supplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, and 

punitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as an 

additional plaintiff but has not yet identified a specific amount of damages claimed. The case was stayed at 

the request of the parties in October 2004, but was reinstated to the active calendar in March 2008. A related 

case against the U.S. Government is presently before the U.S. Supreme Court. The outcome of that case 

could affect the Navajo Nation’s pursuit of claims against SCE. A decision from the U.S. Supreme Court is 

expected in mid-2009. 

SCE cannot predict the outcome of the Tribe’s complaints against SCE or the ultimate impact on these 

complaints of the on-going litigation by the Navajo Nation against the U.S. Government in the related case. 

Catalina South Coast Air Quality Management District Potential Environmental Proceeding 

During the first half of 2006, the South Coast Air Quality Management District (SCAQMD) issued three NOVs 

alleging that Unit 15, SCE’s primary diesel generation unit on Catalina Island, had exceeded the NOx emission 

limit dictated by its air permit. Prior to the NOVs, SCE had filed an application with the SCAQMD seeking a 

permit revision that would allow a three-hour averaging of the NOx limit during normal (non-startup) operations 

and clarification regarding a startup exemption. In July 2006, the SCAQMD denied SCE’s application to revise 

the Unit 15 air permit, and informed SCE that several conditions would have to be satisfied prior to 

re-application. SCE is currently in the process of developing and supplying the information and analyses 

required by those conditions. 

On October 2, 2006 and July 19, 2007, SCE received two additional NOVs pertaining to two other Catalina 

Island diesel generation units, Unit 7 and Unit 10, alleging that these units have exceeded their annual NOx 

limit in 2004 (Unit 10), 2005 (Unit 7), and 2006 (Unit 10). Going forward, SCE expects that the new Continuous 

Emissions Monitoring System, installed in late 2006, which monitors the emissions from these units, along with 

the employment of best practices, would enable these units to meet their annual NOx limits in 2007. 

In July 2008, SCE received an additional NOV for emitting NOx in excess of SCE’s Regional Clean Air 

Incentives Market (RECLAIM) credits. Under the RECLAIM program, a RECLAIM-regulated facility must have 









(Mo, Da, Yr) 

04/18/2009 



sufficient RECLAIM Trading Credits to equal the amount of NOx that the facility emits. The NOV alleges that 

SCE did not have sufficient RECLAIM Trading Credits in the first and second quarters of 2007 to match the 

actual NOx emissions at Catalina’s generating units. 

Settlement negotiations with the SCAQMD regarding the penalties are ongoing and the SCAQMD has not yet 

proposed any specific fines to be imposed on SCE. 

Question 10. Material transactions involving officers, directors, or security holders with a material 

interest in the transaction 

Mr. Olson, a member of the SCE Board of Directors, is a Senior Partner of the law firm of Munger, Tolles and 

Olson, which provided legal services to Edison International (SCE’s parent company), SCE, and/or their 

subsidiaries in 2008. Such services are expected to continue to be provided in the future. The amount paid in 

2008 by SCE to Munger, Tolles and Olson for legal services was $724,951. 

SCE believes that the transaction described above is comparable to that which would have been undertaken 

under similar circumstances with nonaffiliated entities or persons. 

Except for those transactions disclosed in the Notes to Financials appearing on pages 122-123 of this filing, 

transactions between the respondent and its parent holding company and other affiliated entities are not 

understood to be subject to reporting in this item. 

Question 11. Reserved 

Question 12. 

N/A 

Question 13. a) Changes in officers and directors of the respondent & b) changes in majority security 

holders and voting powers of the respondent 

a) Changes in officers and directors of the respondent 

There have been no changes in directors of the respondent since October 17, 2008, the date “as of” which this 

information was reported in the FERC Form 3Q for the third quarter of 2008. The changes in officers of the 

respondent are reflected in the following table: 

OFFICERS AS OF MARCH 9, 20091 







(Mo, Da, Yr) 

04/18/2009 





Officer Name 

Title 

Date Initially Elected 

Effective Date 

Alan J. Fohrer Chairman of the Board and Chief Executive Officer 04/26/2007 06/12/2007 

John R. Fielder President 10/20/2005 10/20/2005 

Pedro J. Pizarro Executive Vice President 02/28/2008 04/01/2008 

Bruce C. Foster Senior Vice President 03/01/2006 03/01/2006 

Cecil R. House Senior Vice President 02/22/2007 03/01/2007 

James A. Kelly Senior Vice President 02/28/2008 04/01/2008 

Thomas M. Noonan Senior Vice President and Chief Financial Officer 05/19/2005 06/01/2005 

Stephen E. Pickett Senior Vice President and General Counsel 12/13/2001 01/01/2002 

Ross T. Ridenoure Senior Vice President and Chief Nuclear Officer 04/24/2008 05/31/2008 

Mahvash Yazdi Senior Vice President and Chief Information Officer 12/09/1999 01/01/2000 

Lynda L. Ziegler Senior Vice President 03/01/2006 03/01/2006 

Robert C. Boada Vice President and Treasurer 12/14/2000 01/01/2001 

Lisa D. Cagnolatti Vice President 10/03/2007 11/01/2007 

Kevin R. Cini Vice President 02/22/2007 03/01/2007 

Ann P. Cohn Vice President and Associate General Counsel 04/21/2005 05/01/2005 

Paul J. De Martini Vice President 04/24/2008 05/01/2008 

Erwin G. Furukawa Vice President 02/22/2007 04/01/2007 

Stuart R. Hemphill Vice President 02/28/2008 03/01/2008 

Harry B. Hutchison Vice President 06/26/2000 06/26/2000 

Akbar Jazayeri Vice President 03/01/2006 03/01/2006 

Walter J. Johnston Vice President 11/18/2004 01/01/2005 

Russell W. Krieger Vice President 06/17/1993 06/17/1993 

Barbara E. Mathews 

Vice President, Associate General Counsel, Chief 

09/16/2005 09/26/2005 

Governance Officer and Corporate Secretary 

David L. Mead Vice President 04/24/2008 05/01/2008 

Kevin M. Payne Vice President 03/01/2006 03/01/2006 

Frank J. Quevedo Vice President 05/16/1996 06/01/1996 

Megan E. Scott-Kakures Vice President and General Auditor 04/26/2007 04/26/2007 

Michael P. Short Vice President 09/04/2008 10/01/2008 

Leslie E. Starck Vice President 10/03/2007 11/01/2007 

Kenneth S. Stewart 

Vice President and Chief Ethics and Compliance 

02/17/2005 02/17/2005 

Officer 

Linda G. Sullivan Vice President and Controller 05/19/2005 06/01/2005 

Russell C. Swartz Associate General Counsel 02/22/2007 03/01/2007 

Frank Cooley Assistant General Counsel 04/26/2007 04/26/2007 

Maria Charca Assistant Controller 12/11/2008 12/11/2008 

Chris C. Dominski Assistant Controller 02/22/2007 03/01/2007 

George T. Tabata Assistant Treasurer 10/26/2006 10/26/2006 

Paige W. R. White Assistant Secretary 11/21/1996 01/01/1997 

Keith J. Larson Assistant Secretary 04/24/2008 04/24/2008 

Darla F. Forte Assistant Secretary 05/20/2004 05/20/2004 

Bonita J. Smith Assistant Secretary 01/16/1997 01/16/1997 

Marga Rosso Assistant Secretary 04/24/2008 04/24/2008 

Nihal P. Perera Assistant Secretary 04/24/2008 04/24/2008 

Vicki M. Kaiser Assistant Secretary 01/16/1997 01/16/1997 

Wilhelmina M. Lopez Assistant Secretary 01/16/1997 01/16/1997 







(Mo, Da, Yr) 

04/18/2009 





Since October 17, 2008: 

1 Vice Presidents James T. Reilly and Tommy Ross retired effective December 1, 2008 and January 1, 2009, 

respectively. Maria Charca was elected Assistant Controller effective December 11, 2008. 

b) Changes in majority security holders 

There have been no changes in the major security holders of SCE’s voting stock. 

c) Changes in voting powers of the respondent 

None 

Question 14. Cash Management Programs 

SCE does not currently participate in a cash management program. 




Date of Report Year/Period of Report 


(Mo, Da, Yr) 



04/18/2009 End of 2008/Q4 

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 

50 

51 

52 

Title of Account 

(a) 

UTILITY PLANT 

Utility Plant (101-106, 114) 

Construction Work in Progress (107) 

TOTAL Utility Plant (Enter Total of lines 2 and 3) 

(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 

Net Utility Plant (Enter Total of line 4 less 5) 

Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 

Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 

Nuclear Fuel Assemblies in Reactor (120.3) 

Spent Nuclear Fuel (120.4) 

Nuclear Fuel Under Capital Leases (120.6) 

(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 

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

Net Utility Plant (Enter Total of lines 6 and 13) 

Utility Plant Adjustments (116) 

Gas Stored Underground - Noncurrent (117) 

OTHER PROPERTY AND INVESTMENTS 

Nonutility Property (121) 

(Less) Accum. Prov. for Depr. and Amort. (122) 

Investments in Associated Companies (123) 

Investment in Subsidiary Companies (123.1) 

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

Noncurrent Portion of Allowances 

Other Investments (124) 

Sinking Funds (125) 

Depreciation Fund (126) 

Amortization Fund - Federal (127) 

Other Special Funds (128) 

Special Funds (Non Major Only) (129) 

Long-Term Portion of Derivative Assets (175) 

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

TOTAL Other Property and Investments (Lines 18-21 and 23-31) 

CURRENT AND ACCRUED ASSETS 

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

Cash (131) 

Special Deposits (132-134) 

Working Fund (135) 

Temporary Cash Investments (136) 

Notes Receivable (141) 

Customer Accounts Receivable (142) 

Other Accounts Receivable (143) 

(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 

Notes Receivable from Associated Companies (145) 

Accounts Receivable from Assoc. Companies (146) 

Fuel Stock (151) 

Fuel Stock Expenses Undistributed (152) 

Residuals (Elec) and Extracted Products (153) 

Plant Materials and Operating Supplies (154) 

Merchandise (155) 

Other Materials and Supplies (156) 

Nuclear Materials Held for Sale (157) 

Allowances (158.1 and 158.2) 

Ref. 

Page No. 

(b) 

200-201 

200-201 

200-201 

202-203 

202-203 

122 

224-225 

228-229 

227 

227 

227 

227 

227 

227 

202-203/227 

228-229 

Current Year 

End of Quarter/Year 

Balance 

(c) 

Prior Year 

End Balance 

12/31 

(d) 

27,965,586,390 26,877,268,717 

2,471,279,830 1,656,072,793 

30,436,866,220 28,533,341,510 

14,067,220,437 13,564,955,819 

16,369,645,783 14,968,385,691 

83,879,428 76,870,352 

372,420 54,117,279 

514,584,596 368,617,337 

0 0 

0 0 

338,697,960 268,750,355 

260,138,484 230,854,613 

16,629,784,267 15,199,240,304 

0 0 

0 0 

156,230,590 160,753,225 

78,464,728 69,942,264 

0 0 

522,693,764 707,270,912 

0 0 

696 696 

0 0 

0 0 

0 0 

2,609,317,158 3,484,823,403 

0 308,397,000 

74,037,656 27,978,419 

0 0 

3,283,815,136 4,619,281,391 

0 0 

31,931,145 100,000 

0 0 

69,068 53,980 

1,489,351,634 82,600,000 

35,980 68,941 

523,039,555 496,328,002 

258,629,154 231,119,567 

38,714,313 34,478,217 

0 0 

88,635,792 108,388,278 

32,152,960 15,728,482 

0 290 

0 0 

280,757,374 235,850,625 

0 0 

0 0 

0 0 

0 0 

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





(Mo, Da, Yr) 



04/18/2009 End of 2008/Q4 

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued) 

Line 

No. 

53 

54 

55 

56 

57 

58 

59 

60 

61 

62 

63 

64 

65 

66 

67 

68 

69 

70 

71 

72 

73 

74 

75 

76 

77 

78 

79 

80 

81 

82 

83 

84 

85 


(a) 

(Less) Noncurrent Portion of Allowances 

Stores Expense Undistributed (163) 

Gas Stored Underground - Current (164.1) 

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

Prepayments (165) 

Advances for Gas (166-167) 

Interest and Dividends Receivable (171) 

Rents Receivable (172) 

Accrued Utility Revenues (173) 

Miscellaneous Current and Accrued Assets (174) 

Derivative Instrument Assets (175) 

(Less) Long-Term Portion of Derivative Instrument Assets (175) 

Derivative Instrument Assets - Hedges (176) 

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

Total Current and Accrued Assets (Lines 34 through 66) 

DEFERRED DEBITS 

Unamortized Debt Expenses (181) 

Extraordinary Property Losses (182.1) 

Unrecovered Plant and Regulatory Study Costs (182.2) 

Other Regulatory Assets (182.3) 

Prelim. Survey and Investigation Charges (Electric) (183) 

Preliminary Natural Gas Survey and Investigation Charges 183.1) 

Other Preliminary Survey and Investigation Charges (183.2) 

Clearing Accounts (184) 

Temporary Facilities (185) 

Miscellaneous Deferred Debits (186) 

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

Research, Devel. and Demonstration Expend. (188) 

Unamortized Loss on Reaquired Debt (189) 

Accumulated Deferred Income Taxes (190) 

Unrecovered Purchased Gas Costs (191) 

Total Deferred Debits (lines 69 through 83) 

TOTAL ASSETS (lines 14-16, 32, 67, and 84) 

Ref. 

Page No. 

(b) 

227 

230 

230 

232 

233 

352-353 

234 

Current Year 


Balance 

(c) 

Prior Year 

End Balance 

12/31 

(d) 

0 0 

1,162,212 2,787,134 

0 0 

0 0 

36,519,305 25,624,209 

0 0 

1,690,353 632,172 

11,296,249 5,362,208 

327,522,454 370,386,667 

277,614,609 140,287,130 

231,120,444 82,099,152 

74,037,656 27,978,419 

0 0 

0 0 

3,478,776,319 1,734,960,201 

48,934,761 40,302,631 

0 0 

3,882,256 4,154,349 

5,518,253,743 2,712,855,010 

0 0 

0 0 

2,653 0 

0 0 

713,924 751,460 

252,882,336 252,101,081 

0 0 

0 0 

309,326,650 330,626,237 

1,071,940,176 1,409,044,664 

0 0 

7,205,936,499 4,749,835,432 

30,598,312,221 26,303,317,328 




Line 

No. 


(a) 


(1) x An Original 

(2) A Rresubmission 

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) 


(mo, da, yr) 

04/18/2009 end of 2008/Q4 

Ref. 

Page No. 

(b) 

1 PROPRIETARY CAPITAL 

2 Common Stock Issued (201) 

250-251 

3 Preferred Stock Issued (204) 

250-251 

4 Capital Stock Subscribed (202, 205) 

252 

5 Stock Liability for Conversion (203, 206) 

252 

6 Premium on Capital Stock (207) 

252 

7 Other Paid-In Capital (208-211) 

253 

8 Installments Received on Capital Stock (212) 

252 

9 (Less) Discount on Capital Stock (213) 

254 

10 (Less) Capital Stock Expense (214) 

254 

11 Retained Earnings (215, 215.1, 216) 

118-119 

12 Unappropriated Undistributed Subsidiary Earnings (216.1) 

118-119 

13 (Less) Reaquired Capital Stock (217) 

250-251 

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

15 Accumulated Other Comprehensive Income (219) 

122(a)(b) 

16 Total Proprietary Capital (lines 2 through 15) 

17 LONG-TERM DEBT 

18 Bonds (221) 

256-257 

19 (Less) Reaquired Bonds (222) 

256-257 

20 Advances from Associated Companies (223) 

256-257 

21 Other Long-Term Debt (224) 

256-257 

22 Unamortized Premium on Long-Term Debt (225) 

23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 

24 Total Long-Term Debt (lines 18 through 23) 

25 OTHER NONCURRENT LIABILITIES 

26 Obligations Under Capital Leases - Noncurrent (227) 

27 Accumulated Provision for Property Insurance (228.1) 

28 Accumulated Provision for Injuries and Damages (228.2) 

29 Accumulated Provision for Pensions and Benefits (228.3) 

30 Accumulated Miscellaneous Operating Provisions (228.4) 

31 Accumulated Provision for Rate Refunds (229) 

32 Long-Term Portion of Derivative Instrument Liabilities 

33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 

34 Asset Retirement Obligations (230) 

35 Total Other Noncurrent Liabilities (lines 26 through 34) 

36 CURRENT AND ACCRUED LIABILITIES 

37 Notes Payable (231) 

38 Accounts Payable (232) 

39 Notes Payable to Associated Companies (233) 

40 Accounts Payable to Associated Companies (234) 

41 Customer Deposits (235) 

42 Taxes Accrued (236) 

262-263 

43 Interest Accrued (237) 

44 Dividends Declared (238) 

45 Matured Long-Term Debt (239) 

Current Year 


Balance 

(c) 

2,168,054,319 

920,004,950 

0 

0 

923,708 

545,450,772 

0 

0 

14,558,320 

3,813,144,769 

559,219 

0 

0 

-14,271,894 

7,419,307,523 

5,802,445,000 

248,585,000 

0 

825,871,347 

0 

17,582,925 

6,362,148,422 

12,811,994 

122,642 

210,733,987 

2,324,774,878 

181,088,979 

0 

738,347,396 

0 

2,992,130,909 

6,460,010,785 

1,892,625,000 

1,021,101,858 

0 

71,120,525 

227,153,689 

70,794,744 

156,165,884 

105,445,107 

0 

Prior Year 

End Balance 

12/31 

(d) 

2,168,054,319 

928,754,950 

0 

0 

937,708 

521,099,657 

0 

0 

14,750,820 

3,524,136,454 

30,059,316 

0 

0 

-15,416,249 

7,142,875,335 

4,302,445,000 

36,665,000 

0 

825,911,893 

0 

10,881,489 

5,080,810,404 

16,347,732 

0 

210,004,880 

644,218,436 

173,308,292 

0 

13,345,639 

0 

2,862,316,642 

3,919,541,621 

500,000,000 

1,037,780,250 

151,000,000 

22,585,481 

218,173,864 

54,865,494 

130,163,625 

30,415,357 

0 

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



Line 

No. 


(a) 


(1) x An Original 

(2) A Rresubmission 


(mo, da, yr) 

04/18/2009 end of 2008/Q4 

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

Ref. 

Page No. 

(b) 

46 Matured Interest (240) 

47 Tax Collections Payable (241) 

48 Miscellaneous Current and Accrued Liabilities (242) 

49 Obligations Under Capital Leases-Current (243) 

50 Derivative Instrument Liabilities (244) 

51 (Less) Long-Term Portion of Derivative Instrument Liabilities 

52 Derivative Instrument Liabilities - Hedges (245) 

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

54 Total Current and Accrued Liabilities (lines 37 through 53) 

55 DEFERRED CREDITS 

56 Customer Advances for Construction (252) 

57 Accumulated Deferred Investment Tax Credits (255) 

266-267 

58 Deferred Gains from Disposition of Utility Plant (256) 

59 Other Deferred Credits (253) 

269 

60 Other Regulatory Liabilities (254) 

278 

61 Unamortized Gain on Reaquired Debt (257) 

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

272-277 

63 Accum. Deferred Income Taxes-Other Property (282) 

64 Accum. Deferred Income Taxes-Other (283) 

65 Total Deferred Credits (lines 56 through 64) 

66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 

Current Year 


Balance 

(c) 

0 

4,119,200 

579,446,564 

3,535,737 

894,063,946 

738,347,396 

0 

0 

4,287,224,858 

154,712,261 

100,926,223 

0 

651,194,025 

1,065,118,270 

0 

0 

1,753,375,919 

2,344,293,935 

6,069,620,633 

30,598,312,221 

Prior Year 

End Balance 

12/31 

(d) 

0 

34,014,128 

573,725,162 

3,344,683 

113,347,453 

13,345,639 

0 

0 

2,856,069,858 

171,604,213 

104,937,659 

0 

635,716,710 

2,385,160,361 

0 

0 

1,594,968,509 

2,411,632,658 

7,304,020,110 

26,303,317,328 

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






STATEMENT OF INCOME 


(Mo, Da, Yr) 

04/18/2009 



Quarterly 

1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year. 

2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in (j) the 

quarter to date amounts for other utility function for the current year quarter. 

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 (k) the 

quarter to date amounts for other utility function for the prior year quarter. 

4. If additional columns are needed place them in a footnote. 

Annual or Quarterly if applicable 

5. 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 to 

a 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. 

8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2. 

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 


(a) 

UTILITY OPERATING INCOME 

Operating Revenues (400) 

Operating Expenses 

Operation Expenses (401) 

Maintenance Expenses (402) 

Depreciation Expense (403) 

Depreciation Expense for Asset Retirement Costs (403.1) 

Amort. & Depl. of Utility Plant (404-405) 

Amort. of Utility Plant Acq. Adj. (406) 

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

Amort. of Conversion Expenses (407) 

Regulatory Debits (407.3) 

(Less) Regulatory Credits (407.4) 

Taxes Other Than Income Taxes (408.1) 

Income Taxes - Federal (409.1) 

- Other (409.1) 

Provision for Deferred Income Taxes (410.1) 

(Less) Provision for Deferred Income Taxes-Cr. (411.1) 

Investment Tax Credit Adj. - Net (411.4) 

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

Losses from Disp. of Utility Plant (411.7) 

(Less) Gains from Disposition of Allowances (411.8) 

Losses from Disposition of Allowances (411.9) 

Accretion Expense (411.10) 

TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 

Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 

(Ref.) 

Page No. 

(b) 

300-301 

320-323 

320-323 

336-337 

336-337 

336-337 

336-337 

262-263 

262-263 

262-263 

234, 272-277 

234, 272-277 

266 

Total 

Current Year to 

Date Balance for 

Quarter/Year 

(c) 

Total 

Prior Year to 

Date Balance for 

Quarter/Year 

(d) 

10,268,382,076 10,221,356,322 

8,405,906,599 6,793,512,928 

422,814,939 382,964,134 

945,442,421 937,406,751 

99,397,440 87,642,542 

243,801 243,801 

272,107 272,093 

409,660 822,180 

-1,470,036,144 134,988,896 

-257,447,762 -320,964,452 

223,434,013 209,369,102 

63,761,073 304,578,113 

51,327,921 115,027,600 

195,728,445 -81,531,181 

-24,797,060 -19,604,075 

-4,011,700 -7,319,000 

3,888 

9,634,189 375,919 

9,207,297,320 9,218,170,567 

1,061,084,756 1,003,185,755 

Current 3 Months 

Ended 

Quarterly Only 

No 4th Quarter 

(e) 

Prior 3 Months 

Ended 



(f) 

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






(Mo, Da, Yr) 


04/18/2009 

STATEMENT OF INCOME FOR THE YEAR (Continued) 



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 be 

made 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 effected 

the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights 

of 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 rate 

proceeding 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 to 

this schedule. 

ELECTRIC UTILITY 

GAS UTILITY 

OTHER UTILITY 

Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line 

(in dollars) 

(in dollars) 

(in dollars) 

(in dollars) 

(in dollars) 

(in dollars) 

No. 

(g) 

(h) 

(i) 

(j) 

(k) 

(l) 

1 

10,261,745,645 10,217,524,856 2,213,999 

2,194,766 4,422,432 

1,636,700 2 

3 

8,401,752,629 6,790,294,880 2,103,190 

1,891,076 2,050,780 

1,326,972 4 

421,376,094 381,360,355 105,116 

154,676 1,333,729 

1,449,103 5 

944,759,240 936,716,605 186,534 

186,936 

496,647 

503,210 6 

7 

99,397,440 87,642,542 8 

243,801 243,801 9 

272,107 272,093 10 

409,660 822,180 11 

-1,470,036,144 134,988,896 12 

-257,447,762 -320,964,452 13 

223,255,669 209,233,386 45,576 

31,725 

132,768 

103,991 14 

64,063,794 305,534,206 -97,555 

-103,980 

-205,166 

-852,113 15 

51,363,651 115,216,713 -20,403 

-20,831 

-15,327 

-168,282 16 

195,714,750 -81,527,445 13,695 

-3,736 

17 

-24,797,060 -19,604,075 18 

-4,011,700 -7,319,000 19 

3,888 20 

21 

9,634,189 375,919 22 

23 

24 

9,201,167,736 9,213,671,820 2,336,153 

2,135,866 3,793,431 

2,362,881 25 

1,060,577,909 1,003,853,036 -122,154 

58,900 

629,001 

-726,181 26 




Line 

No. 


(a) 




(Mo, Da, Yr) 


04/18/2009 

STATEMENT OF INCOME FOR THE YEAR (continued) 

TOTAL 

(Ref.) 

Page No. Current Year Previous Year 

(b) 

(c) 

(d) 



Current 3 Months 

Ended 



(e) 

Prior 3 Months 

Ended 



(f) 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 

50 

51 

52 

53 

54 

55 

56 

57 

58 

59 

60 

61 

62 

63 

64 

65 

66 

67 

68 

69 

70 

71 

72 

73 

74 

75 

76 

77 

78 

Net Utility Operating Income (Carried forward from page 114) 

Other Income and Deductions 

Other Income 

Nonutilty Operating Income 

Revenues From Merchandising, Jobbing and Contract Work (415) 

(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 

Revenues From Nonutility Operations (417) 

(Less) Expenses of Nonutility Operations (417.1) 

Nonoperating Rental Income (418) 

Equity in Earnings of Subsidiary Companies (418.1) 

Interest and Dividend Income (419) 

Allowance for Other Funds Used During Construction (419.1) 

Miscellaneous Nonoperating Income (421) 

Gain on Disposition of Property (421.1) 

TOTAL Other Income (Enter Total of lines 31 thru 40) 

Other Income Deductions 

Loss on Disposition of Property (421.2) 

Miscellaneous Amortization (425) 

Donations (426.1) 

Life Insurance (426.2) 

Penalties (426.3) 

Exp. for Certain Civic, Political & Related Activities (426.4) 

Other Deductions (426.5) 

TOTAL Other Income Deductions (Total of lines 43 thru 49) 

Taxes Applic. to Other Income and Deductions 

Taxes Other Than Income Taxes (408.2) 

Income Taxes-Federal (409.2) 

Income Taxes-Other (409.2) 

Provision for Deferred Inc. Taxes (410.2) 

(Less) Provision for Deferred Income Taxes-Cr. (411.2) 

Investment Tax Credit Adj.-Net (411.5) 

(Less) Investment Tax Credits (420) 

TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 

Net Other Income and Deductions (Total of lines 41, 50, 59) 

Interest Charges 

Interest on Long-Term Debt (427) 

Amort. of Debt Disc. and Expense (428) 

Amortization of Loss on Reaquired Debt (428.1) 

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

(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 

Interest on Debt to Assoc. Companies (430) 

Other Interest Expense (431) 

(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 

Net Interest Charges (Total of lines 62 thru 69) 

Income Before Extraordinary Items (Total of lines 27, 60 and 70) 

Extraordinary Items 

Extraordinary Income (434) 

(Less) Extraordinary Deductions (435) 

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

Income Taxes-Federal and Other (409.3) 

Extraordinary Items After Taxes (line 75 less line 76) 

Net Income (Total of line 71 and 77) 

119 

340 

340 

262-263 

262-263 

262-263 

234, 272-277 

234, 272-277 

340 

340 

262-263 

1,061,084,756 1,003,185,755 

33,613,803 10,851,638 

17,860,792 3,639 

396,063 -293,836 

47,203,776 53,394,158 

18,793,361 31,515,537 

53,689,187 46,433,512 

13,936,448 6,755,854 

67,646 819,540 

149,839,492 149,472,764 

356,614 1,498 

14,607,487 11,299,267 

-24,261,306 -23,160,780 

27,500,000 -14,702,598 

31,953,513 23,333,676 

40,981,077 8,553,510 

91,137,385 5,324,573 

1,709,848 1,633,823 

-62,770,835 -34,661,063 

-14,571,859 -7,828,566 

42,371 551,617 

-27,267,617 -6,720,135 

-48,322,858 -33,584,054 

107,024,965 177,732,245 

302,890,095 279,689,247 

16,334,239 6,668,067 

10,414,505 20,330,644 

649,972 12,061,641 

130,067,873 127,425,115 

26,600,098 24,478,999 

433,756,586 421,695,715 

734,353,135 759,222,285 

734,353,135 759,222,285 







(Mo, Da, Yr) 


04/18/2009 

STATEMENT OF RETAINED EARNINGS 


End of 


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 unappropriated 

undistributed 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. Follow 

by 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 be 

recurrent, 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. 

Line 

No. 

Item 

(a) 

Contra Primary 

Account Affected 

(b) 

Current 

Quarter/Year 

Year to Date 

Balance 

(c) 

Previous 

Quarter/Year 

Year to Date 

Balance 

(d) 

UNAPPROPRIATED RETAINED EARNINGS (Account 216) 

1 Balance-Beginning of Period 

2 Changes 

3 Adjustments to Retained Earnings (Account 439) 

4 Credit: FIN 48 Adoption 

5 Credit: Dividends Received from Subsidiaries - Net 

6 

7 

8 

9 TOTAL Credits to Retained Earnings (Acct. 439) 

10 Debit: Reacquired Capital Stock Expense 

11 Debit: Stock Option Exercises 

12 Debit: Shares Purchased for Performance Shares 

13 Debit: Dividend Equivalents on Deferred Compensation 

14 Debit: Change in Classification of Shares Purchased to Settle Performance 

15 TOTAL Debits to Retained Earnings (Acct. 439) 

16 Balance Transferred from Income (Account 433 less Account 418.1) 

17 Appropriations of Retained Earnings (Acct. 436) 

18 Appropriations of Retained Earnings 

19 

20 

21 

22 TOTAL Appropriations of Retained Earnings (Acct. 436) 

23 Dividends Declared-Preferred Stock (Account 437) 

24 Preferred Stock Dividends 

25 

26 Preferred Stock Dividends 

27 

28 

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

30 Dividends Declared-Common Stock (Account 438) 

31 Common Stock Dividends 

32 

33 

34 

35 

36 TOTAL Dividends Declared-Common Stock (Acct. 438) 

37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 

38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 

APPROPRIATED RETAINED EARNINGS (Account 215) 

39 

40 

3,391,514,442 

76,703,873 

76,703,873 

-12,441,174 

-5,292,107 

-6,165,540 

-23,898,821 

687,149,359 

-3,840,996 

-3,840,996 

-50,946,097 

-50,946,097 

-400,000,000 

-400,000,000 

3,676,681,760 

2,690,194,967 

212,622,075 

102,507,883 

315,129,958 

( 69,286,010) 

( 10,623,047) 

( 4,279,748) 

( 78,102,459) 

( 162,291,264) 

705,828,127 

( 6,073,998) 

( 6,073,998) 

( 51,273,348) 

( 51,273,348) 

( 100,000,000) 

( 100,000,000) 

3,391,514,442 







(Mo, Da, Yr) 


04/18/2009 

STATEMENT OF RETAINED EARNINGS 


End of 


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 unappropriated 

undistributed 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. Follow 

by 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 be 

recurrent, 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. 

Line 

No. 

Item 

(a) 

Contra Primary 

Account Affected 

(b) 

Current 

Quarter/Year 

Year to Date 

Balance 

(c) 

Previous 

Quarter/Year 

Year 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) 

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 

49 Balance-Beginning of Year (Debit or Credit) 

50 Equity in Earnings for Year (Credit) (Account 418.1) 

51 (Less) Dividends Received (Debit) 

52 Other Changes (Explain): Prior Year Adjustment 

53 Balance-End of Year (Total lines 49 thru 52) 

136,463,009 

136,463,009 

3,813,144,769 

30,059,316 

47,203,776 

76,703,873 

559,219 

132,622,012 

132,622,012 

3,524,136,454 

79,174,496 

53,394,158 

102,507,883 

( 1,455) 

30,059,316 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




NOTES TO STATEMENT OF RETAINED EARNINGS FOR THE YEAR TO DATE DECEMBER 31, 2008 

Dividend 

Per Share 

Cumulative Preferred - 

4.08% Series $1.02 $ 695,751 

4.24% Series 1.06 1,272,001 

4.32% Series 1.08 1,785,703 

4.78% Series 1.195 1,549,642 

$100 Preference Stock - 

5.349% Series A 5.349 21,396,000 

6.125% Series B 6.125 12,250,000 

6.000% Series C 6.000 12,000,000 

____________ 

Total Preferred Dividends $ 50,946,097 







STATEMENT OF CASH FLOWS 


(Mo, Da, Yr) 

04/18/2009 



(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 as 

investments, 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 Cash 

Equivalents 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 reported 

in 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 to 

the 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 the 

dollar amount of leases capitalized with the plant cost. 

Line 

Description (See Instruction No. 1 for Explanation of Codes) 

No. 

(a) 

1 Net Cash Flow from Operating Activities: 

2 Net Income (Line 78(c) on page 117) 

3 Noncash Charges (Credits) to Income: 

4 Depreciation and Depletion 

5 Amort. of Nuc. Fuel, Loss on Reacq Debt, Prem. & Disc. of L/T Debt 

6 Regulatory Assets and Liabilities - Long Term 

7 Other Long Term Liabilities 

8 Deferred Income Taxes (Net) 

9 Investment Tax Credit Adjustment (Net) 

10 Net (Increase) Decrease in Receivables 

11 Net (Increase) Decrease in Inventory 

12 Net (Increase) Decrease in Allowances Inventory 

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 

16 (Less) Allowance for Other Funds Used During Construction 

17 (Less) Undistributed Earnings from Subsidiary Companies 

18 Other (provide details in footnote): 

19 Accrued Taxes 

20 Prepayments and Other Current Assets 

21 Other - Net 

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): 

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 

30 (Less) Allowance for Other Funds Used During Construction 


32 Cost of Removal, Salvage Value and Others 

33 

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) 

Current Year to Date 

Quarter/Year 

(b) 

734,353,135 

1,044,672,588 

96,777,155 

-2,627,600,584 

8,398,179 

214,467,179 

-4,011,436 

14,529,833 

-59,706,016 

-136,519,639 

-407,922,804 

91,506,690 

80,289,285 

47,203,776 

47,871,043 

37,793,829 

-148,222,575 

2,546,120,586 

1,325,014,102 

-2,051,642,361 

-99,231,475 

1,967,513 

-80,289,285 

-151,477,389 

-2,220,094,427 

9,638,078 

86,190,435 

Previous Year to Date 

Quarter/Year 

(c) 

759,222,285 

1,024,875,041 

95,465,198 

304,740,711 

-15,265,670 

113,630,018 

-7,318,651 

91,405,499 

-28,879,656 

64,601,598 

357,108,440 

19,369,651 

70,912,511 

53,394,158 

45,705,902 

-120,574,168 

-36,740,707 

2,543,038,822 

-2,041,064,148 

-122,843,387 

-3,774,488 

-70,912,511 

-148,812,356 

-2,245,581,868 

375,919 

91,979,166 







STATEMENT OF CASH FLOWS 


(Mo, Da, Yr) 

04/18/2009 



(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 as 

investments, 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 Cash 

Equivalents 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 reported 

in 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 to 

the 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 the 

dollar amount of leases capitalized with the plant cost. 

Line 

Description (See Instruction No. 1 for Explanation of Codes) 

No. 

(a) 

46 Loans Made or Purchased 

47 Collections on Loans 

48 

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 

53 Other: Proceeds from Nuclear Decommissioning trust sales 

54 Purchases of Nuclear Decommissioning Trust Investment 

55 Other 

56 Net Cash Provided by (Used in) Investing Activities 

57 Total of lines 34 thru 55) 

58 

59 Cash Flows from Financing Activities: 

60 Proceeds from Issuance of: 

61 Long-Term Debt (b) 

62 Preferred Stock 

63 Common Stock 


65 

66 Net Increase in Short-Term Debt (c) 


68 Tax benefit related to stock-based awards 

69 Proceeds from Stock Option Exercises 

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 


77 Shares Purchased for Stock-based Compensation 

78 Net Decrease in Short-Term Debt (c) 

79 Dividends on Preference Stock 

80 Dividends on Preferred Stock 

81 Dividends on Common Stock 

82 Net Cash Provided by (Used in) Financing Activities 

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 

88 Cash and Cash Equivalents at Beginning of Period 

89 

90 Cash and Cash Equivalents at End of period 

Current Year to Date 

Quarter/Year 

(b) 

3,129,780,212 

-3,137,028,376 

-15,103,318 

-2,146,617,396 

1,479,869,444 

1,392,625,000 

4,136,174 

17,182,521 

2,893,813,139 

-215,305,231 

-6,825,000 

-35,565,401 

-45,646,000 

-5,270,346 

-325,000,000 

2,260,201,161 

1,438,597,867 

82,753,980 

1,521,351,847 

Previous Year to Date 

Quarter/Year 

(c) 

3,696,654,755 

-3,829,708,208 

-591,795 

-2,286,872,031 

-850,137 

-109,396 

500,000,000 

28,476,623 

55,674,687 

583,191,777 

-436,314,633 

-135,167,888 

-45,646,000 

-5,627,347 

-135,000,000 

-174,564,091 

81,602,700 

1,151,280 

82,753,980 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 120 Line No.: 18 Column: b 

Represents Dividends received from unconsolidated subsidiary 

Schedule Page: 120 Line No.: 61 Column: c 

Represents issuance costs 




This 

(1) 


X 

Is: 

An Original 



04/18/2009 



NOTES TO FINANCIAL STATEMENTS 

1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained 

Earnings 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 of 

any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of 

a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears 

on cumulative preferred stock. 

3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of 

disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant 

adjustments 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, give 

an 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 such 

restrictions. 

6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are 

applicable 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 not 

misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be 

omitted. 

8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred 

which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently 

completed 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; and 

changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such 

matters 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 are 

applicable and furnish the data required by the above instructions, such notes may be included herein. 

PAGE 122 INTENTIONALLY LEFT BLANK 

SEE PAGE 123 FOR REQUIRED INFORMATION. 







NOTES TO FINANCIAL STATEMENTS (Continued) 


(Mo, Da, Yr) 

04/18/2009 



Glossary 

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. 

AB 

ACC 

AFUDC 

APS 

ARO(s) 

CAA 

CAIR 

CAMR 

CARB 

CDWR 

CEC 

CPSD 

CPUC 

CRRs 

District Court 

DOE 

DOJ 

DPV2 

DRA 

DWP 

EITF 

EITF No. 01-8 

EME 

ERRA 

FASB 

FERC 

FGIC 

FIN 39-1 

FIN 46(R) 

FIN 46(R)-6 

FIN 47 

FIN 48 

FSP 

FTRs 

GAAP 

GHG 

Assembly Bill 

Arizona Corporation Commission 

allowance for funds used during construction 

Arizona Public Service Company 

asset retirement obligation(s) 

Clean Air Act 

Clean Air Interstate Rule 

Clean Air Mercury Rule 

California Air Resources Board 

California Department of Water Resources 

California Energy Commission 

Consumer Protection and Safety Division 

California Public Utilities Commission 

congestion revenue rights 

U.S. District Court for the District of Columbia 

United States Department of Energy 

Department of Justice 

Devers-Palo Verde II 

Division of Ratepayer Advocates 

Los Angeles Department of Water & Power 

Emerging Issues Task Force 

EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease 

Edison Mission Energy 

energy resource recovery account 

Financial Accounting Standards Board 

Federal Energy Regulatory Commission 

Financial Guarantee Insurance Company 

Financial Accounting Standards Interpretation No. 39-1, Amendment of FASB 

Interpretation No. 39 

Financial Accounting Standards Board Interpretation No. 46, Consolidation of 

Variable Interest Entities 

Financial Accounting Standards Board Interpretation No. 46(R)-6, Determining 

Variability to be Considered in Applying FIN 46(R) 

Financial Accounting Standards Board Interpretation No. 47, Accounting for 

Conditional Asset Retirement Obligations 

Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in 

Income Taxes - an interpretation of FAS 109 

FASB Staff Position 

Firm transmission rights 

generally accepted accounting principles 

greenhouse gas 









(Mo, Da, Yr) 

04/18/2009 



Global 

Settlement 

A settlement that has been negotiated between Edison International and the IRS, 

which, if consummated, would resolve outstanding tax disputes for all Edison 

International subsidiaries, including SCE, for open tax years 1986 through 2002, 

including affirmative claims for unrecognized tax benefits. There can be no assurance 

about the timing of such settlement or that a final settlement will be ultimately 

consummated. 

General Rate Case 

SCE, SDG&E and PG&E 

GRC 

Investor-Owned 

Utilities 

IRS 

Internal Revenue Service 

ISO 

California Independent System Operator 

kWh(s) 

kilowatt-hour(s) 

MD&A Management’s Discussion and Analysis of Financial Condition and Results of 

Operations 

Mohave Mohave Generating Station 

MRTU 

Market Redesign Technical Upgrade 

MW 

megawatts 

MWh 

megawatt-hours 

Ninth Circuit United States Court of Appeals for the Ninth Circuit 

NOx 

nitrogen oxide 

NRC 

Nuclear Regulatory Commission 

Palo Verde Palo Verde Nuclear Generating Station 

PBOP(s) postretirement benefits other than pension(s) 

PBR 

performance-based ratemaking 

PG&E 

Pacific Gas & Electric Company 

POD 

Presiding Officer’s Decision 

PX 

California Power Exchange 

QF(s) 

qualifying facility(ies) 

RICO 

Racketeer Influenced and Corrupt Organization 

ROE 

return on equity 

S&P 

Standard & Poor’s 

SAB 

Staff Accounting Bulletin 

San Onofre San Onofre Nuclear Generating Station 

SCAQMD South Coast Air Quality Management District 

SCE 


SDG&E San Diego Gas & Electric 

SFAS 

Statement of Financial Accounting Standards issued by the FASB 

SFAS No. 71 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of 

Certain Types of Regulation 

SFAS No. 115 Statement of Financial Accounting Standards No. 115, Accounting for Certain 

Investments in Debt and Equity Securities 

SFAS No. 123(R) Statement of Financial Accounting Standards No. 123(R), Share-Based Payment 

(revised 2004) 

SFAS No. 133 Statement of Financial Accounting Standards No. 133, Accounting for Derivative 

Instruments and hedging Activities 

SFAS No. 143 Statement of Financial Accounting Standards No. 143, Accounting for Asset 

Retirement Obligations 

SFAS No. 157 Statement of Financial Accounting Standards No. 157, Fair Value Measurements 

SFAS No. 158 Statement of Financial Accounting Standards No. 158, Employers’ Accounting for 

Defined Benefit Pension and Other Post-Retirement Plans 









(Mo, Da, Yr) 

04/18/2009 



SFAS No. 159 

SFAS No. 160 

SFAS No. 161 

SO 2 

SRP 

The Tribes 

TURN 

VIE(s) 

Statement of Financial Accounting Standards No. 159, The Fair Value Option for 

Financial Assets and Financial Liabilities 

Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in 

Consolidated Financial Statements 

Statement of Financial Accounting Standards No. 161, Disclosures about Derivative 

Instruments and Hedging Activities, an amendment of FASB Statement No. 133 

sulfur dioxide 

Salt River Project Agricultural Improvement and Power District 

Navajo Nation and Hopi Tribe 

The Utility Reform Network 

variable interest entity(ies) 









(Mo, Da, Yr) 

04/18/2009 



ITEM 1: NOTES TO THE FINANCIAL STATEMENTS 

General Note 

SCE is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and 

southern California. 

These financial statements are prepared in accordance with the requirements of the FERC as set forth in its applicable 

Uniform System of Accounts and published accounting releases which is a comprehensive basis of accounting other than 

generally accepted accounting principles. These notes include specific information requested by the FERC. See the 

Company’s Annual Report to Shareholders as of, and for the year-ended, December 31, 2008 for financial statements and 

complete footnotes prepared in accordance with accounting principles generally accepted in the United States. 

SCE applies SFAS No. 71 to the portion of its operations in which regulators set rates at levels intended to recover the 

estimated costs of providing service, plus a return on capital. Due to timing and other differences in the collection of 

revenue, these principles allow an incurred costs that would otherwise be charged to expense by a nonregulated entity to 

be capitalized as a regulatory asset if it is probable that the cost is recoverable through future rates; and conversely these 

principles requires creation of a regulatory liability for probable future costs collected through rates in advance of the 

actual costs being incurred. SCE’s management continually evaluates the anticipated recovery of regulatory assets, 

liabilities, and revenue subject to refund and provides for allowances and/or reserves as appropriate. 

Financial statements prepared in conformity with FERC as set forth in its applicable Uniform System of Accounts and 

published accounting releases require management to make estimates and assumptions that affect the reported amounts of 

assets and liabilities and disclosure of contingency assets and liabilities at the date of the financial statements and the 

reported amounts of revenue and expenses during the reported period. Actual results could differ from those estimates. 

SCE’s outstanding common stock is owned entirely by its parent company, Edison International. 

The following are material differences between FERC reporting standards and GAAP: 

• Variable Interest Entities 

SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions based on the 

price of natural gas. Further, four of these contracts are with entities that are partnerships owned in part by a related 

party, EME. These four contracts had 20-year terms at inception. The QFs sell electricity to SCE and steam to nonrelated 

parties. Under FIN 46 (R), SCE consolidated these four projects under GAAP effective March 31, 2004. These four 

projects are not consolidated under FERC reporting standards, and are not accounted for as an equity investment since 

SCE has no ownership interests. 

• Equity Investment Differences 

SCE accounts for its investments in majority-owned subsidiaries using the equity method rather than consolidating the 

assets, liabilities, revenues and expenses of the subsidiaries which is required by GAAP. In general, the accounting for 

investments in majority-owned subsidiaries using the equity method rather than the consolidated method in accordance 

with GAAP has no effect on net income or retained earnings. Due to the nature of the business, SCE continues to 

consolidate Edison Material and Supplies. 









(Mo, Da, Yr) 

04/18/2009 



• Asset Impairments 

For FERC reporting purposes, asset impairments related to SCE’s nuclear and coal investments are written-off against the 

accumulated provision for depreciation of electric utility plant. FERC requires electric plant in service to be reported at 

its original cost and does not permit a company to reduce the amount recorded in electric plant in service below its 

original cost. As a result, asset impairments and additions made prior to cost-of-service ratemaking are recorded in the 

accumulated provision for depreciation of electric utility plant, as the Uniform System of Accounts allows extraordinary 

property losses to be credited to this account. Under cost-of-service ratemaking, additions to SCE’s nuclear and coal plant 

investments are recorded in electric plant in service. 

Under GAAP, asset impairments related to SCE’s nuclear and coal investments are written-off against the original 

amounts recorded in both electric plant in service and accumulated provision for depreciation of electric utility plant. In 

accordance with SFAS No. 71, SCE concluded that its asset impairments related to nuclear and coal investments, 

including additions made prior to cost-of-service ratemaking, were probable of recovery, and recorded a regulatory asset. 

Under cost-of-service ratemaking, SCE’s additions to nuclear and coal plant are recorded in electric plant in service. 

• Asset Retirement Obligation 

The accumulated net removal costs for SCE’s regulated plant assets that do not meet the definition of an ARO under 

SFAS No. 143 or conditional ARO under FIN 47 are classified as regulatory liabilities under GAAP and as accumulated 

depreciation under FERC. 

• Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS No. 150) 

Preferred stock subject to mandatory redemption is classified as a liability under GAAP and as proprietary capital under 

FERC. Also, dividends on preferred stock subject to mandatory redemption subsequent to July 1, 2003 are classified as 

interest expense under GAAP and as a reduction of retained earnings under FERC. 

• Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158) 

For FERC reporting purposes, the asset for an overfunded postretirement defined benefit plan is classified on the FERC 

financial statements as special funds, a noncurrent asset. For GAAP reporting purposes, this asset is classified as a 

miscellaneous deferred debit, which is also a noncurrent asset. 

• Other Differences 

The FERC required current maturities of long-term debt to be included as part of long-term debt, while GAAP requires 

such maturities to be classified as a current liability. Accumulated deferred income taxes are classified as current and 

noncurrent for GAAP, while FERC classifies all accumulated deferred income taxes as noncurrent. Regulatory assets and 

liabilities are classified as current and noncurrent for GAAP, while FERC classifies all regulatory assets and liabilities as 

noncurrent. Retained earnings is presented differently under the Uniform System of Accounts for FERC purposes than it 

is for GAAP purposes. Additionally the FERC requires only current year presentation of statements of cash flows and 

retained earnings while GAAP requires a comparative presentation. 

In 2008, for GAAP reporting purposes, SCE eliminated the previously reported income statement caption "Provsion for 

regulatory adjustment clauses - net" through classifications within relevant captions including "Operating revenue," 

Purchased power," "Other operation and maintenance" and "Depreciation, decommissioning and amortization." 









(Mo, Da, Yr) 

04/18/2009 



Certain prior-year amounts were reclassified to conform to the December 31, 2008 financial statement presentation. 

SCE’s outstanding common stock is owned entirely by its parent company, Edison International. 

Commitments 

Leases 

In accordance with EITF No. 01-8, power contracts signed or modified after June 30, 2003, need to be assessed for lease 

accounting requirements. Unit specific contracts in which SCE takes virtually all of the output of a facility are generally 

considered to be leases. As of December 31, 2005, SCE had six power contracts classified as operating leases. In 2006, 

SCE modified 62 power contracts. No contracts were modified in 2007 and 2008. The modifications to the contracts 

resulted in a change to the contractual terms of the contracts at which time SCE reassessed these power contracts under 

EITF No. 01-8 and determined that the contracts are leases and subsequently met the requirements for operating leases 

under SFAS No. 13. These power contracts had previously been grandfathered relative to EITF No. 01-8 and did not meet 

the normal purchases and sales exception. As a result, these contracts were recorded on the consolidated balance sheets at 

fair value in accordance with SFAS No. 133. Due to regulatory mechanisms, fair value changes did not affect earnings. 

At the time of modification, SCE had assets and liabilities related to mark-to-market gains or losses. Under 

SFAS No. 133, the assets and liabilities were reclassified to a lease prepayment or accrual and were included in the cost 

basis of the lease. The lease prepayment and accruals are being amortized over the life of the lease on a straight-line 

basis. At December 31, 2008, the net liability was $64 million. At December 31, 2008, SCE had 69 power contracts 

classified as operating leases. Operating lease expense for power purchases was $328 million in 2008, $297 million in 

2007, and $188 million in 2006. In addition, as of December 31, 2008, SCE had four power purchase contracts which met 

the requirements for capital leases. These capital leases have a net commitment of $1.22 billion at December 31, 2008 

and $20 million at December 31, 2007. The total estimated capital lease executory costs and interest expense were 

$1.71 billion at December 31, 2008 and $20 million at December 31, 2007. 

Other operating lease expense, primarily for vehicle leases, was $47 million in 2008, $39 million in 2007 and $31 million 

in 2006. The leases have varying terms, provisions and expiration dates. 

The following are estimated remaining commitments for noncancelable operating leases, including power purchases, 

vehicles, office space, and other equipment: 

Power 

Contracts 

Operating 

Leases 

Other 

Operating 

Leases 

In millions Year ending December 31, 

2009 $ 638 $ 51 

2010 625 49 

2011 458 42 

2012 355 34 

2013 349 29 

Thereafter 2,000 93 

Total $ 4,425 $ 298 

As discussed above, SCE modified numerous power contracts which increased the noncancelable operating lease future 

commitments and decreased the power purchase commitments below in “Other Commitments.” 









(Mo, Da, Yr) 

04/18/2009 



Rent expense under operating leases for vehicle, office space and other equipment is levelized over the terms of the 

leases. 

Capital leases are reported as long-term obligations on the consolidated balance sheets. In accordance with SFAS No. 71, 

SCE’s capital lease amortization expense and interest expense are reflected in purchased power on the consolidated 

statements of income. 

Nuclear Decommissioning 

As a result of SCE’s adoption of SFAS No. 143 in 2003, SCE recorded the fair value of its liability for AROs, primarily 

related to the decommissioning of its nuclear power facilities. At that time, SCE adjusted its nuclear decommissioning 

obligation, capitalized the initial costs of the ARO into a nuclear-related ARO regulatory asset, and also recorded an 

ARO regulatory liability as a result of timing differences between the recognition of costs recorded in accordance with 

SFAS No. 143 and the recovery of the related asset retirement costs through the rate-making process. 

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the NRC. 

Decommissioning is expected to begin after the plants’ operating licenses expire. The operating licenses currently expire 

in 2022 for San Onofre Units 2 and 3, and in 2024, 2025 and 2027 for the Palo Verde units. Decommissioning costs, 

which are recovered through nonbypassable customer rates over the term of each nuclear facility’s operating license, are 

recorded as a component of depreciation expense, with a corresponding credit to the ARO regulatory liability. The 

earnings impact of amortization of the ARO asset included within the unamortized nuclear investment and accretion of 

the ARO liability, both established under SFAS No. 143, are deferred as increases to the ARO regulatory liability 

account, with no impact on earnings. 

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in 

independent trusts. The cost of removal amounts, in excess of fair value collected for assets not legally required to be 

removed, are classified as regulatory liabilities. 

SCE’s nuclear decommissioning trusts are accounted for in accordance with SFAS No. 115, and due to regulatory 

recovery of SCE nuclear decommissioning expense, rate-making accounting treatment is applied to all nuclear 

decommissioning trust activities in accordance with SFAS No. 71. As a result, nuclear decommissioning activities do not 

affect SCE’s earnings. 

SCE’s nuclear decommissioning trust investments are classified as available-for-sale. SCE has debt and equity 

investments for the nuclear decommissioning trust funds. Due to regulatory mechanisms, earnings and realized gains and 

losses (including other-than-temporary impairments) have no impact on operating revenue. Unrealized gains and losses 

on decommissioning trust funds increase or decrease the trust asset and the related regulatory asset or liability and have 

no impact on operating revenue or decommissioning expense. SCE reviews each security for other-than-temporary 

impairment losses on the last day of each month compared to the last day of the previous month. If the fair value on both 

days is less than the cost for that security, SCE will recognize a realized loss for the other-than-temporary impairment. If 

the fair value is greater or less than the cost for that security at the time of sale, SCE will recognize a related realized gain 

or loss, respectively. 

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in 

independent trusts. The fair value of decommissioning SCE’s nuclear power facilities is $2.9 billion as of December 31, 

2008, based on site-specific studies performed in 2005 for San Onofre and Palo Verde. Changes in the estimated costs, 

timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to the estimated 

total cost to decommission. SCE estimates that it will spend approximately $11.5 billion through 2049 to decommission 









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its active nuclear facilities. This estimate is based on SCE’s decommissioning cost methodology used for rate-making 

purposes, escalated at rates ranging from 1.7% to 7.5% (depending on the cost element) annually. These costs are 

expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately 

$46 million per year. SCE estimates annual after-tax earnings on the decommissioning funds of 4.4% to 5.8%. If the 

assumed return on trust assets is not earned, it is probable that additional funds needed for decommissioning will be 

recoverable through rates in the future. If the assumed return on trust assets is greater than estimated, funding amounts 

may be reduced through future decommissioning proceedings. 

Decommissioning of San Onofre Unit 1 is underway and will be completed in three phases: (1) decontamination and 

dismantling of all structures and some foundations; (2) spent fuel storage monitoring; and (3) fuel storage facility 

dismantling, removal of remaining foundations, and site restoration. Phase one was scheduled to continue through 2008. 

Phase two is expected to continue until 2026. Phase three will be conducted concurrently with the San Onofre Units 2 

and 3 decommissioning projects. In February 2004, SCE announced that it discontinued plans to ship the San Onofre Unit 

1 reactor pressure vessel to a disposal site until such time as appropriate arrangements are made for its permanent 

disposal. It will continue to be stored at its current location at San Onofre Unit 1. This action results in placing the 

disposal of the reactor pressure vessel in Phase three of the San Onofre Unit 1 decommissioning project. 

All of SCE’s San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning trust funds and are 

subject to CPUC review. The estimated remaining cost to decommission San Onofre Unit 1 is recorded as an ARO 

liability ($59 million at December 31, 2008). Total expenditures for the decommissioning of San Onofre Unit 1 were 

$583 million from the beginning of the project in 1998 through December 31, 2008. 

Decommissioning expense under the rate-making method was $46 million, $46 million and $32 million in 2008, 2007 

and 2006, respectively. The ARO for decommissioning SCE’s active nuclear facilities was $2.9 billion and $2.7 billion at 

December 31, 2008 and 2007, respectively. 

Other Commitments 

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase. SCE has a coal fuel 

contract that requires payment of certain fixed charges whether or not coal is delivered. 

SCE has power purchase contracts with certain QFs (cogenerators and small power producers) and other power 

producers. These contracts provide for capacity payments if a facility meets certain performance obligations and energy 

payments based on actual power supplied to SCE (the energy payments are not included in the table below). There are no 

requirements to make debt-service payments. In an effort to replace higher-cost contract payments with lower-cost 

replacement power, SCE has entered into power purchase settlements to end its contract obligations with certain QFs. 

The settlements are reported as power purchase contracts on the consolidated balance sheets. 

Certain commitments for the years 2009 through 2013 are estimated below: 

In millions 2009 2010 2011 2012 2013 

Fuel supply $ 207 $ 117 $ 158 $ 198 $ 192 

Purchased power $ 289 $ 368 $ 519 $ 681 $ 660 

SCE has an unconditional purchase obligation for firm transmission service from another utility. Minimum payments are 

based, in part, on the debt-service requirements of the transmission service provider, whether or not the transmission line 

is operable. The contract requires minimum payments of $60 million through 2016 (approximately $7 million per year). 









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Indemnities 

Indemnity Provided as Part of the Acquisition of Mountainview 

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific 

environmental claims related to SCE’s previously owned San Bernardino Generating Station, divested by SCE in 1998 

and reacquired as part of the Mountain acquisition. SCE retained certain responsibilities with respect to environmental 

claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement 

for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires 

on or before March 12, 2033. SCE has not recorded a liability related to this indemnity. 

Other Indemnities 

SCE provides other indemnifications through contracts entered into in the normal course of business. These are primarily 

indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified 

environmental indemnities and income taxes with respect to assets sold. SCE’s obligations under these agreements may 

be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain 

indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum 

amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability 

related to these indemnities. 

Compensation and Benefits 

Employee Savings Plan 

SCE has a 401(k) defined contribution savings plan designed to supplement employees’ retirement income. The plan 

received employer contributions of $65 million in 2008, $61 million in 2007 and $57 million in 2006. 

Pension Plans and Postretirement Benefits Other Than Pensions 

SFAS No. 158 requires companies to recognize the overfunded or underfunded status of defined benefit pension and 

other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilities are normally offset 

through other comprehensive income (loss). SCE adopted SFAS No. 158 as of December 31, 2006. In accordance with 

SFAS No. 71, SCE recorded regulatory assets and liabilities instead of charges and credits to other comprehensive 

income (loss) for its postretirement benefit plans that are recoverable in utility rates. 

Pension Plans 

Noncontributory defined benefit pension plans (some with cash balance features) cover most employees meeting 

minimum service requirements. SCE recognizes pension expense for its nonexecutive plan as calculated by the actuarial 

method used for ratemaking. The expected contributions (all by the employer) are approximately $39 million for the year 

ended December 31, 2009. The fair value of the plan assets is determined primarily by quoted market prices. 

Volatile market conditions have affected the value of SCE’s trusts established to fund its future long-term pension 

benefits. The market value of the investments (reflecting investment returns, contributions and benefit payments) within 

the plan trusts declined 35% during 2008. This reduction in the value of plan assets resulted in a change in the pension 

plan funding status from overfunded to underfunded and will also result in increased future expense and increased future 

contributions. Changes in the plan’s funded status affect the assets and liabilities recorded on the balance sheet in 

accordance with SFAS No. 158. Due to SCE’s regulatory recovery treatment, the recognition of the funded status is 









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offset by regulatory liabilities and assets. In the 2009 GRC, SCE requested recovery of and continued balancing account 

treatment for amounts contributed to these trusts. The Pension Protection Act of 2006 establishes new minimum funding 

standards and restricts plans underfunded by more than 20% from providing lump sum distributions and adopting 

amendments that increase plan liabilities. 

Information on plan assets and benefit obligations is shown below: 

In millions Year ended December 31, 2008 2007 

Change in projected benefit obligation 

Projected benefit obligation at beginning of year $ 3,106 $ 3,176 

Service cost 104 100 

Interest cost 184 171 

Amendments — (5) 

Actuarial gain (2) (90) 

Special termination benefits — 2 

Benefits paid (217) (248) 

Projected benefit obligation at end of year $ 3,175 $ 3,106 

Change in plan assets 

Fair value of plan assets at beginning of year $ 3,459 $ 3,340 

Actual return (loss) on plan assets (1,059) 284 

Employer contributions 55 83 


Fair value of plan assets at end of year $ 2,238 $ 3,459 

Funded status at end of year $ (937) $ 353 

Amounts recognized in the consolidated balance sheets consist of: 

Long-term assets $ — $ 445 

Current liabilities (5) (5) 

Long-term liabilities (932) (87) 

$ (937) $ 353 

Amounts recognized in accumulated other comprehensive loss consist of: 

Prior service cost $ 1 $ 1 

Net loss 23 24 

$ 24 $ 25 

Amounts recognized as a regulatory asset (liability): 

Prior service cost $ 33 $ 49 

Net gain 951 (357) 

$ 984 $ (308) 

Total not yet recognized as expense $ 1,008 $ (283) 

Accumulated benefit obligation at end of year $ 2,898 $ 2,773 

Pension plans with an accumulated benefit obligation in excess of plan assets: 

Projected benefit obligation $ 3,175 $ 92 

Accumulated benefit obligation $ 2,898 $ 75 

Fair value of plan assets $ 2,238 — 

Weighted-average assumptions used to determine obligations at end of year: 

Discount rate 6.25% 6.25% 

Rate of compensation increase 5.0% 5.0% 









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Expense components and other amounts recognized in other comprehensive income: 

Expense components are: 

In millions Year ended December 31, 2008 2007 2006 

Service cost $ 104 $ 100 $ 102 

Interest cost 184 171 169 

Expected return on plan assets (249) (237) (225) 

Special termination benefits — 2 8 

Amortization of prior service cost 17 17 16 

Amortization of net loss 3 3 3 

Expense under accounting standards $ 59 $ 56 $ 73 

Regulatory adjustment – deferred (5) (3) (10) 

Total expense recognized $ 54 $ 53 $ 63 

Other changes in plan assets and benefit obligations recognized in other comprehensive income: 


Net loss (gain) $ (4) $ 5 

Prior service cost (1) — 

Amortization of prior service cost — — 

Amortization of net loss 3 (3) 

Total recognized in other comprehensive (income) loss $ (2) $ 2 

Total recognized in expense and other comprehensive income $ 52 $ 55 

Effective with the adoption of SFAS No. 158, as of December 31, 2006, and in accordance with SFAS No. 71, SCE 

records regulatory assets and liabilities instead of charges and credits to other comprehensive income (loss) for its 

postretirement benefit plans that are recoverable in utility rates. The estimated amortization amounts for 2009 are 

$17 million for prior service cost and $52 million for net gain including zero and $3 million respectively, reclassified 

from other comprehensive income. 

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits. 

The following are weighted-average assumptions used to determine expense: 

Year ended December 31, 2008 2007 2006 

Weighted-average assumptions: 

Discount rate 6.25% 5.75% 5.5% 

Rate of compensation increase 5.0% 5.0% 5.0% 

Expected return on plan assets 7.5% 7.5% 7.5% 









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The following are benefit payments, which reflect expected future service, expected to be paid: 


2009 $ 279 

2010 $ 284 

2011 $ 297 

2012 $ 303 

2013 $ 300 

2014 – 2018 $ 1,480 

The following are asset allocations by investment category: 

Target December 31, 

for 

2009 2008 2007 

United States equities 39% 41% 47% 

Non-United States equities 17% 22% 25% 

Private equities 4% 4% 2% 

Fixed income 40% 33% 26% 

Postretirement Benefits Other Than Pensions 

Most nonunion employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health 

and dental care, life insurance and other benefits. Eligibility depends on a number of factors, including the employee’s 

hire date. The expected contributions (all by the employer) to the PBOP trust are $125 million for the year ended 

December 31, 2009. The fair value of plan assets is determined primarily by quoted market prices. 

Volatile market conditions have affected the value of SCE’s trusts established to fund its future other postretirement 

benefits. The market value of the investments (reflecting investment returns, contributions and benefit payments) within 

the plan trust declined 33% during 2008. This reduction in the value of plan assets resulted in an increase in the plan 

underfunded status and will also result in increased future expense and increased future contributions. Changes in the 

plan’s funded status affect the assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. Due 

to SCE’s regulatory recovery treatment, the recognition of the funded status is offset by regulatory liabilities and assets. 

In the 2009 GRC, SCE requested recovery of and continued balancing account treatment for amounts contributed to this 

trust. 









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04/18/2009 



Information on plan assets and benefit obligations is shown below: 


Change in benefit obligation 

Benefit obligation at beginning of year $ 2,182 $ 2,178 

Service cost 38 43 

Interest cost 130 125 

Amendments — 6 

Actuarial gain (26) (77) 

Special termination benefits — 1 

Plan participants’ contributions 11 8 

Medicare Part D subsidy received 5 4 


Benefit obligation at end of year $ 2,247 $ 2,182 

Change in plan assets 

Fair value of plan assets at beginning of year $ 1,815 $ 1,743 

Actual return (loss) on assets (557) 117 

Employer contributions 31 49 

Plan participants’ contributions 11 8 

Medicare Part D subsidy received 5 4 


Fair value of plan assets at end of year $ 1,212 $ 1,815 

Fund status at end of year $ (1,035) $ (367) 

Amounts recognized in the consolidated balance sheets consist of: 

Current liabilities $ (17) $ (18) 

Long-term liabilities (1,018) (349) 

$ (1,035) $ (367) 

Amounts recognized in accumulated other comprehensive loss (income) 

consist of: 

Prior service cost $ — $ — 

Net loss — — 

$ — $ — 

Amounts recognized as a regulatory asset (liability): 

Prior service cost (credit) $ (178) $ (206) 

Net loss 1,076 437 

$ 898 $ 231 

Total not yet recognized as expense $ 898 $ 231 

Weighted-average assumptions used to determine obligations at end of 

year: 

Discount rate 6.25% 6.25% 

Assumed health care cost trend rates: 

Rate assumed for following year 8.75% 9.25% 

Ultimate rate 5.5% 5.0% 

Year ultimate rate reached 2016 2015 









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Expense components and other amounts recognized in other comprehensive income: 

Expense components are: 


Service cost $ 38 $ 43 $ 43 

Interest cost 130 125 116 

Expected return on plan assets (122) (119) (106) 

Special termination benefits — 1 4 

Amortization of prior service cost (credit) (29) (29) (29) 

Amortization of net loss 14 28 41 

Total expense $ 31 $ 49 $ 69 

Other changes in plan assets and benefit obligations recognized in other comprehensive income: 


Net loss $ — $ — 

Prior service cost — — 

Amortization of prior service cost (credit) — — 

Amortization of net loss — — 

Total recognized in other comprehensive 

income $ — $ — 

Total recognized in expense and other 

comprehensive income $ 31 $ 49 

Effective with the adoption of SFAS No. 158, as of December 31, 2006, and in accordance with SFAS No. 71, SCE 

records regulatory assets and liabilities instead of charges and credits to other comprehensive income (loss) for its 

postretirement benefit plans that are recoverable in utility rates. The estimated amortization amounts for 2009 are 

$(29) million for prior service cost (credit) and $61 million for net loss. 

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits. 

The following are weighted-average assumptions used to determine expense: 


Discount rate 6.25% 5.75% 5.5% 

Expected return on plan assets 7.0% 7.0% 7.0% 

Assumed health care cost trend rates: 

Current year 9.25% 9.25% 10.25% 

Ultimate rate 5.0% 5.0% 5.0% 

Year ultimate rate reached 2015 2015 2011 

Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of 

December 31, 2008 by $247 million and annual aggregate service and interest costs by $17 million. Decreasing the health 

care cost trend rate by one percentage point would decrease the accumulated benefit obligation as of December 31, 2008 









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by $222 million and annual aggregate service and interest costs by $15 million. 

The following benefit payments are expected to be paid: 


Before 

Subsidy* Net 

2009 $ 102 $ 97 

2010 112 106 

2011 122 115 

2012 131 123 

2013 139 131 

2014 – 2018 821 765 

* Medicare Part D prescription drug benefits 

The following are asset allocations by investment category: 

Asset allocations are: 

Target for December 31, 

2009 2008 2007 

United States equities 45% 58% 62% 

Non-United States equities 17% 11% 14% 

Private equities 1% — — 

Fixed income 37% 31% 24% 

Description of Pension and Postretirement Benefits Other Than Pensions Investment Strategies 

The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a 

combination of asset classes, and may have active and passive investment strategies within asset classes. As a result of 

the significant increase in global financial market volatility, during 2008 and in early 2009, the trusts’ investment 

committee approved interim changes in target asset allocations. SCE employs multiple investment management firms. 

Investment managers within each asset class cover a range of investment styles and approaches. Risk is managed through 

diversification among multiple asset classes, managers, styles and securities. Plan, asset class and individual manager 

performance is measured against targets. SCE also monitors the stability of its investments managers’ organizations. 

Allowable investment types include: 

United States Equities: Common and preferred stock of large, medium, and small companies which are predominantly 

United States-based. 

Non-United States Equities: Equity securities issued by companies domiciled outside the United States and in depository 

receipts which represent ownership of securities of non-United States companies. 

Private Equity: Limited partnerships that invest in nonpublicly traded entities. 

Fixed Income: Fixed income securities issued or guaranteed by the United States government, non-United States 

governments, government agencies and instrumentalities, mortgage backed securities and corporate debt obligations. A 









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small portion of the fixed income position may be held in debt securities that are below investment grade. 

Permitted ranges around asset class portfolio weights are plus or minus 3%. Where approved by the fiduciary investment 

committee, futures contracts are used for portfolio rebalancing and to approach fully invested portfolio positions. Where 

authorized, a few of the plan’s investment managers employ limited use of derivatives, including futures contracts, 

options, options on futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to 

markets. Derivatives are not used to leverage the plans or any portfolios. 

Determination of the Expected Long-Term Rate of Return on Assets 

The overall expected long term rate of return on assets assumption is based on the long-term target asset allocation for 

plan assets and capital markets return forecasts for asset classes employed. A portion of the PBOP trust asset returns are 

subject to taxation, so the expected long-term rate of return for these assets is determined on an after-tax basis. 

Capital Markets Return Forecasts 

Capital markets return forecasts are based on a long-term equilibrium forecast from an independent firm, as well as a 

separate analysis of expected equilibrium returns. The independent firm uses its research and judgment to determine 

long-term equilibrium forecasts. A core set of macroeconomic variables is used including real GDP growth, personal 

consumption expenditures, the federal funds target rate, dividend yield, and the Treasury yield curve. Fixed income, 

equity and private equity returns are determined from these factors. In addition, a separate analysis of equilibrium returns 

is made. The estimated total return for fixed income is based on an equilibrium yield for intermediate United States 

government bonds plus a premium for exposure to non-government bonds in the broad fixed income market. The 

equilibrium yield is based on analysis of historic and projected data and is consistent with experience over various 

economic environments. The premium of the broad market over United States government bonds is a historic average 

premium. The estimated rate of return for equity includes a 3% premium over the estimated total return of intermediate 

United States government bonds. The rate of return for private equity is estimated to be a 5% premium over public 

equity, reflecting a premium for higher volatility and illiquidity. 

Stock-Based Compensation 

Stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units have been granted 

under Edison International’s long-term incentive compensation programs. Edison International usually does not issue new 

common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the 

purchase and delivery of outstanding common stock for settlement of option exercises, performance shares and restricted 

stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International 

has discretion under certain of the awards to pay the half subject to cash settlement in Edison International’s common 

stock. Deferred stock units granted to management are settled in cash, not stock and represent a liability. Restricted stock 

units are settled in commons stock; however, Edison International will substitute cash awards to the extent necessary to 

pay tax withholding or any government levies. 

On April 26, 2007, Edison International’s shareholders approved a new incentive plan (the 2007 Performance Incentive 

Plan) that includes stock-based compensation. No additional awards were granted under Edison International’s prior 

stock-based compensation plans on or after April 26, 2007, and all future issuances will be made under the new plan. The 

maximum number of shares of Edison International’s common stock that may be issued or transferred pursuant to awards 

under the new incentive plan is 8.5 million shares, plus the number of any shares subject to awards issued under Edison 

International’s prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being 

exercised or shares being issued. As of December 31, 2008, Edison International had approximately 5.8 million shares 









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remaining for future issuance under its stock-based compensation plans. 

SFAS No. 123(R) requires companies to use the fair value accounting method for stock-based compensation. SCE 

implemented SFAS No. 123(R) in the first quarter of 2006 and applied the modified prospective transition method. Under 

the modified prospective method, the new accounting standard was applied effective January 1, 2006 to the unvested 

portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not 

restated under this method. The new accounting standard resulted in the recognition of expense for all stock-based 

compensation awards. In addition, SCE elected to calculate the pool of windfall tax benefits as of the adoption of 

SFAS No. 123(R) based on the method (also known as the short-cut method) proposed in FSP FAS 123(R)-3, “Transition 

Election to Accounting for the Tax Effects of Share-Based Payment Awards.” Prior to adoption of SFAS No. 123(R), 

SCE presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating 

cash flows under the caption “Other liabilities” in the consolidated statements of cash flows. SFAS No. 123(R) requires 

the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost 

recognized for those options (excess tax benefits) to be classified as financing cash flows. The $4 million, $28 million 

and $17 million of excess tax benefits are classified as financing cash flows in 2008, 2007 and 2006, respectively. Due to 

the adoption of SFAS No. 123(R), SCE recorded a cumulative effect adjustment that increased net income by less than 

$1 million, net of tax, in the first quarter of 2006, mainly to reflect the change in the valuation method for performance 

shares classified as liability awards and the use of forfeiture estimates. 

Prior to January 1, 2006, SCE accounted for these plans using the intrinsic value method. Upon grant, no stock-based 

compensation cost for stock options was reflected in net income, as the grant date was the measurement date, and all 

options granted under these plans had an exercise price equal to the market value of the underlying common stock on the 

date of grant. Previously, stock-based compensation cost for performance shares was remeasured at each reporting period 

and related compensation expense was adjusted. As discussed above, effective January 1, 2006, SCE implemented a new 

accounting standard that requires companies to use the fair value accounting method for stock-based compensation 

resulting in the recognition of expense for all stock-based compensation awards. SCE recognizes stock-based 

compensation expense on a straight-line basis over the requisite service period. Because SCE capitalizes a portion of 

cash-based compensation and SFAS No. 123(R) requires stock-based compensation to be recorded similarly to 

cash-based compensation, SCE capitalizes a portion of its stock-based compensation related to both unvested awards and 

new awards. SCE recognizes stock-based compensation expense for awards granted to retirement-eligible participants as 

follows: for stock-based awards granted prior to January 1, 2006, SCE recognized stock-based compensation expense 

over the explicit requisite service period and accelerated any remaining unrecognized compensation expense when a 

participant actually retired; for awards granted or modified after January 1, 2006, to participants who are 

retirement-eligible or will become retirement-eligible prior to the end of the normal requisite service period for the award, 

stock-based compensation will be recognized on a prorated basis over the initial year or over the period between the date 

of grant and the date the participant first becomes eligible for retirement. If SCE recognized stock-based compensation 

expense for awards granted prior to January 1, 2006, over a period to the date the participant first became eligible for 

retirement, stock-based compensation expense would have decreased $1 million and $4 million for 2007 and 2006, 

respectively. 

Total stock-based compensation expense, net of amounts capitalized, (reflected in the caption “Other operation and 

maintenance” on the consolidated statements of income) was $15 million, $21 million and $27 million for 2008, 2007 

and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $6 million, 

$8 million and $11 million for 2008, 2007 and 2006, respectively. Total stock-based compensation cost capitalized was 

$3 million, $4 million and $6 million for 2008, 2007 and 2006, respectively. 









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Stock Options 

Under various plans, SCE has granted stock options at exercise prices equal to the average of the high and low price and, 

beginning in 2007, at the closing price at the grant date. Edison International may grant stock options and other awards 

related to or with a value derived from its common stock to directors and certain employees. Options generally expire 

10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly 

over the requisite service period, except for awards granted to retirement-eligible participants. Stock-based compensation 

expense, net of amounts capitalized, associated with stock options was $12 million, $12 million and $20 million for 2008, 

2007 and 2006, respectively. 

Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five years of the option term. Stock 

options granted in 2007 and 2008 have no dividend equivalent rights. Unless transferred to nonqualified deferral plan 

accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid only on options that vest, 

including options that are unexercised. Dividend equivalents are paid in cash after the vesting date. Edison International 

has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison 

International will substitute cash awards to the extent necessary to pay tax withholding or any government levies. 

The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. 

The Black-Scholes option-pricing model requires various assumptions noted in the following table. 


Expected terms (in years) 7.4 7.5 9 to 10 

Risk-free interest rate 2.6% – 3.8% 4.6% – 4.8% 4.3% – 4.7% 

Expected dividend yield 2.3% – 3.9% 2.1% – 2.4% 2.3% – 2.8% 

Weighted-average expected dividend yield 2.5% 2.4% 2.4% 

Expected volatility 17% – 19% 16% – 17% 16% – 17% 

Weighted-average volatility 17.3% 16.5% 16.3% 

The expected term represents the period of time for which the options are expected to be outstanding and is primarily 

based on historical exercise and post vesting cancellation experience and stock price history. The risk-free interest rate 

for periods within the contractual life of the option is based on a zero coupon U.S. Treasury issued STRIPs (separate 

trading of registered interest and principal of securities) whose maturity equals the option’s expected term on the 

measurement date. In 2006 – 2008, expected volatility is based on the historical volatility of Edison International’s 

common stock for the most recent 36 months. 









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The following is a summary of the status of Edison International stock options granted to SCE employees: 

Weighted-Average 

Remaining 

Stock 

Options 

Exercise 

Price 

Contractual 

Term 

(Years) 

Aggregate 

Intrinsic 

Value 

Outstanding at December 31, 2007 6,260,384 $ 31.21 

Granted 1,189,404 $ 49.88 

Expired (13,905) $ 46.85 

Forfeited (94,032) $ 45.67 

Exercised (645,078) $ 25.89 

Transfer to associate (296,039) $ 37.45 

Outstanding at December 31, 2008 6,400,734 $ 34.58 6.30 

Vested and expected to vest at December 31, 2008 6,173,098 $ 34.23 6.22 $ 71,607,937 

Exercisable at December 31, 2008 3,717,758 $ 26.85 5.14 $ 70,563,047 

Stock options granted in 2007 and 2008 do not accrue dividend equivalents. 

The weighted-average grant-date fair value of options granted during the 2008, 2007 and 2006 was $10.19, $11.36 and 

$14.42, respectively. The total intrinsic value of options exercised during 2008, 2007 and 2006 was $13 million, 

$69 million and $43 million, respectively. At December 31, 2008, there was $13 million of total unrecognized 

compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a 

weighted-average period of approximately two years. The fair value of options vested during 2008, 2007 and 2006 was 

$12 million, $14 million and $27 million, respectively. 

The amount of cash used to settle stock options exercised was $30 million, $125 million and $88 million for 2008, 2007 

and 2006, respectively. Cash received from options exercised for 2008, 2007 and 2006 was $17 million, $56 million and 

$45 million, respectively. The estimated tax benefit from options exercised for 2008, 2007 and 2006 was $5 million, 

$28 million and $17 million. 

Performance Shares 

A target number of contingent performance shares were awarded to executives in March 2006, March 2007 and March 

2008, and vest at the end of December 2008, 2009 and 2010, respectively. Performance shares awarded in 2005 and 2006 

accrue dividend equivalents which accumulate without interest, and will be payable in cash following the end of the 

performance period when the performance shares are paid. Edison International has discretion to pay certain dividend 

equivalents in Edison International common stock. Performance shares awarded in 2007 and 2008 contain dividend 

equivalent reinvestment rights. An additional number of target contingent performance shares will be credited based on 

dividends on Edison International common stock for which the ex-dividend date falls within the performance period. The 

vesting of Edison International’s performance shares is dependent upon a market condition and three years of continuous 

service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but 

payment cannot be accelerated. The market condition is based on Edison International’s common stock performance 

relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of 

performance shares earned is determined based on Edison International’s ranking among these companies. Dividend 









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equivalents will be adjusted to correlate to the actual number of performance shares paid. Performance shares earned are 

settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to 

pay the half subject to cash settlement in common stock. Additionally, cash awards are substituted to the extent necessary 

to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a 

share-based liability award. The fair value of these shares is remeasured at each reporting period and the related 

compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a 

share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. 

Performance shares expense is recognized ratably over the requisite service period based on the fair values determined, 

except for awards granted to retirement-eligible participants. Stock-based compensation expense, net of amounts 

capitalized, associated with performance shares was less than zero, $6 million and $7 million for 2008, 2007, and 2006, 

respectively. The amount of cash used to settle performance shares classified as equity awards was $5 million, 

$11 million and $19 million for 2008, 2007 and 2006, respectively. In 2007 we changed the classification of the cash paid 

for the settlements of performance shares from common stock to retained earnings to conform with the classification for 

settlements of stock option exercises. 

The performance shares’ fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo 

simulation valuation model requires a risk-free interest rate and an expected volatility rate assumption. The risk-free 

interest rate is based on a 52-week historical average of the three-year zero coupon U.S. Treasury issued STRIPs 

(separate trading of registered interest and principal of securities) and is used as a proxy for the expected return for the 

specified group of companies. Volatility is based on the historical volatility of Edison International’s common stock for 

the recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data 

services provider. 

Edison International’s risk-free interest rate used to determine the grant date fair values for the 2008, 2007 and 2006 

performance shares classified as share-based equity awards was 3.9%, 4.8% and 4.1%, respectively. Edison 

International’s expected volatility used to determine the grant date fair values for the 2008, 2007 and 2006 performance 

shares classified as share-based equity awards was 17.4%, 16.5% and 16.2%, respectively. The portion of performance 

shares classified as share-based liability awards are revalued at each reporting period. The risk-free interest rate and 

expected volatility rate used to determine the fair value as of December 31, 2008 was to 0.8% and 19.2%, respectively for 

2008 performance shares. The risk-free interest rate and expected volatility rate used to determine the fair value as of 

December 31, 2007 was 4.3% and 17.1%, respectively for 2007 performance shares. 

The total intrinsic value of performance shares settled during 2008, 2007 and 2006 was $11 million, $23 million and 

$38 million, respectively, which included cash paid to settle the performance shares classified as liability awards for 

2008, 2007 and 2006 of $3 million, $5 million and $9 million, respectively. At December 31, 2008, there was $2 million 

(based on the December 31, 2008 fair value of performance shares classified as liability awards) of total unrecognized 

compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period 

of approximately two years. The fair values of performance shares vested during 2008, 2007 and 2006 were $2 million, 

$8 million and $14 million, respectively. 









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The following is a summary of the status of Edison International nonvested performance shares granted to SCE 

employees and classified as equity awards: 


Performance 

Shares 

Grant Date 

Fair Value 

Nonvested at December 31, 2007 85,243 $ 55.01 

Granted 47,101 $ 55.55 

Forfeited (46,209) $ 53.36 

Transferred to associate (7,618) $ 53.41 

Paid out — $ — 

Nonvested at December 31, 2008 78,517 $ 56.45 

The weighted-average grant-date fair value of performance shares classified as equity awards granted during 2008, 2007 

and 2006 was $55.55, $57.70 and $52.76, respectively. 

The following is a summary of the status of Edison International nonvested performance shares granted to SCE 

employees and classified as liability awards: 

Performance 

Shares 


Fair Value 

Nonvested at December 31, 2007 85,387 

Granted 46,957 

Forfeited (46,209) 

Transferred to associate (7,618) 

Paid out — 

Nonvested at December 31, 2008 78,517 $ 3.75 

Derivative Instruments and Hedging Activities 

SCE uses derivative financial instruments to manage financial exposure on its investments and fluctuations in commodity 

prices and interest rates. SCE manages these risks in part by entering into interest rate swap, cap and lock agreements, 

and forward commodity transactions, including options, swaps and futures. SCE is exposed to credit loss in the event of 

nonperformance by counterparties. To mitigate credit risk from counterparties, master netting agreements are used 

whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each 

counterparty and the risk associated with the transaction. 

SCE records its derivative instruments on its consolidated balance sheets at fair value as either assets or liabilities unless 

they meet the definition of a normal purchase or sale. The normal purchases and sales exception requires, among other 

things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of 

business. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria 

are met which requires SCE to formally document, designate, and assess the effectiveness of hedge transactions. For 

those derivative transactions that qualify for and for which SCE has elected hedge accounting, gains or losses from 

changes in the fair value of a recognized asset or liability or a firm commitment are reflected in earnings for the 

ineffective portion of a designated fair value hedge. For a designated hedge of the cash flows of a forecasted transaction, 

the effective portion of the gain or loss is initially recorded as a separate component of shareholders’ equity under the 









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caption “Accumulated other comprehensive income (loss),” and subsequently reclassified into earnings when the 

forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized 

currently in earnings. 

Derivative assets and liabilities are shown at gross amounts on the consolidated balance sheets, except that net 

presentation is used when SCE has the legal right of offset, such as multiple contracts executed with the same 

counterparty under master netting arrangements. In addition, derivative positions are offset against margin and cash 

collateral deposits in accordance with FIN No. 39-1 as discussed below in “Margin and Collateral Deposits” and “New 

Accounting Pronouncements.” The results of derivative activities are recorded as part of cash flows from operating 

activities on the consolidated statements of cash flows. 

To mitigate SCE’s exposure to spot-market prices, the CPUC has authorized SCE to enter into power purchase contracts 

(including QFs), energy options, tolling arrangements and forward physical contracts. SCE records these derivative 

instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale 

(as discussed above), or are classified as VIEs or leases. The derivative instrument fair values are marked to market at 

each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and 

offset through the provision for regulatory adjustment clauses - net, as the CPUC allows these costs to be recovered from 

or refunded to customers through a regulatory balancing account mechanism. As a result, fair value changes do not 

affect SCE’s earnings. SCE has elected not to use hedge accounting for these transactions due to this regulatory 

accounting treatment. 

Most of SCE’s QF contracts are not required to be recorded on the consolidated balance sheets because they either do not 

meet the definition of a derivative or meet the normal purchases and sales exception. However, SCE purchases power 

from certain QFs in which the contract pricing is based on a natural gas index, but the power is not generated with natural 

gas. The portion of these contracts that is not eligible for the normal purchases and sales exception is recorded on the 

consolidated balance sheets at fair value. Unit-specific contracts (signed or modified after June 30, 2003) in which SCE 

takes virtually all of the output of a facility are generally considered to be leases under EITF No. 01-8. 

SCE enters into interest-rate locks to mitigate interest rate risk associated with future financings. SCE expects to recover 

any fair value changes associated with the interest-rate lock through regulatory mechanisms. Realized and unrealized 

gains and losses do not affect current earnings. Realized gains/losses are amortized and recovered through interest 

expense over the life of the new debt. 

SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to 

meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, 

fuel tolling arrangements, and its own gas-fired generation, including the Mountainview plant. SCE’s realized and 

unrealized gains and losses arising from derivative instruments are reflected in purchased-power expense and offset 

through the provision for regulatory adjustment clauses - net on the consolidated statements of income and thus do not 

affect earnings, but may temporarily affect cash flows. 

Changes in realized and unrealized gains and losses on economic hedging activities were primarily due to significant 

decreases in forward natural gas prices in 2008 compared to 2007. Changes in realized and unrealized gains and losses on 

economic hedging activities in 2007 compared to 2006 were primarily due to changes in SCE’s gas hedge portfolio mix 

as well as an increase in the natural gas futures market in 2007. 

See further information about SCE’s derivative instruments in “Fair Value Measurements.” 









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Income Taxes 

SCE and its subsidiaries are included in Edison International’s consolidated federal income tax and combined state 

franchise tax returns. Under an income tax-allocation agreement approved by the CPUC, SCE’s tax liability is computed 

as if it filed its federal and state income tax returns on a separate return basis. 

SCE applies the asset and liability method of accounting for deferred income taxes as required by SFAS No. 109, 

“Accounting for Income Taxes.” In accordance with FIN 48, “Accounting for Uncertainty in Income Taxes,” SCE applies 

judgment to assess each tax position taken on filed tax returns and tax positions expected to be taken on future returns to 

determine whether a tax position is more likely than not to be sustained and recognized in the financial statements. 

However, all temporary tax positions, whether or not the more likely than not threshold of FIN 48 is met, are recorded in 

the financial statements in accordance with the measurement principles of FIN 48. 

As part of the process of preparing its consolidated financial statements, SCE is required to estimate its income taxes in 

each jurisdiction in which it operates. This process involves estimating actual current tax expense together with assessing 

temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. 

These differences result in deferred tax assets and liabilities, which are included within SCE’s consolidated balance 

sheet. SCE takes certain tax positions it believes are applied in accordance with tax laws. The application of these 

positions is subject to interpretation and audit by the IRS. 

Investment tax credits associated with rate-regulated public utility property are deferred and amortized over the lives of 

the properties. 

Accounting for tax obligations requires judgments, including estimating reserves for potential adverse outcomes 

regarding tax positions that have been taken. Management uses judgment in determining whether the evidence indicates it 

is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Management 

continually evaluates its income tax exposures and provides for allowances and/or reserves as appropriate, reflected in 

accrued taxes and other deferred credits and long-term liabilities on the consolidated balance sheets. Income tax expense 

includes the current tax liability from operations and the change in deferred income taxes during the year. Interest 

expense and penalties associated with income taxes are reflected in the caption “Income tax expense” on the consolidated 

statements of income. 

The components of income tax expense from continuing operations by location of taxing jurisdiction are: 


Current: 

Federal $ 53 $ 295 $ 681 

State 43 94 159 

96 389 840 

Deferred: 

Federal 232 (31) (312) 

State 14 (21) (90) 

246 (52) (402) 

Total $ 342 $ 337 $ 438 









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The components of the net accumulated deferred income tax liability are: 

In millions December 31, 2008 2007 

Deferred tax assets: 

Property-related 497 396 

Regulatory balancing accounts 436 519 

Unrealized gains and losses 70 393 

Decommissioning 168 182 

Pensions and PBOPs 203 177 

Other 439 552 

Total $ 1,813 $ 2,219 

Deferred tax liabilities: 

Property-related $ 3,493 $ 3,155 

Capitalized software costs 231 128 

Regulatory balancing accounts 433 521 

Unrealized gains and losses 70 394 

Decommissioning 148 158 

Other 209 273 

Total $ 4,584 $ 4,629 

Accumulated deferred income tax liability – net $ 2,771 $ 2,410 

The federal statutory income tax rate is reconciled to the effective tax rate from continuing operations as follows: 


Federal statutory rate 35.0% 35.0% 35.0% 

State tax – net of federal benefit 3.5 4.4 3.6 

Property-related (6.1) (1.0) (0.3) 

Tax reserve adjustments 0.7 (4.8) 3.1 

ESOP dividend payment (0.9) (0.8) (0.9) 

Resolution of state audit issue — — (3.9) 

Other (0.4) (2.0) (2.0) 

Effective tax rate 31.8% 30.8% 34.6% 









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The composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state 

income taxes) for all periods presented. The lower effective tax rate of 31.8% in 2008 as compared to the statutory rate 

was primarily due to software and property related flow through deductions. The lower effective tax rate of 30.8% in 

2007 as compared to the statutory rate was primarily due to reductions made to the income tax reserve to reflect progress 

made in an administrative appeals process with the IRS related to the income tax treatment of certain costs associated 

with environmental remediation and to reflect a settlement of state tax audit issues. The lower effective tax rate of 34.6% 

in 2006 as compared to the statutory rate was primarily due to a settlement reached with the California Franchise Tax 

Board regarding a state apportionment issue partially offset by tax reserve accruals. 

Accounting for Uncertainty in Income Taxes 

FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by 

determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical 

merits, that the position will be sustained on audit. Edison International has filed affirmative tax claims related to tax 

positions, which, if accepted, could result in refunds of taxes paid or additional tax benefits for positions not reflected on 

filed original tax returns. FIN 48 requires the disclosure of all unrecognized tax benefits, which includes the reserves 

recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims. 

Unrecognized Tax Benefits Tabular Disclosure 

The following table provides a reconciliation of unrecognized tax benefits from January 1 to December 31: 

In millions 2008 2007 

Balance at January 1 $ 1,950 $ 1,985 

Tax positions taken during the current year 

Increases 111 63 

Decreases — — 

Tax positions taken during a prior year 

Increases 162 124 

Decreases (157) (222) 

Decreases for settlements during the period — — 

Reductions for lapses of applicable statute of limitations — — 

Balance at December 31 $ 2,066 $ 1,950 

The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of $1.5 billion 

and $1.6 billion, at December 31, 2008 and 2007, respectively, that have been claimed on amended tax returns, but have 

not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS as part of their examinations. 

These affirmative claims remain unpaid by the IRS and no receivable has been recorded. Edison International has 

vigorously defended these affirmative claims in IRS administrative appeals proceedings and these claims are included in 

the ongoing Global Settlement negotiations. 

It is reasonably possible that Edison International could resolve, as part of the Global Settlement, or otherwise, with the 

IRS, all or a portion of SCE’s unrecognized tax benefits through tax year 2002 within the next 12 months, which could 









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reduce unrecognized tax benefits by up to $1.4 billion. 

The total amount of unrecognized tax benefits as of December 31, 2008 and 2007, respectively, that if recognized, would 

have an effective tax rate impact is $60 million and $65 million, respectively. 

Accrued Interest and Penalties 

The total amounts of accrued interest and penalties related to SCE’s income tax reserve were $120 million and 

$96 million as of December 31, 2008 and 2007, respectively. The after-tax interest expense (income) recognized and 

included in income tax expense was $14 million and $(24) million in 2008 and 2007, respectively. 

California Apportionment 

In December 2006, Edison International reached a settlement with the California Franchise Tax Board regarding the 

sourcing of gross receipts from the sale of electric services for California state tax apportionment purposes for tax years 

1981 to 2004. In 2006, SCE recorded a $49 million benefit related to a tax reserve adjustment as a result of this 

settlement. In the FIN 48 adoption, a $54 million benefit was recorded related to this same issue. In addition, Edison 

International received a net cash refund of approximately $52 million in April 2007. 

Tax Positions being Addressed as Part of Active Examinations, Administrative Appeals and the Global Settlement 

In the normal course, Edison International’s federal income tax returns are examined by the IRS and Edison International 

challenges deficiency adjustments, asserted as part of an examination, to the Administrative Appeals branch of the IRS 

(IRS Appeals) to the extent Edison International believes its tax reporting positions properly complied with the relevant 

tax law and that the IRS’ basis for making such adjustments lacks merit. Edison International has challenged certain IRS 

deficiency adjustments, asserted as part of the examination of tax years 1994 – 1999 with IRS Appeals. Edison 

International has also been under active IRS examination for tax years 2000 – 2002 and during the third quarter of 2008, 

the IRS commenced an examination of tax years 2003 – 2006. In addition, the statute of limitations remains open for tax 

years 1986 – 1993, which has allowed Edison International to file certain affirmative claims related to these tax years. 

Most of the tax positions that Edison International is addressing with IRS Appeals relate to the timing of when deductions 

for federal income tax purposes are allowed to be reflected on filed income tax returns and, as such, any deductions not 

sustained would be deductible on future tax returns filed by Edison International. However, any penalties and interest 

associated with disallowed deductions would result in a permanent cost. Edison International has also filed affirmative 

claims with respect to certain tax years 1986 through 2005 with the IRS and state tax authorities. At this time, there has 

not been a final determination of these affirmative claims by the IRS or state tax authorities which are included in the 

Global Settlement with the IRS as discussed below. Benefits, if any, associated with these affirmative claims would be 

recorded in accordance with FIN 48 which provides that recognition would occur at the earlier of when Edison 

International would make an assessment that the affirmative claim position has a more likely than not probability of being 

sustained or when a final settlement of the affirmative claim is consummated with the tax authority. Certain of these 

affirmative claims have been recognized as part of the implementation of FIN 48. 

Edison International has been engaged in settlement negotiations with the IRS to reach a Global Settlement described 

below of all unresolved tax disputes and affirmative claims for tax years 1986 – 2002. 

In addition to the IRS audits, Edison International’s California and other state income tax returns are, in the normal 

course, subjected to examination by the California Franchise Tax Board and the other state tax authorities. The Franchise 

Tax Board has substantially completed its examination of all tax years through 2002 and is currently awaiting resolution 

of the IRS audit before finalizing the audit for these tax years. Edison International is currently under active examination 

for tax years 2003 – 2004 and remains subject to examination by the California Franchise Tax Board for tax years 2005 









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and forward. 

Edison International filed amended California Franchise tax returns for tax years 1997 – 2002 to mitigate the possible 

imposition of California non-economic substance penalty provisions on transactions that may be considered as Listed or 

substantially similar to Listed Transactions described in an IRS notice that was published in 2001. These transactions 

include an SCE subsidiary contingent liability company transaction, described below. Edison International filed these 

amended returns under protest retaining its appeal rights. 

Global Settlement 

As previously disclosed, Edison International has negotiated the material terms of a Global Settlement with the IRS 

which, if consummated, would resolve all outstanding tax disputes for open tax years 1986 through 2002, including 

certain affirmative claims for unrecognized tax benefits. As negotiated with the IRS, consummation of the Global 

Settlement is subject to completion of closing procedures with the IRS, following review of the Global Settlement by the 

Joint Committee on Taxation, a committee of the United States Congress. 

If and when Edison International and the IRS consummate a settlement, Edison International will file amended tax returns 

with the Franchise Tax Board and other state administrative agencies, for those states in which Edison International has 

an income tax filing requirement, to reflect the respective state income tax impact of the settlement terms. 

The issues discussed below are included in the scope of issues being addressed as part of the Global Settlement process. 

Balancing Account Over-Collections 

In response to an affirmative claim filed by Edison International related to balancing account over-collections, the IRS 

issued a Notice of Proposed Adjustment in July 2007 as part of the ongoing IRS examinations and administrative appeals 

processes. The tax years to which adjustments are made pursuant to this Notice of Proposed Adjustment are included in 

the scope of the Global Settlement process. The cash and earnings impacts of this position are dependent on the ultimate 

settlement of all open tax issues, including this issue, in these tax years. Edison International expects that resolution of 

this issue could potentially increase earnings and cash flows within the range of $70 million to $80 million and 

$300 million to $350 million, respectively. 

Contingent Liability Company 

The IRS has asserted tax deficiencies and penalties of $53 million and $22 million, respectively, for tax years 1997 – 

1999 with respect to a transaction entered into by a former SCE subsidiary which the IRS has asserted to be substantially 

similar to a Listed Transaction described by the IRS as a contingent liability company. 

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations, Administrative 

Appeals and the Global Settlement 

Edison International continues its efforts to resolve open tax issues through tax year 2002 as part of the Global 

Settlement. Although the timing for resolving these open tax positions is uncertain, it is reasonably possible that all or a 

significant portion of these open tax issues through tax year 2002 could be resolved within the next 12 months. 

Fair Value Measurements 

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an 









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orderly transaction between market participants at the measurement date (referred to as an “exit price” in SFAS No. 157). 

SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity’s non-performance risk. In 

addition, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to 

measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for 

identical asset and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 

measurements). The three levels of the fair value hierarchy under SFAS No. 157 are: 

• Level 1 – Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets 

and liabilities; 

• Level 2 – Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are 

observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial 

instrument; and 

• Level 3 – Prices or valuations that require inputs that are both significant to the fair value measurements and 

unobservable. 

SCE’s assets and liabilities carried at fair value primarily consist of derivative contracts, SCE nuclear decommissioning 

trust investments and money market funds. Derivative contracts primarily relate to power and gas and include contracts 

for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis 

(including futures contracts). Derivative contracts can be exchange traded or over-the-counter traded. 

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the 

underlying commodities, and other factors. Derivatives that are exchange traded in active markets for identical assets or 

liabilities are classified as Level 1. SCE’s Level 2 derivatives primarily consist of financial natural gas swaps, fixed float 

swaps, and natural gas physical trades for which SCE obtains the applicable Henry Hub and basis forward market prices 

from the New York Mercantile Exchange and Intercontinental Exchange. 

Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts, capacity 

contracts, and QF contracts. The fair value of these SCE derivatives is determined using uncorroborated non-binding 

broker quotes (from one or more brokers) and models which may require SCE to extrapolate short-term observable inputs 

in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for 

reasonableness. SCE has Level 3 fixed float swaps for which SCE obtains the applicable Henry Hub and basis forward 

market prices from the New York Mercantile Exchange. However, these swaps have contract terms that extend beyond 

observable market data and the unobservable inputs incorporated in the fair value determination are considered 

significant compared to the overall swap’s fair value. 

Level 3 also includes derivatives that trade infrequently (such as FTRs and CRRs in the California market and 

over-the-counter derivatives at illiquid locations), and long-term power agreements. For illiquid FTRs, SCE reviews 

objective criteria related to system congestion and other underlying drivers and adjusts fair value when SCE concludes a 

change in objective criteria would result in a new valuation that better reflects the fair value. Recent auction prices are 

used to determine the fair value of short-term CRRs and the proprietary model is used for long-term CRRs. SCE recorded 

liquidity reserves against the long-term CRRs fair values since there were no quoted long-term market prices for the 

CRRs and insufficient evidence of long-term market prices. 

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, 

fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using 

the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair 









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value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In 

circumstances where SCE cannot verify fair value with observable market transactions, it is possible that a different 

valuation model could produce a materially different estimate of fair value. As markets continue to develop and more 

pricing information becomes available, SCE continues to assess valuation methodologies used to determine fair value. 

The SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other 

fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable 

market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as 

Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable 

market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer 

quotes, issuer spreads, bids, offers and relevant credit information. 

The following table sets forth financial assets and liabilities that were accounted for at fair value as of December 31, 

2008 by level within the fair value hierarchy: 

Netting and 

Collateral(1) 

Total at 

December 31, 

2008 

In millions Level 1 Level 2 Level 3 

Assets at Fair Value 

Money market funds(2) $ 1,486 $ — $ — $ — $ 1,486 

Derivative contracts 2 2 227 — 231 

Nuclear decommissioning 

trusts (3) 1,502 1,026 — — 2,528 

Long-term disability plan 7 — — — 7 

Total assets(4) 2,997 1,028 227 — 4,252 

Liabilities at Fair Value 

Derivative contracts (2) (219) (745) 72 (894) 

Net assets (liabilities) $ 2,995 $ 809 $ (518) $ 72 $ 3,358 

(1) Represents cash collateral and the impact of netting across the levels of the fair value 

hierarchy. Netting among positions classified within the same level is included in that 

level. 

(2) Included in cash and cash equivalents on SCE’s consolidated balance sheet. 

(3) Excludes net liabilities of $4 million of interest and dividend receivables and 

receivables related to pending securities sales and payables related to pending securities 

purchases. 

(4) Excludes $32 million of cash surrender value of life insurance investments for 

deferred compensation. 









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The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the year 

ended December 31, 2008: 

In millions 2008 

Fair value of derivative contracts, net at January 1, 2008 $ (22) 

Total realized/unrealized losses: 

Included in earnings — 

Included in regulatory assets and liabilities (1) (645) 

Included in accumulated other comprehensive loss — 

Purchases and settlements, net 167 

Transfers in or out of Level 3 (18) 

Fair value of derivative contracts, net at December 31, 2008 $ (518) 

Change during the period in unrealized losses related to net derivative 

contracts, held at December 31, 2008 $(573) 

(1) Due to regulatory mechanisms, SCE’s realized and unrealized gains and losses are recorded as 

regulatory assets and liabilities. 

Nuclear Decommissioning Trusts 

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in 

independent trusts. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The 

CPUC has set certain restrictions related to the investments of these trusts. 

Trust investments (at fair value) include: 

In millions 

Maturity 

Dates 

December 31, 


December 31, 

2007 

Municipal bonds 2009 – 2044 $ 629 $ 561 

Stocks – 1,308 1,968 

United States government issues 2009 – 2049 304 552 

Corporate bonds 2009 – 2047 260 241 

Short-term investments, primarily 

cash equivalents 2009 23 56 

Total $ 2,524 $ 3,378 

Note: Maturity dates as of December 31, 2008. 

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. 

Net earnings (losses) were $(10) million, $143 million and $130 million in 2008, 2007 and 2006, respectively. Proceeds 

from sales of securities (which are reinvested) were $3.1 billion, $3.7 billion and $3.0 billion in 2008, 2007 and 2006, 

respectively. Unrealized holding gains, net of losses, were $618 million and $1.1 billion at December 31, 2008 and 2007, 

respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible. 









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The following table sets forth a summary of changes in the fair value of the trust for the year ended December 31, 2008: 

In millions 2008 

Balance at beginning of period $ 3,378 

Realized losses – net (65) 

Unrealized losses – net (545) 

Other-than-temporary impairment (317) 

Earnings and other 73 

Balance at December 31, 2008 $ 2,524 

The decrease in the trust investments was primarily due to net unrealized losses and other-than-temporary impairment 

resulting from a volatile stock market environment. Due to regulatory mechanisms, earnings and realized gains and losses 

(including other-than-temporary impairments) have no impact on operating revenue. 

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded from independent 

decommissioning trusts, which currently receive contributions of approximately $46 million per year. Contributions to 

the decommissioning trusts are reviewed every three years by the CPUC. The next filing is in April 2009 for contribution 

changes in 2011. These contributions are determined based on an analysis of the current value of trusts assets and 

long-term forecasts of cost escalation, the estimate and timing of decommissioning costs, and after-tax return on trust 

investments. Favorable or unfavorable investment performance in a period will not change the amount of contributions 

for that period. However, trust performance for the three years leading up to a CPUC review proceeding will provide 

input into future contributions. The CPUC has set certain restrictions related to the investments of these trusts. If 

additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through 

customer rates. 

Fair Values of Financial Instruments 

The carrying amounts and fair values of financial instruments are: 

In millions 

December 31, 

2008 2007 

Carrying Fair Carrying 

Amount Value Amount 

Fair 

Value 

Derivatives: 

Interest rate hedges $ — $ — $ (33) $ (33) 

Commodity price assets 231 231 82 82 

Commodity price liabilities (964) (964) (77) (77) 

QF power contracts liabilities (2) (2) (3) (3) 

Other: 

Decommissioning trusts 2,524 2,524 3,378 3,378 

Long-term debt (6,212) (6,566) (5,081) (5,100) 

Long-term debt due within one year (150) (151) — — 

Fair values are based on: brokers’ quotes and bank evaluations for interest rate hedges and long-term debt. See “Fair 

Value Measurements” above for discussion of valuation of derivatives and the decommissioning trusts. 









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In January and February 2008, SCE settled interest rate locks resulting in realized losses of $33 million. A related 

regulatory asset was recorded in this amount and SCE is amortizing and recovering this amount as interest expense 

associated with its 2008 financings. 

New Accounting Pronouncements 

Accounting Pronouncements Adopted 

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts 

recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) 

against fair value amounts recognized for derivative instruments executed with the same counterparty under a master 

netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset 

or not offset fair value amounts recognized for derivative instruments under master netting agreements. SCE adopted 

FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits 

with derivative positions on SCE’s consolidated balance sheets, but had no impact on its consolidated statements of 

income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which 

resulted in a decrease in net assets (margin and collateral deposits) of $2 million. The consolidated statements of cash 

flows for the years ended December 31, 2007 and 2006 have been retroactively restated to reflect the balance sheet 

changes, which had no impact on total operating cash flows from continuing operations. 

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and 

liabilities at fair value, with changes in fair value recognized in earnings. SCE adopted this pronouncement effective 

January 1, 2008. The adoption of this standard had no impact because SCE did not make an optional election to report 

additional financial assets and liabilities at fair value. 

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework 

for measuring fair value and expands the disclosures on fair value measurements. SCE adopted SFAS No. 157 effective 

January 1, 2008. The adoption did not result in any retrospective adjustments to its consolidated financial statements. The 

accounting requirements for employers’ pension and other postretirement benefit plans were effective at the end of 2008, 

which was the next measurement date for these benefit plans. SCE will adopt this standard for nonrecurring nonfinancial 

assets and liabilities (AROs) measured or disclosed at fair value during the first quarter of 2009. Since this standard is 

applied prospectively, AROs existing before the adoption of the standard will not be adjusted for nonperformance risk. 

On October 10, 2008, the FASB issued FSP SFAS No. 157-3, “Determining the Fair Value of a Financial Asset When the 

Market for That Asset Is Not Active.” This position clarifies the application of SFAS No. 157 in a market that is not 

active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the 

market for that financial asset is not active. It also reaffirms the notion of fair value as an exit price as of the measurement 

date. This position was effective upon issuance, including prior periods for which financial statements have not been 

issued. The adoption had no impact on SCE’s consolidated financial statements. 

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which 

identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation 

of financial statements for nongovernmental entities that are presented in conformity with U.S. GAAP. This statement 

transfers the GAAP hierarchy from the American Institute of Certified Public Accountants Statement on Auditing 

Standards No. 69, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles” to the 

FASB. SFAS No. 162, was effective on November 15, 2008. The adoption of this standard did not have an impact on 

SCE’s consolidated results of operations, financial position or cash flows. 









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In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) 

about Transfers of Financial Assets and Interests in Variable Interest Entities.” For asset transfers, the additional 

disclosure requirements primarily focus on the transferor’s continuing involvement with transferred financial assets and 

the related risks retained. For VIEs, this position requires public enterprises to provide additional disclosures about their 

involvement with variable interest entities including the method for determining whether an enterprise is the primary 

beneficiary, the significant judgments and assumptions made and the details of any financial or other support provided to 

a VIE. This position was effective for reporting periods ending after December 15, 2008. The adoption did not have an 

impact on SCE’s consolidated financial position, results of operations or cash flows. 

In December 2008, the FASB issued FSP EITF 99-20-1, “Amendments to the Impairment guidance of EITF Issue 

No. 99-20,” which amends the guidance for purchased beneficial interests to achieve more consistent determination of 

whether an other-than-temporary impairment has occurred for available-for-sale or held-to-maturity debt securities. This 

pronouncement was effective for reporting periods ending after December 15, 2008. Because SCE already evaluates 

impairment for these securities in accordance with SFAS No. 115, the adoption did not have an impact on its 

consolidated financial position, results of operations or cash flows. 

Accounting Pronouncements Not Yet Adopted 

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest that reflects the 

ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the 

entity’s equity in the consolidated financial statements. It also requires the amount of consolidated net income 

attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the 

consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and, 

when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain 

or loss on the deconsolidation of the subsidiary be measured at fair value. SCE will adopt SFAS No. 160 in the first 

quarter of 2009. In accordance with this standard, SCE will reclassify minority interest to a component of shareholders’ 

equity. 

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, 

including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are 

accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial 

performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early 

adoption permitted. SCE will adopt SFAS No. 161 in the first quarter of 2009. Since SFAS No. 161 impacts disclosures 

only, the adoption of this standard will not have an impact on SCE’s consolidated results of operations, financial position 

or cash flows. 

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers” Disclosures about Postretirement Benefit Plan 

Assets.” This position requires additional plan asset disclosures about the major categories of assets, the inputs and 

valuation techniques used to measure fair value, the level within the fair value hierarchy, the effect of using significant 

unobservable inputs (Level 3) and significant concentrations of risk. This position is effective for years ending after 

December 15, 2009 and therefore, SCE will adopt FSP FAS 132(R)-1 at year-end 2009. FSP FAS 132(R)-1 will impact 

disclosures only and will not have an impact on SCE’s consolidated results of operations, financial position or cash 

flows. 









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BALANCE SHEET: 

Book Overdrafts 

Book overdrafts represent timing difference associated with outstanding checks in excess of cash funds that are on 

deposit with financial institutions. SCE’s ending daily cash funds are temporarily invested in short-term investments, 

until required for check clearings. SCE reclassifies the amount for checks issued but not yet paid by the financial 

institution, from cash to book overdrafts. 

Cash and Equivalents 

Cash equivalents included money market funds totaling $1.5 billion and $83 million at December 31 2008 and 2007, 

respectively. The carrying value of cash equivalents approximates fair value due to maturities of less than three months. 

For further discussion of money market funds, “Fair Value Measurements.” 

Deferred Financing Costs 

Debt premium, discount and issuance expenses are deferred and amortized on a straight-line basis through interest 

expense over the life of each related issue. Under CPUC rate-making procedures, debt reacquisition expenses are 

amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. California law 

prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. SCE had unamortized loss on reacquired 

debt of $309 million at December 31, 2008 and $331 million at December 31, 2007 reflected in “Regulatory assets” in 

the long-term section of the consolidated balance sheets. SCE had unamortized debt issuance costs of $49 million at 

December 31, 2008 and $40 million at December 31, 2007 reflected in “Other long-term assets” on the consolidated 

balance sheets. 

Dividend Restrictions 

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International. In SCE’s most 

recent cost of capital proceeding, the CPUC sets an authorized capital structure for SCE which included a common equity 

component of 48%. SCE may make distributions to Edison International as long as the common equity component of 

SCE’s capital structure remains at or above the authorized level on a 13-month weighted average basis of 48%. At 

December 31, 2008, SCE’s 13-month weighted-average common equity component of total capitalization was 50.6% 

resulting in the capacity to pay $345 million in additional dividends. 

Impairment of Long-Lived Assets 

SCE evaluates the impairment of its long-lived assets based on a review of estimated cash flows expected to be generated 

whenever events or changes in circumstances indicate the carrying amount of such investments or assets may not be 

recoverable. If the carrying amount of the asset exceeds the amount of the expected future cash flows, undiscounted and 

without interest charges, then an impairment loss is recognized in accordance with SFAS No. 144. In accordance with 

SFAS No. 71, SCE’s impaired assets are recorded as a regulatory asset if it is deemed probable that such amounts will be 

recovered from the ratepayers. 









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Inventory 

Inventory is stated at the lower of cost or market, cost being determined by the average cost method for fuel and materials 

and supplies. 

Jointly Owned Utility Projects 

SCE owns interests in several generating stations and transmission systems for which each participant provides its own 

financing. SCE’s proportionate share of expenses for each project is included in the consolidated statements of income. 

The following is SCE’s investment in each project as of December 31, 2008: 

In millions 

Investment 

in 

Facility 

Accumulated 

Depreciation and 

Amortization 

Ownership 

Interest 

Transmission systems: 

Eldorado $ 71 $ 13 60% 

Pacific Intertie 310 103 50 

Generating stations: 

Four Corners Units 4 and 5 (coal) 554 454 48 

Mohave (coal) 345 294 56 

Palo Verde (nuclear) 1,824 1,501 16 

San Onofre (nuclear) 4,833 4,024 78 

Total $ 7,937 $ 6,389 

All of Mohave and a portion of San Onofre and Palo Verde are included in regulatory assets on the consolidated balance 

sheets. Mohave ceased operations on December 31, 2005. In December 2006, SCE acquired the City of Anaheim’s 

approximately 3% ownership interest of San Onofre Units 2 and 3. 

Liabilities and Lines of Credit 

Long-Term Debt 

Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as 

collateral for borrowed funds obtained from pollution-control bonds issued by government agencies. SCE used these 

proceeds to finance construction of pollution-control facilities. SCE has a debt covenant that requires a debt to total 

capitalization ratio be met. At December 31, 2008, SCE was in compliance with this debt covenant. Bondholders have 

limited discretion in redeeming certain pollution-control bonds, and SCE has arranged with securities dealers to remarket 

or purchase them if necessary. 

The interest rates on one issue of SCE’s pollution control bonds insured by FGIC, totaling $249 million, were reset every 

35 days through an auction process. Due to a loss of confidence in the creditworthiness of the bond insurers, there was a 

significant reduction in market liquidity for auction rate bonds and interest rates on these bonds increased. Consequently, 

SCE purchased in the secondary market $37 million of its auction rate bonds in December 2007 and the remaining 

$212 million during the first three months of 2008. In March 2008, SCE converted the issue to a variable rate mode and 









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terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been 

retired or cancelled. 

Long-term debt maturities and sinking-fund requirements for the next five years are: 2009 – $150 million; 2010 – 

$250 million; 2011 – zero, 2012 – zero and 2013 – zero. 

Short-Term Debt 

Short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary 

cash requirements including power purchase payments. At December 31, 2008, the outstanding short-term debt was 

$1.89 billion at a weighted-average interest rate of 0.67%. This short-term debt is supported by a $2.5 billion credit line. 

At December 31, 2007, the outstanding short-term debt was $500 million at a weighted-average interest rate of 5.29%. 

This short-term debt was supported by a $2.5 billion credit line. See below in “Credit Agreements.” 

Credit Agreements 

In March 2008, SCE amended its $2.5 billion credit facility, extending the maturity to February 2013. The related 

borrowings are classified as short-term debt as it is expected to be repaid by year-end 2009. The amendment also 

provides four extension options which, if all exercised, and agreed to by lenders, will result in a final termination in 

February 2017. 

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. 

A subsidiary of Lehman Brothers Holdings, Lehman Brothers Bank, FSB, is one of the lenders in SCE’s credit agreement 

representing a total commitment of $106 million. Lehman Brothers Bank, FSB, had funded $25 million of SCE’s 

borrowing request during the second quarter of 2008 but declined SCE’s requests during the second half of 2008 for 

funding of approximately $57 million. 

The following table summarizes the status of the SCE credit facility: 


Commitment $ 2,500 $ 2,500 

Less: Unfunded commitment from Lehman Brothers subsidiary (81) — 

2,419 2,500 

Outstanding borrowings (1,893) (500) 

Outstanding letters of credit (141) (229) 

Amount available $ 385 $ 1,771 

Margin and Collateral Deposits 

Margin and collateral deposits include margin requirements and cash deposited with and received from counterparties 

and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based 

on changes in the fair value of the related positions. See “New Accounting Pronouncements” below for a discussion of 

the adoption of FIN No. 39-1. In accordance with FIN No. 39-1, SCE presents a portion of its margin and cash collateral 

deposits net with its derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral 

provided to others that have been offset against net derivative liabilities totaled $72 million and $2 million at 









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December 31, 2008 and 2007, respectively. 

Preferred and Preference Stock Not Subject to Mandatory Redemption 

SCE’s authorized shares are: $100 cumulative preferred – 12 million shares, $25 cumulative preferred – 24 million shares 

and preference – 50 million shares. There are no dividends in arrears for the preferred stock or preference shares. Shares 

of SCE’s preferred stock have liquidation and dividend preferences over shares of SCE’s common stock and preference 

stock. All cumulative preferred stock is redeemable. When preferred shares are redeemed, the premiums paid, if any, are 

charged to common equity. No preferred stock not subject to mandatory redemption was issued or redeemed in the years 

ended December 31, 2008, 2007 and 2006. In January 2008, SCE repurchased 350,000 shares of 4.08% cumulative 

preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and recorded a $2 million 

gain on the cancellation of reacquired capital stock (reflected in the caption “Additional paid-in capital on the 

consolidated balance sheets”). There is no sinking fund requirement for redemptions or repurchases of preferred stock. 

Shares of SCE’s preference stock rank junior to all of the preferred stock and senior to all common stock. Shares of 

SCE’s preference stock are not convertible into shares of any other class or series of SCE’s capital stock or any other 

security. The preference shares are noncumulative and have a $100 liquidation value. There is no sinking fund for the 

redemption or repurchase of the preference shares. 

Preferred stock and preference stock not subject to mandatory redemption is: 

Dollars in millions, except per-share amounts December 31, 2008 2007 

December 31, 2008 

Shares Redemption 

Outstanding Price 

Cumulative preferred stock: 

$25 par value: 

4.08% Series 650,000 $ 25.50 $ 16 $ 25 

4.24% Series 1,200,000 $ 25.80 30 30 

4.32% Series 1,653,429 $ 28.75 41 41 

4.78% Series 1,296,769 $ 25.80 33 33 

Preference stock: 

No par value: 

5.349% Series A 4,000,000 $ 100.00 400 400 

6.125% Series B 2,000,000 $ 100.00 200 200 

6.00% Series C 2,000,000 $ 100.00 200 200 

Total $ 920 $ 929 

The Series A preference stock, issued in 2005, may not be redeemed prior to April 30, 2010. After April 30, 2010, SCE 

may, at its option, redeem the shares in whole or in part and the dividend rate may be adjusted. The Series B preference 

stock, issued in 2005, may not be redeemed prior to September 30, 2010. After September 30, 2010, SCE may, at its 

option, redeem the shares in whole or in part. The Series C preference stock, issued in 2006, may not be redeemed prior 

to January 31, 2011. After January 31, 2011, SCE may, at its option, redeem the shares in whole or in part. No preference 

stock not subject to mandatory redemption was redeemed in the last three years. 









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04/18/2009 



Property and Plant 

Utility Plant 

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and 

labor, construction overhead, a portion of administrative and general costs capitalized at a rate authorized by the CPUC, 

and AFUDC. AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction. 

Currently, AFUDC debt and equity is capitalized during certain plant construction and reported in interest expense and 

other nonoperating income, respectively. AFUDC is recovered in rates through depreciation expense over the useful life 

of the related asset. Depreciation of utility plant is computed on a straight-line, remaining-life basis. 

On November 26, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission 

projects, DPV2, Tehachapi Transmission Project (“Tehachapi”), and Rancho Vista Substation Project (“Rancho Vista”). 

The order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction of all 

three projects. On February 29, 2008, the FERC approved SCE’s revision to its Transmission Owner Tariff to collect 

100% of construction work in progress (CWIP) for these projects in rate base and earn a return on equity, rather than 

capitalizing AFUDC. SCE implemented the CWIP rate, subject to refund, on March 1, 2008. For further discussion, see 

“FERC Transmission Incentives” in Item 2: Significant Contingencies discussed below. 

If SCE had not implemented this transmission incentive mechanism, and continued to follow the FERC Uniform System 

of Accounts for these costs, approximately $14 million would have been capitalized as of December 31, 2008. The 

following is a partial balance sheet that includes the amounts not capitalized because of the transmission rate incentives: 

December 31, 

In millions 


Utility Plant $ 27,966 

Construction Work in Progress 2,485 

Total Utility Plant 30,451 

(Less) Accum. Prov. for Depr, Amort, Depl. (14,067) 

Net Utility Plant $ 16,384 

Depreciation expense stated as a percent of average original cost of depreciable utility plant was, on a composite basis, 

4.3% for 2008, 4.2% for 2007 and 4.2% for 2006. 

AFUDC – equity was $54 million in 2008, $46 million in 2007 and $32 million in 2006 AFUDC – debt was $27 million 

in 2008, $24 million in 2007 and $18 million in 2006. 

Replaced or retired property costs are charged to the accumulated provision for depreciation. Cash payments for removal 

costs less salvage reduce the liability for AROs. 

In May 2003, the Palo Verde units returned to traditional cost-of-service ratemaking while San Onofre Units 2 and 3 

returned to traditional cost-of-service ratemaking in January 2004. SCE’s nuclear plant investments made prior to the 

return to cost-of-service ratemaking are recorded as regulatory assets on its consolidated balance sheets. Since the return 

to cost-of-service ratemaking, capital additions are recorded in utility plant. These classifications do not affect the 

rate-making treatment for these assets. 









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Estimated useful lives (authorized by the CPUC) and weighted-average useful lives of SCE’s property, plant and 

equipment, are as follows: 

Estimated 

Useful Lives 

Weighted- Average 

Useful Lives 

Generation plant 38 years to 69 years 40 years 

Distribution plant 30 years to 60 years 40 years 

Transmission plant 35 years to 65 years 45 years 

Other plant 5 years to 60 years 20 years 

Nuclear fuel is recorded as utility plant (nuclear fuel in the fabrication and installation phase is recorded as construction 

in progress) in accordance with CPUC rate-making procedures. Nuclear fuel is amortized using the units of production 

method. 

Nonutility Property 

Nonutility property, including construction in progress, is capitalized at cost, including interest accrued on borrowed 

funds that finance construction. Capitalized interest was less than a million dollars in 2008, 2007 and 2006. 

Depreciation and amortization is primarily computed on a straight-line basis over the estimated useful lives of nonutility 

properties. Depreciation expense stated as a percent of average original cost of depreciable nonutility property was, on a 

composite basis, 8.8% for 2008, 9.1% for 2007 and 8.9% for 2006. 

Estimated useful lives for nonutility property are as follows: 

Furniture and equipment 

Building, plant and equipment 

Land easements 

3 years to 20 years 

5 years to 30 years 

60 years 

Asset Retirement Obligation 

SCE accounts for its asset retirement obligations in accordance with in accordance with SFAS No. 143 and FIN 47. 

SCE’s AROs related to decommissioning of its nuclear power facilities are based on site-specific studies. The initial 

establishment of a nuclear-related ARO is at fair value and results in a corresponding regulatory asset. See “Nuclear 

Decommissioning” above for further discussion. Over time, the liability is increased for accretion each period. SCE’s 

conditional AROs are recorded at fair value in the period in which it is incurred if the fair value can be reasonably 

estimated even though uncertainty exists about the timing and/or method of settlement. When the liability is initially 

recorded, the cost is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability 

is increased for accretion each period, and the capitalized cost is depreciated over the useful life of the related asset. 

Settlement of an ARO liability, for an amount other than its recorded amount, results in a gain or loss. 

As a result of the adoption of SFAS No. 143 in 2003, SCE recorded the fair value of its liability for legal AROs, which 

was primarily related to the decommissioning of its nuclear power facilities. In addition, SCE capitalized the initial costs 

of the ARO into a nuclear-related ARO regulatory asset, and also recorded an ARO regulatory liability as a result of 

timing differences between the recognition of costs recorded in accordance with the standard and the recovery of the 









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related asset retirement costs through the rate-making process. SCE has collected in rates amounts for the future costs of 

removal of its nuclear assets, and has placed those amounts in independent trusts. The fair value of the nuclear 

decommissioning trusts was $2.5 billion at December 31, 2008. For a further discussion about nuclear decommissioning 

see “Commitments” and “Fair Value Measurements” above. 

A reconciliation of the changes in the ARO liability is as follows: 

In millions 2008 2007 2006 

Beginning balance $ 2,877 $ 2,749 $ 2,621 

Accretion expense 175 168 160 

Revisions (10) 3 (3) 

Liabilities added — — 41 

Liabilities settled (35) (43) (70) 

Ending balance $ 3,007 $ 2,877 $ 2,749 

The ARO liability as of December 31, 2008 includes an ARO liability of $2.9 billion related to nuclear decommissioning. 

Receivables 

SCE records an allowance for uncollectible accounts, generally as determined by the average percentage of amounts 

written-off in prior periods. SCE assesses its customers a late fee of 0.9% per month, beginning 21 days after the bill is 

prepared. Inactive accounts are written off after 180 days. 

Regulatory Assets and Liabilities 

In accordance with SFAS No. 71, SCE records regulatory assets, which represent probable future recovery of certain 

costs from customers through the rate-making process, and regulatory liabilities, which represent probable future credits 

to customers through the rate-making process. 

Included in SCE’s regulatory assets and liabilities are regulatory balancing accounts. Sales balancing accounts 

accumulate differences between recorded operating revenue and revenue SCE is authorized to collect through rates. Cost 

balancing accounts accumulate differences between recorded costs and costs SCE is authorized to recover through rates. 

Undercollections are recorded as regulatory balancing account assets. Overcollections are recorded as regulatory 

balancing account liabilities. SCE’s regulatory balancing accounts accumulate balances until they are refunded to or 

received from SCE’s customers through authorized rate adjustments. Primarily all of SCE’s balancing accounts can be 

classified as one of the following types: generation-revenue related, distribution-revenue related, generation-cost related, 

distribution-cost related, transmission-cost related or public purpose and other cost related. 

Balancing account undercollections and overcollections accrue interest based on a three-month commercial paper rate 

published by the Federal Reserve. Income tax effects on all balancing account changes are deferred. 

Amounts included in regulatory assets and liabilities are generally recorded with corresponding offsets to the applicable 

income statement accounts. 

Regulatory Assets 

SCE’s regulatory assets related to energy derivatives are an offset to unrealized losses on recorded derivatives and an 









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offset to lease accruals. SCE’s regulatory assets related to purchased-power settlements were recovered through October 

2008. SCE’s regulatory assets related to deferred FTR proceeds represent the deferral of operating revenue associated 

with FTRs that SCE received as a transmission owner from the annual ISO FTR auction. The deferred FTR proceeds 

were recognized through March 2009. Based on current regulatory ratemaking and income tax laws, SCE expects to 

recover its net regulatory assets related to flow-through taxes over the life of the assets that give rise to the accumulated 

deferred income taxes. SCE’s regulatory asset related to the ARO represents timing differences between the recognition 

of AROs in accordance with generally accepted accounting principles and the amounts recognized for rate-making 

purposes. SCE’s nuclear-related regulatory assets related to San Onofre are expected to be recovered by 2022. SCE’s 

nuclear-related regulatory assets related to Palo Verde are expected to be recovered by 2027. SCE’s net regulatory asset 

related to its unamortized coal plant investment is being recovered through June 2016. SCE’s net regulatory asset related 

to its unamortized loss on reacquired debt will be recovered over the remaining original amortization period of the 

reacquired debt over periods ranging from one year to 30 years. SCE’s regulatory asset related to SFAS No. 158 

represents the offset to the additional amounts recorded in accordance with SFAS No. 158. This amount will be 

recovered through rates charged to customers. SCE’s regulatory asset related to environmental remediation represents the 

portion of SCE’s environmental liability recognized at the end of the period in excess of the amount that has been 

recovered through rates charged to customers. This amount will be recovered in future rates as expenditures are made. 

SCE’s unamortized nuclear investment – net and unamortized coal plant investment – net regulatory assets earned a 

8.75% and 8.77% return in 2008 and 2007, respectively. 

Regulatory Liabilities 

Rate reduction notes – transition cost overcollection represents the nonbypassable rates charged to customers subsequent 

to the final principal payment of SCE’s rate reduction bonds. These amounts will be refunded to ratepayers. SCE’s 

regulatory liabilities related to energy derivatives are an offset to unrealized gains on recorded derivatives and an offset to 

a lease prepayment. SCE’s regulatory liabilities related to deferred FTR costs represent the deferral of the costs 

associated with FTRs that SCE purchased during the annual ISO auction process. The FTRs provide SCE with scheduling 

priority in certain transmission grid congestion areas in the day-ahead market. The FTRs meet the definition of a 

derivative instrument and are recorded at fair value and marked to market each reporting period. Any fair value change 

for FTRs is reflected in the deferred FTR costs regulatory liability. The deferred FTR costs are recognized as FTRs are 

used or expire in various periods through March 2009. SCE’s regulatory liability related to the ARO represents timing 

differences between the recognition of AROs in accordance with generally accepted accounting principles and the 

amounts recognized for rate-making purposes. SCE’s regulatory liabilities related to costs of removal represent operating 

revenue collected for asset removal costs that SCE expects to incur in the future. SCE’s regulatory liability related to 

SFAS No. 158 represents the offset to the additional amounts recorded in accordance with SFAS No. 158. This amount 

will be returned to ratepayers in some future rate-making proceeding. SCE’s regulatory liabilities related to employee 

benefit plan expenses represent pension costs recovered through rates charged to customers in excess of the amounts 

recognized as expense or the difference between these costs calculated in accordance with rate-making methods and these 

costs calculated in accordance with SFAS No. 87, and PBOP costs recovered through rates charged to customers in 

excess of the amounts recognized as expense. These balances will be returned to ratepayers in some future rate-making 

proceeding, be charged against expense to the extent that future expenses exceed amounts recoverable through the 

rate-making process, or be applied as otherwise directed by the CPUC. 

Related Party Transactions 

Specified administrative services such as payroll and employee benefit programs, performed by SCE employees, are 

shared among all subsidiaries of Edison International, and the cost of these corporate support services are allocated to all 

subsidiaries. Costs are allocated based on one of the following formulas: percentage of time worked, relative amount of 









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04/18/2009 



equity in investment, number of employees, or multi-factor method (operating revenue, operating expenses, total assets 

and number of employees). In addition, services of SCE employees are sometimes directly requested by an Edison 

International subsidiary and these services are performed for the subsidiary’s benefit. Labor and expenses of these 

directly requested services are specifically identified and billed at cost. 

During the first quarter of 2008, a subsidiary of EME was awarded by SCE, through a competitive bidding process, a 

ten-year power sales contract with SCE for the output of a 479 MW gas-fired peaking facility located in the City of 

Industry, California, which is referred to as the “Walnut Creek” project. The power sales agreement was approved by the 

CPUC on September 18, 2008 and by the FERC on October 2, 2008. Deliveries under the power sales agreement are 

scheduled to commence in 2013. 

Short-term Investments 

At different times during 2007 and 2006, SCE held various variable rate demand notes related to short-term cash 

management activities. The interest rate process for these securities allow for a resetting of interest rates related to 

changes in terms and/or credit quality, similar to cash and cash equivalents. In accordance with SFAS No. 115, if on hand 

at the end a period, these notes would be classified as short-term available-for-sale investment securities and recorded at 

fair value. There were no outstanding notes as of December 31, 2008 and 2007. Both sales and purchases of the notes 

were $7 billion and $6 billion for the years ended December 31, 2007 and 2006, respectively. There were no realized or 

unrealized gains or losses. 

INCOME STATEMENT: 

Other Nonoperating Income and Deductions 

Other nonoperating income and deductions are as follows: 


AFUDC $ 54 $ 46 $ 32 

Increase in cash surrender value of life insurance policies 24 23 21 

Performance-based incentive awards 3 4 19 

Other 20 16 13 

Total other nonoperating income $ 101 $ 89 $ 85 

Various penalties $ 59 $ 5 $ 23 

Civic, political and related activities and donations 42 35 29 

Other 22 5 8 

Total other nonoperating deductions $ 123 $ 45 $ 60 

The 2008 increase in nonoperating deductions primarily resulted from a CPUC decision in September 2008 related to 

SCE incentives claimed under a CPUC-approved PBR mechanism. The decision required SCE to refund $28 million and 

$20 million related to customer satisfaction and employee safety reporting incentives, respectively, and further required 

SCE to forego claimed incentives of $20 million and $15 million related to customer satisfaction and employee safety 

reporting, respectively. The decision also required SCE to refund $33 million for employee bonuses related to the 

program and imposed a statutory penalty of $30 million. During the third quarter of 2008, SCE recorded a charge of 

$49 million, after-tax ($60 million, pre-tax) related to this decision. 









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04/18/2009 



Planned Major Maintenance 

Certain plant facilities require major maintenance on a periodic basis. These costs are expensed as incurred. 

Purchased-Power 

From January 17, 2001 to December 31, 2002, the CDWR purchased power on behalf of SCE’s customers for SCE’s 

residual net short power position (the amount of energy needed to serve SCE’s customers in excess of SCE’s own 

generation and power-purchase contracts). Additionally, the CDWR signed long-term contracts that provide power for 

SCE’s customers. Effective January 1, 2003, SCE resumed power procurement responsibilities for its residual net short 

position. SCE acts as a billing agent for the CDWR power, and any power purchased by the CDWR for delivery to SCE’s 

customers is not considered a cost to SCE. 

Revenue Recognition 

Operating revenue is recognized as electricity is delivered and includes amounts for services rendered but unbilled at the 

end of each reporting period. Rates charged to customers are based on CPUC-authorized and FERC-approved revenue 

requirements. CPUC rates are implemented upon final approval. FERC rates are often implemented on an interim basis at 

the time when the rate change is filed. Revenue collected prior to a final FERC approval decision is subject to refund. 

SCE’s revenue requirements are based on its cost of service, referred to as base rate revenue requirement, and also 

provide recovery of pass-through costs under ratemaking mechanisms (balancing accounts) authorized by the CPUC. The 

base rate revenue requirement provides an opportunity to recover operation and maintenance expenses, capital-related 

carrying costs and earn an authorized rate of return. The revenue requirement for pass-through costs provides recovery of 

fuel and purchased-power expenses, demand-side management programs, nuclear decommissioning, public purpose 

programs, certain operation and maintenance expenses and depreciation expense related to certain projects. 

The CPUC-authorized decoupling revenue mechanisms allow differences in revenue resulting from actual and forecast 

volumetric electricity sales to be collected from or refunded to ratepayers therefore such differences do not impact 

operating revenue. Differences between authorized operating costs included in SCE’s base rate revenue requirement and 

actual operating costs incurred, other than pass-through costs, do not impact operating revenue, but have an impact on 

earnings. 

Since January 17, 2001, power purchased by the CDWR or through the ISO for SCE’s customers is not considered a cost 

to SCE because SCE is acting as an agent for these transactions. Furthermore, amounts billed to ($2.2 billion in 2008, 

$2.3 billion in 2007 and $2.5 billion in 2006) and collected from SCE’s customers for these power purchases, CDWR 

bond-related costs (effective November 15, 2002) and a portion of direct access exit fees (effective January 1, 2003) are 

being remitted to the CDWR and are not recognized as operating revenue by SCE. 

Sales and Use Taxes 

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use 

taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order 

to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a 

CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE’s ability to collect from the 

customer, are accounted for on a gross basis and reflected in operating revenue and other operation and maintenance 









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expense. SCE’s franchise fees billed to customers and recorded as operating revenue were $103 million, $104 million and 

$107 million for the years ended December 31, 2008, 2007 and 2006, respectively. When SCE acts as an agent, and the 

tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. 

Amounts billed to and collected from customers for these taxes are being remitted to the taxing authorities and are not 

recognized as operating revenue. 

CASH FLOW STATEMENT: 

Supplemental Cash Flows Information 

SCE supplemental cash flows information is: 


Cash payments for interest and taxes: 

Interest – net of amounts capitalized $ 303 $ 292 $ 321 

Tax payments – net $ 251 $ 299 $ 832 

Noncash investing and financing activities: 

Details of debt exchange: 

Pollution-control bonds redeemed $ — $ — $ (331) 

Pollution-control bonds issued $ — $ — $ 331 

Details of obligation under capital leases: 

Capital lease purchased $ — $ (10) $ — 

Capital lease obligation issued $ — $ 10 $ — 

Dividends declared but not paid: 

Common stock $ 100 $ 25 $ 60 

Preferred and preference stock not subject to mandatory redemption $ 13 $ 13 $ 9 

Item 2: Significant Contingencies 

In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory proceedings before 

various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the 

outcome of these other proceedings will not materially affect its results of operations or liquidity. 

Environmental Remediation 

SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate 

existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the 

environment. 

SCE believes that it is in substantial compliance with environmental regulatory requirements; however, possible future 

developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the 

manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance 

that additional costs would be recovered from customers or that SCE’s financial position and results of operations would 

not be materially affected. 

SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a 









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04/18/2009 



range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by 

assessing a range of reasonably likely costs for each identified site using currently available information, including 

existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of 

involvement and financial condition of other potentially responsible parties. These estimates include costs for site 

investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, 

SCE records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at 

undiscounted amounts. 

As of December 31, 2008, SCE’s recorded estimated minimum liability to remediate its 24 identified sites was 

$41 million, of which $10 million was related to San Onofre. This remediation liability is undiscounted. The ultimate 

costs to clean up SCE’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the 

estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the 

varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of 

identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due 

to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to 

$173 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a 

range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of 

costs is at least $1 million), SCE also has 30 immaterial sites whose total liability ranges from $3 million (the recorded 

minimum liability) to $9 million. 

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 million of its 

recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, 

SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the 

opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance 

claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. 

SCE has recorded a regulatory asset of $40 million for its estimated minimum environmental-cleanup costs expected to 

be recovered through customer rates. 

SCE’s identified sites include several sites for which there is a lack of currently available information, including the 

nature and magnitude of contamination and the extent, if any, that SCE may be held responsible for contributing to any 

costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites. 

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several 

years are expected to range from $11 million to $31 million. Recorded costs were $29 million, $25 million and 

$14 million for 2008, 2007 and 2006, respectively. 

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper 

limit of the estimated range for its identified sites and, based upon the CPUC’s regulatory treatment of environmental 

remediation costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or 

financial position. There can be no assurance, however, that future developments, including additional information about 

existing sites or the identification of new sites, will not require material revisions to such estimates. 

Federal and State Income Taxes 

Edison International remains subject to examination and administrative appeals by the IRS for various tax years. See 

“Item 2: Significant Contingencies” for further information. 









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04/18/2009 



2009 FERC Rate Case 

In an order issued in September 2008, the FERC accepted and made effective on March 1, 2009, subject to refund and 

settlement procedures, SCE’s proposed revisions to its tariff, filed in the 2009 transmission rate case. The revisions 

reflected changes to SCE’s transmission revenue requirement and transmission rates, as discussed below. 

SCE requested a $129 million increase in its retail transmission revenue requirements (or a 39% increase over the current 

retail transmission revenue requirement) due to an increase in transmission capital-related costs and increases in 

transmission operating and maintenance expenses that SCE expects to incur in 2009 to maintain grid reliability. The 

transmission revenue requirement request is based on a return on equity of 12.7%, which is composed of a 12.0% base 

ROE and 0.7% in transmission incentives previously approved by the FERC (see “FERC Transmission Incentives” below 

for further information). SCE is unable to predict the revenue requirement that the FERC will ultimately authorize. 

FERC Transmission Incentives 

The Energy Policy Act of 2005 established incentive-based rate treatments for the transmission of electric energy in 

interstate commerce by public utilities for the purpose of benefiting consumers by ensuring reliability and reducing the 

cost of delivered power by reducing transmission congestion. Pursuant to this act, in November 2007, the FERC issued an 

order granting incentives on three of SCE’s largest proposed transmission projects. These include 125 basis point ROE 

adders on SCE’s proposed base ROE for SCE’s DPV2 and Tehachapi transmission projects and a 75 basis point ROE 

adder for SCE’s Rancho Vista Substation Project (“Rancho Vista”). 

In June 2007, the ACC denied the approval of the DPV2 project which resulted in an estimated two year delay of the 

project. SCE continues its efforts to obtain the regulatory approvals necessary to construct the DPV2 project and 

continues to evaluate its options, which include but are not limited to, filing a new application with the ACC and building 

the project in various phases. 

The order also grants a 50 basis point ROE adder on SCE’s cost of capital for its entire transmission rate base in SCE’s 

next FERC transmission rate case for SCE’s participation in the CAISO. In addition, the order on incentives permits SCE 

to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all 

three projects and 100% recovery of prudently-incurred abandoned plant costs for two of the projects, if either are 

cancelled due to factors beyond SCE’s control. 

In August 2008, the CPUC filed an appeal of the FERC incentives order at the DC Circuit Court of Appeals. The court 

issued a ruling on November 6, 2008, accepting the CPUC’s request that the court refrain from ruling on the CPUC’s 

appeal until a final FERC order is issued in the 2008 CWIP case (see “FERC Construction Work in Progress Mechanism” 

below for further information). 

FERC Construction Work in Progress Mechanism 

FERC CWIP 2008 

In February 2008, the FERC approved SCE’s revision to its tariff to collect 100% of CWIP in rate base for its Tehachapi, 

DPV2, and Rancho Vista, as authorized by FERC in its transmission incentives order discussed above which resulted in 

an authorized base transmission revenue requirement of $45 million subject to refund. In March 2008, the CPUC filed a 

petition for rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP and in another 2008 









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04/18/2009 



protest to an SCE compliance filing, requested an evidentiary hearing to be set to further review SCE’s costs. SCE cannot 

predict the outcome of the matters in this proceeding. 

FERC CWIP 2009 

SCE filed its 2009 CWIP rate adjustment in October 2008 proposing a reduction to its CWIP revenue requirement from 

$45 million to $39 million to be effective on January 1, 2009. Several parties, including the CPUC, filed protests to the 

October filing in November 2008, primarily contesting SCE’s proposed base ROE of 12.0%. The FERC issued an order 

in December 2008, allowing the proposed 2009 CWIP rates to go into effect on January 1, 2009, subject to refund, and 

directing that the 2009 CWIP ROE be made subject to the outcome of the pending 2008 FERC CWIP proceeding. The 

FERC also consolidated all issues other than ROE with SCE’s 2009 FERC rate case proceeding. 

Four Corners CPUC Emissions Performance Standard Ruling 

The emission performance standards adopted by the CPUC and CEC pursuant to SB 1368 prohibits SCE and other 

California load-serving entities from entering into long-term financial commitments with generators that emit more than 

1,100 pounds of CO 2 per MWh, which would include most coal-fired plants. In January 2008, SCE filed a petition with 

the CPUC seeking clarification that the emission performance standard would not apply to capital expenditures required 

by existing agreements among the owners at Four Corners. The CPUC issued a proposed decision finding that the 

emission performance standard was not intended to apply to capital expenditures at Four Corners requested by SCE in its 

GRC for the period 2007 – 2011. In October 2008, the Assigned Commissioner and Administrative Law Judge issued a 

ruling withdrawing the proposed decision and seeking additional comment on whether the finding in the proposed 

decision should be changed and whether SCE should be allowed to recover such capital expenditures. SCE estimates that 

its share of capital expenditures approved by the owners at Four Corners since the GHG emission performance standard 

decision was issued in January 2007 is approximately $43 million, of which approximately $8 million had been expended 

through December 31, 2008. The ruling also directs SCE to explain why certain information was not included in its 

petition and why the failure to include such information should not be considered misleading in violation of CPUC rules. 

SCE filed its response and comments to the ruling in November and December 2008 and cannot predict the outcome of 

this proceeding or estimate the amount, if any, of penalties or disallowances that may be imposed. 

ISO Disputed Charges 

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, 

Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service 

related charges. The potential cost to SCE of the FERC order, net of amounts SCE expects to receive through the PX, 

SCE’s scheduling coordinator at the pertinent time, is estimated to be approximately $20 million to $25 million, 

including interest. The order has been the subject of continuing legal proceedings since it was issued. SCE believes that 

the most recent substantive order FERC has issued in the proceedings correctly allocates responsibility for these ISO 

charges. However, SCE cannot predict the final outcome of the rehearing. If a subsequent regulatory decision changes the 

allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may 

seek recovery in its reliability service rates. SCE cannot predict whether recovery of these charges in its reliability service 

rates would be permitted. 

Navajo Nation Litigation 

The Navajo Nation filed a complaint in June 1999 in the District Court against SCE, among other defendants, arising out 

of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal 

RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by 









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04/18/2009 



nondisclosure, and various contract-related claims. The complaint claims that the defendants’ actions prevented the 

Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks 

damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion. In March 

2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of 

damages claimed. The case was stayed at the request of the parties in October 2004, but was reinstated to the active 

calendar in March 2008. 

A related case against the U.S. Government is presently before the U.S. Supreme Court. The outcome of that case could 

affect the Navajo Nation’s pursuit of claims against SCE. A decision from the U.S. Supreme Court is expected in 

mid-2009. 

SCE cannot predict the outcome of the Tribe’s complaints against SCE or the ultimate impact on these complaints of the 

on-going litigation by the Navajo Nation against the U.S. Government in the related case. 

Nuclear Insurance 

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is 

currently approximately $12.5 billion. SCE and other owners of San Onofre and Palo Verde have purchased the 

maximum private primary insurance available ($300 million). The balance is covered by the industry’s retrospective 

rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the 

United States results in claims and/or costs which exceed the primary insurance at that plant site. 

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this 

secondary level, effective June 1994. Beginning October 29, 2008, the maximum deferred premium for each nuclear 

incident is approximately $118 million per reactor, but not more than approximately $18 million per reactor may be 

charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per 

reactor for each nuclear incident is adjusted for inflation at least once every five years. The most recent inflation 

adjustment took effect on October 29, 2008. Based on its ownership interests, SCE could be required to pay a maximum 

of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately 

$35 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy 

public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal 

law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on 

all licensed reactor operators as a measure for raising further operating revenue. 

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo 

Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been 

purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses 

during an accident-related nuclear unit outage. A mutual insurance company owned by utilities with nuclear facilities 

issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds 

for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately 

$45 million per year. Insurance premiums are charged to operating expense. 

Palo Verde Nuclear Generating Station Outage and Inspection 

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the 

results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo 

Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, 

Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant 









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04/18/2009 



personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and 

survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. 

APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by 

mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately 

$7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 

2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to 

estimate how long SCE will continue to incur these costs. In the 2009 GRC, SCE requested recovery of, and two-way 

balancing account treatment for, Palo Verde operation and maintenance expenses including costs associated with these 

corrective actions. If approved, this would provide for recovery of these costs over the three-year GRC cycle. 

Procurement of Renewable Resources 

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail 

electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than 

December 31, 2010. 

It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, 

SCE may still meet the 20% target by utilizing the flexible compliance rules, such as banking of past surplus and 

earmarking of future deliveries from executed contracts. SCE continues to engage in several renewable procurement 

activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other 

initiatives. 

Under current CPUC decisions, potential penalties for SCE’s inability to achieve its renewable procurement objectives 

for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. 

Under the CPUC’s current rules, the maximum penalty for inability to achieve renewable procurement targets is 

$25 million per year. SCE does not believe it will be assessed penalties for 2008 or the prior years and cannot predict 

whether it will be assessed penalties for future years. 

Spent Nuclear Fuel 

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of 

spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance 

of spent nuclear fuel by January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from 

San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives 

and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear 

generation at San Onofre (approximately $24 million, plus interest). SCE has also been paying a required quarterly fee 

equal to 0.1¢ per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating 

agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE’s 

failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. 

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Such interim 

storage for San Onofre is on-site. 

APS, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel at Palo Verde. Palo 

Verde plans to add storage capacity incrementally to maintain full core off-load capability for all three units. In order to 

increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed an independent spent 

fuel storage facility. 









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04/18/2009 



Item 3 

N/A 

Item 4 

These accounts are used where applicable. The balance for unamortized loss on reacquired debt (account number 

189.100) at December 31, 2008 was approximately $309 million. There is no unamortized gain (account number 

257.xxx) recorded on the books at December 31, 2008. 

Item 5 

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International. In SCE’s most 

recent cost of capital proceeding, the CPUC sets an authorized capital structure for SCE which included a common equity 

component of 48%. SCE may make distributions to Edison International as long as the common equity component of 

SCE’s capital structure remains at or above the authorized level on a 13-month weighted average basis of 48%. At 

December 31, 2008, SCE’s 13-month weighted-average common equity component of total capitalization was 50.6% 

resulting in the capacity to pay $345 million in additional dividends. 

Item 6 

See response to Item 1 & 2 above. 







(Mo, Da, Yr) 




04/18/2009 

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

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. 

Line 

No. 

Item 

(a) 

Unrealized Gains and 

Losses on Availablefor-Sale 

Securities 

(b) 

Minimum Pension 

Liability adjustment 

(net amount) 

(c) 

Foreign Currency 

Hedges 

(d) 

Other 

Adjustments 

(e) 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

Balance of Account 219 at Beginning of 

Preceding Year 

Preceding Qtr/Yr to Date Reclassifications 

from Acct 219 to Net Income 

Preceding Quarter/Year to Date Changes in 

Fair Value 

Total (lines 2 and 3) 

Balance of Account 219 at End of 

Preceding Quarter/Year 

Balance of Account 219 at Beginning of 

Current Year 

Current Qtr/Yr to Date Reclassifications 

from Acct 219 to Net Income 

Current Quarter/Year to Date Changes in 

Fair Value 

Total (lines 7 and 8) 

Balance of Account 219 at End of Current 

Quarter/Year 

( 14,467,238) 

( 12,394,566) 

14,467,238 ( 3,021,683) 

14,467,238 ( 15,416,249) 

( 15,416,249) 

( 15,416,249) 

1,954,292 

( 809,937) 

1,144,355 

( 14,271,894) 

FERC FORM NO. 1 (NEW 06-02) 

Page 122a






(Mo, Da, Yr) 




04/18/2009 

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

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

Other Cash Flow 

Hedges 

Interest Rate Swaps 

(f) 

Other Cash Flow 

Hedges 

[Specify] 

(g) 

Totals for each 

category of items 

recorded in 

Account 219 

(h) 

( 14,467,238) 

( 12,394,566) 

11,445,555 

( 949,011) 

( 15,416,249) 

( 15,416,249) 

1,954,292 

( 809,937) 

1,144,355 

( 14,271,894) 

Net Income (Carried 

Forward from 

Page 117, Line 78) 

(i) 

Total 

Comprehensive 

Income 

(j) 

759,222,285 758,273,274 

734,353,135 735,497,490 

FERC FORM NO. 1 (NEW 06-02) 

Page 122b






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04/18/2009 

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS 

FOR DEPRECIATION. AMORTIZATION AND DEPLETION 



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 in 

column (f) common function. 

Line 

No. 

1 

Utility Plant 

Classification 

(a) 

Total Company for the 

Current Year/Quarter Ended 

(b) 

Electric 

(c) 

2 

In Service 

3 

Plant in Service (Classified) 

26,034,278,767 

26,004,809,278 

4 

Property Under Capital Leases 

16,347,731 

16,347,731 

5 

Plant Purchased or Sold 

6 

Completed Construction not Classified 

1,914,479,343 

1,914,479,343 

7 

Experimental Plant Unclassified 

8 

Total (3 thru 7) 

27,965,105,841 

27,935,636,352 

9 

Leased to Others 

10 

Held for Future Use 

480,549 

480,549 

11 

Construction Work in Progress 

2,471,279,830 

2,462,677,194 

12 

Acquisition Adjustments 

13 

Total Utility Plant (8 thru 12) 

30,436,866,220 

30,398,794,095 

14 

Accum Prov for Depr, Amort, & Depl 

14,067,220,437 

14,059,587,239 

15 

Net Utility Plant (13 less 14) 

16,369,645,783 

16,339,206,856 

16 

Detail of Accum Prov for Depr, Amort & Depl 

17 

In Service: 

18 

Depreciation 

13,750,368,353 

13,742,735,155 

19 

Amort & Depl of Producing Nat Gas Land/Land Right 

20 

Amort of Underground Storage Land/Land Rights 

21 

Amort of Other Utility Plant 

316,852,084 

316,852,084 

22 

Total In Service (18 thru 21) 

14,067,220,437 

14,059,587,239 

23 


24 

Depreciation 

25 

Amortization and Depletion 

26 

Total Leased to Others (24 & 25) 

27 

Held for Future Use 

28 

Depreciation 

29 

Amortization 

30 

Total Held for Future Use (28 & 29) 

31 

Abandonment of Leases (Natural Gas) 

32 

Amort of Plant Acquisition Adj 

33 

Total Accum Prov (equals 14) (22,26,30,31,32) 

14,067,220,437 

14,059,587,239 






(Mo, Da, Yr) 



04/18/2009 

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS 

FOR DEPRECIATION. AMORTIZATION AND DEPLETION 

Gas 

Other (Specify) 



(d) (e) (f) 

(g) 



Common 

4,580,151 23,770,149 

1,119,189 3 

4,580,151 23,770,149 

1,119,189 8 

1,025,931 7,023,497 

553,208 11 

5,606,082 30,793,646 

1,672,397 13 

1,348,156 5,862,975 

422,067 14 

4,257,926 24,930,671 

1,250,330 15 

1,348,156 5,862,975 

422,067 18 

1,348,156 5,862,975 

422,067 22 

1,348,156 5,862,975 

422,067 33 

(h) 

Line 

No. 

1 

2 

4 

5 

6 

7 

9 

10 

12 

16 

17 

19 

20 

21 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 







(Mo, Da, Yr) 


04/18/2009 

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) 



1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the 

respondent. 

2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the 

quantity used and quantity on hand, and the costs incurred under such leasing arrangements. 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

Description of item 

Balance 

Beginning of Year 

(a) 

(b) 

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

Fabrication 

Changes during Year 

Additions 

(c) 

Nuclear Materials 76,870,352 92,801,061 

Allowance for Funds Used during Construction 

(Other Overhead Construction Costs, provide details in footnote) 

SUBTOTAL (Total 2 thru 5) 76,870,352 

Nuclear Fuel Materials and Assemblies 

In Stock (120.2) 54,117,279 6,891,185 

In Reactor (120.3) 368,617,337 146,555,645 

SUBTOTAL (Total 8 & 9) 422,734,616 

Spent Nuclear Fuel (120.4) 

Nuclear Fuel Under Capital Leases (120.6) 

(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 268,750,355 

TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 230,854,613 

Estimated net Salvage Value of Nuclear Materials in line 9 

Estimated net Salvage Value of Nuclear Materials in line 11 

Est Net Salvage Value of Nuclear Materials in Chemical Processing 

Nuclear Materials held for Sale (157) 

Uranium 

Plutonium 

Other (provide details in footnote): 

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







(Mo, Da, Yr) 


04/18/2009 

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) 



Amortization 

(d) 

-69,982,882 

Changes during Year 

Other Reductions (Explain in a footnote) 

(e) 

Balance 

End of Year 

(f) 

85,791,985 83,879,428 

83,879,428 

60,636,044 372,420 

588,386 514,584,596 

514,957,016 

35,277 338,697,960 

260,138,484 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 202 Line No.: 3 Column: e 

Transfer of costs from fuel in process to fuel in stock or fuel in the reactor. (Account 120.1) 


Transfer of costs from fuel in stock to fuel in the reactor. (Account 120.2) 


Amortization for fuel batches moved from production to stock and from stock to production. 


Amortization for fuel batches moved from production to stock and from stock to production. 







(Mo, Da, Yr) 


04/18/2009 

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



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 and 

reductions 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 included 

in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount 

of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such 

retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) 

Line 

Account Balance Additions 

No. 


(a) 

(b) 

(c) 

1 1. INTANGIBLE PLANT 

2 (301) Organization 51,314 

3 (302) Franchises and Consents 60,256,111 1,517,794 

4 (303) Miscellaneous Intangible Plant 445,343,595 289,157,084 

5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 505,651,020 290,674,878 

6 2. PRODUCTION PLANT 

7 A. Steam Production Plant 

8 (310) Land and Land Rights 1,474,073 

9 (311) Structures and Improvements 58,689,168 2,378,839 

10 (312) Boiler Plant Equipment 584,338,768 13,260,060 

11 (313) Engines and Engine-Driven Generators 

12 (314) Turbogenerator Units 113,444,219 3,636,240 

13 (315) Accessory Electric Equipment 41,324,107 1,521,837 

14 (316) Misc. Power Plant Equipment 32,165,329 189,050 

15 (317) Asset Retirement Costs for Steam Production 314,397 

16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 831,750,061 20,986,026 

17 B. Nuclear Production Plant 

18 (320) Land and Land Rights 2,294,566 15,116 

19 (321) Structures and Improvements 1,535,073,575 21,047,656 

20 (322) Reactor Plant Equipment 2,254,204,316 23,948,630 

21 (323) Turbogenerator Units 831,472,145 18,693,138 


23 (325) Misc. Power Plant Equipment 593,754,887 7,112,186 

24 (326) Asset Retirement Costs for Nuclear Production 

25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 6,085,490,832 79,923,559 

26 C. Hydraulic Production Plant 


28 (331) Structures and Improvements 107,246,840 722,958 

29 (332) Reservoirs, Dams, and Waterways 423,266,246 5,990,613 

30 (333) Water Wheels, Turbines, and Generators 116,083,634 2,232,848 


32 (335) Misc. Power PLant Equipment 11,139,295 25,961 

33 (336) Roads, Railroads, and Bridges 9,047,572 

34 (337) Asset Retirement Costs for Hydraulic Production 5,962,989 

35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 786,099,989 11,615,772 

36 D. Other Production Plant 

37 (340) Land and Land Rights 1,815 

38 (341) Structures and Improvements 3,514,072 214,287 

39 (342) Fuel Holders, Products, and Accessories 3,241,055 4,555 

40 (343) Prime Movers 207,116,658 21,224,503 

41 (344) Generators 8,272,366 564 


43 (346) Misc. Power Plant Equipment 1,848,463 181,538 

44 (347) Asset Retirement Costs for Other Production 1,651,181 

45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 279,489,902 32,757,377 

46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 7,982,830,784 145,282,734 

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

Page 204







(Mo, Da, Yr) 

04/18/2009 



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

Line 

Account Balance Additions 

No. 


(a) 

(b) 

(c) 

47 3. TRANSMISSION PLANT 



50 (353) Station Equipment 2,662,051,719 84,655,796 

51 (354) Towers and Fixtures 433,176,257 418,804 

52 (355) Poles and Fixtures 416,238,586 16,317,064 

53 (356) Overhead Conductors and Devices 505,342,552 5,752,370 

54 (357) Underground Conduit 38,360,192 233,539 

55 (358) Underground Conductors and Devices 159,123,604 11,536,020 

56 (359) Roads and Trails 24,300,833 

57 (359.1) Asset Retirement Costs for Transmission Plant 2,507,588 

58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 4,655,424,552 125,696,405 

59 4. DISTRIBUTION PLANT 



62 (362) Station Equipment 1,189,734,342 54,133,284 

63 (363) Storage Battery Equipment 

64 (364) Poles, Towers, and Fixtures 1,172,866,339 80,418,945 

65 (365) Overhead Conductors and Devices 900,632,650 44,915,480 

66 (366) Underground Conduit 1,013,243,401 69,550,209 

67 (367) Underground Conductors and Devices 3,078,951,857 205,584,098 

68 (368) Line Transformers 2,193,402,157 148,690,934 

69 (369) Services 978,630,851 35,911,773 

70 (370) Meters 544,922,769 29,840,654 

71 (371) Installations on Customer Premises 

72 (372) Leased Property on Customer Premises 

73 (373) Street Lighting and Signal Systems 650,791,257 23,361,269 

74 (374) Asset Retirement Costs for Distribution Plant 7,118,563 

75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 12,146,469,548 694,821,548 

76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 

77 (380) Land and Land Rights 

78 (381) Structures and Improvements 

79 (382) Computer Hardware 

80 (383) Computer Software 

81 (384) Communication Equipment 

82 (385) Miscellaneous Regional Transmission and Market Operation Plant 

83 (386) Asset Retirement Costs for Regional Transmission and Market Oper 

84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 

85 6. GENERAL PLANT 



88 (391) Office Furniture and Equipment 466,657,277 66,735,112 

89 (392) Transportation Equipment 8,427,485 128,901 

90 (393) Stores Equipment 11,031,594 1,198,937 

91 (394) Tools, Shop and Garage Equipment 25,851,119 7,594,334 

92 (395) Laboratory Equipment 63,051,609 4,030,361 

93 (396) Power Operated Equipment 3,405,961 

94 (397) Communication Equipment 450,154,752 44,175,916 

95 (398) Miscellaneous Equipment 15,210,877 1,665,703 

96 SUBTOTAL (Enter Total of lines 86 thru 95) 1,543,735,316 140,569,656 

97 (399) Other Tangible Property 

98 (399.1) Asset Retirement Costs for General Plant 874,188 

99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,544,609,504 140,569,656 

100 TOTAL (Accounts 101 and 106) 26,834,985,408 1,397,045,221 

101 (102) Electric Plant Purchased (See Instr. 8) 

102 (Less) (102) Electric Plant Sold (See Instr. 8) 

103 (103) Experimental Plant Unclassified 

104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 26,834,985,408 1,397,045,221 


Page 206







(Mo, Da, Yr) 

04/18/2009 




distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these 

amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of 

respondent’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 account 

classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated 

provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary 

account 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 showing 

subaccount 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 

Retirements 

Adjustments 

Transfers 

Balance at 

Line 

(d) 

(e) 

(f) 

End of Year 

(g) 

No. 

1 

51,314 2 

61,773,905 3 

33,013,949 701,486,730 

4 

33,013,949 763,311,949 

5 

6 

7 

1,474,073 8 

3,591,470 57,476,537 

9 

188,640 204,900 

597,615,088 

10 

11 

761,668 116,318,791 

12 

2,342,278 45,188,222 

13 

239,683 -2,547,178 

29,567,518 

14 

314,397 15 

4,781,461 847,954,626 

16 

17 

2,309,682 18 

56,820 -9,778 

51,761,760 

1,607,816,393 

19 

8,184,352 -4,446,393 

386,665 

2,265,908,866 

20 

6,218,650 -399,702 

843,546,931 

21 

-342 254,712 

878,052,546 

22 

275,797 -695,379 

-52,403,137 

547,492,760 

23 

24 

14,735,619 -5,551,594 

6,145,127,178 

25 

26 

5,076,047 27 

1,631 107,968,167 

28 

296,059 428,960,800 

29 

21,048 118,295,434 

30 

5,675,847 105,244,911 

31 

11,165,256 32 

9,047,572 33 

-66,976 5,896,013 

34 

5,994,585 -66,976 

791,654,200 

35 

36 

1,815 37 

3,728,359 38 

3,245,610 39 

228,341,161 40 

8,272,930 41 

110,256 64,865,966 

42 

2,030,001 43 

-156,156 1,495,025 

44 

110,256 -156,156 

311,980,867 

45 

25,621,921 -5,774,726 

8,096,716,871 

46 


Page 205







(Mo, Da, Yr) 

04/18/2009 




Retirements 

Adjustments 

Transfers 

Balance at 

Line 

(d) 

(e) 

(f) 

End of Year 

(g) 

No. 

47 

6,768 5,592,613 

205,392,911 

48 

337,973 220,960,994 

49 

19,537,890 2,727,169,625 

50 

9,211 -14,120 

433,571,730 

51 

4,436,928 -262 

428,118,460 

52 

958,767 14,120 

510,150,275 

53 

11,914 38,581,817 

54 

2,103,923 168,555,701 

55 

24,300,833 56 

-1,439,613 1,067,975 

57 

27,403,374 4,153,000 

-262 

4,757,870,321 

58 

59 

1,096 -1,297,669 

100,983,697 

60 

2,598,748 313,709,054 

61 

7,949,281 1,235,918,345 

62 

63 

7,157,047 262 

1,246,128,499 

64 

8,338,424 937,209,706 

65 

1,089,927 1,921 

1,081,705,604 

66 

19,945,195 1,911 

3,264,592,671 

67 

23,375,428 -1,346,496 

2,317,371,167 

68 

3,068,267 -2,248 

1,011,472,109 

69 

6,493,197 568,270,226 

70 

71 

72 

3,856,386 -1,585 

670,294,555 

73 

-3,821,080 3,297,483 

74 

83,872,996 -6,465,245 

261 

12,750,953,116 

75 

76 

77 

78 

79 

80 

81 

82 

83 

84 

85 

27,292,854 86 

1,645,786 486,046,394 

87 

58,476,498 474,521 

475,390,412 

88 

834,494 -584,324 

7,137,568 

89 

327,874 11,902,657 

90 

473,813 584,324 

33,555,964 

91 

4,384,414 62,697,556 

92 

3,405,961 93 

66,209,783 -474,521 

427,646,364 

94 

1,761,822 15,114,758 

95 

134,114,484 1,550,190,488 

96 

97 

-628,311 245,877 

98 

134,114,484 -628,311 

1,550,436,365 

99 

304,026,724 -8,715,282 

-1 

27,919,288,622 

100 

101 

102 

103 

304,026,724 -8,715,282 

-1 

27,919,288,622 

104 


Page 207






(Mo, Da, Yr) 


04/18/2009 

ELECTRIC PLANT LEASED TO OTHERS (Account 104) 



Line 

No. 

1 

Name of Lessee 

(Designate associated companies 

with a double asterisk) 

(a) 

None. 

Description of 

Property Leased 

(b) 

Commission 

Authorization 

(c) 

Expiration 

Date of 

Lease 

(d) 

Balance at 

End of Year 

(e) 

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 







(Mo, Da, Yr) 


04/18/2009 

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) 



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 held 

for 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 to 

other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105. 

Line Description and Location Date Originally Included Date Expected to be used Balance at 

No. 

Of Property 

in This Account in Utility Service 

End of Year 

(a) 

(b) 

(c) 

(d) 

1 Land and Rights: 

2 350 - Land and Land Rights: 

3 

4 

5 Under $250,000 (3 Properties) Various 

Various 

210,090 

6 

7 

8 

9 360 - Land and Land Rights: 

10 

11 

12 Under $250,000 (3 Properties) Various 

Various 

270,459 

13 

14 

15 

16 

17 

18 

19 

20 

21 Other Property: 

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 480,549 







(Mo, Da, Yr) 


04/18/2009 

CONSTRUCTION WORK IN PROGRESS - - 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 (see 

Account 107 of the Uniform System of Accounts) 

3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped. 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

Description of Project Construction work in progress - 

Electric (Account 107) 

(a) 

(b) 

WORK ORDERS OVER $1,000,000: 

5047-5001 RANCHO VISTA - CONSTRUCT SUBSTATION 

140,196,302 

1819-6032 UNIT 2 STEAM GENERATOR REPLACEMENT 

111,668,585 

1819-6033 UNIT 3 STEAM GENERATOR REPLACEMENT 

92,689,595 

ANTELOPE-PARDEE 500KV T/L: CONSTRUCT 25 MILES 500KV TRANSMISSION LINE 

71,256,231 

3280-0301 MCGRATH BEACH - PURCHASE & INSTALL A NATURAL GAS FIRED COMBUSTION 

40,281,339 

TURBINE 

WILDOMAR S/C - CONSTRUCT NEW SERVICE CENTER 

35,729,305 

MRTU-Capital Master WO PF/MKT/CRR 

33,996,875 

ANTELOPE-VINCENT 500KV T/L: CONSTRUCT 21.5 MILES T/L 

30,395,454 

ANTELOPE-WINDHUB 500KV T/L: CONSTRUCT 21.6MI T/L 

27,910,119 

9077-3134--MDM SOFTWARE 

27,881,702 

EMS Proj Capital Master Work Order 

27,128,148 

4701-5005--ANTELOPE-VINCENT #2 500K PRELIMINARY ENGINEERING 

26,910,381 

4585-5008--DEVERS-PALO VERDE: PRELIMINARY ENGINEERING 

20,186,599 

SANTA CLARA-GETTY-CARPENTERIA SANTA CLARA-CARPENTERIA 66KV - RECONSTRUCT 

17,090,433 

LINES 

ERP SW RELEASE 2 

15,787,566 

SONGS UNIT 3 - REPLACE RPV HEADS 

14,535,501 

SONGS UNIT 2 - REPLACE RPV HEADS 

14,516,277 

1868-6831-PALO VERDE NGS WATER FACILITY 2005 

14,396,320 

8012-5020--MIRAGE: BUILD NEW 115-KV SUBSTATION 

14,196,297 

9051-3169-R4 SOFTWARE 

14,139,337 

MOORPARK: INSTALL NEW DOUBLE BREAKER 220KV BANK POSITION 

13,345,555 

9051-3108-SAP - BOLT ON GUI/GDT 

12,498,251 

PURCHASE SPARE "AA" BANKS 

12,292,361 

5012-5081--MESA: INSTALLATION OF SAS 

11,690,835 

5052-5059--ANTELOPE: EXPAND SUBSTATION 

11,527,202 

ESC R1 MDMS Capital Master SW WO 

11,277,957 

FERC - ANTELOPE TRANSMISSION PROJECT PHASE 1 SEGMENT 3 

11,089,605 

FERC - ANTELOPE TRANSMISSION PROJECT PHASE 1 SEGMENT 2 

11,066,072 

5374-5001--RIVERWAY: CREATE NEW 66/12 KV SUBSTATION 

10,884,292 

4585-9000--DEVERS-PALO VERDE: PE & ENVIRONMENTAL WORK 

10,558,964 

4589-8201--CALDWELL-VICTOR 230KV T/L - INSTALL SEVEN MILES OF LINE 

10,500,156 

9219-2077 - TRTP Segment 1 

10,133,091 

SONGS UNITS 2/3 - ISFSI CYCLE 15 - DRY CASK STORAGE 

10,063,749 

9078-0311--MAINFRAME SERVERS - IOC 

9,731,893 

El Casco Sub - Construct new switchrack 

9,716,266 

1868-6832-PALO VERDE - WATER RECLAMATION 

8,993,202 

1320-0600-MOHAVE CONTINUED OPERATION 

8,441,677 

BIG CREEK 3 RELICENSING 

8,407,851 


8,053,706 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

BIG CREEK 2A RELICENSING 

7,995,664 


7,872,791 

SONGS UNITS 2/3 - ISFSI CYCLE 15 AHSM'S 

7,788,908 

VALLEY SUB: REPLACE 500KV GIS SWITCHRACK & RELATED EQUIPMENT 

7,733,657 

ERP SW ROLLOUT 3 

7,608,887 


7,300,737 

EASTERN - KERN RIVER 1-REBUILD TUNNELS & FOREBAY PHASE 3 

7,265,951 

C 00 EPS RELICENSING 

7,109,120 

5061-5089--LUGO: REPLACE (3 OF 6) - 500KV LINE REACTORS 

6,908,530 

ALHAMBRA C.S.- INSTALL ZONE CONTROLLER, SYSTEM SERVER 

6,904,201 

ANTELOPE SUB: INSTALL 4TH 280 MVA, 220/66 KV TRANSFORMER 

6,606,271 

1320-0604-MOHAVE-'C' AQUIFER STUDY, PRELIMINARY ENGINEERING 

6,428,560 

Business Objects Software Project 

6,087,078 

5358-5018--MONOLITH SUB: INSTALL STATION EQUIPMENT 

6,065,321 

SONGS UNITS 2/3 - ISFSI PAD - PHASE 3 

6,020,287 

EL CASCO: CONSTRUCT NEW 220KV OPEN AIR SWITCHRACK 

6,012,574 

DEVERS: ADDITION OF NEW AA BANK 

5,946,242 

VALLEY: INTERCONNECT 669 MW OF GENERATION TO THE VALLEY 500KV BUS 

5,900,752 

1866-6831-PALO VERDE NGS U3, 2005 

5,882,678 

GOLETA: REPLACE THE 3A & 4A BANK WITH 1-3 280MVA TRANSFORMER 

5,707,573 

1860-6831-PALO VERDE NGS, U1, 2004 

5,634,339 

8047-8201--TIEFORT SUB: RECONFIGURE THE 33KV SWITCHYARD 

5,611,556 

MOORPARK SUBTRANS LINE: CREATE A NEW MOORPARK-SIMI LINE 

5,595,665 

ANTELOPE-PARDEE 500KV T/L: ENGR, ENVIRONMENTAL, & CONSTRUCT T/L 

5,572,095 

4269-5001--BIG CREEK#3-SPRINGVILLE 

5,544,983 

4518-5004--MIRA LOMA-ETIWANDA & MIRA LOMA PADUA - REPLACE THE EXISTING LINE 

5,415,608 

8073-5010--IVYGLEN: ADD 1-28MVA, 115 KV TRANSFORMER BANK 

5,223,821 

2501 8006 BISHOP CREEK AUTOMATION UPGRADE 

4,963,417 

ESC Rollout 2A - Superior Work Order 

4,876,327 

VICTOR-RIVERTEX: INSTALL APPROX. 8.1 MILES OF NEW SINGLE CKT115KV LINE 

4,715,297 

CPUC - LAS LOMAS (PORTOLA SUB) SITE - ACQUIRE FEE PROPERTY 

4,686,393 

RECONDUCTOR VIDEO 16KV 

4,658,008 

SAN JACINTO VALLEY S/C BUILDING EXPANSION PROJECT 

4,620,517 

6054-8301--PORTERVILLE S/C - CONSTRUCT NEW SERVICE CENTER 

4,610,032 

9077-0561--GO2 DATA CENTER UPGRADE 

4,546,468 

1868-6833-PALO VERDE NGS, WATER RECLAMATION FACILITY 

4,502,762 

LUGO-SERRANO 500KV T/L: LOOP THE EXISTING LUGO-SERRANO 500KV TL INTO RANCHO 

4,300,338 

VISTA SUB 

APPLE VALLEY: INSTALL 2-12KV CIRCUITS AND 28MVA 115/12KV TRANSFORMER 

4,268,648 

6452-5303-75301-DCN MONOLITH SUB 

4,203,917 

EMPIRE LAKES - CCO. REPLACE ENTIRE TELEPHONE SYSTEM 

4,200,509 

6443-5342-75301-JRC - DSP CIRCUIT NIGUEL 

3,982,788 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

MRTU-Capital Master WO PPBU DATA 

3,935,682 

9051-3167-Rollout 3 SOFTWARE 

3,896,173 

9051-3147-Rollout 2 SOFTWARE 

3,770,489 

CUSTOMER SERVICE (CSBU) - AMI PHASE 3 - FACILITY CAPITAL 

3,737,886 

ESC Oracle Licenses - Software 

3,630,113 

8958-5044--SYLMAR CONVERTER STATION - REPLACE STATION EQUIPMENT 

3,619,799 

8046-5044--KRAMER: REPLACE 6 & 7 TRANSFORMER BANKS 

3,614,648 

SONGS UNIT 2 - CYCLE 13 PLANT MODIFICATIONS 

3,559,108 

8073-5007--IVYGLEN SUB: PRELIMINARY ENGINEERING 

3,536,209 

DSP U/G PETE 12KV O/O TELEGRAPH 

3,532,888 

8007-8201--RIVER-TEX: INSTALL A CUSTOMER DEDICATED SUBSTATION 

3,518,831 

OMS Capital Master Work Order 

3,473,593 

6061-8907- BRUSH FIRE 

3,398,274 

INSTALL STRUCTURE/CBLE PER R20B(HILL CENTRAL) 

3,396,866 

9216-0396-CSBU - AMI PRODUCT MANAGEMENT - Hardware 

3,248,490 

5096-5065--ETIWANDA SUB: INSTALL PROTECTION AS REQUIRED 

3,240,672 

FIRESTORM 11/15/08 

3,197,874 

9077-0315--UNIX SERVERS - GO - IT 

3,194,544 

9068-9754--LONG BEACH PLAZA - CCO. REPLACE PHONE SYSTEM 

3,142,921 

9077-3194--ERP DOCUMENTS MANAGEMENT 

3,132,400 

MRTU-Capital Master WO - Ops& Sett 

3,109,478 

4513-4904--GARNET-SANTA ROSA 115KV T/L 

3,085,728 

SANTA ANA NO 3 - CAPITAL MASTER ORDER 

2,987,293 

SONGS UNIT 3 - MFWPT HYDRAULIC GOVERNOR DIGITAL CONTROL 

2,957,867 

1864-6831-PALO VERDE NGS, U2, 2005 

2,936,031 

MRTU-Capital Master WO - Integration 

2,830,950 

VALLEY-INLAND: DESIGN AND CONSTRUCT AND STRING VALLEY SUBSTATION RACK 

2,811,446 

POSITION 

VINCENT: INSTALL 500 KV DOUBLE BREAKERS ON #1AA BANK 

2,806,910 

ORCOSAN SUB: ENGINEER & CONSTRUCT A 44.8MVA, 66/12KV CUSTOMER DEDICATED 

2,788,619 

SUBSTATION 

9216-3102-AMI SYSTEM INTEGRATOR - D 

2,783,152 

2007 DSP CIRCUIT #1 O/O VICTOR 

2,772,895 

MOORPARK-POTRERO-THOUSAND OAKS 66KV: INSTALL 2ND CKT. TO MOORPARK 

2,734,143 

5012-8301--MESA SUBSTATION - CONSTRUCT NEW CONTROL ROOM 

2,720,320 

VISTA SUBSTATION - CONSTRUCT NEW TEST & OFFICE BUILDING 

2,707,626 

9077-4111--DIM PROJECT SOFTWARE 

2,661,663 

INSTALL STRUCTURE/CABLE PER 20B UUAD #6 (SAND CENTRAL) 

2,655,798 

DEVERS-MIRAGE 115KV SYSTEM: SPLIT THE DEVERS-MIRAGE 'A' SYSTEM INTO SEPARATE 

2,588,586 

LINES 

CKT #1 '08 LA VETA 65301-UG , REL TO 65300-OH 

2,565,325 

9216-3101-AMI SYSTEMS INTEGRATOR - SOFTWARE 

2,541,867 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

1866-6833-PALO VERDE NGS, UNIT 3, 2 

2,535,022 

9033-0469--GO ELEVATOR PROJECT 

2,525,034 

VALLEY-AULD-PAUBA 115KV: RECONDUCTOR VALLEY LEG OF THE VALLEY-AULD-PAUBA T/L 

2,502,340 

FCGS 06-05 - UNIT 5 LOWER BOILER REPLACEMENT 

2,489,755 

9219-1753--HIGH DESERT POWER PROJECT 

2,472,966 

5079-5001--Windhub: CONSTRUCT SUBSTATION 

2,462,379 

6533-7109-E7102-JM1 RULE 20B DISTRICT 68 

2,457,594 

5566-5013--QUARTZ HILL SUB: PROVIDE / MODIFY PROTECTION AS REQUIRED 

2,449,640 

8086-5010--CAJALCO: ADD 28MVA W/LTC BANK AND CIRCUITS 

2,432,491 

9077-0276--UNIX DISK STORAGE - GO 

2,424,678 

Firestorm 11/14/2008 

2,414,514 

6449-6201-36200-WSS STRUCTURE RULE 20A 

2,411,308 

6431-5322-65306-RGJ 2007 URBITA 12KV 

2,400,412 

1867-6813-PALO VERDE 2000 COMMON 

2,397,772 

3064 0373 PBGS-INSTALL 25 NEW MICRO TURBINES 

2,392,667 

RELOC OH/UG FACILITIES FOR RR UNDERPASS 

2,378,706 

9051-3143-SAP - ROLLOUT 3 BUSINESS 

2,363,410 

9077-0310--MAINFRAME TAPE STORAGE - 

2,359,822 

5097-0305--PALO VERDE SITCHRACK: CAPITAL EXPENDITURES FOR PLANT 

2,342,580 

6433-5318-75301-BK KEWAMEE O/O CROWN 

2,290,364 

FCGS 06-06: UNIT 5 - PENDANT REHEATER & OUTLET HEADER REPLACEMENT 

2,285,706 

PALO VERDE COMMON - PVNGS COMMON CAPITAL IMPROVEMENTS 2006 

2,279,093 

THOUSAND OAKS: REPLACE 2-20MVA BANKS WITH 2-28MVA BANKS 

2,268,760 

IVYGLEN: BRING IN SECOND 115KV LINE FROM VALLEY TO IVYGLEN 

2,230,897 

2007 DSP MARICHINO SUB CIR 2-ROUNDEL 12K 

2,221,888 

LAGUNA BELL: REPLACE 13-220KV CIRCUIT BREAKERS 

2,202,707 

9216-3103-AMI SYSTEM INTEGRATOR-SYSTEM ARCHITECTURE SOFTWARE 

2,173,998 

8958-5001--SYLMAR CONVERTER STATION - REPLACE MASTER CONTROLLER SYSTEM 

2,170,761 

9051-3142-SAP - ROLLOUT 2 BUSINESS PROCESS 

2,165,502 

4305-5966--RIO HONDO-ANITA NO. 1 66KV - RULE 20A 

2,165,415 

75305-2008 DSP BIRCHWOOD 16 KV CIRCUIT OAK PARK SUBSTATION 

2,162,794 

9078-0310--MAINFRAME TAPE STORAGE - 

2,162,002 

9219-1696--T/L SEPARATION PROJECT - 

2,153,517 

9077-0278--UNIX SERVERS - GO 

2,107,905 

8504-5001--RITTER RANCH - CONSTRUCT NEW SUBSTATION 

2,103,697 

SONGS UNIT 2 - SALT WATER COOLING PUMPS 

2,095,925 

ESC R2a DCA - Irvine 

2,067,854 

EL SEGUNDO: ENGINEERING, DESIGN, CONSTRUCTION, GRID FUNCTIONAL FACILITIES 

2,049,129 

& EQUIPMENT 

8059-8201--PUREWATER SUB: ENGINEER & CONSTRUCT A CUSTOMER DEDICATED 

2,048,299 

SUBSTATION 

6073-8340--VICTORVILLE S/C EXPANSION 

2,039,560 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

9219-2080--FERC - DEVERS-SAN BERNARDINO-VISTA T/L - ACQUIRE EASEMENTS 

2,036,096 

6533-7113-E7106-PHT RULE 20B, CABLE 

2,018,654 

VENIDA: REPLACE EXISTING BANK 1 & 2 WITH NEW 2-28MVA TRANSFORMER 

2,005,089 

9077-3160--BILL ENHANCEMENT-APPLICATION SOFTWARE 

1,992,936 

ERP Scheduling Phase 2 

1,985,159 

5095-5001--TRITON SUB: CONSTRUCT NEW SUBSTATION 

1,970,271 

9077-0268--NON-UNIX TAPE STORAGE HARDWARE 

1,964,619 

2008 DSP EXTINGUISHER 12KV O/O FIREHOUSE 

1,953,604 

SONGS UNIT 2 - TPCW HEAT EXCHANGER 

1,910,189 

C 07 BC1 INSTALL CARRIAGE APARTMENT 

1,894,503 

CATHODIC PROTECTION, SHALLOW ANODES 

1,883,509 

AVALANCHE 08 YORBA LINDA UG 

1,876,947 

VALLEY-SUN CITY 115KV: RECONDUCTOR & REBUILD VALLEY-SUN CITY115KV LINE 

1,873,100 

07105 RULE 20B STRUCTURES/CABLE 

1,866,940 

5028-5030--REDONDO: REPLACE 4-220KV CIRCUIT BREAKERS 

1,860,837 

INSTALL DUCT FOR STREET IMPROVEMENT 

1,853,903 

5069-5068--MIRA LOMA: ADD TWO 500KV CIRCUIT BREAKERS 

1,846,646 

S/A SANTIAGO-BORREGO-MORRO & SANTIAGO-BORREGO 66KV T/L 

1,845,262 

RECTOR: INSTALL NEW MOD 3 HUB AT RCC LOCATION. 

1,835,571 

2008 DSP KAY TWO 12KV MIRA LOMA JR 

1,835,426 

WILDLIFE (FORMERLY JURUPA): INSTALL NEW 220KV SWITCHYARD FACILITIES 

1,815,390 

CKT #2 '08 LA VETA UG 

1,805,180 

EASTERN - GEM - INSTALL GEOMEMBRANE ON UPSTREAM FACE OF DAM & REPAIR FRACTURE 

1,801,473 

6435-5323-55310-BSD NEW CIRCUIT 

1,795,721 

J7104/INST NEW UG SYS PER 20B DUCTS & STRUCTURES 

1,793,113 

CHANNEL ISLAND: ADD 28MVA TRANSFORMER BANK IN PARALLEL WITH #1 BANK 

1,785,584 

GO2-INSTALL DATA EQUIPMENT 

1,783,067 

WINDHUB-HIGHWIND 230KV T/L: CONSTRUCT NEW 9.6 MILES TRANSMISSION LINE 

1,771,456 

Fire Storm10/12/2008, Marek/Sesson 

1,745,650 

1860-6833-PALO VERDE NGS, UNIT 1, 2 CAPITAL IMPROVEMENTS 

1,743,183 

FCGS 06-07: UNIT 5 - 2ND STAGE PENDANT SUPERHEATER REPLACEMENT 

1,740,493 

1864-6833-PALO VERDE NGS, UNIT 2, CAPITAL IMPROVEMENTS 

1,728,865 

RIALTO C.S.-INSTALL COMMUNICATION EQUIPMENT 

1,724,718 

Log Retention Capital Master Order 

1,724,464 

ESC R1 MDMS Build System Test Environment 

1,716,711 

9077-4127--NON-UNIX OPERATING SOFTWARE 

1,713,745 

9077-0316--NON - UNIX DISK STORAGE HARDWARE 

1,712,796 

6449-6202-36201-WSS CABLE RULE 20A 

1,699,822 

66KV ANTELOPE UPG UPGRADES AND RECONDUCTORING 

1,692,239 

KIMBALL SUBSTATION - INCREASE TRANSFORMER CAPACITY FROM 0 TO 56MVA. 

1,690,452 

5086-8205--ELLIS SUB: INSTALL NEW LINE 

1,685,208 

9184-9704--PERRY-08-RIVERGRADE COMPLEX - INSTALL DATE NETWORKING EQUIPMENT 

1,678,439 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

IVANPAH SUB: INITIAL LAND STUDIES AND ENVIRONMENTAL ANALYSIS. 

1,665,990 

4405-0439--LAGUNA BELL-BANDINI-REFUSE-VAIL - RIGHT OF WAY 

1,659,885 

1867-6834-PALO VERDE COMMON - 2008 CAPITAL IMPROVEMENTS 

1,658,273 

9077-0212--IDM INFRA S/W 

1,646,310 

8020-5020--SAVAGE: REPLACE THE EXISTING TRANSFORMER BANK 

1,645,809 

56204/INSTALL STRUCTURES FOR RULE 20A 

1,645,192 

5074-5058--LAGUNA BELL: REPLACE (8) 66KC CIRCUIT BREAKERS 

1,613,857 

U/G STELLA 12KV O/O MARION 

1,612,994 

8339-8201--STENT: ENGINEERING AND CONSTRUCT A NEW SUBSTATION 

1,611,645 

1330-0465-FCGS 06-08: UNIT 5 - HP TURBINE REPLACEMENT 

1,611,333 

6443-6087-66002-BMA RCS AUTOMATION PROCESS 

1,599,613 

8346-5005--FOGARTY: INCREASE STATION CAPACITY 

1,598,298 

5579-5007--WAKEFIELD: REPLACE 2 TRANSFORMER BANKS 

1,596,836 

SONGS UNIT 2 - MFWPT DIGITAL SPEED CONTROL UPGRADE 

1,596,615 

5050-5039--PARDEE: REPLACE 8-220KV CIRCUIT BREAKERS 

1,563,484 

iVOS Capital Master Order 

1,561,171 

DEVERS: INSTALL NEW MOD 3 HUB AT RCC LOCATION 

1,558,013 

8564-5001--PRESIDENTIAL SUB: ENGINEER AND CONSTRUCT NEW SUBSTATION 

1,548,141 

3064 0375 AUX TRANSFORMER BETTERMENT 

1,548,019 

C 08 MPPHU2 REPLACE LINER PLATES 

1,547,766 

SONGS UNIT 3 - SALT WATER COOLING PUMPS 

1,534,145 

RANCHO VISTA SUB-INSTALL MICROWAVE AND SONET TRANSMISSION EQUIPMENT 

1,524,476 

MOORPARK-THOUSAND OAKS #1 66KV: U.G. SECTION 

1,523,942 

CATALINA: INSTALL NEW SUBMARINE CABLE FROM MAINLAND TO ISLAND 

1,521,651 

HIGHWIND: GRADE AND FENCE NEW HIGHWIND 230 KV SUBSTATION 

1,520,804 

GRC WORK PAPER PROCESS AUTOMATION AND ENHANCEMENT PROJECT 

1,502,956 

6036-6719-76740 RELOCATE FACILITIES 

1,500,148 

CYPRESS: ADD NEW 28 MVA TRANSFORMER WITH CIRCUIT BREAKER AND DISCONNECTS 

1,493,544 

ET-00140* DEVERS-PALO VERDE 500KV: REINFORCE LEGS ON VARIOUS TOWERS 

1,485,725 

47191 INSTALL UG STR PER RULE 20B 

1,480,555 

1867-6830-PALO VERDE 2004 COMMON - CAPITAL IMPROVEMENTS 

1,471,009 

9077-0231--DSRP HARDWARE AND INFRASTRUCTURE 

1,470,273 

UG KANAN S/O 101 FRWY 

1,466,088 

56200, RULE 20A STRUCTURES 

1,459,131 

DOWNEY MED (KAISER): CONSTRUCT NEW 66/12KV SUB 

1,441,226 

8029-5013--HI DESERT: INSTALLATION OF SAS 

1,438,951 

6431-5327-65315-RHS DSP WILSON CREEK 

1,437,249 

SONGS UNIT 2 - NSR CHILLER CONTROL 

1,432,589 

ANTELOPE SUB: PROVIDE AND/OR MODIFY PROTECTION AS REQUIRED 

1,400,025 

DEVERS-PALO VERDE NO. 2 500KV T/L (CA): BUILD 125.4 MI SGL CKT 500KV T/L 

1,390,088 

ORANGE COAST SC-INSTALL ROUTER AND SWITCHES 

1,376,913 

6073-5414 RECONDUCTOR 1.5 CAPS,REGULATORS, SWITCHES 

1,369,157 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

9051-3153-SAP - ROLLOUT 3 TECHNOLOGY SOFTWARE 

1,358,776 

PARDEE: EQUIP EXISTING 220KV POSITION #5 WITH CIRCUIT BREAKERS, DISCONNECT SWITCHES 

1,350,423 

BARK BEETLE PROJECT REPLACEMENT/REPAIRS 

1,345,923 

LEE VINING SUB.-INSTALL COMM SITE AND ASSOCIATED EQUIPMENT 

1,344,746 

BOTTLE SUB: INSTALL A NEW 16.8MVA 115/4KV CUSTOMER DEDICATED SUBSTATION 

1,344,615 

VALLEY-AULD 115KV. RECONDUCTOR 10.61 MILES OF 653.9 ACSR TO 954 SAC 

1,344,418 

VARIOUS 66KV T/L'S & R/W'S: RAINSTORM RELATED REPLACEMENTS 

1,340,173 

SBRO - REMODEL APPROX 65,000SQFT BOTH 1ST AND 2ND FLOORS 

1,332,255 

59-Sayre Fire 

1,332,226 

REPLACE 151 WOOD POLES & 35,000 CIRUIT FT. OF 4/O 

1,328,204 

RANCHO VISTA (RELIANT GENERATING PLANT) RELOCATE WELL EASEMENT 

1,327,413 

9009-0068-NON-EXEMPT (PORTABLE) TOOLS 

1,310,373 

CATALINA *PBGS-RIP RAP RESTORATION PROJECT 

1,307,065 

GE SMALLWORLD APPLICATION SOFTWAREUPGRADE - GIS MAPPING 

1,302,327 

RANCHO VISTA: INSTALL 2 AA BANKS & DOUBLE BREAKER 500KV LINE POS 

1,293,144 

INSTRUMENT AIR PIPING WITH REQUIRED CONTROL ROOM MODIFICATIONS 

1,293,100 

2006 CAPACITOR PROJECT 

1,277,508 

LESSANDRO-HIGHGROVE-MAXWELL-TANKER 115KV - R/R 2-1/2 MI (75 WOOD POLES) 

1,273,372 

NEW DSP CKT O/O STETSON SUB 

1,268,723 

BIG CREEK 3-SPRINGVILLE TAP 220KV T/L: INSTALL OPGW ON EXISTING TOWERS 

1,264,633 

9077-0313--MAINFRAME PRINTERS - GO 

1,253,182 

SAS - Planning and Analysis Work order 

1,251,966 

S/A VILLA PARK-BURPIT-ILLA PARK-BURPIT-CANYON-YORBA LINDA 66KV T/L:CONVERT528 

1,249,676 

L.A.D.W.P. Celilo-Sylmar DC transmission 

1,244,554 

ALESSANDRO: REPLACE #1 BANK 115/33KV WITH 115/33KV TRANSFORMER WITH LTC 

1,229,899 

AMI PRODUCT MANAGEMENT - METERS. PHASE 3 

1,226,559 

BARRE SUB - PURCHASE AND INSTALL NATURAL GAS FIRED COMBUSTION TURBINE ENGINE 

1,223,741 

REPLACE DETERIORATED CABLE 

1,204,907 

BLOOMINGTON SUB (BLOOMINGTON): ADD 1-12KV CIRCUIT WITH UGG 

1,203,543 

S/L RELATED TO BACKBONE 

1,200,776 

FORM TRANSMISSION LINES INTO NEW PORPOSED ORCOSAN SUB 

1,197,207 

C 06 TUNNEL 2 INSTALL LINER 

1,193,368 

SKINWATER: INSTALL NEW 33/4 14MVA SUBSTATION 

1,193,161 

SONGS UNIT 2: REPLACE (3)-220 KV CB'S TO SUPPORT U3 MAIN RES AUX CB'S 

1,186,822 

SONGS UNIT 2: REPLACE (3)-220 KV CB'S TO SUPPORT U3 MAIN RES AUX CB'S 

1,182,716 

6426-7125-57125-MDC RULE 20B STRUCTURES 

1,173,261 

DSP INSTALL NEW UG YOSEMITE16 KV CIRUIT OUT OF SANTA SUSANA SUB 

1,171,572 

OLINDA-ATWOOD-BREA-CAROLINA 66KV: CONVERT O.H. TO U.G. RULE 20/C 

1,158,647 

RELOCATE POLES/STREET IMPROVEMENT 

1,149,524 

9077-4110--INTEGRATED TEST ENVIRONMENT 

1,145,072 

C 08 BC1 Install Propane Heating 

1,144,728 

JOHANNA-BRYAN-IRVINE-STEELCASE 66KV NEW EXPANSION 

1,141,208 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 


04/18/2009 








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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 



(a) 

(b) 

MIRA LOMA: REPLACE (14) CHC/SAM LBFB RELAYS WITH SEL-352 LBFB RELAYS 

1,113,080 

C 08 BIG CREEK 3 U5 STATOR REWIND 

1,112,270 

1867-6833-PALO VERDE NGS, COMMON, 2 - CAPITAL IMPROVEMENTS 

1,099,513 

ESC R2A DCA - Rosemead 

1,089,515 

MOORPARK SUB: INSTALL MOD-2 USAT ULTRASATNET HUB. 

1,084,057 

SAUGUS-HASKELL-SOLEMINT & SAUGUS-LOCKHEED AND ANTELOPE-P.S. 74 66KV LINES 

1,083,089 

5331-5014--VISALIA: REPLACE (7) 66K CIRCUIT BREAKERS 

1,076,310 

IVYGLEN SUB: ADD 1-28.8MVAR 115KV CAPACITOR BANK 

1,068,012 

CLAREMONT SUB: REPLACE EXISTING 11.2MVA TRANSFORMER WITH NEW22.4MVA 

1,062,229 

TRANSFORM 

DISTRIBUTION CIRCUIT MANAGEMENT 

1,061,885 

5054-5087--VINCENT: UPGRADE PROTECTION AS REQUIRED 

1,053,368 

MRTU-Capital Master WO MS/PM/MS/ARC 

1,048,267 

SAUGUS-NORTH OAKS FO CABLE (PROPOSED) INSTALL 95,000FT 48/ADSS 

1,043,328 

G.O.2-LAB EQUIPT. 2004-INSTALL NEW CATALYST SWITCHES 

1,040,613 

FCGS 07-08: UNIT 5 - COAL PIPE ELBOW REPLACEMENT. 

1,037,066 

U3 TG Bldg Oily Sump Discharge line 

1,036,954 

DIMP Capital Master Order 

1,033,391 

LUCERNE: REPLACE #1N AND 1S 33/12KV WITH 33/12KV TRANSFORMER WITH LTC 

1,031,889 

8016-5018--FARRELL SUB: INSTALL A NEW TRANSFORMER 

1,029,109 

9077-3136--DCA SOFTWARE 

1,025,158 

5576-5016--NEWHALL SUB: PROVIDE PROTECTION AS REQUIRED 

1,021,707 

5018-8201--Drycreekwind Sub: Engineer & construct new substation 

1,012,158 

Enterprise Thin Client Solution-Cap 

1,010,210 

HUNTINGTON PARK: REPLACE #1 & #2 BANKS 16/4KV WITH 2-3 UNITS 

1,009,531 

9077-0210--INTEGRATED TEST ENVIRONMENT HARDWARE 

1,008,334 

6573-5303-85301 DSP 

1,004,733 

9051-3152-SAP - ROLLOUT 2 TECHNOLOGY / SOFTWARE 

1,001,661 

TELEPACIFIC - VARIOUS LOCATIONS - CONSTRUCT CIRCUITS AND ASSOCIATED EQUIPMENT 

1,088,646 

DMX Project 2008 

1,133,541 

WORK ORDERS UNDER $1,000,000 

795,978,804 

43 TOTAL 2,462,677,194 







(Mo, Da, Yr) 




04/18/2009 

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

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 for 

electric 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 when 

such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded 

and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book 

cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional 

classifications. 

4. Show separately interest credits under a sinking fund or similar method of depreciation accounting. 

Line 

No. 

Item 

(a) 

Section A. Balances and Changes During Year 

Total 

Electric Plant in 

(c+d+e) 

Service 

(b) 

(c) 

Electric Plant Held 

for Future Use 

(d) 

Electric Plant 


(e) 

1 Balance Beginning of Year 

13,267,176,028 13,267,176,028 

2 Depreciation Provisions for Year, Charged to 

3 (403) Depreciation Expense 

932,834,837 932,834,837 

4 (403.1) Depreciation Expense for Asset 

Retirement Costs 

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

6 Transportation Expenses-Clearing 

451,132 451,132 

7 Other Clearing Accounts 

2,478,017 2,478,017 

8 Other Accounts (Specify, details in footnote): 

40,052,913 40,052,913 

9 

10 TOTAL Deprec. Prov for Year (Enter Total of 

975,816,899 975,816,899 

lines 3 thru 9) 

11 Net Charges for Plant Retired: 

12 Book Cost of Plant Retired 

220,428,825 220,428,825 

13 Cost of Removal 

205,568,792 205,568,792 

14 Salvage (Credit) 

21,939,217 21,939,217 

15 TOTAL Net Chrgs. for Plant Ret. (Enter Total 

404,058,400 404,058,400 

of lines 12 thru 14) 

16 Other Debit or Cr. Items (Describe, details in 

-96,199,372 -96,199,372 

footnote): 

17 

18 Book Cost or Asset Retirement Costs Retired 

19 Balance End of Year (Enter Totals of lines 1, 

13,742,735,155 13,742,735,155 

10, 15, 16, and 18) 

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

20 Steam Production 

771,462,938 771,462,938 

21 Nuclear Production 

5,778,879,303 5,778,879,303 

22 Hydraulic Production-Conventional 

319,366,215 319,366,215 

23 Hydraulic Production-Pumped Storage 

24 Other Production 

25,944,016 25,944,016 

25 Transmission 

1,605,669,881 1,605,669,881 

26 Distribution 

4,505,989,448 4,505,989,448 

27 Regional Transmission and Market Operation 

28 General 

735,423,354 735,423,354 

29 TOTAL (Enter Total of lines 20 thru 28) 

13,742,735,155 13,742,735,155 


Page 219






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Retirement Work in Progress Charged to $ 24,851,206 

Accumulated Provision for Depreciation of 

Electric Plant (Contra Account 107) 




Line 

No. 




(Mo, Da, Yr) 


04/18/2009 

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) 

Description of Investment 

(a) 

Date Acquired 

(b) 

Date Of 

Maturity 

(c) 



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 in 

columns (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 to 

current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity 

date, 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 for 

Account 418.1. 

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 

Edison ESI 

Capital Stock 

Additional Paid-in Capital 

Undistributed Earnings 

Subtotal 

Mono Power Company 

Capital Stock 



Subtotal 

Southern States Realty 

Capital Stock 



Subtotal 

SCE Capital Company 

Capital Stock 



Subtotal 

SCE Funding LLC 

Capital Stock 



Subtotal 

Conservation Financing Corp. 

Capital Stock 



Subtotal 

12/06/68 

12/06/68 

03/02/70 

03/02/70 

01/22/73 

01/22/73 

09/10/82 

09/10/82 

06/27/97 

06/27/97 

10/22/97 

10/22/97 

none 

none 

none 

none 

none 

none 

none 

none 

none 

none 

none 

none 

Amount of Investment at 


(d) 

10 

99,990 

4,428,666 

4,528,666 

100 

2,749,150 

-2,061,510 

687,740 

100 

82,634 

82,734 

20,000 

100,000 

-2,723,020 

-2,603,020 

52,191,400 

-7,504,409 

44,686,991 

20,000 

62,982,651 

37,836,954 

100,839,605 

42 Total Cost of Account 123.1 $ 474,263,502 

TOTAL 707,270,912 




Line 

No. 




(Mo, Da, Yr) 


04/18/2009 

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) 

Description of Investment 

(a) 

Date Acquired 

(b) 

Date Of 

Maturity 

(c) 



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 in 

columns (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 to 

current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity 

date, 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 for 

Account 418.1. 

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 

Mountainview Power Co. LLC 

Capital Stock 



Subtotal 

03/12/04 

03/12/04 

- 

none 

none 

- 

Amount of Investment at 


(d) 

510,912,240 

48,135,956 

559,048,196 

42 Total Cost of Account 123.1 $ 474,263,502 

TOTAL 707,270,912 







(Mo, Da, Yr) 


04/18/2009 

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) 



4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee 

and 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 (or 

the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible 

in column (f). 

8. Report on Line 42, column (a) the TOTAL cost of Account 123.1 

Equity in Subsidiary 

Revenues for Year 

Amount of Investment at Gain or Loss from Investment 

Earnings of Year 

(e) (f) 

End of Year 

(g) 

Disposed of 

(h) 

Line 

No. 

10 2 

99,990 3 

837,658 5,266,324 

4 

837,658 5,366,324 

5 

100 8 

2,749,150 9 

6,590 -2,054,920 

10 

6,590 694,330 

11 

1 

6 

7 

12 

13 

100 14 

-8,749 73,885 

16 

-8,749 73,985 

17 

20,000 20 

100,000 21 

-3,050 -2,726,070 

22 

-3,050 -2,606,070 

23 

5,488 28 

5,488 29 

-1,505,204 34 

-1,505,204 35 

15 

18 

19 

24 

25 

26 

27 

30 

31 

32 

33 

36 

37 

38 

39 

40 

41 

47,203,776 522,693,764 

42 







(Mo, Da, Yr) 


04/18/2009 

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) 



4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee 


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 (or 

the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible 

in column (f). 

8. Report on Line 42, column (a) the TOTAL cost of Account 123.1 

Equity in Subsidiary 

Revenues for Year 

Amount of Investment at Gain or Loss from Investment 

Earnings of Year 

(e) (f) 

End of Year 

(g) 

Disposed of 

(h) 

Line 

No. 

471,294,152 3 

47,871,043 47,871,043 

4 

47,871,043 519,165,195 

5 

1 

2 

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 

47,203,776 522,693,764 

42 




Line 

No. 




MATERIALS AND SUPPLIES 


(Mo, Da, Yr) 

04/18/2009 

Account Balance Balance 


End of Year 

(a) 

(b) 

(c) 


End of 


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 the 

various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense 

clearing, 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) 

15,728,482 32,152,960 Various 

290 Various 

37,253,063 222,053,768 Various 

125,520,559 38,504,599 Various 

2,975,993 2,460,504 Various 

54,386,400 13,370,493 Various 

15,714,610 4,368,010 Various 

235,850,625 280,757,374 

2,787,134 1,162,212 Various 

254,366,531 314,072,546 

Department or 

Departments which 

Use Material 

(d) 


Page 227



Line 

No. 




(Mo, Da, Yr) 


04/18/2009 

Allowances (Accounts 158.1 and 158.2) 

Allowances Inventory 

Current Year 

(Account 158.1) No. Amt. 

(a) 

(b) 

(c) 

No. 

(d) 


End of 


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 General 

Instruction 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 remaining 

succeeding years in columns (j)-(k). 

5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. 

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 

Balance-Beginning of Year 

Acquired During Year: 

Issued (Less Withheld Allow) 

Returned by EPA 

Purchases/Transfers: 

Total 

Relinquished During Year: 

Charges to Account 509 

Other: 

Cost of Sales/Transfers: 

Total 

Balance-End of Year 

Sales: 

Net Sales Proceeds(Assoc. Co.) 

Net Sales Proceeds (Other) 

Gains 

Losses 

Allowances Withheld (Acct 158.2) 

Balance-Beginning of Year 

Add: Withheld by EPA 

Deduct: Returned by EPA 

Cost of Sales 

Balance-End of Year 

Sales: 

Net Sales Proceeds (Assoc. Co.) 

Net Sales Proceeds (Other) 

Gains 

Losses 

2009 

Amt. 

(e) 







Allowances (Accounts 158.1 and 158.2) 

(Continued) 


(Mo, Da, Yr) 

04/18/2009 


End of 


6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 

43-46 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 "associated 

company" 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. 

No. 

(f) 

2010 2011 

Amt. 

(g) 

No. 

(h) 

Amt. 

(i) 

Future Years 

Totals 

No. Amt. No. Amt. 

(j) 

(k) (l) (m) 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 




Line Description of Extraordinary Loss 

No. [Include in the description the date of 

Commission Authorization to use Acc 182.1 

and period of amortization (mo, yr to mo, yr).] 

(a) 

1 None 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 




(Mo, Da, Yr) 


04/18/2009 

EXTRAORDINARY PROPERTY LOSSES (Account 182.1) 

Total 

Amount 

of Loss 

(b) 

Losses 

Recognised 

During Year 

(c) 

WRITTEN OFF DURING YEAR 

Account 

Charged 

Amount 

(d) 

(e) 



Balance at 

End of Year 

(f) 

20 TOTAL 

FERC FORM NO. 1 (ED. 12-88) Page 230a






(Mo, Da, Yr) 




04/18/2009 

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) 

Line Description of Unrecovered Plant 

Total 

Costs 

WRITTEN OFF DURING YEAR Balance at 

No. and Regulatory Study Costs [Include 

Amount 

Recognised 

in the description of costs, the date of of Charges During Year Account 

Charged 

Amount 

End of Year 

Commission Authorization to use Acc 182.2 

and period of amortization (mo, yr to mo, yr)] 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

21 SONGS #2 - Amount to be amortized 15,702,337 407 -110,767 1,504,587 

22 over a 25 year period beginning 

23 January 1989 to December 2013 

24 

25 SONGS #3 - Amount to be amortized 15,296,204 407 -108,089 1,468,202 

26 over a 25 year period beginning 

27 January 1989 to December 2013 

28 

29 Palo Verde Nuclear Generating 7,772,588 407 -53,237 909,467 

30 Regulatory Study Cost 

31 

32 Unamortized SONGS #1 Plant 636,913,184 

33 Investment 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 TOTAL 675,684,313 -272,093 3,882,256 

FERC FORM NO. 1 (ED. 12-88) Page 230b






(Mo, Da, Yr) 


04/18/2009 

Transmission Service and Generation Interconnection Study Costs 

7. In column (e) report the account credited with the reimbursement received for performing the study. 

Line 

Costs Incurred During 

No. 

Description 

Period 

Account Charged 

(a) 

(b) 

(c) 

Reimbursements 

Received During 

the Period 

(d) 



1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and 

generator 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. 

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 

Transmission Studies 

Interconnection Studies 115,855 143 ( 91,934) 143 

Generation Studies 

Interconnection Studies 2,127,752 143 ( 6,085,887) 143 

Account Credited 

With Reimbursement 

(e) 

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






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




1)Transmission Interconnection Studies include interconnection studies related to transmission interconnection requests and wholesale load interconnection requests. 

Project Type Work Order Costs Incurred Account 

Charged 

Reimbursements Account 

Credited 

Transmission 800063831 Interconnection Study $0.00 143 143 

Transmission 800063834 Interconnection Study $1,904.24 143 143 










Transmission 800063957 Interconnection Study ($36,533.66) 143 143 






Transmission 9010-5511 Interconnection Study $0.00 143 143 











Transmission 9010-5608 Interconnection Study ($11.07) 143 $45,698.36 143 


Transmission 9010-5631 Interconnection Study $5,695.54 143 $56,606.84 143 














Transmission 9010-5945 Interconnection Study $374.14 143 $4,940.47 143 


Transmission 800064495 Interconnection Study $567.99 143 ($3,780.00) 143 

Transmission 800064508 Interconnection Study $6,244.56 143 ($20,000.00) 143 





Transmission 800174022 Interconnection Study 143 ($11,000.00) 143 

Transmission 800198079 Interconnection Study 143 ($30,000.00) 143 






TRANSMISSION TOTAL $115,854.73 ($91,934.33) 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Column (b) includes Southern California Edison administrative and general (A&G) expenses on closed work orders only. 


Column (d) includes refunds that were paid to the interconnection customer in 2008 resulting from payments received 

exceeding actual study costs. 


Project Type Work Order Costs Incurred Account 

Charged 

Reimbursements Account 

Credited 

Generation 800063809 Interconnection Study $1,877.37 143 143 

Generation 800063808 Interconnection Study $0.00 143 143 




Generation 800063811 Interconnection Study ($371.54) 143 143 

Generation 9010-5105 Interconnection Study $1,059.39 143 $7,426.83 143 







Generation 800063818 Interconnection Study $5,947.01 143 ($14,316.41) 143 

Generation 800063825 Interconnection Study $231.39 143 ($1,714.63) 143 











Generation 9010-5139 Interconnection Study $532.17 143 ($3,932.35) 143 







Generation 9010-5148 Interconnection Study $0.00 143 143 

















Generation 800063859 Interconnection Study ($9,325.72) 143 ($42,435.57) 143 



Generation 9010-5171 Interconnection Study $112.75 143 ($918.13) 143 









(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 









































































(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 


























Generation 800064051 Interconnection Study ($5,327.66) 143 143 


Generation 800064055 Interconnection Study ($197.62) 143 $4,909.05 143 




Generation 800064059 Interconnection Study $2,330.59 143 $14,416.71 143 












Generation 9010-5654 Interconnection Study $1,508.54 143 $37,161.56 143 












Generation 800064104 Interconnection Study ($25,200.40) 143 $15,050.70 143 

















(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 













Generation 800064124 Interconnection Study ($729.05) 143 $17,618.16 143 



Generation 800064129 Interconnection Study $0.00 143 $60,000.00 143 



Generation 9010-5739 Interconnection Study $4,818.55 143 ($27,381.89) 143 




Generation 9010-5744 Interconnection Study $724.43 143 $665.20 143 






Generation 9010-5752 Interconnection Study ($4.86) 143 $19,150.50 143 

Generation 9010-5753 Interconnection Study $82.94 143 $19,380.27 143 

Generation 9010-5754 Interconnection Study ($323.09) 143 $19,710.89 143 


Generation 800064144 Interconnection Study $49.67 143 $19,358.31 143 












Generation 9010-5781 Interconnection Study $1,585.84 143 $52.54 143 

Generation 9010-5782 Interconnection Study $1,210.95 143 $181.27 143 



























(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 






Generation 9010-5817 Interconnection Study ($606.86) 143 ($1,592.96) 143 




















Generation 9010-5855 Interconnection Study ($74.23) 143 143 
































Generation 9010-5903 Interconnection Study ($4.99) 143 143 















(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 





























































Generation 800064369 Interconnection Study $47.78 143 ($326.89) 143 












(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 

































Generation 800064412 Interconnection Study $5,484.51 143 $0.00 143 








































(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 









































































(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 









































































(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 








































































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 






Generation 800216012 Interconnection Study 143 ($190,000.00) 143 




























































Generation Total $2,127,752.45 ($6,085,887.16) 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 









(Mo, Da, Yr) 


04/18/2009 

OTHER REGULATORY ASSETS (Account 182.3) 



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 $50,000 which ever is less), may be grouped 

by classes. 

3. For Regulatory Assets being amortized, show period of amortization. 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

Description and Purpose of 


Balance at 

Debits CREDITS 

Written off During 

the Quarter/Year 


(a) 

Income Tax-Related Deferred Charges 

- FASB 109 gross-up of taxes. 

Unamortized Cost - Palo Verde Commercial 

Operating Date Adjustment 

- To recover costs incurred between FERC and 

CPUC commercial operating date. 

(Amortization Period: 03/1988-01/2026) 

Health and Safety Rewards 

-To reflect accrued rewards related to health 

and safety, number of circuit interruptions, and 

customer satisfaction. 

Exchange Energy 

- To record non-cash related energy costs not 

involving the transfer of cash between SCE and 

third parties. 

Decommissioning Not Yet Collected in 

Rates San Onofre 1 - Long Term 

- To recover remaining decommissioning costs on 

unit shut down in 1992. 

Palo Verde Units 2 & 3 

- To recover deferred common facilities charges. 

(Amortization Period: 09/1986 - 01/2026) 

Catastrophic Event Memorandum Account 

-To record costs incurred by SCE assoc- 

iated with a catastrophic event for restoring 

utility service to customers; repairing, replacing, 

or restoring damaged utility facilities; and 

complying with governmental agency orders. 

Base Rate Performance Memo Account 

-To record customer share of PBR Revenues 

due to SCE's financial results being outside the 

Revenue Sharing Dead Band and inside the 

Revenue Sharing Band. 

Beginning of 

Current 

Quarter/Year 

(b) 


the Period 

Amount 

Balance at end of 

Current Quarter/Year 

(c) 

(d) 

(e) 

(f) 

1,110,284,679 855,563,420 Various 

629,215,776 1,336,632,323 

504,920 406 

27,922 

476,998 

13,000,000 13,000,000 

4,492,240 1,229,769 Various 

5,722,008 

1 

83,368,189 Various 

83,368,189 

2,030,292 406 

112,274 

1,918,018 

66,895,592 16,126,394 Various 

46,770,548 

36,251,438 

76,881,993 1,700,741 Various 

24,087,169 

54,495,565 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 



Balance at 





(a) 

Environmental Clean-up Costs 

-To recover ratepayer's portion of environ- 

mental costs. 

Nuclear Fuel CC Fuel Stock-SONGS/Palo Verde 

-Reg. asset for nuclear fuel carrying costs. 

San Onofre Nuclear Generating Station 

-To recover deferred common facilities charges 

incurred between FERC and CPUC commercial 

operating date. 


Hazardous Waste Balancing Account 

-To recover collaborative hazardous waste costs. 

Miscellaneous Regulatory Account 

-To capture various other regulatory items 

resulting from rate actions by the CPUC. 

Post Employment Benefit Accrual 

-To reflect a regulatory asset for future recovery 

of post employment benefits associated with 

SFAS 112. 

Environmental Remediation 

-To recover 90% of estimated future environ- 

mental remediation/cleanup costs. 

GCAC Balancing Account 

- Balance composed of Gas Cost Adj. Clause 

which recovers/refunds gas costs on 

Catalina Island. 

Unamortized Steam Plant 

-To reflect Mohave Generating Station Plant as a 

regulatory asset. 


Beginning of 

Current 

Quarter/Year 

(b) 


the Period 

Amount 



(c) 

(d) 

(e) 

(f) 

55,868,098 18,249,394 Various 

23,187,192 

50,930,300 

2,114,760 770,329 518 

979,965 

1,905,124 

1,510,907 406 

103,606 

1,407,301 

6,410,881 7,229,166 Various 

7,367,979 

6,272,068 

70,191,612 23,043,608 

93,235,220 

30,402,072 1,098,782 Various 

5,384,581 

26,116,273 

214,101 233,088 Various 

198,976 

248,213 

59,967,496 136,248 Various 

12,057,027 

48,046,717 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.1






(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

Various Settlements 



Balance at 





(a) 

-To reflect the future recovery of termination 

payments for various purchased-power 

contracts. 

Various Settlements (Short Term) 

-To reflect the short-term portion of future re- 

covery of termination payments for various 

purchased-power contracts. 

Transmission Access Charge Balancing Acct. 

-To track the flow through to end-use customers the 

net cost-shift billed to SCE by the ISO under the 

Transmission Access Charge (TAC) as per 

Section 5.6 of the TO Tariff. 

CARE Balancing Account 

-To reflect in rates, through application of the 

Public Purpose Program Charge the costs assoc- 

iated with the CARE Program as authorized in 

various CPUC Decisions. 

Unamortized Nuclear Plant 

-To reflect SONGS and Palo Verde Nuclear 

Plants as regulatory assets. 


Energy Settlements Memorandum Account (ESMA) 

-To record refund amounts received by SCE resulting 

from FERC investigation settlement agreements 

associated with wholesale power purchases made on 

behalf of SCE's bundled service customers, net of 

litigation costs recorded in the Litigation Costs 

Tracking Account. 

Family Energy Rate Assistance Balancing Account 

-To record FERA-related program O&M costs and 

revenue that will result from charging FERA 

eligible customers Tier 2 electricity rates for 

their Tier 3 usage. 

Beginning of 

Current 

Quarter/Year 

(b) 

(c) 

(d) 


the Period 

Amount 

7,748,000 228 

7,748,000 

(e) 



33,395,297 11,785,748 Various 

24,542,424 

20,638,621 

2,327,549 30,874,611 Various 

4,410,240 

28,791,920 

405,367,243 Various 

30,216,909 

375,150,334 

11,767,363 Various 

11,767,363 

47,602 79,256 254 

47,603 

79,255 

(f) 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 



Balance at 





(a) 

Nuclear & Coal Asset Retirement Obligation (ARO) 

-To establish a regulatory asset for decommission- 

ing costs collected in rates for Nuclear and coal 

ARO property (Amort. Period: 12/2003-12/2025) 

Late Payment Charge (LPC) Revenue Balancing Account 

-To record differences between LPC OOR authorized 

by the Commission and recorded LPC OOR. 

PBR and Other Related Ratemaking 

-Reclassification of PBR Incentive and other rate- 

making amounts to a contra-asset account. 

Public Purpose Programs Adjustment Mechanism 

-To record Public Goods Charge Revenue, PGC 

expenses authorized in P.U. Code Section 399.8, and 

other CPUC Public Purpose Program revenues and 

expenses. 

Energy Resource Recovery Account 

-To record SCE's ERRA Revenue, Utility Retained 

Generation fuel costs, and purchased power related 

expenses. 

Bilateral Energy & Gas Financial Instruments- 

Short Term 

-To record the mark-to-market adjustments related 

to the short term financial instruments used to 

hedge power purchases and natural gas costs 

for tolling. 

Bilateral Energy & Gas Financial Instruments- 

Long Term 


to the long term financial instruments used to 

hedge power purchases and natural gas costs for 

tolling. 

Firm Transmission Rights Revenue (FTR) 

-To record FTR Revenue received from CAISO. 

Beginning of 

Current 

Quarter/Year 

(b) 

(c) 

(d) 


the Period 

Amount 

(e) 



298,098,707 2,086,154 Various 

20,604,656 

279,580,205 

431,647 1,319,104 Various 

1,519,426 

231,325 

( 89,881,993) 36,666,965 Various 

14,280,537 

-67,495,565 

1,179,924 

435,986,031 Various 

1,179,924 

30,114,692 

(f) 

405,871,339 

63,438,600 200,935,701 Various 

133,964,478 

130,409,823 

6,109,071 667,814,463 Various 

8,218,141 

665,705,393 

15,229,057 53,771,666 407 

59,740,660 

9,260,063 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 



Balance at 





(a) 

Advanced Metering and Demand Response 

Memorandum Account 

-To record the incremental one-time set-up and 

ongoing O&M and A&G expenses incurred to develop 

and implement the Demand Response programs adopted 

in Phase 1 of the Advanced Metering Demand Response 

and Dynamic Pricing Proceeding. 

Mohave Balancing Account 

-To track the difference between: 1) recorded 

capital-related expenses, operating expenses and 

worker protection expenses associated with the 

Mohave Generating Station; and 2) the authorized 

Mohave revenue requirement as adopted in 

in D.06-05-016. 

Residential Deferred Revenue Memorandum Account 

-To record the revenue undercollection resulting 

from deferring the rate increase authorized in 

D.06-06-067 for residential customers from 

August 1, 2006 until December 31, 2006. 

Base Revenue Requirement Balancing Account 

-To record the difference between SCE's 

distribution, generation, and recorded revenue 

requirements and other amounts authorized by the 

Commission. 

Regulatory Asset - SFAS 158 

-To reflect regulatory asset resulting from the 

adoption of SFAS 158-Employers' Accounting 

for Defined Benefit Pension & Other Postretirement 

Plans. 

Agricultural Line Extension Costs Memorandum Acct. 

-To record capital-related costs (net of customer 

contributions) of installing line and service 

extensions to convert agricultural and pumping 

customers from diesel fuel-driven engines to 

electric pumps. 

Beginning of 

Current 

Quarter/Year 

(b) 

(c) 

(d) 


the Period 

Amount 

(e) 



231,230 218,025 254 

231,230 

218,025 

446,488 3,330,412 407 

3,339,001 

437,899 

145,280,898 249,347,887 Various 

394,628,785 

230,680,000 1,651,524,000 

1,882,204,000 

182,385 326,498 182 

182,385 

326,498 

(f) 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 



Balance at 





(a) 

Project Development Division Memorandum Account 

-To track the Project Development Division recorded 

support costs, as authorized in CPUC D.06-05-016. 

Quarterly Compliance Filings Audit Expense 

Memorandum Account 

-To record audit expenses paid to outside audit 

firm assigned to review SCE's quarterly procurement 

related compliance filings. 

Leases for Power Contracts 

-To record regulatory asset associated with power 

contracts that are subject to lease accounting 

rules under the guidance of EITF No. 01-8 and 

SFAS 13. 

(Amortization Period: 12/2006 - 12/2016) 

Advanced Metering Infrastructure Memorandum Account 

-To record incremental costs associated with the 

Advanced Metering Infrastructure (AMI) Phase II 

pre-deployment activities. 

Nuclear Decommissioning Adjustment Mechanism 

-To record NDAM revenue, authorized and recorded 

costs related to the decommissioning of San Onofre 

Nuclear Generating Station and Palo Verde Nuclear 

Generating Station. 

Gross Revenue Sharing Mechanism 

-To record the customers' share of certain Other 

Operating Revenue (OOR), as per Advice Letter 

No. 1413-E-A, dated September 16, 1999. 

Undistributed Expense Regulatory Asset 

-To record a regulatory asset associated with the 

accrual of various undistributed expenses. 

Beginning of 

Current 

Quarter/Year 

(b) 

(c) 

(d) 


the Period 

Amount 

(e) 



2,405,854 3,960,897 

2,456,731 

3,910,020 

140,454 53,052 254 

140,454 

53,052 

72,144,934 Various 

7,762,179 

64,382,755 

2,563,082 2,563,082 

208,757 1,954,936 Various 

2,163,693 

116,223 254 

29,579,048 Various 

116,223 

27,765,261 

(f) 

1,813,787 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 



Balance at 





(a) 

Dept of Energy Litigation Memorandum Acct. 

-To record SCE's incremental litigation costs and 

damages and other proceeds received by SCE from 

the federal government associated with the breach 

of contract complaint brought against the DOE for 

failure to take possession of San Onofre Nuclear 

Generating Station spent fuel. 

Results Sharing Memorandum Account (RSMA) 

-To track the difference between authorized and 

recorded Results Sharing expenses paid out. 

New System Generation Memorandum Account (NSGMA) 

-To record the net costs (benefits and costs) 

associated with the Power Purchase Agreement 

between SCE and Long Beach Generation LLC in 

accordance with the Joint Settlement Agreement 

filed on May 11, 2007 in R.06-02-013. 

Other Hazardous Substance Cleanup Cost Memorandum 

Account 

-To track cleanup costs associated with sites which 

have not been identified as Covered Sites, but for 

which SCE has filed or plans to file an Advice 

Letter requesting that the site be identified as 

Covered Site. 

Congestion Revenue Rights 

To record a regulatory asset associated with the 

procurement of Congestion Revenue Rights as hedges 

against congestion costs under the California 

Independent System Operator's (CAISO) MRTU 

initiative. 

Market Redesign and Technology Upgrade Memorandum 

Account (MRTUMA) 

To record SCE's incremental costs associated with 

the CAISO's MRTU initiative. 

Misc. Balancing Account Activity 

To capture various accrued purchased power 

agreements and other miscellaneous regulatory 

liabilities 

Beginning of 

Current 

Quarter/Year 

(b) 

(c) 

(d) 


the Period 

Amount 

(e) 



198,868 66,096 

264,964 

8,933,261 Various 

8,725,795 

(f) 

207,466 

11,385,427 27,040,449 Various 

718,198 

37,707,678 

15,028 363 

15,391 

1,238,044 407 

1,238,044 

2,653,138 2,783,292 Various 

276,067 

5,160,363 

1,600,000 

1,600,000 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 






by classes. 


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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 



Balance at 





(a) 

Solar Photovoltaic Program Memo Account P9099 

To record incremental O&M and capital related 

revenue requirement associated with the first $25 

million of direct capital expenditures incurred in 

the Solar PV Program 

Long-Term Procurement Technical Assist MA P9102 

To record the technical assistance costs incurred 

by the Commission and paid by SCE in connection 

with the implementation and administration of the 

Long-Term Procurement Plan (LTPP) 

Non-discretionary Service Cost MA LT P9103 

To record SCE's incremental costs incurred for 

providing non-discretionary services in accordance 

with Ordering Paragraph 9 or D.08-05-003 

Beginning of 

Current 

Quarter/Year 

(b) 

(c) 

720,584 

72,324 

665 

(d) 


the Period 

Amount 

(e) 



(f) 

720,584 

72,324 

665 

44 TOTAL 2,712,855,010 4,444,644,126 

1,639,245,393 5,518,253,743 







(Mo, Da, Yr) 


04/18/2009 

MISCELLANEOUS DEFFERED DEBITS (Account 186) 



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 $50,000, whichever is less) may be grouped by 

classes. 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

Description of Miscellaneous Balance at 


Balance at 

Deferred Debits 


Account 

Amount 

End of Year 

Charged 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

Function Suspense 

444,998 Various 

444,998 

SSID-JO 

504,902 550 

504,902 

Automotive Services 

246,487 650 

246,487 

Real Properties Job Order Systm 

505,118 600 

505,118 

Telecommunications Job Orders 

9,241 530 

9,241 

Trans/Subs Division Job Orders 

46,253 570 

46,253 

IT-DBU / IS-JO 

-10,755 10,755 610 

Other Suspense - Various 

-208,663 208,663 Various 

Plant Construction Claims Pendg 

16,987,523 1,936,169 980 

3,289,586 

15,634,106 

Research & Development 

58,047 470 

58,047 

Undistributed Job Orders 

-2,177,219 2,177,219 699 

Engineering & Construction Jobs 

56,965 500 

56,965 

Allocated Fax & Copy Charges 

608,283 728-729 

608,283 

Pension Fund 

74,987,000 392 

4,463,000 

70,524,000 

Assembly/Rebuild Operation 

68,369 685 

68,369 

Internal Market Mechanism 

. Chargebacks 

1,020,290 Various 

1,020,290 

Prepaid Software License 

2,796,680 1,321,383 870 

1,930,708 

2,187,355 

Right to Purchase Power 

. Hoover Contract (WAPA) 

22,250,000 228 

1,720,000 

20,530,000 

Nuclear Generation Job Order 

676 N/A 

676 

Unamortized Cost - Long Beach 

. Operation Agreement 

1,323,418 920 

661,680 

661,738 

Def. Prepaid Pension Cost 

92,183,958 926 

92,183,958 

Metering Services - JO 


82,196 

Bear Valley Settlement 

3,158,596 143 

3,158,596 

Catalina Wells Settlement 

50,000 107 

50,000 

Carrier Solutions - JO 


10,922 

Information Technology - JO 


39,337 

Prepaid Lease Asset 

6,366,881 555 

6,366,881 

ERP - JO 


630,352 

Misc. Deferred Debit 

352,362,920 Various 

347,607,024 

4,755,896 

CWIP - ECS Def Debit 

8,665,088 Various 

5,516,777 

3,148,311 

Prelim Eng Cost 

6,787 Various 

247 

6,540 

CSBU DSGN Eng Def Exp 


178,421 

-40,099 

CSBU DWR Admin Fees 

Various 

9,149 

-9,149 

SLU Def Proj Cost 

2,499,170 Various 

2,499,170 

Unbilled Rev Cat - LT 

455,334 414 

32,945 

422,389 

47 Misc. Work in Progress 

48 

Deferred Regulatory Comm. 

Expenses (See pages 350 - 351) 

49 TOTAL 

30,061,226 40,378,121 

252,101,081 252,882,336 







(Mo, Da, Yr) 


04/18/2009 

ACCUMULATED DEFERRED INCOME TAXES (Account 190) 

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. 



Line 

No. 

1 

Electric 

Description and Location 

(a) 

Balance of Begining 

of Year 

(b) 

Balance at End 

of Year 

(c) 

2 

See Footnote 

1,423,241,880 

1,087,588,291 

3 

4 

5 

6 

7 

Other 

8 

TOTAL Electric (Enter Total of lines 2 thru 7) 

1,423,241,880 

1,087,588,291 

9 

Gas 

10 

See Footnote 

-14,197,216 

-15,648,115 

11 

12 

13 

14 

15 

Other 

16 

TOTAL Gas (Enter Total of lines 10 thru 15 

-14,197,216 

-15,648,115 

17 


18 

TOTAL (Acct 190) (Total of lines 8, 16 and 17) 

1,409,044,664 

1,071,940,176 

Notes 








(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 



Sub- at Beginning at End 

Division Description of Year of Year 

ELECTRIC: 

190.010 Amort of Debt Issuance Cost 135,885.24 213,412.84 

190.100 ECAC 70,294.44 49,205.75 

190.106 Franchise Requirements 4,238.60 3,851.83 

190.107 Relicensing Fees (5,948,301.08) (5,836,320.26) 

190.108 AC Def Inc Tax - Exchg Energy (1,803,454.31) (0.01) 

190.110 AC Def Inc Tax - ECAC Incent 0.00 0.00 

190.111 Yuma Axis Generating Stn 0.00 0.00 

190.112 Toxic Substance Settlemt 0.00 0.00 

190.113 Executive Incentive Comp 3,776,054.34 3,887,202.96 

190.124 AC Def Inc Tax - TCF PV3 Ovrcoll 03 1,489,635.31 1,567,489.52 

190.125 Unbilled Revenue (1,992,301.45) (1,992,301.45) 

190.130 Acc charges 2,127,738.00 2,127,738.00 

190.131 DIT - APS Right of Way 5,700,732.00 6,383,215.56 

190.132 Corp Name Change 30,259.67 21,929.50 

190.144 QF termination payments 63,720.05 63,720.05 

190.145 Mescalero Fuel Storage (86,874.34) (87,368.14) 

190.146 San Antonio Trust 0.00 0.00 

190.148 Photovoltaic Facilities (28,484.20) (59,523.90) 

190.190 Uncollectible Accts. Exp. (541,611.29) (455,234.76) 

190.191 CCFT - TSB -FAS 109 483,948.24 595,580.56 

190.208 RAR Rollforward 1,729,276.00 1,522,140.00 

190.210 Prepaid Expenses (5,184,496.76) (4,790,768.35) 

190.216 Bond Discount Amort 1,313,195.98 1,413,890.12 

190.220 CCFT - Electric 30,472,673.12 15,207,385.85 

190.222 Decom Net Earn - Non Qua 89,690,166.42 88,501,844.91 

190.224 Def Tax Flow Thru ITC 49,369,604.85 45,574,536.13 

190.225 Def Tax ITC 2-Yr Average 1,247,247.90 1,082,940.49 

190.232 Executive Incentive Plan 12,958,726.01 657,108.45 

190.234 Pension Reserve 98,218,797.80 108,602,591.32 

190.237 Restricted Stock 0.00 0.00 

190.240 Uncollectible Accounts E 8,250,628.80 12,108,471.20 

190.241 Coolwater - CPUC 1,348,832.01 0.00 

190.242 Exec Retrmnt Provision - FAS109 (27,852,533.27) (27,852,533.27) 

190.243 CRE Lease Options 0.00 0.00 

190.244 ARAM 11,483,806.71 10,249,259.31 

190.248 Ins - Inj/Damages Prov 71,507,778.75 78,003,954.16 

190.253 Misc Def Tax (7,041,538.95) (7,537,861.52) 

190.254 Unrealized Gain - Decomm 393,479,637.56 69,476,866.75 

190.255 Hazardous Waste (576,957.75) (576,957.75) 

190.256 Accrued Vacation 25,659,161.28 25,727,653.77 

190.258 Health Care - IBNR 294,642.73 1,093,021.82 

190.266 Uncollec Accts-Claims 1,814,144.99 1,467,325.68 

190.297 Def Tax - CCFT Base Rates - R.L. 17,859,127.02 19,734,426.15 

190.319 Ins Res/Casualty Loss 108,202.35 0.00 

190.350 DOC ER88-83 0.00 18,787,097.78 

190.351 FERC Res Misc 0.00 0.00 

190.365 Decomm NQ Expenses 79,809,447.91 79,809,447.90 

190.368 FERC ER 85-67 0.00 0.00 

190.393 DIT - SFAS 158 - Short Term 9,527,127.55 9,286,572.72 

190.407 GRC Marine Mitigation 2,181,589.12 2,181,589.12 

190.417 DIT on Late Pymt Bal Acct. 0.00 0.00 

190.419 Air Conditiong Cycling Program Mech. Acct. (ACCPMA) 0.00 0.00 

190.426 Def Tax - Prov For Basln Bal. Acct. 0.00 0.00 

190.431 Nuc Decomm Adj Mech (NDAM) (83,807.84) 0.01 

190.433 Pub Purp Prg Adj Mech (PPPAM) 6,379,263.87 6,379,263.85 

190.434 Family Energy Rate Assistance Bal. Acct. (FERABA) (19,110.62) (31,818.35) 

190.435 Elect Dist Rev Adj Bal (EDRABA) 5,962,587.23 0.00 

190.436 Energy Resource Recov (ERRA) 0.00 0.00 

190.444 DIT - SRPIM 916,375.54 916,375.54 

190.445 DIT WECC Statutory Costs 1,286,139.62 0.00 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



190.448 Base Revenue Requirement 12,116,788.74 70,441,257.90 

190.457 Demand Responsiveness Memo 40,923,933.95 40,923,933.95 

190.459 DIT - FIN Reporting Reserves 40,514,676.10 34,123,787.11 

190.463 DIT Demand Respon Prg Bal Acct 8,797,685.24 8,797,685.24 

190.485 DIT Energy Assistant Fund (676,871.20) 0.00 

190.510 Nuclear Fuel (24,842,584.68) (18,178,992.73) 

190.520 NQ Decom. Withdraws (104,337,130.78) (108,530,796.02) 

190.561 R&D Overcollection 242,743.41 242,743.41 

190.640 DSMAC Expenses 49,231,676.58 49,231,676.60 

190.700 Conserv Hardware Rebate 0.00 0.00 

190.738 Cont in Aid of Const (34,877,566.90) (47,143,635.16) 

190.745 Int Capitalized - AFUDC 120,942,493.40 133,962,447.48 

190.746 Contra-Int Capitalized (19,115,927.00) (18,792,259.00) 

190.748 ITCC - CIAC - State 287,095,594.75 298,735,460.60 

190.800 PBOP 401H Amortization 131,550,680.76 86,684,033.17 

190.910 Fixed Costs 44,755,102.97 10,959,845.85 

190.925 LSFO Differential (14,844,858.20) (14,844,858.20) 

190.926 DFO Differential 57,638.94 (61,825.25) 

190.961 ADIT - Environ Remed 116,588.15 116,588.16 

DIT DSM-ENERGY EFFICIENCY 0.00 (347,759.07) 

DIT DSM-LOW INCOME 0.00 (1,770,297.63) 

DIT FIRM TRANSMISSION RIGHTS BA 0.00 (2,592,776.23) 

SOLAR INVESTMENT TAX CREDIT 0.00 2,155,609.12 

Total Electric 1,423,241,879.38 1,087,588,291.14 



Sub- at Beginning at End 

Division Description of Year of Year 

GAS AND OTHER INCOME: 

190.125 Unbilled Revenue 0.00 0.00 

190.180 DIT - RAR Rollforward - State 4,056,314.94 4,019,595.50 

190.181 DIT - RAR Rollforward - Federal (15,680,831.08) (16,630,584.48) 

190.208 RAR Rollforward 0.00 0.00 

190.212 Ad Val Lien Date-Other (416,292.77) (227,339.99) 

190.217 CCFT - Gas (7,045.20) (12,182.98) 

190.218 CCFT - Other (2,129,644.04) (2,739,998.00) 

190.219 CCFT - Water (88,359.05) (98,419.71) 

190.231 Def Tax - Etiwanda Wst Wtr 49,293.11 38,117.57 

190.501 ACRS SONGS PV Write-off 19,346.90 2,695.68 

190.910 Book Reserve 0.00 0.00 

190.912 Misc FPO 1.61 1.61 

Total Gas and Other Income (14,197,215.58) (15,648,114.80) 







(Mo, Da, Yr) 


04/18/2009 

CAPITAL STOCKS (Account 201 and 204) 



1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate 

series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting 

requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and 

company 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. 

Line 

No. 

Class and Series of Stock and 

Name of Stock Series 

Number of shares 

Authorized by Charter 

Par or Stated 

Value per share 

Call Price at 

End of Year 

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 

(a) 

Account 201 

Common Stock, no par value 

TOTAL_COM 

Account 204 

Preferred stock - without 

Mandatory Redemption Requirements 

Cumulative participating, not redeemable 

Cumulative Preferred: 

4.08% Series 

4.24% Series 

4.32% Series 

4.78% Series 

Preferred Stock - with Mandatory Redemption 

Requirements 

$100 Cumulative Preferred: 

Preference Stock 

No Par Value 

Non-Voting and Non-Cumulative 

5.349% SERIES A 

6.125% SERIES B 

6.000% SERIES C 

TOTAL_PRE 

(b) 

560,000,000 

560,000,000 

24,000,000 

12,000,000 

50,000,000 

86,000,000 

(c) 

25.00 

25.00 

25.00 

25.00 

(d) 

25.50 

25.80 

28.75 

25.80 

100.00 

100.00 

100.00 







(Mo, Da, Yr) 


04/18/2009 

CAPITAL STOCKS (Account 201 and 204) (Continued) 



3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission 

which 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 or 

non-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 which 

is pledged, stating name of pledgee and purposes of pledge. 

OUTSTANDING PER BALANCE SHEET 

HELD BY RESPONDENT 

Line 

(Total amount outstanding without reduction 

AS REACQUIRED STOCK (Account 217) 

IN SINKING AND OTHER FUNDS No. 

for amounts held by respondent) 

Shares 

(e) 

Amount 

(f) 

Shares 

(g) 

Cost 

(h) 

Shares 

(i) 

Amount 

(j) 

1 

434,888,104 2,168,054,319 

2 

434,888,104 2,168,054,319 

3 

4 

5 

6 

7 

8 

9 

10 

650,000 16,250,000 

11 

1,200,000 30,000,000 

12 

1,653,429 41,335,725 

13 

1,296,769 32,419,225 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

4,000,000 400,000,000 

27 

2,000,000 200,000,000 

28 

2,000,000 200,000,000 

29 

30 

12,800,198 920,004,950 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 







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


(Mo, Da, Yr) 

04/18/2009 



Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a 

subheading 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 more 

columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such 

change. 

(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 to 

amounts 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 end 

of 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. 

Line Item Amount 

No. 

(a) 

(b) 

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 

Accounts 208, 209 and 210 

None 

Miscellaneous Paid-in Capital (Account 211) 

Respondent issued 778,150 shares of Common Stock in the form of 

a 4% stock dividend to the holders of Original Preferred and 

Common Stock on January 5, 1961. 

778,150 X 32.875 $25,581,681.25 (Market Value) 

778,150 X 12.500 9,726,875.00 (Account 201) 

Respondent recorded this amount ($51,497) as a result of merging 

with California Electric Power Co., which in turn had recorded it 

in connection with the acquisition of a subsidiary company in 1948. 

Respondent issued 7,220,000 shares of Common Stock and 296,769 

shares of 4.78% Cumulative Preferred Stock to the respective 

holders on December 31, 1963, of California Electric Power Co. 

Common and $3 Cumulative Preferred Stock. 

Common Stock: 

Acquired Book Value - $37,570,757.06 

Account 201 (7,220,000 X 4 -1/6) = 30,083,333.33 

4.78% Cumulative Preferred Stock: 

Acquired Book Value - $4,946,150.00 

Account 201 (296,769 X $25.00) = 7,419,225.00 

15,854,806 

51,497 

7,487,424 

-2,473,075 

40 TOTAL 545,450,772 









(Mo, Da, Yr) 

04/18/2009 






change. 









No. 

(a) 

(b) 

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 

Miscellaneous Paid-in Capital (Account 211) Continued: 

Return of money deposited in Trust Fund for redemption of 

Cumulative Preferred Stock - 4.88% Series. 

Respondent recorded this amount as a result of the conversion 

of 12-1/2% convertible subordinated debentures, due 1997. 

Amount represents interest foregone by debenture holders 

from the interest payment date to the conversion dates. 

Issuance of 10,000 shares of Edison International Common Stock under 

Edison's 1987 Long-term Incentive Compensation Plan. (1988) 


Edison's 1987 Long-term Incentive Compensation Plan. (1989) 

Accrued dividend equivalents in connection with the exercise 

of stock options to purchase 1,600 shares of Edison International Com- 

mon Stock under Edison's 1987 Long-term Incentive Compensation 

Plan. (1991) 

Edison International capital contribution (1992) 


Edison's 1992 Directors Incentive Compensation Plan. (1992) 

Issuance of 4,935 shares of Edison International Common Stock by 

exercising stock options under Edison's 1987 Long-term 

Incentive Compensation Plan. (1992) 

Difference in market price and option price for stock 

option exercise on 12-22-95 under Executive Long-Term 

Incentive Plan. (1995) 

Transferred to Common Stock Account 201 as a result of 

stock split effective June 1, 1993. 

10,445 

921,446 

317,500 

492,188 

11,392 

184,500,000 

64,228 

29,911 

7,616 

-25,230,392 

40 TOTAL 545,450,772 









(Mo, Da, Yr) 

04/18/2009 






change. 









No. 

(a) 

(b) 

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 

Miscellaneous Paid-in-Capital (Account 211) Continued: 

Stock Options Exercised (1998) 

Edison International Capital Contribution (1998) 

Performance Shares (2001) 





Stock-Based Compensation (2006) 

Excess Tax Benefits Related to Stock Based Awards (2006) 

Reclassification of Shares Purchased for Stock Based Compensation 

(2002-2006) 

Stock Based Compensation (2007) 

Excess Tax Benefits Related to Stock Based Awards (2007) 

Stock Based Compensation (2008) 

Excess Tax Benefits Related to Stock Based Awads (2008) 

Gain on Reacquired Preferred Stock (2008) 

600,289 

153,000,000 

2,473,341 

4,203,885 

-3,806,452 

12,273,434 

20,536,431 

8,157,333 

17,087,817 

78,102,459 

17,949,511 

28,476,623 

18,468,441 

4,136,174 

1,746,500 

40 TOTAL 545,450,772 







(Mo, Da, Yr) 


04/18/2009 

CAPITAL STOCK EXPENSE (Account 214) 



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. 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

Class and Series of Stock 

(a) 

Common Stock 

Preferred Stock 

Preference Stock 

5.349% SERIES A 

6.125% SERIES B 

6.000% SERIES C 

SERIES D Preference Stock (Proposed Issuance) - Rating Agency Fees 

Balance at End of Year 

(b) 

103,156 

1,709,919 

5,420,936 

3,435,743 

3,779,170 

109,396 

22 TOTAL 14,558,320 







(Mo, Da, Yr) 


04/18/2009 

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



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. Designate 

demand 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 were 

issued. 

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 with 

issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as 

specified by the Uniform System of Accounts. 

Line 

No. 

Class and Series of Obligation, Coupon Rate 

(For new issue, give commission Authorization numbers and dates) 

(a) 

1 Account 221 

2 First and Refunding Mortgage Bonds: 

3 Series 2004A 5.0 

Principal Amount 

Of Debt issued 

(b) 

300,000,000 

Total expense, 

Premium or Discount 

(c) 

2,074,000 

4 1,306,366 D 

5 Series 2004B 6.0 

525,000,000 

4,809,750 

6 8,661,850 D 

7 Maricopa 2004 D&E 2.9 

144,400,000 

800,000 

8 Series 2004F 4.65 

300,000,000 

1,830,000 

9 2,996,350 D 

10 Series 2004G 5.75 

350,000,000 

3,062,500 

11 2,657,584 D 

12 

13 

14 

Series 2004H 

Series 2005A 

Floating 

5.0 

150,000,000 

400,000,000 

235,000 

2,896,154 

15 132,000 D 

16 Series 2005B 5.55 

250,000,000 

2,341,346 

17 732,500 D 

18 Series 2005E 5.35 

350,000,000 

3,062,500 

19 168,000 D 

20 Series 2005A&B 3.55 

203,460,000 

2,600,000 

21 Series 2005 A,B & C 

Variable 

248,585,000 

2,100,000 

22 Series 2006A 5.625 

350,000,000 

3,430,000 

23 857,500 D 

24 

25 

26 

27 

28 

29 

30 

Series 2006B 

Series 2006A&B 

Series 2006C&D 

Series 2006E 

Floating 

4.10 

4.25 

5.55 

150,000,000 

196,000,000 

135,000,000 

400,000,000 

682,500 

2,183,000 

1,517,000 

4,000,000 

31 2,176,000 D 

32 Series 2008A 5.95 

600,000,000 

2,760,000 D 

33 TOTAL 6,779,019,000 89,563,404 







(Mo, Da, Yr) 


04/18/2009 











issued. 








Line 

No. 







(a) 

(b) 

(c) 

1 

6,350,000 

2 

3 First and Refunding Mortgage Bonds Continued: 

4 Series 2008B 5.50 

400,000,000 

2,272,000 D 

5 

3,250,000 

6 Series 2008C 5.75 

500,000,000 

2,540,000 D 

7 

3,800,000 

8 

9 SUBTOTAL Account 221 

5,952,445,000 

78,283,900 

10 

11 Account 222 

12 Series 2005 A, B, & C 

Variable 

13 SUBTOTAL- Account 222 

14 


16 

17 

18 SUBTOTAL- Account 223 

19 


21 Other Long-Term Debt: 

22 

23 6.65% Notes 6.650 

300,000,000 

1,462,000 

24 3,615,000 D 

25 Ft. Irwin Loan 5.06 

7,734,000 

26 

27 

28 Pollution Control Indebtedness: 

29 

30 Four Corner Series 99-A 5.125 

55,540,000 

769,000 

31 381,004 D 

32 

33 TOTAL 6,779,019,000 89,563,404 







(Mo, Da, Yr) 


04/18/2009 











issued. 








Line 

No. 



(a) 

1 Calif Pol Cntrl Refunding Revenue 

2 Bonds 1999 A-D 

Variable 

3 

4 Clark County 2000A 

Variable 

5 Clark County 2000B 

Variable 

6 Clark County 2000C 

Variable 

7 

8 7 5/8% Notes 7.625 



(b) 

138,300,000 

40,000,000 

15,000,000 

20,000,000 

250,000,000 



(c) 

3,000,000 

318,000 

120,000 

162,000 

827,500 

9 625,000 D 

10 

11 Capitalized Interest Related to Nuclear Fuel 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

SUBTOTAL- Account 224 

826,574,000 

11,279,504 

33 TOTAL 6,779,019,000 89,563,404 







(Mo, Da, Yr) 


04/18/2009 

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



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, Premium 

on Debt - Credit. 

12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term 

advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid 

during 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 pledgee 


14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of 

year, 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 interest 

expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on 

Long-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. 

AMORTIZATION PERIOD 

Outstanding 

Line 

Nominal Date Date of 

(Total amount outstanding without Interest for Year 

No. 

of Issue Maturity Date From Date To 

reduction for amounts held by 

respondent) 

Amount 

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

1 

2 

01/14/04 1/15/14 01/14/04 1/15/14 

300,000,000 15,041,667 3 

4 

01/14/04 01/15/34 01/14/04 01/15/34 

525,000,000 31,587,500 5 

6 

03/01/04 03/01/09 03/01/04 03/01/09 

144,400,000 4,187,600 7 

03/23/04 04/01/15 03/23/04 04/01/15 

300,000,000 13,950,000 8 

9 

03/23/04 04/01/35 03/23/04 04/01/35 

350,000,000 20,125,000 10 

11 

12/13/04 12/13/07 12/13/04 12/13/07 

-409,285 12 

13 

1/19/05 1/15/16 1/19/05 

1/15/16 

400,000,000 20,055,556 14 

15 

1/19/05 1/15/36 1/19/05 

1/15/36 

250,000,000 13,913,542 16 

17 

6/27/05 7/15/35 6/27/05 

7/15/35 

350,000,000 18,777,014 18 

19 

3/23/05 4/1/10 

3/23/05 

4/1/10 

203,460,000 7,222,830 20 

8/31/05 8/1/35 

8/31/05 

8/31/35 

248,585,000 771,433 21 

1/31/06 2/1/36 

1/31/06 

2/1/36 

350,000,000 19,687,500 22 

23 

1/31/06 2/2/09 

1/31/06 

2/2/09 

150,000,000 4,851,117 24 

25 

4/12/06 4/1/28 

4/12/06 

4/1/28 

196,000,000 8,036,000 26 

27 

4/12/06 11/1/33 4/12/06 

11/1/33 

135,000,000 5,737,500 28 

29 

12/11/06 1/15/37 12/11/06 1/15/37 

400,000,000 22,261,667 30 

31 

1/22/08 2/1/38 

1/22/08 

2/1/38 

600,000,000 33,617,500 32 

6,379,731,347 302,890,095 

33 







(Mo, Da, Yr) 


04/18/2009 




















Line 



No. 



respondent) 

Amount 

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

1 

2 

3 

8/18/08 8/15/08 8/18/08 

8/15/18 

400,000,000 8,127,778 4 

5 

10/15/08 3/15/14 10/15/08 3/15/14 

500,000,000 6,069,444 6 

7 

8 

xxxxxxxxxx xxxxxxxxxx xxxxxxxxxx xxxxxxxxxx 

5,802,445,000 253,611,363 9 

10 

11 

-248,585,000 12 

-248,585,000 13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

04/01/99 04/01/29 04/01/99 04/01/29 

300,000,000 19,950,000 23 

24 

09/01/03 09/01/53 09/01/03 09/01/53 

7,031,347 356,907 25 

26 

27 

28 

29 

04/29/99 04/01/29 04/29/99 04/01/29 

55,540,000 2,846,425 30 

31 

32 

6,379,731,347 302,890,095 

33 







(Mo, Da, Yr) 


04/18/2009 




















Line 



No. 



respondent) 

Amount 

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

1 

09/01/99 09/01/31 09/01/99 09/01/31 

138,300,000 7,574,864 2 

3 

09/12/00 06/1/31 09/12/00 06/1/31 

40,000,000 1,584,379 4 

09/12/00 06/1/31 09/12/00 06/1/31 

15,000,000 365,621 5 

09/12/00 06/1/40 09/12/00 06/1/40 

20,000,000 487,500 6 

7 

01/15/00 01/15/10 01/15/00 01/15/10 

250,000,000 19,115,451 8 

9 

10 

xxxxxxxxxx xxxxxxxxxx xxxxxxxxxx xxxxxxxxxx 

-3,002,415 11 

12 

13 

14 

825,871,347 49,278,732 15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

6,379,731,347 302,890,095 

33 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Maturities and sinking fund requirements of long-term debts for the five years subsequent to December 31, 2007 will be $0 for 2008; $150,000,000 

for 2009; $250,000,000 for 2010; $0 for 2011; and $0 for 2012. 

Reacquisition expenses associated with long-term debt issues reacquired prior to maturity, including unamortized premium, discount and issuance 

expense pertaining to the retired indebtedness, are amortized over the remaining lives of the retired indebtedness when reacquired without refunding 

and over the lives of the new debt issues when reacquired with refunding. 

On December 11, 1997 SCE received the proceeds from the issuance of the rate reduction bonds from SCE Funding LLC. SCE issued a promissory 

note which is classified as a note payable on SCE’s financial statements. The terms of the note payable mirror the terms of the rate reduction bonds 

on the books of SCE Funding LLC. The note will be paid through the collection of a nonbypassable charge billed to SCE’s customers. This charge 

to customers is authorized by recent electric utility legislation (California Assembly Bill AB 1890). During 2007, collection of $246,300,000 

applied to the principal of the rate reduction bonds. Principal payments made in 2007 retired the SCE Funding LLC note payable. 

Schedule Page: 256.1 Line No.: 21 Column: a 

Maturities and sinking fund requirements of long-term debts for the five years subsequent to December 31, 2008 will be 

$150,028,000 for 2009; $250,027,000 for 2010; $12,000,000 for 2011; $0 for 2012 and $0 for 2013.. 

Reacquisition expenses associated with long-term debt issues reacquired prior to maturity, including unamortized 

premium, discount and issuance expense pertaining to the retired indebtedness, are amortized over the remaining lives of 

the retired indebtedness when reacquired without refunding and over the lives of the new debt issues when reacquired 

with refunding. 

During 2008, respondent capitalized a portion of interest expense on long-term debt for the purpose of financing the 

Company’s nuclear fuel inventory. For 2008 the capitalized interest expense totaled $3,002,415. 







(Mo, Da, Yr) 




04/18/2009 

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

1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show 

computation 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 for 

the 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 a 

separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group 

member, 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 of 

the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote. 

Line 

No. 

1 Net Income for the Year (Page 117) 

2 

3 

4 Taxable Income Not Reported on Books 

5 

6 

7 

8 

Particulars (Details) 

(a) 

9 Deductions Recorded on Books Not Deducted for Return 

10 

11 

12 

13 

14 Income Recorded on Books Not Included in Return 

15 

16 

17 

18 

19 Deductions on Return Not Charged Against Book Income 

20 

21 

22 

23 

24 

25 

26 

27 Federal Tax Net Income 

28 Show Computation of Tax: 

29 Federal Tax @ 35% 

30 

31 

32 Other Reserves/Adjustments/Credits 

33 

34 

35 Total Federal Tax 

36 

37 

38 

39 

40 Note in respose to item number 2 of FERC Schedule Instructions 

41 

42 

43 

44 

Amount 

(b) 

734,353,135 

139,396,920 

665,251,206 

67,734,923 

1,369,282,676 

101,983,662 

35,694,282 

35,694,282 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Taxable Income Not Recorded on Books: 

Base Revenue Requirement 145,280,897.65 

CIAC 1,449,899.46 

ITCC (4,018,310.00) 

NQ Decomm Trust Taxable 705,683.10 

Earnings 

Earnings of Utility Subs (4,242,572.20) 

Gross Revenue Sharing 

(0.01) 

Tracking Account 

Late Payment Charge 

200,321.82 

Revenue 

Leased Vehicles 21,000.00 

139,396,919.82 


Deductions Recorded on Books Not Deducted for Return: 

Accrued Vacation Pay 2,800,000.00 

Advanced Metering & 

13,204.50 

Demand 

Advanced Metering 

2,563,081.67 

Infrastructure M/A 

Interest Capitalized 56,686,776.95 

Qtrly Compl. Filings Audit 

87,401.33 

M/A (new in 12/06) 

Decomm Trust Earnings - 2,322,264.52 

Book 

Decomm expenses pd with (36,548,110.60) 

Qualified funds 

Decomm funds withdrawn 24,278,609.74 

from Qualified trust 

Deferred Credit (NEW IN (14,852,257.34) 

12/07) 

DSM - Low Inc Energy 

(5,275,884.77) 

Efficiency Program 

DOE Litigation M/A (new in (66,096.26) 

5/07) 

Easements (Quarterly) - 102,270,523.00 

NEW 09/08 

Exchange Energy Provision 4,492,239.12 

Stock Options - Expense 14,354,738.57 

Accrued to APIC 

Haz Waste Bal Acct. 138,813.37 

ITCC Deposits 193,927.65 

Legislative Expenses 

26,604,963.94 

Unallow. 

Misc Reg Liab / Asset (fka 71,346,417.41 

ECAC Bal Acc) 

Mohave Transition Costs 8,589.02 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Non Deductible Business 4,284,841.69 

Meals 

Nuclear Decomm. Adjust. 

208,757.62 

Mech. (NDAM) 

Nuclear Unit Def Charges 131,526.88 

Palo Verde Common 112,274.16 

Penalties 27,518,000.00 

Pension Reserves 25,940,559.24 

Refunding & Retirement of 53,964,269.19 

Debt 

Right of Way - APS 1,700,004.00 

Rollforward of Settled Federal (2,845,784.00) 

Audits 

LLC - 4,915,327.15 

Transmission Access Charge 12,756,676.62 

Balance 

Uncollectible Accts. Reserve 9,609,531.22 

Federal tax expense 275,536,020.56 

665,251,206.15 


Income Recorded on Books Not Included in Return: 

Agricultural Line Ext. M/A 144,113.77 

(new in 12/06) 

CARE Adjustment 26,464,370.68 

Catastrophic Memo Account (59,212,414.49) 

Catastrophic Memo Account 28,568,260.18 

(CEMA L/T) 

Corporate Life Insurance 10,571,802.25 

Proceeds 

Environmental Remediation (14,642,546.03) 

Environmental Remediation - (15,182.44) 

Below the line 

Family Energy Rate 

31,653.75 

Assistance 

Financial Reporting 

15,918,833.00 

Presentation Reserve 

Firm Transmission Rights 6,458,367.51 

(Balancing Acc) 

NQ Decomm Trust Taxable 3,483,641.13 

Earnings 

PBOP - Nontaxable Receipts 2,092,979.29 

Mountain View - Subsidiary 47,871,043.44 

Income After Tax 

67,734,922.04 


Deductions on Return Not Charged Against Book Income: 

Ad Val Lien Date Adj - 

4,711,450.84 

Electric 

Ad Val Lien Date Adj - Gas (576.00) 

Ad Val Lien Date Adj - (81,437.00) 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



OTHER 

Ad Val Lien Date Adj - Water (646.00) 

Ad Val Lien Date Adj - 

(394,208.00) 

Telecom 

AFUDC - Debt 26,600,098.06 

AFUDC - Equity 53,689,187.45 

Amortization of Debt Expense 810,297.24 

Base Rate Performance M/A (22,386,428.12) 

Bond Discount Amortization (185,000.00) 

Depreciation - BOOK Electric (1,009,981,729.49) 

Depreciation - BOOK Gas (186,533.96) 

Depreciation - BOOK Other (519,991.56) 

Depreciation - BOOK Water (496,647.28) 

Depreciation - BOOK 

(10,642,201.09) 

Telecom 

Depreciation - Cal Electric 1,334,912,724.00 

Depreciation - Cal Gas 278,569.00 

Depreciation - Cal OTHER 551,327.00 

Depreciation - Cal Water 998,812.00 

Depreciation - Cal Telecom 7,868,428.00 

Removal Costs - Electric 92,932,000.00 

Repair Allowance 58,612,000.00 

Capitalized Software - ERP 115,338,732.00 

(Flowthru) - NEW IN 11/07 

Capitalized Software - Others (42,717,826.73) 

- NEW IN 11/07 

Debt Issuance Cost 

(189,000.00) 

Amortization (new in 9/07) 

Energy Resource Recovery 405,871,339.22 

Account 

ESOP Dividend Payment 27,153,735.52 

Etiwanda Waste Water Line 28,000.00 

Executive Incentive Awards - 2,895,962.48 

ST 

Executive Incentive Awards - 3,355,116.55 

LT 

Executive Retirement 

105,730.19 

Provision 

Fixed Costs (Below the Line) 67,921,131.12 

Fixed Costs 13,253,342.88 

Severance Accruals 3,006,408.70 

Fuel Write-down - DFO 297,574.34 

GCAC 34,112.62 

Other Haz Sub Cleanup MA - 

362.83 

NEW 10/2007 

Interest on Tax 

65,236.77 

Deficiencies/Refunds 

Key Person Life Insurance 24,261,306.19 

Lease Acctng - PPBU - 

191,053.83 

Long-term 

Lease Acctng - PPBU - 

(191,053.83) 

Short-term 

LT Proc. Plan Tech 

72,324.10 

Assistance M/A (LTAMA) - 

new 5/08 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Mark to Market - Interest 

32,790,102.00 

Rate Lock (new in 9/07) 

MRTU (new in 12/07) 2,507,224.52 

NDSCMA - new 10/08 664.63 

New System Generation M/A 26,322,249.58 

- ST 

Nuclear Fuel Carrying Costs 3,002,415.08 

PBOP 63,810.52 

Project Devel Div. M/A (new 1,504,165.88 

in 12/06) 

Reserve for Injuries and 

3,027,191.63 

Damages 

Results Sharing M/A 207,467.03 

Right of Way Amort. 3,660,000.00 

Solar Photovoltaic Program 

720,584.44 

MA (SPVPMA) 

Stock Option Costs 13,072,621.58 

Uncollectible Accounts - 

863,895.11 

Damage Claim 

Uncollectible Accounts - OAR 8,738,218.35 

263a Adjustment (Quarterly) 61,139,986.00 

CCFT Lag - Electric Current (37,133,653.89) 

Year 

CCFT Lag - Electric Prior 85,887,485.27 

Year 

Manufacturer's Deduction - 4,256,164.00 

Sec. 199 

Preferred Dividend Deduction 809,000.00 

1,369,282,675.60 


The company files a consolidated tax return with its subsidiaries. The amounts set forth in this schedule have been 

determined on a separate return basis. Tax liabilities for each subsidiary listed below are determined and apportioned on 

a separate return basis and are included in the Equity Earnings of Subsidiary Companies on page 119 of this report 

Account 

418.130 Energy Services Inc. 837,658 

418.131 Contra Account Energy Services 

0 

Earnings 

456.913 Energy Services Inc. 0 

837,658 

418.135 Edison Material Supply 4,909,931 

418.136 Contral Account Edison Mission 

0 

Supply 

456.911 Edison Material Supply 0 

4,909,931 

418.140 Mono Power Co. 6,590 

418.141 Contra Account Mono Power Co. 0 

456.917 Mono Power Co. 0 

6,590 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



418.150 Southern States Realty Co. (8,749) 

418.151 Contra Account Southern States 

0 

Realty Co. 

456.915 Southern States Realty Co. 0 

(8,749) 

418.160 Conservation Financing Corp. (1,505,204) 

418.161 Contra Account Conservation 

0 

Financing Corp 

456.916 Conservation Financing Corp. 0 

(1,505,204) 

418.180 SCE Funding 5,488 

418.181 Contra Account SCE Funding 0 

456.918 SCE Funding 0 

5,488 

418.190 SCE Capital Company (3,050) 

418.191 Contra Account SCE Capital 

0 

Company 

456.919 SCE Capital Company 0 

(3,050) 

418.120 Mountain View Power 47,871,043 

418.121 Contra Account Mountain View 

0 

Power 

0 

47,871,043 

456.912 SCE UK Services 0 

0 







(Mo, Da, Yr) 


04/18/2009 

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 



1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during 

the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the 

actual, 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 other 

than 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. 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

BALANCE AT BEGINNING OF YEAR 

Taxes 

Taxes 

Charged 

Paid 

Taxes Accrued Prepaid Taxes 

During 

During 

(Account 236) (Include in Account 165) Year 

Year 

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

Kind of Tax 

(See instruction 5) 

FEDERAL TAXES: 

Federal Income Taxes 

Income Taxes 

Fed Ins Cont Act- Current 

Fed Ins Cont Act- Prior 

FICA/OASDI Emp Incntv 

FICA/HIT Emp Incntv 

Fed Unemp Tax Act- Current 

Superfund Tax 

SUBTOTAL- FED TAXES : 

STATE TAXES : 

CA Corp. Franchise Tax 

Income Tax- Arizona 

Income Tax- New Mexico 

Income Tax- Utah and 

Income Tax- DC 

Empl Tax-Arizona-Current 

CA SUI Current 

CA ET- Current 

SUI Florida-Current (EME) 

SUI Missouri 

SUI R.I. (Source) 

SUI WI 

EMOM MN SUI TAX 

SUI Mass- Current (EC) 

SOURCE KY SUI TAX 

ENOM NM SUI TAX 

ENOM IA SUI TAX 

ED. SUPPLY NV SUI TAX 

SUI TAX - NEVADA 

NV SUI TAX (SOURCE) 

SUI NEVADA - CURRENT 

SUI New York-Current 

SUI Texas- EMOM 

SUI Texas- Current 

5,586,273 

-55,860,082 

10,171 

5,886,337 

1,643,392 

33,957 

-42,699,952 

95,963,927 

698,687 

133,216 

-100 

-215,513 

92,019 

777 

16,065 

-1 

80,523 

-69 

30 

32,991,375 

53,403,956 

5,332,944 

1,341,230 

1,038,758 

94,108,263 

37,133,654 

860,752 

378,135 

200 

2,707,294 

109,930 

1,012 

31,696 

729 

Adjustments 

-160,627,473 -131,373,008 

266,364,051 

-53,308,299 -30,716 

-5,389,923 

-1,371,578 

-1,048,651 -3,760 

-221,745,924 134,956,567 

-74,815,039 

-2,091,495 

-810,447 -500 

-100,575 

-2,739,039 -1,942 

-526 

-116,574 -3,744 

-780 -233 

-1,554 

1 

-753 -210 

-30 

41 TOTAL 

54,865,494 

-3,502,357 

351,050,284 -390,008,635 57,058,341 







(Mo, Da, Yr) 


04/18/2009 













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 

32 

33 

34 

35 

36 

37 

38 

39 

40 


Taxes 

Taxes 

Charged 

Paid 


During 

During 


Year 

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

Kind of Tax 


SUI OK- Current (EC) 

SUI OR-Current (Source) 

SUI Virginia-Current 

STATE TAXES (cont): 

ACCD SUI TAX - WASH D.C. 

D.C. SUI TAX -EME 

SUI Tax DC-Current 

SUI W. Vir-Current(EME) 

HOMER CITY PA SUI 

EME FS. PA SUI TAX 

EMMT PA SUI TAX 

PA SUI TAX MOMI 

SUI Pennsylvania-Current 

MWG IL SUI TAX 

MG EME IL SUI TAX 

EME SERVICES IL SUI TAX 

EMMT IL SUI TAX 

SUI ILLINOIS MEC 

SUI Illinois-Current(Source) 

SUI Georgia-Current(Source) 

SUI NJ-Current(Source) 

NY SUI TAX - EMMT 

SUI Colo-Current(Source) 

SUI Hawaii- Current(Source) 

SUI Idaho- Current (Source) 

SUI N Mex-Current(Source) 

SUI Wash-Current(Source) 

WY SUI TAX - EMOM 

SUI Wyoming-Current 

SUI MI-Current(Source) 

SUI South Carolina 

SUI CT (Select) 

SUI IA O&M 

SUI IAX 

MA Hlth INS TX - EMMT 

SF Pyrl Exp Tx - SCE 

EMG Pyrl Tax Pay Recl 

CADI Vol Plan Assess 

Use Tax-Arizona-Prior 

-1 

610 

25,291 

-61 

3 

88 

48 

-1,249 

1,461 

6,956 

61,232 

669,504 

-1,407 

Adjustments 

-6,936 -20 

-64,332 2,095 

-669,497 -6,909 

1 

-6 

276 

-88 

-48 

1,249 

-172 

10,642 

23,237 

-664,599 

41 TOTAL 

54,865,494 

-3,502,357 

351,050,284 -390,008,635 57,058,341 







(Mo, Da, Yr) 


04/18/2009 













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 

32 

33 

34 

35 

36 

37 

38 

39 

40 


Taxes 

Taxes 

Charged 

Paid 


During 

During 


Year 

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

Kind of Tax 


Use Tax-Arizona-Current 

Use Tax-California-Prior 

Use Tax-California-Current 

Use Tax-New Mexico-Prior 

SALES TAX ACCRUED 

Sales Tax Payable - CA 

Sales Tax Payable - District 

Sales Tax-O&M Services 

Accrued District/Local use CA 

Sales Tax Accrued/ Contra 

SUBTOTAL-STATE TAXES: 

LOCAL TAXES: 

Property Tax-Ariz Current 

Property Tax-Ariz Prepaid 

Property Tax-Calif Current 

Property Tax-Calif Prepaid 

Property Tax-D.C. Current 

Property Tax-Nevada Current 

Property Tax-Nevada Prepaid 

Property Tax-N Mex Current 

Property Tax-N Mex Prepaid 

Accrued Tax Liab.Not 

Charged to Inc. 

Hazardous Waste 

Use Tax-Nevada-Prior 

Use Tax-Nevada-Current 

Use Tax-LA County-Prior 

Use Tax- LA County Current 

Use Tax-Nuclear Fuel 

SUBTOTAL- LOCAL TAXES 

48,044 

620,768 

68,349 

97,531,451 

32,533 

1,462 

33,995 

-3,308,631 

-193,726 

-3,502,357 

8,566,892 

44,500,168 

6,602 

509 

33,310 

95,070,036 

5,588,097 

2,307,840 

120,534,391 

25,693,498 

93,500 

645,152 

5,034,635 

1,693,750 

372 

280,750 

161,871,985 

Adjustments 

-4,131,802 31,405 

-1,827 

-283 

-4,782 

-214,451 

-69,547 

-8,550,013 -77,901,228 

-7,936,161 2,348,064 

-777 -2,307,063 

-144,121,747 23,587,357 

-23,587,357 

-89,727 -3,773 

-520,428 -60,128 

-6,754,290 1,719,655 

-372 

-289,196 

-1,693,750 

-3 

-159,712,698 3,002 

41 TOTAL 

54,865,494 

-3,502,357 

351,050,284 -390,008,635 57,058,341 







(Mo, Da, Yr) 


04/18/2009 

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 



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 adjustments 

by parentheses. 

7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending 

transmittal 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 409.1 

pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and 

amounts 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. 

BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED 

(Taxes accrued Prepaid Taxes 

Electric Extraordinary Items Adjustments to Ret. 

Other 

Account 236) (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Earnings (Account 439) 

(g) (h) (i) (j) (k) (l) 

1 

2 

-253,422,833 89,140,667 

-56,149,292 3 

210,503,968 4 

75,111 53,403,956 

5 

6 

5,829,358 5,332,944 7 

1,613,044 1,341,230 8 

20,304 1,038,758 9 

10 

11 

-35,381,048 142,544,623 

-48,436,360 12 

13 

14 

15 

58,282,542 50,124,564 

-12,990,910 16 

-532,057 860,752 

17 

-299,596 378,135 

18 

100 200 

19 

-316,088 20 

21 

22 

58,333 2,707,294 

23 

24 

25 

26 

27 

28 

251 109,930 29 

5,676 30 

31 

1,012 32 

33 

34 

35 

36 

110,665 31,696 37 

38 

-303 729 39 

40 

Line 

No. 

70,794,744 

-1,331,620 391,190,462 -40,140,176 

41 







(Mo, Da, Yr) 


04/18/2009 

















Other 


(g) (h) (i) (j) (k) (l) 

1 

2 

3 

4 

5 

54 1,461 6 

7 

6,956 8 

9 

10 

11 

12 

-396 61,232 13 

14 

15 

16 

17 

18 

18,389 669,504 19 

20 

-61 21 

-6 22 

23 

24 

25 

26 

27 

276 28 

29 

3 30 

31 

32 

33 

34 

-172 35 

10,642 36 

23,237 37 

-664,599 38 

39 

40 

Line 

No. 

70,794,744 

-1,331,620 391,190,462 -40,140,176 

41 







(Mo, Da, Yr) 


04/18/2009 

















Other 


(g) (h) (i) (j) (k) (l) 

1 

2 

4,514,538 8,566,893 3 

4 

44,906,486 44,500,168 

5 

4,776 6 

227 6,602 7 

-1,198 33,310 8 

28,527 9 

509 10 

11 

106,150,246 98,571,113 

-3,501,076 12 

13 

14 

15 

5,572,317 15,780 16 

2,302,849 4,992 17 

1 112,100,387 

8,434,004 18 

-1,202,490 23,029,260 

2,664,238 19 

20 

81,906 11,594 21 

-129,130 592,205 

52,947 22 

4,745,977 288,658 23 

1,649,825 43,925 24 

25 

26 

32,530 27 

28 

372 29 

30 

-6,985 280,750 31 

32 

33 

25,546 -1,331,620 

150,074,726 

11,797,260 34 

35 

36 

37 

38 

39 

40 

Line 

No. 

70,794,744 

-1,331,620 391,190,462 -40,140,176 

41 




the average period over which the tax credits are amortized. 

Line Account Balance at Beginning 

No. Subdivisions 

of Year 

(a) 

(b) 




(Mo, Da, Yr) 


04/18/2009 

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) 



Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and 

nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) 

Allocations to 

Deferred for Year 

Current Year's Income 

Adjustments 

Account No. Amount Account No. Amount 

(c) 

(d) (e) (f) (g) 

1 Electric Utility 

2 3% 

3 4% 

4 7% 

5 10% 

6 

7 

104,937,659 410/411 4,011,700 

264 

8 TOTAL 104,937,659 4,011,700 

264 

9 Other (List separately 

and show 3%, 4%, 7%, 

10% and TOTAL) 

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 






(Mo, Da, Yr) 



04/18/2009 

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




of Year 

(h) 

Average Period 

of Allocation 

to Income 

(i) 

ADJUSTMENT EXPLANATION 

100,926,223 25 7 

100,926,223 8 

Line 

No. 

1 

2 

3 

4 

5 

6 

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 




Line 

No. 

Description and Other 

Deferred Credits 

(a) 




(Mo, Da, Yr) 


04/18/2009 

OTHER DEFFERED CREDITS (Account 253) 

Balance at 


(b) 

Contra 

Account 

(c) 

DEBITS 

Amount 

(d) 

Credits 

(e) 



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 $10,000, whichever is greater) may be grouped by classes. 

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 

Balance at 

End of Year 

Advance on Jobbing Accounts 97,744,135 Various 

117,270,817 129,933,384 

110,406,702 

Miscellaneous 

Deferred Credits 50,251,493 Various 

58,204,766 56,928,397 

48,975,124 

Unclaimed Checks and Drafts 17,280 930.2 

32,438 

15,158 

Miscellaneous Work In Progress 204,188,652 186 

221,413,707 224,313,344 

207,088,289 

Lease Payable - Long-Term 64,377,067 555 

7,753,662 

56,623,405 

Income Tax Component of 181,025,282 Various 

1,700,950,939 1,704,479,230 

184,553,573 

Contributions in Aid of 

Construction 

SONGS 1 Decommissioning - 

amount to be amortized over a 21 

year period beginning January 1993 

to December 2013. 186 

430,033,328 430,033,328 

Environmental Remediation 38,112,801 186 

120,172,806 125,606,937 

43,546,932 

(f) 

47 TOTAL 635,716,710 

2,655,832,463 2,671,309,778 

651,194,025 







(Mo, Da, Yr) 




04/18/2009 

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

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable 

property. 

2. For other (Specify),include deferrals relating to other income and deductions. 

Line 

No. 

CHANGES DURING YEAR 

Account 

Balance at 


Amounts Debited 

Amounts Credited 

to Account 410.1 to Account 411.1 

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

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 







(Mo, Da, Yr) 




04/18/2009 

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

3. Use footnotes as required. 


ADJUSTMENTS 

Amounts Debited Amounts Credited 

Debits 

Credits 

Balance at 

to Account 410.2 to Account 411.2 Account 

Amount 

Account 

Amount 

End of Year 

Credited 

Debited 

(e) (f) (g) 

(h) (j) 

(i) 

(k) 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

NOTES (Continued) 







(Mo, Da, Yr) 




04/18/2009 

ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282) 

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not 

subject to accelerated amortization 



Line 

Account 

Balance at 

No. 


Amounts Debited 

Amounts Credited 


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

1 Account 282 

2 Electric 1,594,968,509 166,985,322 

3 Gas 

4 

5 TOTAL (Enter Total of lines 2 thru 4) 1,594,968,509 166,985,322 

6 

7 

8 

9 TOTAL Account 282 (Enter Total of lines 5 thru 1,594,968,509 166,985,322 


11 Federal Income Tax 1,594,968,509 166,985,322 



NOTES 






(Mo, Da, Yr) 



04/18/2009 

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





ADJUSTMENTS 


Debits 

Balance at Line 

Credits 


Amount 

Account 

Amount 

End of Year No. 

Credited 

Debited 

(e) (f) (g) 

(h) (j) 

(i) 

(k) 

1 

Various 19,609,127Various 11,031,215 1,753,375,919 2 

3 

4 

19,609,127 11,031,215 1,753,375,919 5 

6 

7 

8 

19,609,127 11,031,215 1,753,375,919 9 

10 

19,609,127 11,031,215 1,753,375,919 11 

12 

13 








(Mo, Da, Yr) 




04/18/2009 

ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283) 

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts 

recorded in Account 283. 



Line 

Account 

Balance at 


No. 



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

1 Account 283 

2 Electric 

3 See Detail Attached 

2,219,957,573 

241,601,268 

96,084,906 

4 

5 

6 

7 

8 

9 TOTAL Electric (Total of lines 3 thru 8) 

10 Gas 

11 See Detail Attached 

12 

13 

14 

15 

16 

17 TOTAL Gas (Total of lines 11 thru 16) 

18 Other (See Detail Attached) 

19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 


21 Federal Income Tax 



2,219,957,573 

380,029 

380,029 

191,295,056 

2,411,632,658 

2,411,632,658 

241,601,268 

13,695 

13,695 

42,446 

241,657,409 

241,657,409 

96,084,906 

41,734,626 

137,819,532 

137,819,532 

NOTES 







(Mo, Da, Yr) 




04/18/2009 

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

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



ADJUSTMENTS 


Debits 

Credits 

Balance at Line 


Amount 

Account 

Amount 


Credited 

Debited 

(e) (f) (g) 

(h) (i) 

(j) (k) 

1 

2 

Various 969,523,397 Various 

782,618,800 2,178,569,338 3 

969,523,397 782,618,800 2,178,569,338 9 

Various 103,326 Various 

59,397 

349,795 11 

103,326 59,397 

349,795 17 

Various 1,923,555 Various 

17,695,481 

165,374,802 18 

971,550,278 800,373,678 2,344,293,935 19 

971,550,278 800,373,678 2,344,293,935 21 

4 

5 

6 

7 

8 

10 

12 

13 

14 

15 

16 

20 

22 

23 








FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Account 

Sub- 

Balance at 

Division Description End of Year 

ELECTRIC: 

283.100 283.100 ECAC 

283.105 283.105 Acc Def Inc Tax - AMT 

283.108 283.108 SONGS 1 Settlement 

283.112 283.112 Balancing Account Overcollection 

283.116 283.116 Marine Mitigation 

283.119 283.119 Acc Def Inc Tax - TCF Inct Song 

283.120 283.120 Acc Def Inc Tax - TCF Songs 2 

283.122 283.122 Acc Def Inc Tax - TCF PV1 

283.126 283.126 Bilateral Energy Balancing Account 

283.133 283.133 EDRA 

283.138 283.138 Direct Access Memo Acct. 

283.139 283.139 Transition Cost Audit 

283.142 283.142 Payroll Tax 

283.143 283.143 Rfundable Recvbl-Line Ext 

283.144 283.144 Electric Vehicles 

283.145 283.145 DOE Decont & Decomm 

283.150 283.150 Acc Def Inc Tax - CLMAC 

283.200 283.200 Acc Def Inc Tax - Other Inc 

283.203 283.203 Mohave Transition Costs 

283.205 283.205 Unbilled Revenues 

283.209 283.209 SONGS Nuc DBD Costs 

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

- 

- 

- 

(267,271,686) 

(4,590,842) 

- 

- 

1,024,377 

- 

5,544,490 

- 

- 

(1,643,975) 

324,931 

- 

16,163,972 

- 

- 

(175,799) 

-






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.212 283.212 OPAC / 263A Adjustment 

(1,667,805) 

283.214 283.214 Ad Valorem Lien Date Electric 

(6,707,160) 

283.215 283.215 AFUDC Equity Gross Up 

(47,850,718) 

283.221 283.221 CIAC - Deferred Rev 

(187,246,936) 

283.227 283.227 Depreciation-Elect 

88,682,469 

283.235 283.235 Removal Cost 

(1,020,634,466 

) 

283.236 283.236 Repair Allowance 

(67,205,617) 

283.238 283.238 Right of Way Amort 

(47,719,498) 

283.239 283.239 Salvage Warehouse 

(2,458,455) 

283.245 283.245 Unreal Gains - Decomm 

- 

283.246 283.246 Capitalized Software - Tax Basis 

(69,476,867) 

283.247 283.247 Capitalized Software 

56,332,987 

283.259 283.259 Capitalized Software Costs - ERP 

(131,901,194) 

283.266 283.266 Uncollectible Damage Claim 

(163,909,489) 

283.275 283.275 Def Tax - Gross Rev Shar Trck 

- 

283.276 283.276 GRC Poles 

- 

283.284 283.284 Depr - Coal & Hydro Incre 

- 

283.285 283.285 GRC GTAC & AGTAC 

- 

283.286 283.286 Block Forward Purchase Power Contract 

283.287 283.287 Health & Safty Reward 

283.288 283.288 Firm Transmission Right 

283.289 283.289 Deferred Tax - PEEBA 

- 

0 

(5,218,980) 

7,658,487 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.290 283.290 Acc Def Inc Tax - Palo Ver Reas 

20,903,590 

283.303 283.303 PX/ISO Delay Memo Acct 

- 

283.304 283.304 Perf Based Memo Acct 

- 

283.305 283.305 Calif Solar Intiative Prog M/A 

(21,877,789) 

283.318 283.318 Nuc Unit Deferred Chgs 

101,522,564 

283.320 283.320 ARAM Grossup R/A - By Stn 

(1,264,064) 

283.323 283.323 ITC Reg Asset - By Stn 

- 

283.324 283.324 Normalized Tax - ITC 

- 

283.325 283.325 Radio Frequency 

11,305,941 

283.326 283.326 NQ Decomm Trust Earngs-Book 

(5,275,494) 

283.327 283.327 Contribution to Qualified Decommissioning Trust 

283.340 283.340 Normalized Plant - By Stn 

283.343 283.343 F/T Rg Asset - By Stn 

283.362 283.362 MERMA - DIT - Mohave Emp Related M/A 

283.367 283.367 Advanced Metering Infrastructure M/A 

283.376 283.376 Hazardous Waste B/A 

283.383 283.383 Ad Val Ln Dt R/A - By Stn 

283.384 283.384 Norm Ad Val Ln Dt - By Stn 

283.385 283.385 DIT - His Procurement Chrg B/A 

283.386 283.386 DIR - RES Gen Rev Shortfall M/A 

283.388 283.388 TCBA - Employee Rel Subacct 

283.389 283.389 Transmission Rev Bal Acct 

(35,825,745) 

(4,027,266) 

(122,366,336) 

- 

(0) 

0 

(2,517,985) 

- 

(2,289,880) 

4,375,198 

(0) 

- 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.390 283.390 Collab Environ Remed (410.181) 

12,351,259 

283.393 283.393 DIT - SFAS 158 - Long Term 

(829,773) 

283.395 283.395 Non-Collab Envir Remed (410.181) 

286,045 

283.398 283.398 Normalized Tax - ARAM 

- 

283.402 283.402 RRB Amortization 

77,625 

283.403 283.403 Risk Mgt Tools Memo Acct 

8,073,128 

283.404 283.404 Power Exchng Rev. M/A 

(0) 

283.405 283.405 Acc Def Inc Tax - CEMA 

- 

283.406 283.406 Unavoid Fuel Contrct Cst Memo 

(3,084,489) 

283.407 283.407 GRC Marine Mitigation Acct. 

- 

283.408 283.408 Operative CWIP Book Basis 

- 

283.412 283.412 Investment in Excess of Cost 

- 

283.417 283.417 Late Account Payment Charge 

(29,503,605) 

283.419 283.419 DIT on A/C Cycling Bal Acct 

(92,868) 

283.420 283.420 Electric Energy Transaction Admin 

(0) 

283.421 283.421 Advance Metering & Demand 

0 

283.423 283.423 Transmission Access Chrg B/A 

(87,529) 

283.424 283.424 Real Time Meter Memo Acct 

(8,285,581) 

283.427 283.427 CARE Balancing Account 

(1,691,114) 

283.432 283.432 Other Dist Adj Mech (ODAM) 

(11,558,804) 

283.433 283.433 Pub Purp Prg Adj Mech (PPPAM) 

(0) 

283.434 283.434 Acc Def Inc Tax - FERABA 

1,466,597 

- 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.435 283.435 Duke Settlement 

283.436 283.436 Energy Resrc Recov Acct (ERRA) /5/ 

0 

283.443 283.443 Base Revenue Requirement BA 

(5,416,926) 

283.448 283.448 Base Revenue Requirement DIT 

- 

283.453 283.453 Reliability Service BA 

(70,441,258) 

283.454 283.454 SRBA Rec Costs - Def Tax 

8,272,714 

283.455 283.455 Proact Interest - Def Tax 

- 

283.460 283.460 Def Tax - QF Power Cntrcts /3/ 

- 

283.461 283.461 ESMA - Balancing Account 

- 

283.462 283.462 ESMA - Pacificorp Settlement 

13,310,238 

283.463 283.463 ESMA - Williams 

(3,738,828) 

283.464 283.464 ESMA - Duke 

(2,835,420) 

283.465 283.465 DIT - ESMA - Mirant Settlement 

(3,818,302) 

283.466 283.466 DIT - ESMA - Reliant Settlement 

(37,095,584) 

283.467 283.467 DIT - ESMA - Enron Settlement 

(45,652,990) 

283.468 283.468 DIT - ESMA - IdaCorp Settlement 

- 

283.469 283.469 DIT - ESMA - PS Colorado Settlement 

- 

283.470 283.470 DIT - PCBA 

(830,417) 

283.471 283.471 DIT - Post Emplmnt - Not PCBA 

3,912,644 

283.472 283.472 DIT - RSMA 

12,928,326 

283.473 283.473 DIT - Mohave Balancing Acct 

(83,290) 

283.474 283.474 Direct Access Customer Charge Revenue M/A 

283.475 283.475 Def Tax - RDRMA 

4,350,457 

- 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.476 283.476 DIT - Agricultural Line Ext M/A 

- 

283.477 283.477 DIT - Proj Devel Div M/A 

(131,076) 

283.478 283.478 DIT - Qtrly Compl Filing Aud M/A 

(1,569,716) 

283.479 283.479 DIT - Reliability Costs M/A 

(21,298) 

283.481 283.481 DIT - Affiliate Transfer Fee M/A 

0 

283.482 283.482 DIT - RD&D Royalties M/A 

76,552 

283.484 283.484 DOE Litigation M/A 

10,133 

283.488 283.488 Peaker Gen Memo Acct 

(106,373) 

283.489 283.489 Other Haz Sub Cleanup MA 

0 

283.495 283.495 New System Generation M/A 

(6,179) 

283.496 283.496 MRTU 

(15,138,124) 

283.500 283.500 DIT AIMMA 

(2,071,679) 

283.525 283.525 Palo Verde Common 

1,000 

283.644 283.644 ADIT DSMAC 5% 

(770,007) 

283.700 283.700 Mark to Market - Interest Rate Lock 

0 

283.702 283.702 LISAC Undercollection 

- 

283.731 283.731 Acc Def Inc Tax Call Premiums 

- 

283.800 283.800 ADIT-PBOP 

(107,573,240) 

283.900 283.900 TRA-86 Rate Differential 

- 

283.901 283.901 1996 State Rate Change 

- 

283.905 283.905 1988 Tx Rate Diff-Elect 

- 

283.910 283.910 Miscellaneous 

- 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.960 283.960 Non Collab Env (410.181/410.101) 

- 

283.961 283.961 Collab Env (410.181) 

0 

283.970 283.970 Reg Asset - True Up 

0 

283.000 283.000 Lease Acctng - PPBU - Short-term 

142,067 

283.000 283.000 NDSCMA - new 10/08 

1,419,457 

283.000 283.000 Solar Photovoltaic Program MA (SPVPMA) 

283.262 283.262 Lease Acctng - PPBU - Long-term 

283.301 283.301 Misc Reg Liab/Asset (fka ECAC Bal Acct) 

283.502 283.502 LT Proc. Plan Tech Assistance M/A (LTAMA) 

283.669 283.669 Catastrophic Memo Account (CEMA L/T) 

(267) 

(289,286) 

(1,419,457) 

28,642,733 

(29,035) 

(11,469,014) 

190.000 190.000 Solar Investment Tax Credit - Basis Adj (-963,743) 

Total Electric (2,178,569,338) 


GAS & OTHER INCOME 

283.211 283.211 Lien Date - Gas (a) 

(15,197) 

283.228 283.228 Depreciation - Gas (a) 

(234,950) 

283.300 283.300 GCAC (a) (410.110) /4/ 

(99,648) 

Total Gas 

(349,795) 


283.109 283.109 Acc Def Inc Tax - ECAC FICC 

283.113 283.113 Songs 2&3 TCF Reward 

283.127 283.127 FOPL Depn (417.560) 

283.213 283.213 Lien Date - Water 

283.226 283.226 Depreciation - Other (410.200) 

283.229 283.229 Depreciation - Water 

283.242 283.242 Exec Retire Prov (410.200) 

283.243 283.243 EPTC Dominion over Proceeds 

283.257 283.257 Capital Loss Carryover 

283.258 283.258 Capitalized Software - Normalized 


- 

- 

- 

(42,185) 

(101,190,166) 

207,023 

(1,105,855) 

(0) 

(60,899,146)






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



283.283 283.283 Def Tax - Depreciation - Telecom 

283.295 283.295 Def Tax on Reg Asset - Telecom /1/ 

283.416 283.416 Unamort Loss on Plant Disp (410.200) /2/ 

283.553 283.553 ENVEST Bad Debt Exp (417.550) 

283.557 283.557 ENVEST Warranty Exp (417.550) 

283.205 283.205 Unbilled Revenues 

283.320 283.320 ARAM Grossup R/A - By Stn 

283.323 283.323 ITC Reg Asset - By Stn 

283.324 283.324 Normalized Tax - ITC 

283.398 283.398 Normalized Tax - ARAM 

283.644 283.644 DSM Incentive 

283.900 283.900 TRA-86 Rate Differential 

283.905 283.905 1988 Tx Rate Diff-Elect 

283.910 283.910 Miscellaneous 

Total Other 

2,398,944 

(4,934,429) 

6,976 

(0) 

170,548 

13,489 

- 

- 

- 

- 

- 

0 

- 

- 

- 

(165,374,802) 







(Mo, Da, Yr) 




04/18/2009 

OTHER REGULATORY LIABILITIES (Account 254) 

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 $50,000 which ever is less), may be grouped 

by classes. 

3. For Regulatory Liabilities being amortized, show period of amortization. 

Balance at Begining 

Line Description and Purpose of 

DEBITS 


of Current 

of Current 

No. Other Regulatory Liabilities 

Account Amount 

Credits 

Quarter/Year 

Credited 

Quarter/Year 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 

2 Research Development and Demonstration 604,651 407 

1,133,777 632,127 

103,001 

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 

1 

2 

3 

4 

Balancing Account 

-To track Commission authorized funding and re- 

cord the difference between revenues and costs 

associated with RD&D. 

Demand Reduction and Self-Generation Program 

Incremental Cost (DRSGPIC) Memorandum Account 

-To track the recorded incremental program costs 

and distribution revenue requirement recorded in 

the Base Revenue Requirement Balancing Acct 

(BRRBA) associated with SCE's Small Commercial 

Demand Responsiveness Pilot Program and the 

Self-Generation Pilot Program authorized by the 

CPUC. 

101,937,762 Various 

12,129,081 24,799,617 114,608,298 

Demand Side Management Adjustment Clause 6,697,074 407 

113,527 331,520 

6,915,067 

Balancing Accounts 

-To track Commission authorized funding and 

record the difference between revenues and costs. 

Energy Efficiency Program Adj. Mechanism 

-To track the Public Purpose Program Charge 

Funds allocable to the 1998 energy efficiency 

programs/expenses, and establish the Energy 

Efficiency Program Incentive procedure. 

Low Income Program Adjustment Mechanism 

-To track the Public Purpose Program Charge Funds 

allocable to the 1998 low income programs, and 

the 1998 low income energy efficiency program 

expenses. 

Insurance Settlements 

-Ratepayer portion of environmental insurance 

settlements. 

Pension Regulatory Liability 

-To record the cumulative difference between pen- 

115,982,122 Various 

30,488,458 22,993,502 108,487,166 

( 47,610) Various 

13,630,816 8,354,931 

-5,323,495 


290,410 8,450 

8,450 

74,987,000 4,463,000 70,524,000 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 

FERC FORM NO. 1/3-Q (REV 02-04) Page 278.1



Line 

No. 






(Mo, Da, Yr) 


04/18/2009 


DEBITS 

Account 

Credited 

Amount 

(c) 

(d) 

Credits 

(e) 




applicable. 


by classes. 


(a) 

5 sion expense calculated for ratemaking purposes 

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 

1 

2 

3 

4 

5 

6 

7 

8 

and the amount calculated for accounting purposes 

since implementation of SFAS 87 in 1987. The 

over-collected balance results from the 

ratemaking calculation exceeding the accounting 

calculation during this period of time. 


of Current 

Quarter/Year 

(b) 


of Current 

Quarter/Year 

(f) 

Electric Deferred Refund Account 13,810,816 182 

13,897,036 10,961,260 

10,875,040 

-To reflect refund of various disallowances with 

interest incurred through December 31,1996 to 

ratepayers as per Advice Letter No. 1280-E. 

Procurement Energy Efficiency Balancing Acct. 52,068,924 407 

50,422,631 16,677,390 

18,323,683 

-To track the difference between actual incremen- 

tal procurement related energy efficiency costs 

and authorized procurement related energy 

efficiency revenues per D.03-12-062. 

Energy Settlements Memorandum Account (ESMA) 

-To record refund amounts received by SCE 

resulting from FERC investigation settlement 

agreements associated with wholesale power 

purchases made on behalf of SCE's bundled 

service customers, net of litigation costs re- 

corded in the litigation Costs Tracking Account. 


To record the difference between SCE's 

distribution, generation, and recorded revenue 

requirements and other amounts authorized by the 

Commission. 

Asset Retirement Obligation (ARO) 

-To establish a regulatory liability for 

decommissioning costs collected in rates 

for ARO assets. 

Historical Procurement Charge Balancing Account 

-To record the portion of the Procurement Related 

Obligation Account (PROACT) balance that 

Direct Access customers are responsible for 

33,154,581 Various 

35,948,309 16,783,621 

13,989,893 

Various 

276,636,060 324,724,576 

48,088,516 

792,696,441 Various 

1,126,557,192 109,847,748 -224,013,003 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 




Line 

No. 






(Mo, Da, Yr) 


04/18/2009 


DEBITS 

Account 

Credited 

Amount 

(c) 

(d) 

Credits 

(e) 




applicable. 


by classes. 


(a) 

9 paying and Historical Procurement Charge 

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 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

revenues. 

Transmission Rev Balancing Acct Adj. 

-To record transmission revenue credits, 

congestion revenue, wheeling revenue, sale of an 

FTR revenue, and ancillary service expense to 

the TRBAA. 

Bilateral Energy & Gas Financial Instruments - 

Short Term 


to the short term financial instruments used 

to hedge power purchases and natural gas 

costs for tolling. 

Gross Revenue Sharing Mechanism 

-To record the customer's share of certain Other 

Operating Revenue (OOR), as per Advice Letter 

No. 1413-E-A, dated September 16, 1999. 

Nuclear Decommissioning Adj. Mechanism 

-To record NDAM revenue, authorized and recorded 

costs related to the decommissioning of San 

Onofre Nuclear Generating Station and Palo 

Verde Nuclear Generating Station. 

Unbilled Revenue 

-To record FERC ratemaking related unbilled 

revenue. 

Exchange Energy 

To record non-cash related energy costs not 

involving the transfer of cash between SCE and 

third parties 

FTR Costs 

-To amortize the Firm Transmission Rights 

costs paid to the California Independent 

System Operator (CAISO). 

(Amortization Period: 04/2006-1/2008) 


of Current 

Quarter/Year 

(b) 


of Current 

Quarter/Year 

(f) 

30,765,852 Various 

22,847,609 82,009,596 

89,927,839 

3,240,806 Various 

270,874,128 267,633,322 

Various 

Various 

12,791,371 12,791,371 

510,822 1,174,347 

663,525 

8,134,385 8,189,984 

55,599 

19,076,587 Various 

94,014,573 87,556,205 

12,618,219 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 




Line 

No. 






(Mo, Da, Yr) 


04/18/2009 


DEBITS 

Account 

Credited 

Amount 

(c) 

(d) 

Credits 

(e) 




applicable. 


by classes. 


(a) 

13 

14 

15 

16 Safety and Reliability Incentive Mechanism Acct. 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

-To record SCE's Service Quality Performance 

Rewards earned and/or penalties assessed as per 

Advice Letter No. 1882-E. 


of Current 

Quarter/Year 

(b) 


of Current 

Quarter/Year 

(f) 

2,282,607 55,112 

2,337,719 

Transmission and CPUC Related Ratemaking 11,036,346 182 

11,531,940 17,999,250 

17,503,656 

-Reclassification of ancillary service amounts 

and ESMA - Net Litigation Costs to a liability 

account. 

Energy Agreements Regulatory Account 

and Miscellaneous Regulatory Account 

-To capture various accrued purchased power 

agreements & other miscellaneous Regulatory 

Liabilities 

Bilateral Energy & Gas Financial Instruments - 

Long Term 

-To record the mark-to-market adjustments 

related to the long term financial instruments 

used to hedge power purchases and natural 

gas costs for tolling. 

CARE Balancing Account 

-To reflect in rates, through application of the 

Public Purpose Program Charge the costs 

associated with the CARE Program as 

authorized in various CPUC Decisions. 

( 40,362,327) Various 

40,702,772 81,065,104 

5 

20,741,850 Various 

226,707,886 205,966,036 

Demand Response Program Balancing Account 21,914,226 407 

9,794,730 9,755,033 

21,874,529 

(DRPBA) 

-To record the difference between the actual 

capital related revenue requirement and O&M costs 

incurred by SCE and the authorized Demand 

Response Revenue Requirement approved by the 

Commission in D.06-03-024 and in SCE's 

General Rate Case (GRC) proceedings. 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 




Line 

No. 






(Mo, Da, Yr) 


04/18/2009 


DEBITS 

Account 

Credited 

Amount 

(c) 

(d) 

Credits 

(e) 




applicable. 


by classes. 


(a) 

17 

18 

19 Direct Access Customer Charge Revenue Memorandum 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

Account (DACCRMA) 

-To record and track the revenue associated with 

the $5.00 Direct Access Customer Charge (DACC). 

California Solar Inititative Program Bal Acct. 

To track the recorded incremental California 

Solar Initiative Program costs and authorized 

distribution revenue requirement recorded in the 


(BRRBA) associated with SCE's California 

Solar Initiative Program. 

Results Sharing Memorandum Account (RSMA) 

-To track the difference between authorized and 

recorded Results Sharing expenses paid out. 

Energy Resource Recovery Account 

-To record SCE's ERRA Revenue, Utility 

Retained Generation fuel costs, and purchased 

power related expenses. 

Pension Costs Balancing Account 

-To record the difference between pension costs 

authorized by the Commission, and recorded 

pension expenses. 

Post Employment Benefits Other than Pensions 

(PBOP) Costs Balancing Account 

-To record the difference between PBOP costs 

authorized by the Commission, and recorded 

PBOP expenses. 

Mohave Balancing Account 

-To track the difference between: 1) recorded 

capital-related expenses, operating expenses and 

worker protection expenses associated with the 

Mohave Generating Station; and 2) the authorized 

Mohave revenue requirement as adopted in 

D.06-05-016. 


of Current 

Quarter/Year 

(b) 


of Current 

Quarter/Year 

(f) 

252,883,386 Various 

13,209,301 115,682,423 355,356,508 

432,740,607 Various 

2,531,979,126 2,099,238,519 

9,746,037 Various 

693,995 5,587,879 

14,639,921 

32,203,274 36,826,002 

69,029,276 

10,836,588 Various 

14,040,395 16,231,895 

13,028,088 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 




Line 

No. 



(a) 




(Mo, Da, Yr) 


04/18/2009 


DEBITS 

Account 

Credited 

Amount 

(c) 

(d) 

Credits 

(e) 




applicable. 


by classes. 


21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 


of Current 

Quarter/Year 

(b) 


of Current 

Quarter/Year 

(f) 

Affiliate Transfer Memorandum Account 190,685 182 

190,685 374,304 

374,304 

-To record transfer fees received from affiliates 

when an employee is transferred, assigned, or 

otherwise employed by the affiliate. 

Research, Development and Demonstration 25,241 254 

25,241 

Royalties Memorandum Account 

-To record the ratepayers' share of royalties, 

licensing and other revenues attributable to the 

Company's research, development and demonstration 

programs as authorized by Resolution E-3484. 

Energy Assistance Fund 483,896 407 

1,599,321 1,133,425 

18,000 

-To record regulatory liability associated with 

the 2006 Energy Assistance Fund (EAF) rate relief 

program, and amounts disbursed to United Way, but 

not paid or pledged to rate relief customers. 

Leases for Power Contracts 13,312,567 407 

6,945,688 6,366,879 

-To record regulatory liability associated with 

power contracts that are subject to lease 

accounting rules under the guidance of EITF 

No. 01-8 and SFAS 13. 

(Amortization period: 5/2006-12/2009) 

Regulatory Asset - SFAS 158 308,397,000 186 

983,550,000 675,153,000 

-To reflect regulatory asset resulting from the 

adoption of SFAS 158 - Employers' Accounting for 

Defined Benefit Pension & Other Postretirement 

Plans. 

Public Purpose Programs Adj. Mechanism 

To record Public Goods Charge Revenue, PGC 

expenses authorized in P.U. Code Section 399.8, 

and other CPUC Public Purpose Program revenues 

and expenses. 

GCAC Balancing Account 

Balance composed of Gas Costs Adjustment 

Clause which recovers/refunds gas costs on 

Catalina Island. 

19,543,317 Various 

27,389,121 220,808,858 212,963,054 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 




Line 

No. 






(Mo, Da, Yr) 


04/18/2009 





applicable. 


by classes. 


(a) 

25 Reliability Service (RS) Balancing Account 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

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 

To track the RS revenues and RS costs to ensure 

that SCE neither over-collects nor under-collects 

RS costs assessed. 


DEBITS 


of Current 

of Current 

Account Amount 

Credits 

Quarter/Year 

Credited 

Quarter/Year 

(b) 

(c) 

(d) 

(e) 

(f) 

20,606,569 Various 

13,529,121 12,384,983 

19,462,431 

WECC Statutory Costs 3,203,656 407 

3,203,656 4,331,013 

4,331,013 

To record WECC statutory fees being amortized 

over 12-month period. 

RRB Regulatory Contra Account 

To record the difference between actual billed 

Trust Transfer Amount principal and allocated 

monthly bond payment amount. 

Late Payment Charge (LPC) Revenue Balancing 

Account 

To record the difference between LPC Other 

Operating Revenue (OOR) authorized and LPC OOR 

recorded 

20,109,420 20,109,420 

Various 

Family Energy Rate Assistance Balancing Account 407 

To record FERA-related program O&M costs and 

revenue that will result from charging FERA 

eligible customers Tier 2 electricity rates for 

their Tier 3 usage 

CWIP Balancing Account 

Tracks Construction Work in Progress revenue 

requirement and revenues applicable to retail, 

end-use transmission customers on a monthly basis 

to ensure that the Participating TO neither 

overcollects nor undercollects CWIP revenue 

Purchase Agreement Administrative Costs Balancing 

Account 

To record the difference between SCE's actual 

and authorized administrative costs associated 

with (4) third-party demand response contracts 

during the period March 13, 2008 through December 

31, 2012 in accordance with D. 08-03-017. 

Various 

79,194 79,194 

110 110 

1,954,693 10,702,598 

8,747,905 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 

539,674 

539,674 




Line 

No. 






(Mo, Da, Yr) 


04/18/2009 


DEBITS 

Account 

Credited 

Amount 

(c) 

(d) 

Credits 

(e) 




applicable. 


by classes. 


(a) 

29 

30 

31 

32 Regulatory Liability - L/T 

33 

34 

35 

36 

37 

38 

39 

40 

To capture various accrued purchased power 

agreements and other miscellaneous 

regulatory liabilities 


of Current 

Quarter/Year 

(b) 

32,584,090 


of Current 

Quarter/Year 

(f) 

32,584,090 

41 TOTAL 2,385,160,361 

5,862,010,160 4,541,968,069 1,065,118,270 







(Mo, Da, Yr) 


04/18/2009 

ELECTRIC OPERATING REVENUES (Account 400) 



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 MWH 

related 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 added 

for 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 of 

each 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. 

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 


Operating Revenues Year 

to Date Quarterly/Annual 

(a) 

(b) 

Sales of Electricity 

(440) Residential Sales 3,782,850,004 

(442) Commercial and Industrial Sales 

Small (or Comm.) (See Instr. 4) 4,683,605,877 

Large (or Ind.) (See Instr. 4) 796,814,485 

(444) Public Street and Highway Lighting 93,004,800 

(445) Other Sales to Public Authorities 1,509,080 

(446) Sales to Railroads and Railways 6,687,287 

(448) Interdepartmental Sales 262,098 

TOTAL Sales to Ultimate Consumers 9,364,733,631 

(447) Sales for Resale 579,994,827 

TOTAL Sales of Electricity 9,944,728,458 

(Less) (449.1) Provision for Rate Refunds 

TOTAL Revenues Net of Prov. for Refunds 9,944,728,458 

Other Operating Revenues 

(450) Forfeited Discounts 17,173,547 

(451) Miscellaneous Service Revenues 41,877,260 

(453) Sales of Water and Water Power 205,771 

(454) Rent from Electric Property 73,838,740 

(455) Interdepartmental Rents 

(456) Other Electric Revenues 111,352,498 

(456.1) Revenues from Transmission of Electricity of Others 72,569,371 

(457.1) Regional Control Service Revenues 

(457.2) Miscellaneous Revenues 

TOTAL Other Operating Revenues 317,017,187 

TOTAL Electric Operating Revenues 10,261,745,645 

Operating Revenues 

Previous year (no Quarterly) 

(c) 

3,759,752,970 

4,625,039,293 

813,453,810 

83,684,209 

1,526,670 

6,719,356 

240,548 

9,290,416,856 

489,398,014 

9,779,814,870 

9,779,814,870 

16,962,299 

40,975,780 

244,720 

72,989,404 

245,874,016 

60,663,767 

437,709,986 

10,217,524,856 

FERC FORM NO. 1/3-Q (REV. 12-05) 

Page 300






(Mo, Da, Yr) 


04/18/2009 

ELECTRIC OPERATING REVENUES (Account 400) 



5. 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 the 

respondent 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 classification 

in a footnote.) 

6. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases. 

7. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. 

8. Include unmetered sales. Provide details of such Sales in a footnote. 

MEGAWATT HOURS SOLD 

AVG.NO. CUSTOMERS PER MONTH 

Year to Date Quarterly/Annual 

Amount Previous year (no Quarterly) 

Current Year (no Quarterly) Previous Year (no Quarterly) 

(d) (e) (f) (g) 

30,743,545 29,940,965 4,242,285 

4,224,057 2 

47,135,168 46,682,111 567,288 

562,221 4 

11,088,888 11,347,910 36,009 

36,033 5 

539,164 530,592 14,959 

14,363 6 

235,781 236,835 5 

5 7 

63,612 64,511 56 

56 8 

2,606 2,467 23 

23 9 

89,808,764 88,805,391 4,860,625 

4,836,758 10 

8,768,588 8,882,666 44 

46 11 

98,577,352 97,688,057 4,860,669 

4,836,804 12 

98,577,352 97,688,057 4,860,669 

4,836,804 14 

Line 

No. 

1 

3 

13 

Line 12, column (b) includes $ 

Line 12, column (d) includes 

-43,158,000 

0 

of unbilled revenues. 

MWH relating to unbilled revenues 

FERC FORM NO. 1/3-Q (REV. 12-05) 

Page 301






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Included deferred revenue of $14,852,259 








(Mo, Da, Yr) 

04/18/2009 



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. 

Line 

No. 

1 

Description of Service 

(a) 

Balance at End of Balance at End of 

Quarter 1 Quarter 2 

(b) 

(c) 

Balance at End of 

Quarter 3 

(d) 

Balance at End of 

Year 

(e) 

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 TOTAL 

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302






(Mo, Da, Yr) 


04/18/2009 

SALES OF ELECTRICITY BY RATE SCHEDULES 



1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per 

customer, 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," Page 

300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each 

applicable 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 residential 

schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported 

customers. 

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 (12 

if 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. 

Line Number and Title of Rate schedule MWh Sold 

Revenue Average Number KWh of Sales Revenue Per 

No. 

of Customers Per Customer KWh Sold 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 NOTE: "@" Indicates Direct Acces 

2 

3 ACCOUNT 440 

4 

5 AL-2 

121 

1 

6 D 

20,607,611 2,824,597,582 

2,857,081 7,213 0.1371 

7 D @ 

66,034 4,997,331 

7,050 9,367 0.0757 

8 D-APS 

578,067 76,182,570 

59,844 9,660 0.1318 

9 D-APS @ 

4,889 326,112 

442 11,061 0.0667 

10 D-APS-N 

2,486 270,832 

308 8,071 0.1089 

11 D-APSE 

1,632,668 201,889,291 

172,025 9,491 0.1237 

12 D-APSE @ 

9,467 540,882 

921 10,279 0.0571 

13 D-APSE-N 

6,498 594,728 

832 7,810 0.0915 

14 D-CARE 

5,732,096 474,923,834 

959,384 5,975 0.0829 

15 D-CARE @ 

8,435 317,818 

1,324 6,371 0.0377 

16 D-CARE-APS 

96,347 7,537,752 

12,237 7,873 0.0782 

17 D-CARE-APS @ 

557 14,401 

67 8,313 0.0259 

18 D-CARE-APS-N 

85 6,216 

10 8,500 0.0731 

19 D-CARE-N 

1,168 90,330 

165 7,079 0.0773 

20 D-FERA 

119,998 13,777,157 

17,572 6,829 0.1148 

21 D-FERA @ 

6 463 

0.0772 

22 D-FERA-APS 

2,717 323,318 

296 9,179 0.1190 

23 D-FERA-APS-E 

16,807 1,767,724 

1,903 8,832 0.1052 

24 D-FERA-APS-N 

19 1,865 

2 9,500 0.0982 

25 D-FERA-APSE-N 

9 

1 

26 D-FERA-N 

87 6,732 

10 8,700 0.0774 

27 D-N 

42,525 5,190,510 

5,357 7,938 0.1221 

28 D-PG-S 

-777 

1 

29 D-S 

61,044 8,311,802 

5,315 11,485 0.1362 

30 D-S @ 

454 32,474 

37 12,270 0.0715 

31 D-S-CARE 

4,229 346,563 

417 10,141 0.0819 

32 D-S-CARE @ 

25 958 

3 8,333 0.0383 

33 D-S-CARE-N 

23 1,817 

2 11,500 0.0790 

34 D-S-FERA 

119 12,844 

12 9,917 0.1079 

35 D-S-N 

305 40,794 

39 7,821 0.1338 

36 D-TOU-EV-1 

101 16,410 

49 2,061 0.1625 

37 D-TOU-1 

1,643 232,396 

211 7,787 0.1414 

38 D-TOU-1 @ 

14 1,294 

1 14,000 0.0924 

39 D-TOU-1-APS 

7 918 

1 7,000 0.1311 

40 D-TOU-1-APSE 

147 17,849 

17 8,647 0.1214 

41 TOTAL Billed 

42 Total Unbilled Rev.(See Instr. 6) 

43 TOTAL 

FERC FORM NO. 1 (ED. 12-95) Page 304 

89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 ACCOUNT 440 Continued 

2 D-TOU-1-N 

1,328 64,743 

172 7,721 0.0488 

3 D-TOU-2 

42,013 6,355,576 

2,386 17,608 0.1513 

4 D-TOU-2 @ 

40 4,164 

4 10,000 0.1041 

5 D-TOU-2-APS 

221 33,000 

14 15,786 0.1493 

6 D-TOU-2-APSE 

3,989 544,252 

260 15,342 0.1364 

7 D-TOU-2-APSE @ 

4 352 

0.0880 

8 D-TOU-2-N 

2,111 168,661 

153 13,797 0.0799 

9 D-TOU1-CARE 

139 14,474 

19 7,316 0.1041 

10 D-TOU1-CARE-N 

4 35 

1 4,000 0.0088 

11 D-TOU2-CARE 

1,526 176,667 

118 12,932 0.1158 

12 D-TOU2-CARE @ 

2 184 

0.0920 

13 D-TU1-C-APSE 

23 2,482 

2 11,500 0.1079 

14 D-TU2-C-APSE 

224 23,922 

19 11,789 0.1068 

15 DCARE-APSE 

419,512 30,642,960 

50,362 8,330 0.0730 

16 DCARE-APSE @ 

1,290 21,271 

148 8,716 0.0165 

17 DCARE-APSE-N 

281 18,282 

31 9,065 0.0651 

18 DCARE-E 

3,365 363,171 

296 11,368 0.1079 

19 DCARE-E-APS 

111 13,280 

4 27,750 0.1196 

20 DE 

88,826 8,561,989 

10,273 8,647 0.0964 

21 DE @ 

6 368 

1 6,000 0.0613 

22 DE-APS 

12,177 1,137,384 

1,176 10,355 0.0934 

23 DE-APS-N 

9 540 

1 9,000 0.0600 

24 DE-APSE 

27,821 2,422,009 

2,782 10,000 0.0871 

25 DE-APSE-N 

40 2,219 

7 5,714 0.0555 

26 DE-FERA 

175 15,933 

16 10,938 0.0910 

27 DE-FERA-APS 

17 1,534 

2 8,500 0.0902 

28 DE-FERA-APS-E 

81 6,750 

7 11,571 0.0833 

29 DE-N 

69 5,170 

9 7,667 0.0749 

30 DE-S 

266 23,877 

21 12,667 0.0898 

31 DE-TOU-1-N 

5 178 

1 5,000 0.0356 

32 DE-TOU-2 

449 47,173 

29 15,483 0.1051 

33 DE-TOU-1-APS 

10 1,095 

1 10,000 0.1095 

34 DE-TOU1-APSE 

6 449 

1 6,000 0.0748 

35 DE-TOU2-APS 

50 4,929 

3 16,667 0.0986 

36 DE-TOU2-APSE 

184 18,066 

13 14,154 0.0982 

37 DM 

101,570 13,730,115 

5,908 17,192 0.1352 

38 DM @ 

2,235 198,774 

52 42,981 0.0889 

39 DM-CARE 

-4 -491 

0.1228 

40 DM-CARE-E 

21 2,044 

2 10,500 0.0973 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 ACCOUNT 440 Continued 

2 DM-N 

242 25,392 

18 13,444 0.1049 

3 DMS-1 

38,583 3,781,911 

258 149,547 0.0980 

4 DMS-1 @ 

11 859 

1 11,000 0.0781 

5 DMS-2 

540,327 43,074,266 

1,541 350,634 0.0797 

6 DMS-2 @ 

2,035 103,464 

10 203,500 0.0508 

7 DMS-2-N 

138 8,265 

1 138,000 0.0599 

8 DMS-3 

15,478 1,746,439 

53 292,038 0.1128 

9 DMS-3 @ 

226 18,129 

1 226,000 0.0802 

10 DTU2-CARE-N 

2,621 

1 

11 ** DWL-A 

2,291 643,407 

95 24,116 0.2808 

12 ** DWL-A @ 

16 3,875 

1 16,000 0.2422 

13 DWL-B 

29 4,698 

1 29,000 0.1620 

14 ** DWL-C 

122 20,753 

3 40,667 0.1701 

15 GS-1 

309,294 49,135,188 

56,720 5,453 0.1589 

16 GS-1 @ 

2,203 179,663 

239 9,218 0.0816 

17 GS-1-APS 

19 2,620 

2 9,500 0.1379 

18 GS-1-CARE 

113 11,803 

13 8,692 0.1045 

19 GS-1-N 

92 13,342 

16 5,750 0.1450 

20 GS-2 

111,635 12,605,519 

1,688 66,134 0.1129 

21 GS-2 @ 

3,571 237,241 

35 102,029 0.0664 

22 GS-2-APS 

341 34,218 

1 341,000 0.1003 

23 GS1-APSE 

224 28,467 

19 11,789 0.1271 

24 GS1-C-APSE 

7 558 

1 7,000 0.0797 

25 GS2-TOU-B-S 

663 62,955 

1 663,000 0.0950 

26 GS2-1BL-APSE 

9 1,573 

0.1748 

27 LS-3 

-1 -94 

0.0940 

28 **OL-1-ALLNITE 

2,825 572,680 

3,828 738 0.2027 

29 PA-1 

791 153,550 

133 5,947 0.1941 

30 PA-2 

107 14,070 

3 35,667 0.1315 

31 TOU-GS-1 

5,207 760,067 

364 14,305 0.1460 

32 TOU-GS-1 @ 

33 3,837 

5 6,600 0.1163 

33 TOU-GS-1-N 

5 799 

1 5,000 0.1598 

34 TOU-PA-A 

24 2,334 

1 24,000 0.0973 

35 TOU-PA-B 

10 1,053 

0.1053 

36 TOU-PA-SOP-2 

37 

38 OTHER ADJUSTMENTS 

39 

1 202 

4,308 

0.2020 

40 TOTAL ACCOUNT 440 

30,743,545 3,800,260,533 

4,242,285 7,247 0.1236 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 ACCOUNT 442 

2 AL-1 

3 AL-2 

4 AL-2 @ 

5 EDWARDS-AFB 

6 G2TB/1BL-APSE 

7 G2T-SPP/CPP-S 

8 GS-1 

9 GS-1 @ 

10 GS-1-APS 

11 GS-1-APS @ 

12 GS-1-APS-C 

13 GS1-APSE 

14 GS1-APSE @ 

15 GS1-APSE-N 

16 GS-1-BIP 

17 GS1-C-APSE 

18 GS-1-CARE 

19 GS-1-G-S 

20 GS-1-N 

21 GS-1-S 

22 GS-2 

23 GS-2 # 

24 GS-2 @ 

25 GS2/1BL-APSE 

26 GS2/1BL-APSE @ 

27 GS2/1BLC-APSE 

28 GS-2 APS 

29 GS-2 APS @ 

30 GS-2-APS-C 

31 GS2-APSE 

32 GS2-APSE @ 

33 GS-2-APS-N 

34 GS-2-BIP 

35 GS2-C-APSE 

36 GS-2-CARE 

37 GS-2-N 

38 GS-2-S 

39 GS-2-S @ 

40 GS2T-A-APS 

139,026 7,606,208 

6,612 21,026 0.0547 

3,365 109,233 

40 84,125 0.0325 

696 91,678 

2 348,000 0.1317 

4,407,182 625,274,390 

395,539 11,142 0.1419 

35,632 2,810,826 

3,396 10,492 0.0789 

14,949 1,954,779 

916 16,320 0.1308 

233 15,286 

14 16,643 0.0656 

64 5,834 

3 21,333 0.0912 

48,273 6,051,681 

3,144 15,354 0.1254 

586 35,508 

35 16,743 0.0606 

80 9,221 

9 8,889 0.1153 

21 

29 2,354 

1 29,000 0.0812 

1,073 103,246 

52 20,635 0.0962 

8 -25,152 

2 4,000 -3.1440 

3,005 310,988 

174 17,270 0.1035 

14 2,051 

1 14,000 0.1465 

13,701,651 1,592,186,440 

110,061 124,491 0.1162 

21,438 

751,461 42,363,312 

2,421 310,393 0.0564 

38,249 5,005,721 

521 73,415 0.1309 

111 8,745 

1 111,000 0.0788 

48 4,863 

1 48,000 0.1013 

158,845 20,882,056 

1,295 122,660 0.1315 

27,914 1,671,561 

96 290,771 0.0599 

347 28,117 

3 115,667 0.0810 

204,096 25,243,233 

1,634 124,906 0.1237 

68,883 3,661,978 

250 275,532 0.0532 

1,381 170,499 

7 197,286 0.1235 

181 35,064 

0.1937 

871 65,814 

5 174,200 0.0756 

10,903 831,281 

55 198,236 0.0762 

24,986 3,020,316 

190 131,505 0.1209 

12,549 1,694,055 

42 298,786 0.1350 

607 18,871 

1 607,000 0.0311 

779 135,096 

16 48,688 0.1734 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 ACCOUNT 442 (Continued) 

2 GS2T-A-APSE 

15,263 1,993,681 

221 69,063 0.1306 

3 GS2T-A-APSE-N 

193 28,287 

3 64,333 0.1466 

4 GS2T-B-APS 

11,773 1,790,997 

115 102,374 0.1521 

5 GS2T-B-APS @ 

943 50,418 

2 471,500 0.0535 

6 GS2T-B-APSE 

34,269 3,547,531 

97 353,289 0.1035 

7 GS2T-B-APSE @ 

4,872 281,681 

18 270,667 0.0578 

8 GS-2-TOU # 

2,039 

9 GS2TOU-A/1BL 

461 86,960 

11 41,909 0.1886 

10 GS-2-TOU-A-S 

22,231 3,225,714 

175 127,034 0.1451 

11 GS-2-TOU-A-S-N 

1,091 127,015 

11 99,182 0.1164 

12 GS2TOU-B/1BL 

6,469 753,568 

20 323,450 0.1165 

13 GS2TOUB/1BL-N 

325 48,791 

1 325,000 0.1501 

14 GS2-TOU-B-DL# 

6,686 

15 GS2-TOU-B-EDW 

694 66,901 

5 138,800 0.0964 

16 GS2-TOU-B-P 

3,392 340,074 

13 260,923 0.1003 

17 GS2-TOU-B-S 

835,836 82,266,070 

3,208 260,547 0.0984 

18 GS2-TOU-B-S @ 

367,179 21,433,553 

1,320 278,166 0.0584 

19 GS2-TOU-B-S-N 

20 GS2-TOU-P 

21 GS2-TOU-S 

3,855 

240 

394,369 

26,170 

19 202,895 0.1023 

0.1090 

22 GS2-TOU-S @ 

55 3,243 

0.0590 

23 GS2-TOU-S-B 

7,397 951,124 

12 616,417 0.1286 

24 GS-TOU-EV-3 

212 31,718 

15 14,133 0.1496 

25 GS-TOU-EV-4 

26 I-6-P 

27 I-6-P-BIP 

1,688 

381,869 

200,906 

31,880,737 

20 

48 

84,400 

7,955,604 

0.1190 

0.0835 

28 I-6-P-BIP @ 

84,506 4,012,748 

8 10,563,250 0.0475 

29 I-6-S 

5 692 

0.1384 

30 I-6-S-BIP 

407,407 37,455,884 

111 3,670,333 0.0919 

31 I-6-S-BIP @ 

83,772 4,198,846 

14 5,983,714 0.0501 

32 I-6-S-P-BIP 

47,563 5,197,568 

3 15,854,333 0.1093 

33 I-6-S-P-BIP @ 

46,105 2,477,103 

3 15,368,333 0.0537 

34 I-6-S-S-BIP 

7,720 671,384 

2 3,860,000 0.0870 

35 I-6-S-S-BIP @ 

250 62,082 

1 250,000 0.2483 

36 I-6-S-T 

-86,592 

37 I-6-S-T-BIP 

52,801 4,628,933 

2 26,400,500 0.0877 

38 I-6-T 

2,039 102,247 

1 2,039,000 0.0501 

39 I-6-T # 

940,778 

40 I-6-T-BIP 

291,305 18,222,635 

10 29,130,500 0.0626 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 


2 I-6-T-BIP @ 

455,062 13,452,529 

7 65,008,857 0.0296 

3 **LS-1-ALLNITE 

12,910 3,415,779 

2,774 4,654 0.2646 

4 **LS1-ALLNITE@ 

106 23,964 

7 15,143 0.2261 

5 **LS1-MIDNITE 

8 2,230 

1 8,000 0.2788 

6 **LS1-TAP 

113 40,803 

0.3611 

7 **LS-2 

1,500 122,005 

180 8,333 0.0813 

8 **LS-2 @ 

4 150 

1 4,000 0.0375 

9 LS-3 

23,215 1,430,942 

2,415 9,613 0.0616 

10 LS-3 @ 

1,482 51,065 

124 11,952 0.0345 

11 **OL-1-ALLNITE 

10,624 1,879,522 

6,569 1,617 0.1769 

12 **OL-1ALLNITE@ 

74 9,119 

25 2,960 0.1232 

13 PA-1 

411,503 60,450,397 

17,000 24,206 0.1469 

14 PA-1 @ 

2,706 148,265 

42 64,429 0.0548 

15 PA-1-I 

1,273 156,626 

12 106,083 0.1230 

16 PA-1-N 

303 37,021 

20 15,150 0.1222 

17 PA-1-SPEC-5 

10,661 2,253,242 

2,111 5,050 0.2114 

18 PA-1-SPEC-5@ 

2 635 

1 2,000 0.3175 

19 PA-1-STANDBY 

72 9,133 

1 72,000 0.1268 

20 PA-2 

291,908 29,748,476 

3,135 93,113 0.1019 

21 PA-2 @ 

5,963 370,011 

41 145,439 0.0621 

22 PA-2-DL # 

2,327 

23 PA-2-I 

4,474 336,982 

23 194,522 0.0753 

24 PA-2-S 

337 47,028 

3 112,333 0.1395 

25 RTP-2-DLS # 

26 RTP-2-I-S 

27 RTP-2-P 

48,008 

212,001 

5,380,564 

9 5,334,222 0.1121 

28 RTP-2-P @ 

16,206 1,060,137 

3 5,402,000 0.0654 

29 RTP-2-P-BIP 

30 RTP-2S 

31 RTP-2-S 

42,541 

34,656 

4,522,075 

3,950,518 

7 

20 

6,077,286 

1,732,800 

0.1063 

0.1140 

32 RTP-2-S @ 

18,818 1,335,555 

7 2,688,286 0.0710 

33 RTP-2-S-BIP 

39,641 3,692,561 

15 2,642,733 0.0932 

34 RTP2-SGDR-T 

874,246 73,877,992 

1 874,246,000 0.0845 

35 RTP-2-SGDR-T 

36 RTP2-SGDRTTA 

1 

37 RTP-2-S-P 

4,245 770,611 

1 4,245,000 0.1815 

38 RTP-2-S-S 

2,878 345,379 

1 2,878,000 0.1200 

39 RTP-2-S-S-BIP 

1 

40 RTP-2-S-T 

18,340 1,304,555 

1 18,340,000 0.0711 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 


2 RTP2-S-T-BIP @ 

87,125 2,194,144 

1 87,125,000 0.0252 

3 RTP-2-T @ 

14,552 772,855 

2 7,276,000 0.0531 

4 RTP-2-T-BIP 

25,695 1,382,218 

3 8,565,000 0.0538 

5 T8APSE-P-BIP 

6 T8APSE-S-BIP 

7 T8APSE-S-BIP @ 

615 

1,219 

73,336 

66,642 

1 

1 

615,000 

1,219,000 

0.1192 

0.0547 

8 TC-1 

61,912 6,833,045 

13,509 4,583 0.1104 

9 TC-1 @ 

10 TOU-8-APSE 

11 TOU-8-APSE @ 

1,661 106,531 

343 4,843 0.0641 

12 TOU-8-APSE-P 

53,466 5,465,717 

15 3,564,400 0.1022 

13 TOU-8-APSE-P@ 

12,755 657,907 

1 12,755,000 0.0516 

14 TOU-8-APSE-S 

81,508 9,444,235 

36 2,264,111 0.1159 

15 TOU-8-APSE-S @ 

7,811 441,081 

2 3,905,500 0.0565 

16 TOU-8-APSE-S-P 

5,362 763,522 

2 2,681,000 0.1424 

17 TOU-8-APSE-S-S 

8,411 967,149 

2 4,205,500 0.1150 

18 TOU-8-APSE-T 

109,951 6,089,546 

2 54,975,500 0.0554 

19 TOU-8-APS-P 

30,286 3,169,777 

9 3,365,111 0.1047 

20 TOU-8-APS-P-BIP 

955 110,114 

1 955,000 0.1153 

21 TOU-8-APS-S 

35,778 4,392,503 

18 1,987,667 0.1228 

22 TOU-8-APS-S@ 

23 TOU8-APS-S-S 

24 TOU8-APS-S-T 

14,654 

70,760 

1,099,381 

4,632,196 

8 

2 

1,831,750 

35,380,000 

0.0750 

0.0655 

25 TOU-8-APS-T 

83,722 4,574,829 

1 83,722,000 0.0546 

26 TOU8CPPGCCD-P 

131,399 12,352,549 

27 4,866,630 0.0940 

27 TOU8CPPGCCD-S 

157,991 17,977,721 

82 1,926,720 0.1138 

28 TOU8CPPGCCD-T 

10,542 734,232 

1 10,542,000 0.0696 

29 TOU-8-CPP-P 

583 69,469 

1 583,000 0.1192 

30 TOU-8-CPP-P-BIP 

427 43,014 

2 213,500 0.1007 

31 TOU-8-CPP-S 

5,948 676,755 

3 1,982,667 0.1138 

32 TOU-8-DL-S # 

2,136,983 

33 TOU-8-P 

3,037,395 276,272,692 

423 7,180,603 0.0910 

34 TOU-8-P@ 

1,002,334 49,217,846 

86 11,655,047 0.0491 

35 TOU-8-P-BIP 

720,425 56,381,414 

68 10,594,485 0.0783 

36 TOU-8-P-BIP @ 

125,654 4,648,322 

11 11,423,091 0.0370 

37 TOU-8-P-N 

248,332 21,965,105 

17 14,607,765 0.0885 

38 TOU-8-S 

6,422,715 622,162,716 

1,947 3,298,775 0.0969 

39 TOU-8-S @ 

1,433,448 77,600,131 

349 4,107,301 0.0541 

40 TOU-8-S-BIP 

631,921 49,899,922 

134 4,715,828 0.0790 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 


2 TOU-8-S-BIP @ 

3 TOU-8-S-BN 

4 TOU-8-S-N 

163,628 

51,268 

6,554,427 

5,225,133 

31 

18 

5,278,323 

2,848,222 

0.0401 

0.1019 

5 TOU-8-S-P 

523,516 51,044,093 

52 10,067,615 0.0975 

6 TOU-8-S-P @ 

152,922 9,761,461 

10 15,292,200 0.0638 

7 TOU-8-S-P-BIP 

56,388 6,020,052 

5 11,277,600 0.1068 

8 TOU-8-S-P-BIP@ 

2 

9 TOU-8-S-S 

183,456 18,696,963 

48 3,822,000 0.1019 

10 TOU-8-S-S @ 

14,728 858,108 

4 3,682,000 0.0583 

11 TOU8-S-S-BIP 

18,887 1,485,649 

3 6,295,667 0.0787 

12 TOU8-S-S-BIP @ 

4,435 256,222 

2 2,217,500 0.0578 

13 TOU-8-S-T 

376,745 29,800,756 

56 6,727,589 0.0791 

14 TOU-8-S-T @ 

138,726 5,635,723 

9 15,414,000 0.0406 

15 TOU8-S-T-BIP 

282,687 11,267,546 

2 141,343,500 0.0399 

16 TOU8-S-T-BIP @ 

89,536 2,332,039 

1 89,536,000 0.0260 

17 TOU-8-T 

1,681,829 92,298,175 

45 37,373,978 0.0549 

18 TOU-8-T @ 

1,199,215 41,368,765 

22 54,509,773 0.0345 

19 TOU-8-T-BIP 

1,545,380 69,333,204 

25 61,815,200 0.0449 

20 TOU-8-T-BIP @ 

534,224 12,628,473 

7 76,317,714 0.0236 

21 TOU-8-T-BN 

68,817 2,825,300 

1 68,817,000 0.0411 

22 TOU-8-T-N 

231,450 12,765,846 

4 57,862,500 0.0552 

23 TOUG3A-APSE-P 

726 99,277 

1 726,000 0.1367 

24 TOUG3A-APSE-S 

52,016 7,829,523 

104 500,154 0.1505 

25 TOUG3B-APSE-P 

4,560 472,398 

4 1,140,000 0.1036 

26 TOUG3B-APSE-S 

124,683 15,744,962 

155 804,406 0.1263 

27 TOU-GS-1 

109,658 15,134,167 

3,605 30,418 0.1380 

28 TOU-GS-1 @ 

10,328 1,134,643 

1,316 7,848 0.1099 

29 TOU-GS-1-APS 

35 4,997 

1 35,000 0.1428 

30 TOU-GS-1-APSE 

89 11,174 

6 14,833 0.1256 

31 TOU-GS-1-N 

250 15,228 

7 35,714 0.0609 

32 TOU-GS2A-S 

33 TOU-GS2A-T 

34 TOU-GS2B-P 

35 TOU-GS2B-S 

36 TOU-GS2SOP-S 

37 TOUGS3AAPS-P 

-486 

-4 

317 

-72,391 

-254 

51,137 

1 317,000 

0.1490 

0.0635 

0.1613 

38 TOUGS3AAPS-S 

38,638 5,930,330 

76 508,395 0.1535 

39 TOU-GS3-A-P 

14,147 1,860,971 

20 707,350 0.1315 

40 TOUGS3AP-BIP 

1 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 


2 TOU-GS3-A-P-N 

886 99,278 

2 443,000 0.1121 

3 TOU-GS-3-A-S 

437,813 66,013,223 

790 554,194 0.1508 

4 TOU-GS3-A-S @ 

13,326 887,240 

16 832,875 0.0666 

5 TOUGS3AS-BIP 

9,144 1,324,058 

22 415,636 0.1448 

6 TOUGS3AS-BIP @ 

1,453 30,850 

1 1,453,000 0.0212 

7 TOU-GS3-A-S-N 

7,564 932,397 

9 840,444 0.1233 

8 TOU-GS3A-S-S 

4,669 564,087 

5 933,800 0.1208 

9 TOUGS3BAPS-P 

7,195 817,683 

6 1,199,167 0.1136 

10 TOUGS3BAPS-S 

99,948 12,541,640 

127 786,992 0.1255 

11 TOUGS3BAPS-S @ 

14,803 1,161,670 

21 704,905 0.0785 

12 TOU-GS3B-C-P 

1,139 91,276 

1 1,139,000 0.0801 

13 TOU-GS3B-C-S 

8,591 640,308 

8 1,073,875 0.0745 

14 TOU-GS3B-EDW 

669 56,940 

1 669,000 0.0851 

15 TOU-GS3-B-P 

144,842 15,840,833 

119 1,217,160 0.1094 

16 TOU-GS3-B-P @ 

5,542 345,631 

4 1,385,500 0.0624 

17 TOUGS3BP-BIP 

3,324 227,145 

1 3,324,000 0.0683 

18 TOU-GS3-B-P-N 

1,375 122,843 

1 1,375,000 0.0893 

19 TOU-GS-3-B-S 

6,047,158 662,655,578 

5,420 1,115,712 0.1096 

20 TOU-GS3-B-S @ 

1,639,987 86,947,234 

946 1,733,601 0.0530 

21 TOUGS3BS-BIP 

36,391 3,582,895 

32 1,137,219 0.0985 

22 TOUGS3BS-BIP @ 

7,365 370,332 

8 920,625 0.0503 

23 TOU-GS3-B-S-N 

34,320 3,946,821 

38 903,158 0.1150 

24 TOU-GS3B-S-P 

2,869 510,693 

7 409,857 0.1780 

25 TOU-GS3B-S-S 

30,677 3,317,816 

25 1,227,080 0.1082 

26 TOU-GS3B-S-S @ 

2,809 190,858 

2 1,404,500 0.0679 

27 TOU-GS3-B-T 

2,888 361,367 

4 722,000 0.1251 

28 TOU-GS3-CPP-P 

1,501 207,087 

3 500,333 0.1380 

29 TOU-GS3-CPP-S 

28,958 3,753,162 

29 998,552 0.1296 

30 TOU-GS3SOP-S 

12,853 1,560,008 

17 756,059 0.1214 

31 TOU-PA-5 

777,296 48,432,376 

1,091 712,462 0.0623 

32 TOU-PA-5 @ 

3,002 200,697 

6 500,333 0.0669 

33 TOU-PA-5-BIP 

55 3,784 

1 55,000 0.0688 

34 TOU-PA-5-I 

111,640 5,936,038 

126 886,032 0.0532 

35 TOU-PA-5-I-N 

331 20,453 

1 331,000 0.0618 

36 TOU-PA-5-N 

680 36,477 

1 680,000 0.0536 

37 TOU-PA-5-S 

38 TOU-PA-7-A 

39 TOU-PA-7-A @ 

40 TOU-PA-7-A1 

2,259 

4,190 

154,526 

284,383 

2 

32 

1,129,500 

130,938 

0.0684 

0.0679 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 


2 TOU-PA-7-A2 

27,246 1,740,136 

98 278,020 0.0639 

3 TOU-PA-7-A2@ 

4 TOU-PA-7-B 

5 TOU-PA-7-B1 

15,334 

10,411 

552,782 

831,825 

7 

90 

2,190,571 

115,678 

0.0360 

0.0799 

6 TOU-PA-7-B2 

45,292 3,127,068 

179 253,028 0.0690 

7 TOU-PA-7-B2@ 

8 TOU-PA-7-V @ 

9 TOU-PA-A 

4,171 

150,351 

160,135 

11,907,450 

6 

792 

695,167 

189,837 

0.0384 

0.0792 

10 TOU-PA-A @ 

1,284 66,015 

5 256,800 0.0514 

11 TOU-PA-A-I 

2,545 172,081 

11 231,364 0.0676 

12 TOU-PA-A-N 

1 

13 TOU-PA-B 

920,168 66,940,298 

2,304 399,378 0.0727 

14 TOU-PA-B @ 

38,528 1,508,653 

52 740,923 0.0392 

15 TOU-PA-B-BIP 

1,752 102,770 

1 1,752,000 0.0587 

16 TOU-PA-B-I 

92,042 5,361,317 

142 648,183 0.0582 

17 TOU-PA-B-I-N 

652 31,132 

2 326,000 0.0477 

18 TOU-PA-B-N 

1,156 71,654 

6 192,667 0.0620 

19 TOU-PA-B-S 

3,901 322,413 

4 975,250 0.0826 

20 TOU-PA-ICE 

33,761 2,032,243 

147 229,667 0.0602 

21 TOUPA-ICE-API 

22 TOU-PAS1-IN 


1,010 

165,745 

46,899 

10,719,947 

4 

725 

252,500 

228,614 

0.0464 

0.0647 

24 TOU-PA-SOP1@ 

4,173 184,162 

5 834,600 0.0441 

25 TOUPASOP1-API 

63,058 3,037,413 

174 362,402 0.0482 

26 TOU-PA-SOP1-N 

116 7,627 

2 58,000 0.0658 


69,030 4,341,633 

182 379,286 0.0629 

28 TOU-PA-SOP2@ 

90 7,916 

1 90,000 0.0880 

29 TOUPASOP2-AP1 

31,412 1,488,412 

81 387,802 0.0474 

30 TUGS3BAPSESBIP 

655 75,382 

3 218,333 0.1151 

31 TUGS3BAPSE-S-S 

398 61,408 

1 398,000 0.1543 

32 TUGS3BAPS-SBIP 

33 TUGS1-SPP/CPP 

34 TUGS3-A-S-DL # 

351 49,439 

4,154 

3 117,000 0.1409 

35 TUGS3BAPS-S-N 

966 100,023 

1 966,000 0.1035 

36 TUGS3-B-S-DL # 

95,622 

37 TUGS3SOPS-BIP 

1,566 169,418 

2 783,000 0.1082 

38 WIRETECHRATE 

1,535 164,915 

0.1074 


3 -225,980 

-75.3267 


58,224,056 5,492,445,097 

603,297 96,510 0.0943 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 ACCOUNT 444 

2 

3 AL-2 

1,136 66,705 

92 12,348 0.0587 

4 GS-1 

798 120,653 

132 6,045 0.1512 

5 GS-2 

777 74,651 

4 194,250 0.0961 

6 I-6-P-BIP 

1,636 98,330 

0.0601 

7 **LS-1-ALLNITE 

333,265 75,881,338 

3,877 85,960 0.2277 

8 **LS-2 

101,508 8,693,632 

3,627 27,987 0.0856 

9 **LS-2 @ 

2,468 222,463 

63 39,175 0.0901 

10 **LS-2-B 

107 17,757 

3 35,667 0.1660 

11 LS-3 

61,619 3,972,342 

5,320 11,583 0.0645 

12 LS-3 @ 

7,756 273,788 

643 12,062 0.0353 

13 **LS1-ALLNITE @ 

3,029 533,205 

9 336,556 0.1760 

14 TC-1 

5,298 587,485 

1,175 4,509 0.1109 

15 TC-1 @ 

65 4,514 

12 5,417 0.0694 

16 TOU-GS-1 

8 1,320 

1 8,000 0.1650 

17 TOU-8-P-BIP 

18 


20 

19,695 

-1 

1,327,749 

-655 

1 19,695,000 0.0674 

0.6550 


22 

23 ACCOUNT 445 

24 

539,164 91,875,277 

14,959 36,043 0.1704 

25 EDWARDS-AFB 

187,957 622,415 

3 62,652,333 0.0033 

26 MARCH-AFB 

47,045 860,339 

1 47,045,000 0.0183 

27 SEQUOIA 

28 


30 

778 

1 

26,326 

1 778,000 0.0338 


32 

33 

34 

35 

36 

37 

38 

39 

40 

235,781 1,509,080 

5 47,156,200 0.0064 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041






(Mo, Da, Yr) 


04/18/2009 











customers. 







No. 


(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

1 ACCOUNT 446 

2 

3 GS-1 

151 22,639 

21 7,190 0.1499 

4 TC-1 

42 4,315 

6 7,000 0.1027 

5 TOU-GS2A-P 

2,500 323,370 

4 625,000 0.1293 

6 TOU-GS2B-P 

8,898 1,055,210 

9 988,667 0.1186 

7 TOU-8-P 

8 


10 


12 

13 

14 ACCOUNT 448 

15 

52,019 

2 

63,612 

5,281,754 

-1 

6,687,287 

16 

56 

3,251,188 

1,135,929 

0.1015 

-0.0005 

0.1051 

16 GS-1-SCE 

37 5,291 

4 9,250 0.1430 

17 GS-2-SCE 

1,571 147,763 

2 785,500 0.0941 

18 PA-1-SCE 

373 48,572 

14 26,643 0.1302 

19 PA-2-SCE 

20 


22 


24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

628 

-3 

2,606 

60,472 

262,098 

3 

23 

209,333 

113,304 

0.0963 

0.1006 



43 TOTAL 


89,808,764 9,393,039,372 4,860,625 18,477 0.1046 

0 -43,158,000 0 0 0.0000 

89,808,764 9,349,881,372 4,860,625 18,477 0.1041







(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 


This footnote applies to entire schedule: "@" Symbol represents Direct Access Rate Schedule. 


Less than 1 MWh. 



Schedule Page: 304 Line No.: 5 Column: f 



Less than 12 months' data. 

















Schedule Page: 304.1 Line No.: 7 Column: e 










Schedule Page: 304.2 Line No.: 10 Column: b 




Schedule Page: 304.2 Line No.: 10 Column: f 

















FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 











Other adjustments may include DWR, EDRA, Misc. Billing Errors, Misc. Transactions Used for Billing Purposes, Municipal 

Departing Load, and other miscellaneous adjustments. 

Schedule Page: 304.2 Line No.: 40 Column: c 

Excludes deferred revenue of $6,386,471. 




























Data reflected under parent rate schedule or other applicable tariff. 



















FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 









































Excludes deferred revenue of $8,317,265. 









Excludes deferred revenue of $148,523. 











FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 














(Mo, Da, Yr) 


04/18/2009 

SALES FOR RESALE (Account 447) 



1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than 

power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits 

for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the 

Purchased 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 any 

ownership 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., the 

supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must 

be 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 economic 

reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy 

from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the 

definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the 

earliest 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 Less 

than 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 is 

one year or less. 

LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of 

service, 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" means 

Longer than one year but Less than five years. 

Line 

No. 

1 

Name of Company or Public Authority 

(Footnote Affiliations) 

(a) 

Arizona Public Service Company 

Statistical 


(b) 

SF 

FERC Rate 

Schedule or 

Tariff Number 

(c) 

WSPP-2 

Average 

Monthly Billing 

Demand (MW) 

(d) 

Actual Demand (MW) 

Average 

Average 

Monthly NCP Demand Monthly CP Demand 

(e) 

(f) 

2 

Barclays Bank PLC SF 

FERC Vol. 8 

3 

BE CA LLC SF 


4 

Bear Energy LP SF 


5 

Black Hills Power, Inc. 

SF 

WSPP-2 

6 

Bonneville Power Administration 

SF 

WSPP-2 

7 

BP Energy Company SF 


8 

CA Dept of Water Resources 

OS 

WSPP-2 

9 

CA Independent System Operator OS 

1 

10 

Calpine Energy Services LP SF 


11 

Cargill Power Markets, LLC 

SF 

WSPP-2 

12 

City of Anaheim 

SF 

WSPP-2 

13 

City of Burbank Water and Power 

SF 

WSPP-2 

14 

City of Pasadena 

SF 

WSPP-2 

Subtotal RQ 

0 

0 0 

Subtotal non-RQ 

0 

0 

0 

Total 

0 

0 

0 







(Mo, Da, Yr) 


04/18/2009 



























Line 

No. 

1 



City of Riverside 

(a) 

Statistical 


(b) 

SF 


Schedule or 

Tariff Number 

(c) 

WSPP-2 

Average 



(d) 


Average 

Average 


(e) 

(f) 

2 

Citigroup Energy, Inc. SF 


3 

ConocoPhillips Company SF 


4 

Constellation Energy Commodities Group SF 


5 

Coral Power, LLC SF 


6 

DB Energy Trading LLC SF 


7 

Dynegy Power Marketing, Inc. SF 


8 

EPCOR Energy Marketi ng (US) Inc. SF 


9 

Eugene Water & Electric Board 

SF 

WSPP-2 

10 

Fortis Energy Marketing & Trading GP SF 


11 

FPL Energy Power Marketing, Inc. 

SF 

WSPP-2 

12 

Gila River Power LLC 

SF 

WSPP-2 

13 

IBERDROLA Renewables, Inc. SF 


14 

Idaho Power Company 

SF 

WSPP-2 

Subtotal RQ 

0 

0 0 


0 

0 

0 

Total 

0 

0 

0 







(Mo, Da, Yr) 


04/18/2009 



























Line 

No. 

1 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

J. Aron & Company SF 


Average 



(d) 


Average 

Average 


(e) 

(f) 

2 

J.P. Morgan Ventures Energy Corporation SF 


3 

Lehman Brothers Commodity Services Inc. SF 


4 

Los Angeles Dept of Water & Power 

SF 

WSPP-2 

5 

Macquarie Cook Power Inc. SF 


6 

Mirant Energy Trading LLC SF 


7 

Morgan Stanley Capital Group, Inc. SF 


8 

N. American Credit & Clearing-Contract SF 


9 

Northern California Power Agency 

SF 

WSPP-2 

10 

NRG Power Marketing Inc. SF 


11 

NRG Power Marketing LLC SF 


12 

Occidental Power Services, Inc. SF 


13 

Pacific Gas & Electric Company 

SF 

WSPP-2 

14 

PacifiCorp SF 


Subtotal RQ 

0 

0 0 


0 

0 

0 

Total 

0 

0 

0 







(Mo, Da, Yr) 


04/18/2009 



























Line 

No. 

1 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Pacific Summit Energy LLC SF 


Average 



(d) 


Average 

Average 


(e) 

(f) 

2 

Portland General Electric Company SF 


3 

Powerex Corp SF 


4 

PPM Energy, Inc. SF 


5 

Public Service Co. of Colorado 

SF 

WSPP-2 

6 

Public Service Co. of New Mexico 

SF 

WSPP-2 

7 

Puget Sound Energy, Inc. 

SF 

WSPP-2 

8 

Reliant Energy Services, Inc. SF 


9 

Sacramento Municipal Utility District 

SF 

WSPP-2 

10 

Salt River Project Agricultural Imprvmt 

SF 

WSPP-2 

11 

San Diego Gas & Electric Company 

SF 

WSPP-2 

12 

Seattle City Light 

SF 

WSPP-2 

13 

Sempra Energy Solutions SF 


14 

Sempra Energy Trading LLC SF 


Subtotal RQ 

0 

0 0 


0 

0 

0 

Total 

0 

0 

0 







(Mo, Da, Yr) 


04/18/2009 



























Line 

No. 

1 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Sempra Generation SF 


Average 



(d) 


Average 

Average 


(e) 

(f) 

2 

Shell Energy North America (US) Inc SF 


3 

Snohomish County Public Utility Distri1 

SF 

WSPP-2 

4 

Tacoma Power 

SF 

WSPP-2 

5 

TransAlta Energy Marketing (US), Inc. 

SF 

WSPP-2 

6 

UBS AG SF 


7 

WAPA-WASN-Western Area Sierra NV Rgn SF 


8 

9 

10 

11 

12 

13 

14 

Subtotal RQ 

0 

0 0 


0 

0 

0 

Total 

0 

0 

0 







(Mo, Da, Yr) 


04/18/2009 

SALES FOR RESALE (Account 447) (Continued) 



OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all 

non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 

of 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 reporting 

years. 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 under 

which 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 the 

average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average 

monthly 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 maximum 

metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during 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. 

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, including 

out-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 on 

the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 

401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 

401,iine 24. 

10. Footnote entries as required and provide explanations following all required data. 

MegaWatt Hours 

REVENUE 

Total ($) Line 

Sold 

Demand Charges Energy Charges Other Charges 

(h+i+j) 

No. 

($) ($) ($) 

(g) 

(h) 

(i) 

(j) 

(k) 

4,460 197,299 197,299 1 

443,255 30,634,417 30,634,417 2 

65 3,657 3,657 3 

55,385 3,822,200 3,822,200 4 

6,367 205,069 205,069 5 

94,281 4,920,755 4,920,755 6 

25,582 1,310,831 1,310,831 7 

144,374 8,399,909 8,399,909 8 

2,425,457 164,213,576 164,213,576 9 

38,349 1,800,150 1,800,150 10 

179,759 10,517,533 10,517,533 11 

393 69,225 69,225 12 

3,881 174,252 174,252 13 

184 16,094 16,094 14 

0 

0 

0 

0 0 

8,768,588 

0 

579,994,827 

0 

579,994,827 

8,768,588 

0 

579,994,827 

0 

579,994,827 







(Mo, Da, Yr) 


04/18/2009 




























401,iine 24. 



Sold 

(g) 

REVENUE 



(h+i+j) 

No. 

($) ($) ($) 

(h) 

(i) 

(j) 

(k) 

455 31,442 31,442 1 

498,072 35,996,621 35,996,621 2 

162,050 10,529,609 10,529,609 3 

73,013 5,225,927 5,225,927 4 

-2,492 -12,494 -12,494 5 

63,346 4,023,397 4,023,397 6 

174,910 9,443,119 9,443,119 7 

566 82,776 82,776 8 

36 9 

233,860 15,845,416 15,845,416 10 

78,147 4,933,698 4,933,698 11 

47,246 604,379 604,379 12 

231,218 15,477,471 15,477,471 13 

6 348 348 14 

0 

0 

0 

0 0 

8,768,588 

0 

579,994,827 

0 

579,994,827 

8,768,588 

0 

579,994,827 

0 

579,994,827 







(Mo, Da, Yr) 


04/18/2009 




























401,iine 24. 



REVENUE 


Sold 


(h+i+j) 

No. 

($) ($) ($) 

(g) 

(h) 

(i) 

(j) 

(k) 

56,452 3,374,174 3,374,174 1 

103,803 7,496,004 7,496,004 2 

1,056 73,469 73,469 3 

22,151 1,194,431 1,194,431 4 

6,962 312,592 312,592 5 

12,192 767,090 767,090 6 

539,793 35,249,514 35,249,514 7 

241,021 20,037,996 20,037,996 8 

8,516 570,901 570,901 9 

-581 -36,140 -36,140 10 

3,247 266,553 266,553 11 

51,587 3,305,115 3,305,115 12 

789,745 56,559,594 56,559,594 13 

136,520 5,980,142 5,980,142 14 

0 

0 

0 

0 0 

8,768,588 

0 

579,994,827 

0 

579,994,827 

8,768,588 

0 

579,994,827 

0 

579,994,827 







(Mo, Da, Yr) 


04/18/2009 




























401,iine 24. 



REVENUE 


Sold 


(h+i+j) 

No. 

($) ($) ($) 

(g) 

(h) 

(i) 

(j) 

(k) 

109,239 7,879,924 7,879,924 1 

14,885 887,909 887,909 2 

207,670 11,858,622 11,858,622 3 

-39,444 -2,419,692 -2,419,692 4 

43,308 1,950,517 1,950,517 5 

5,598 -489,704 -489,704 6 

4,469 327,933 327,933 7 

91,417 5,221,858 5,221,858 8 

45,150 3,438,153 3,438,153 9 

42,887 2,257,928 2,257,928 10 

151,109 9,400,492 9,400,492 11 

6,030 386,125 386,125 12 

23,929 1,361,925 1,361,925 13 

361,694 24,277,527 24,277,527 14 

0 

0 

0 

0 0 

8,768,588 

0 

579,994,827 

0 

579,994,827 

8,768,588 

0 

579,994,827 

0 

579,994,827 







(Mo, Da, Yr) 


04/18/2009 




























401,iine 24. 



REVENUE 


Sold 


(h+i+j) 

No. 

($) ($) ($) 

(g) 

(h) 

(i) 

(j) 

(k) 

59,524 3,400,754 3,400,754 1 

494,072 34,076,249 34,076,249 2 

546 27,098 27,098 3 

22 4 

157,626 10,043,995 10,043,995 5 

34,090 2,485,074 2,485,074 6 

78 4,029 4,029 7 

8 

9 

10 

11 

12 

13 

14 

0 

0 

0 

0 0 

8,768,588 

0 

579,994,827 

0 

579,994,827 

8,768,588 

0 

579,994,827 

0 

579,994,827 








(Mo, Da, Yr) 

04/18/2009 

ELECTRIC OPERATION AND MAINTENANCE EXPENSES 

If the amount for previous year is not derived from previously reported figures, explain in footnote. 

Line 

Account 

Amount for 

Current Year 

No. 

(a) 

(b) 



Amount for 

Previous Year 

(c) 

1 1. POWER PRODUCTION EXPENSES 

2 A. Steam Power Generation 

3 Operation 

4 (500) Operation Supervision and Engineering 

2,575,878 

2,628,885 

5 (501) Fuel 

96,080,577 

76,616,984 

6 (502) Steam Expenses 

8,133,878 

7,967,468 

7 (503) Steam from Other Sources 

8 (Less) (504) Steam Transferred-Cr. 

9 (505) Electric Expenses 

852,676 

958,338 

10 (506) Miscellaneous Steam Power Expenses 

15,133,191 

5,636,194 

11 (507) Rents 

-76,629 

228,126 

12 (509) Allowances 

13 TOTAL Operation (Enter Total of Lines 4 thru 12) 

122,699,571 

94,035,995 

14 Maintenance 

15 (510) Maintenance Supervision and Engineering 

794,180 

1,397,212 

16 (511) Maintenance of Structures 

1,153,271 

1,108,960 

17 (512) Maintenance of Boiler Plant 

15,812,983 

11,043,766 

18 (513) Maintenance of Electric Plant 

4,411,238 

3,196,372 

19 (514) Maintenance of Miscellaneous Steam Plant 

5,175,021 

3,257,687 

20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 

27,346,693 

20,003,997 

21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 

150,046,264 

114,039,992 

22 B. Nuclear Power Generation 

23 Operation 


70,043,605 

66,445,100 

25 (518) Fuel 

87,961,874 

88,310,153 

26 (519) Coolants and Water 

3,643,633 

5,419,623 

27 (520) Steam Expenses 

30,610,175 

25,066,623 

28 (521) Steam from Other Sources 

29 (Less) (522) Steam Transferred-Cr. 


10,889,549 

11,950,792 

31 (524) Miscellaneous Nuclear Power Expenses 

109,228,026 

97,467,587 

32 (525) Rents 

4,994,706 

1,601,651 

33 TOTAL Operation (Enter Total of lines 24 thru 32) 

317,371,568 

296,261,529 



32,567,432 

23,384,988 


12,800,172 

15,365,306 

37 (530) Maintenance of Reactor Plant Equipment 

52,046,048 

38,474,650 


27,546,200 

20,394,161 

39 (532) Maintenance of Miscellaneous Nuclear Plant 

35,438,944 

25,882,710 

40 TOTAL Maintenance (Enter Total of lines 35 thru 39) 

160,398,796 

123,501,815 

41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 

477,770,364 

419,763,344 

42 C. Hydraulic Power Generation 

43 Operation 


4,690,323 

4,285,284 

45 (536) Water for Power 

926,262 

3,191,636 

46 (537) Hydraulic Expenses 

2,652,708 

3,406,399 


3,216,360 

3,284,060 

48 (539) Miscellaneous Hydraulic Power Generation Expenses 

11,324,888 

9,226,104 

49 (540) Rents 

210,788 

1,035,960 

50 TOTAL Operation (Enter Total of Lines 44 thru 49) 

23,021,329 

24,429,443 

51 C. Hydraulic Power Generation (Continued) 


53 (541) Mainentance Supervision and Engineering 

1,878,091 

1,579,695 


1,402,762 

2,265,170 

55 (543) Maintenance of Reservoirs, Dams, and Waterways 

2,773,644 

3,580,347 


5,066,631 

6,080,529 

57 (545) Maintenance of Miscellaneous Hydraulic Plant 

2,555,812 

2,203,700 


13,676,940 

15,709,441 

59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 

36,698,269 

40,138,884 








(Mo, Da, Yr) 

04/18/2009 

ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) 


Line 

Account 

Amount for 

Current Year 

No. 

(a) 

(b) 



Amount for 

Previous Year 

(c) 

60 D. Other Power Generation 

61 Operation 


1,389,619 

146,915 

63 (547) Fuel 

10,136,606 

9,281,318 

64 (548) Generation Expenses 

2,743,310 

1,230,759 

65 (549) Miscellaneous Other Power Generation Expenses 

12,265,865 

13,218,571 

66 (550) Rents 

1,083,234 

-18,356 


27,618,634 

23,859,207 



397,892 

135,319 


-49,637 

13,161 

71 (553) Maintenance of Generating and Electric Plant 

2,683,761 

1,766,074 

72 (554) Maintenance of Miscellaneous Other Power Generation Plant 

1,116,949 

187,912 


4,148,965 

2,102,466 

74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 

31,767,599 

25,961,673 

75 E. Other Power Supply Expenses 

76 (555) Purchased Power 

5,724,208,212 

4,237,598,323 

77 (556) System Control and Load Dispatching 

836,686 

681,953 

78 (557) Other Expenses 

69,451,331 

83,314,166 

79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 

5,794,496,229 

4,321,594,442 

80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 

6,490,778,725 

4,921,498,335 

81 2. TRANSMISSION EXPENSES 

82 Operation 


14,507,225 

13,849,919 

84 (561) Load Dispatching 

26,475 

3,537,331 

85 (561.1) Load Dispatch-Reliability 

352,424 

1,205,062 

86 (561.2) Load Dispatch-Monitor and Operate Transmission System 

5,245,467 

4,358,549 

87 (561.3) Load Dispatch-Transmission Service and Scheduling 

88 (561.4) Scheduling, System Control and Dispatch Services 

39,230,455 

37,140,274 

89 (561.5) Reliability, Planning and Standards Development 

3,666,585 

3,286,720 

90 (561.6) Transmission Service Studies 

91 (561.7) Generation Interconnection Studies 

92 (561.8) Reliability, Planning and Standards Development Services 

2,966,100 

6,253,413 

93 (562) Station Expenses 

19,419,818 

19,091,878 

94 (563) Overhead Lines Expenses 

5,674,986 

6,593,595 

95 (564) Underground Lines Expenses 

1,063,642 

1,231,033 

96 (565) Transmission of Electricity by Others 

5,121,271 

5,660,734 

97 (566) Miscellaneous Transmission Expenses 

144,147,689 

139,606,958 

98 (567) Rents 

2,959,159 

3,201,635 


244,381,296 

245,017,101 



2,238,923 

2,269,081 


889,823 

539,810 

103 (569.1) Maintenance of Computer Hardware 

1,923,814 

1,403,022 

104 (569.2) Maintenance of Computer Software 

78,866 

76,777 

105 (569.3) Maintenance of Communication Equipment 

1,557,846 

1,803,299 

106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 

107 (570) Maintenance of Station Equipment 

3,849,741 

7,455,756 

108 (571) Maintenance of Overhead Lines 

16,271,570 

22,155,210 

109 (572) Maintenance of Underground Lines 

1,052,629 

441,420 

110 (573) Maintenance of Miscellaneous Transmission Plant 

1,651,269 

2,685,659 

111 TOTAL Maintenance (Total of lines 101 thru 110) 

29,514,481 

38,830,034 

112 TOTAL Transmission Expenses (Total of lines 99 and 111) 

273,895,777 

283,847,135 








(Mo, Da, Yr) 

04/18/2009 



Line 

Account 

Amount for 

Current Year 

No. 

(a) 

(b) 



Amount for 

Previous Year 

(c) 

113 3. REGIONAL MARKET EXPENSES 

114 Operation 

115 (575.1) Operation Supervision 

116 (575.2) Day-Ahead and Real-Time Market Facilitation 

117 (575.3) Transmission Rights Market Facilitation 

118 (575.4) Capacity Market Facilitation 

119 (575.5) Ancillary Services Market Facilitation 

120 (575.6) Market Monitoring and Compliance 

121 (575.7) Market Facilitation, Monitoring and Compliance Services 

14,748,260 

8,722,797 

122 (575.8) Rents 

123 Total Operation (Lines 115 thru 122) 

14,748,260 

8,722,797 


125 (576.1) Maintenance of Structures and Improvements 

126 (576.2) Maintenance of Computer Hardware 

127 (576.3) Maintenance of Computer Software 

128 (576.4) Maintenance of Communication Equipment 

129 (576.5) Maintenance of Miscellaneous Market Operation Plant 

130 Total Maintenance (Lines 125 thru 129) 

131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 

14,748,260 

8,722,797 

132 4. DISTRIBUTION EXPENSES 

133 Operation 


9,493,116 

6,632,015 

135 (581) Load Dispatching 

136 (582) Station Expenses 

21,256,151 

21,195,532 

137 (583) Overhead Line Expenses 

22,186,258 

23,389,013 

138 (584) Underground Line Expenses 

2,738,056 

4,156,612 

139 (585) Street Lighting and Signal System Expenses 

730,629 

726,374 

140 (586) Meter Expenses 

26,002,616 

29,367,471 

141 (587) Customer Installations Expenses 

22,049,664 

20,399,589 

142 (588) Miscellaneous Expenses 

66,859,369 

103,512,733 

143 (589) Rents 

683,257 

748,928 


171,999,116 

210,128,267 



785,808 

1,720,159 


384,930 

702,482 

148 (592) Maintenance of Station Equipment 

7,668,115 

9,841,682 

149 (593) Maintenance of Overhead Lines 

88,616,391 

95,283,638 

150 (594) Maintenance of Underground Lines 

32,321,226 

15,988,295 

151 (595) Maintenance of Line Transformers 

3,784,913 

2,462,220 

152 (596) Maintenance of Street Lighting and Signal Systems 

6,783,561 

6,963,379 

153 (597) Maintenance of Meters 

1,590,237 

2,270,797 

154 (598) Maintenance of Miscellaneous Distribution Plant 

32,046,989 

34,731,548 

155 TOTAL Maintenance (Total of lines 146 thru 154) 

173,982,170 

169,964,200 

156 TOTAL Distribution Expenses (Total of lines 144 and 155) 

345,981,286 

380,092,467 

157 5. CUSTOMER ACCOUNTS EXPENSES 

158 Operation 

159 (901) Supervision 

14,169,451 

12,203,913 

160 (902) Meter Reading Expenses 

43,361,991 

42,144,263 

161 (903) Customer Records and Collection Expenses 

104,188,572 

110,628,783 

162 (904) Uncollectible Accounts 

28,680,638 

19,452,587 

163 (905) Miscellaneous Customer Accounts Expenses 

16,992,932 

16,256,037 

164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 

207,393,584 

200,685,583 








(Mo, Da, Yr) 

04/18/2009 



Line 

Account 

Amount for 

Current Year 

No. 

(a) 

(b) 



Amount for 

Previous Year 

(c) 

165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 

166 Operation 


41,907,628 

11,478,655 

168 (908) Customer Assistance Expenses 

417,978,101 

364,032,497 

169 (909) Informational and Instructional Expenses 

28,666,347 

31,679,126 

170 (910) Miscellaneous Customer Service and Informational Expenses 

42,516,102 

61,731,309 

171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 

531,068,178 

468,921,587 

172 7. SALES EXPENSES 

173 Operation 


1,467,468 

175 (912) Demonstrating and Selling Expenses 

5,104,659 

5,528,263 

176 (913) Advertising Expenses 

9,699,543 

12,188,328 

177 (916) Miscellaneous Sales Expenses 

693,106 

369,813 

178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 

16,964,776 

18,086,404 

179 8. ADMINISTRATIVE AND GENERAL EXPENSES 

180 Operation 

181 (920) Administrative and General Salaries 

378,987,725 

331,703,992 

182 (921) Office Supplies and Expenses 

157,971,038 

113,417,631 

183 (Less) (922) Administrative Expenses Transferred-Credit 

64,049,993 

52,644,593 

184 (923) Outside Services Employed 

49,216,322 

59,810,445 

185 (924) Property Insurance 

7,957,004 

7,308,346 

186 (925) Injuries and Damages 

50,286,586 

71,238,203 

187 (926) Employee Pensions and Benefits 

216,464,570 

215,311,602 

188 (927) Franchise Requirements 

107,933,376 

105,730,685 

189 (928) Regulatory Commission Expenses 

12,625,126 

11,315,782 

190 (929) (Less) Duplicate Charges-Cr. 

191 (930.1) General Advertising Expenses 

11,756 

367,673 

192 (930.2) Miscellaneous General Expenses 

3,984,443 

5,701,972 

193 (931) Rents 

8,602,135 

9,290,787 


929,990,088 

878,552,525 


196 (935) Maintenance of General Plant 

12,308,049 

11,248,402 

197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 

942,298,137 

889,800,927 

198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 

8,823,128,723 

7,171,655,235 







(Mo, Da, Yr) 


04/18/2009 

PURCHASED POWER (Account 555) 

(Including power exchanges) 



1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of 

debits 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 use 

acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 



supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must 

be 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 for 

economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency 

energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service 

which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract 

defined 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 less 


SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one 

year or less. 

LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of 

service, 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" means 

longer 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 all 


of the service in a footnote for each adjustment. 

Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

NON ASSOCIATED UTILITIES: 

2 

SIERRA PACIFIC - FRINGE 

OS 

N/A 

3 

UNITED STATES DEPARTMENT OF THE 

OS 

N/A 

4 

INTERIOR - BUREAU INDIAN AFFAIRS 

5 

6 

COOPERATIVES: 

7 

VALLEY ELECTRIC ASSOCIATION, INC. RQ 218 

N/A 

N/A 

N/A 

8 

9 

MUNICIPALITIES: 

10 

ANAHEIM, CITY OF FRINGE 

OS 

N/A 

11 

BANNING, CITY OF FRINGE 

OS 

N/A 

12 

L A DEPT OF WTR & PWR FRINGE 

OS 

N/A 

13 

RIVERSIDE, CITY OF FRINGE 

OS 

N/A 

14 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

OTHER PUBLIC AUTHORITIES: 

2 

State of California, Department 

3 

Water Resources 

4 

U.S. DEPT OF ENERGY-WESTERN AREA LF 333 

277.5 

215.2 

161.0 

5 

U.S. DEPT OF THE INTERIOR-BUREAU OF OS 

N/A 

6 

RECLAMATION 

7 

WAPA-WALC-WESTERN AREA 

OS 

N/A 

8 

The Metropolitan Water District 

9 

of Southern California: 

10 

MWD CAPACITY / ENERGY SALE 

LF 

NON-FERC 

N/A 

N/A 

N/A 

11 

CONTRACT - 9 HYDRO PLANTS 

12 

MWD 1987 SERVICE / INTERCHANGE EX 203 

N/A 

N/A 

N/A 

13 

AGREEMENT-EXCHANGE ENERGY 

14 

MWD 1987 SERVICE / INTERCHANGE EX 203 

N/A 

N/A 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

AGREEMENT-BENEFIT ENERGY 

2 

PASADENA, CITY OF - EXCH ENGY EX 317 

N/A 

N/A 

N/A 

3 

RETURNED ENERGY - LADWP 

4 

5 

NEW BILATERAL DETAIL: 

6 

CITIGROUP ENERGY INC. SF FERC Vol. 8 

N/A 

7 

COMMERCE ENERGY INC. SF FERC Vol. 8 

N/A 

8 

DB ENERGY TRADING LLC SF FERC Vol. 8 

N/A 

9 

FORTIS ENERGY MKTG & TRADING SF FERC Vol. 8 

N/A 

10 

NO. CALIF. POWER AGENCY 

SF 

WSPP-2 

N/A 

11 

SEMPRA GENERATION SF FERC Vol. 8 

N/A 

12 

13 

Non-Associated Utilities: 

14 

ARIZONA PUBLIC SERVICE CO 

SF 

WSPP-2 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

FPL ENERGY POWER MARKETING 

SF 

WSPP-2 

N/A 

2 

PACIFIC GAS & ELECTRIC CO 

SF 

WSPP-2 

N/A 

3 

PACIFICORP SF FERC Vol. 8 

N/A 

4 

PORTLAND GENERAL ELECTRIC SF FERC Vol. 8 

N/A 

5 

PUBLIC SERVICE CO. OF COLORADO 

SF 

WSPP-2 

N/A 

6 

PUBLIC SERVICE CO. OF NEW MEXICO 

SF 

WSPP-2 

N/A 

7 

PUGET SOUND 

SF 

WSPP-2 

N/A 

8 

SAN DIEGO GAS & ELECTRIC 

SF 

WSPP-2 

N/A 

9 

SIERRA PACIFIC POWER CO. SF 904.14.0 

N/A 

10 

11 

Gas: 

12 

CHEVRON NATURAL GAS SF FERC Vol. 8 

N/A 

13 

ENSERCO ENERGY, INC. SF FERC Vol. 8 

N/A 

14 

KERN RIVER SF FERC Vol. 8 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

NO. AMERICAN CREDIT AND CLEARING SF FERC Vol. 8 

N/A 

2 

OCCIDENTAL ENERGY MARKETING, INC SF FERC Vol. 8 

N/A 

3 

PACIFIC GAS & ELECTRIC COMPANY - 

SF 

WSPP-2 

N/A 

4 

SOUTHERN CALIFORNIA GAS COMPANY SF FERC Vol. 8 

N/A 

5 

6 

Municipalities: 

7 

CITY OF ANAHEIM 

SF 

WSPP-2 

N/A 

8 

CITY OF BURBANK WATER AND POWER 

SF 

WSPP-2 

N/A 

9 

CITY OF PASADENA 

SF 

WSPP-2 

N/A 

10 

11 

Other Public Authorities: 

12 

BONNEVILLE POWER AUTHORITIES 

SF 

WSPP-2 

N/A 

13 

CALIF DEPT. WATER RESOURCES 

SF 

WSPP-2 

N/A 

14 

L.A.D.W.P. 

SF 

WSPP-2 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

POWEREX CORP. SF FERC Vol. 8 

N/A 

2 

SACRAMENTO MUN. UTIL. DISTRICT 

SF 

WSPP-2 

N/A 

3 

SALT RIVER PROJ. AGRIC. I 

SF 

WSPP-2 

N/A 

4 

SEATTLE CITY LIGHT MARKET 

SF 

WSPP-2 

N/A 

5 

6 

Tolling Units: 

7 

AES HUNTINGTON BEACH LLC LU FERC Vol. 8 

N/A 

8 

AES PLACERITA LU FERC Vol. 8 

N/A 

9 

BE CA LLC (FRMLY WILLIAMS POWER) LU FERC Vol. 8 

N/A 

10 

HARBOR CO GEN LU FERC Vol. 8 

N/A 

11 

LAPALOMA GENERATING CO. LU FERC Vol. 8 

N/A 

12 

MOUNTAINVIEW POWER LF FERC No. 1 

N/A 

13 

NRG LONG BEACH GENERATION LLC LU FERC Vol. 8 

N/A 

14 

NRG POWER MARKETING LU FERC No. 8 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

RELIANT ENERGY - ELLWOOD LU FERC Vol. 8 

N/A 

2 

RELIANT ENERGY - ETIWANDA LU FERC Vol. 8 

N/A 

3 

RELIANT ENERGY - MANDALAY LU FERC Vol. 8 

N/A 

4 

SAN JOAQUIN COGEN LU FERC Vol. 8 

N/A 

5 

VARIOUS SUPPLIERS 

SF 

N/A 

6 

7 

Brokers / Other: 

8 

AMEREX POWER 

OS 

N/A 

9 

ICAP 

OS 

N/A 

10 

INTERCONTINENTAL EXCHANGE 

OS 

N/A 

11 

IVG ENERGY, LTD 

OS 

N/A 

12 

JP MORGAN 

OS 

N/A 

13 

LANDMARK POWER EXCHANGE 

OS 

N/A 

14 

PREBON ENERGY 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

2 

Power Marketers Detail: 

3 

BARCLAYS BANK PLC SF FERC Vol. 8 

N/A 

4 

BEAR ENERGY LP SF FERC Vol. 8 

N/A 

5 

BP ENERGY COMPANY SF FERC Vol. 8 

N/A 

6 

CALPINE ENERGY SERVICES SF FERC Vol. 8 

N/A 

7 

CARGILL POWER MARKETS 

SF 

WSPP-2 

N/A 

8 

CONOCO PHILLIPS SF FERC Vol. 8 

N/A 

9 

CONSTELLATION POWER SOURCE SF FERC Vol. 8 

N/A 

10 

DYNEGY POWER MARKETING INC. LU FERC Vol. 8 

N/A 

11 

EPCOR ENERGY MKTG (US) IN SF FERC Vol. 8 

N/A 

12 

GILA RIVER POWER LLC SF FERC Vol. 8 

N/A 

13 

IBERDROLA RENEWABLES, INC SF FERC Vol. 8 

N/A 

14 

J. ARON & COMPANY SF FERC Vol. 8 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

J.P. MORGAN VENTURES ENERGY SF FERC Vol. 8 

N/A 

2 

LEHMAN BROTHERS COMMODITY SF FERC Vol. 8 

N/A 

3 

MACQUARIE COOK POWER INC SF FERC Vol. 8 

N/A 

4 

MIRANT ENERGY TRADING SF FERC Vol. 8 

N/A 

5 

MORGAN STANLEY CAPITAL GR SF FERC Vol. 8 

N/A 

6 

OCCIDENTAL SF FERC Vol. 8 

N/A 

7 

PACIFIC SUMMIT ENERGY SF FERC Vol. 8 

N/A 

8 

RELIANT ENERGY SERVICES SF FERC Vol. 8 

N/A 

9 

SEMPRA ENERGY SOLUTIONS SF FERC Vol. 8 

N/A 

10 

SEMPRA ENERGY TRADING LLC SF FERC Vol. 8 

N/A 

11 

SHELL ENERGY NO AMERICA US, L.P. SF FERC Vol. 8 

N/A 

12 

TRANSALTA ENERGY MARKETING 

SF 

WSPP-2 

N/A 

13 

UBS ENERGY LLC SF FERC Vol. 8 

N/A 

14 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

2 

NON UTILITIES: QUALIFYING FACILITY 

3 

ACE COGENERATION COMPANY 

OS 

N/A 

4 

ALTA MESA PWR PUR CONTRCT 

OS 

N/A 

5 

AMERICAN ENERGY INC. 

OS 

N/A 

6 

ANDERSON LITHOGRAPHIC CO 

OS 

N/A 

7 

BATES, DANIEL M, ET AL 

OS 

N/A 

8 

BERRY PETRO CO (NEWHALL I) 

OS 

N/A 

9 

BERRY PETROLEUM (NEWHALL II) 

OS 

N/A 

10 

BOX CAR I PPCT 

OS 

N/A 

11 

BOX CAR II PPCT 

OS 

N/A 

12 

CALLEGUAS MUN WTR DIST 

OS 

N/A 

13 

CALLEGUAS MWD 1-CONEJO 

OS 

N/A 

14 

CALLEGUAS MWD 2-CHATSWRTH 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

CALLEGUAS MWD 3-SNTA ROSA 

OS 

N/A 

2 

CALWIND RESOURCES INC 

OS 

N/A 

3 

CALWIND RESOURCES INC 

OS 

N/A 

4 

CAMBRIAN ENERGY WOODVILLE 

OS 

N/A 

5 

CAMERON RIDGE LLC III 

OS 

N/A 

6 

CAMERON RIDGE LLC IV 

OS 

N/A 

7 

CARSON COGENERATION 

OS 

N/A 

8 

CENTRAL HYDRO/ISABELLA 

OS 

N/A 

9 

CHEVRON USA #2 

OS 

N/A 

10 

CITY OF OXNARD 

OS 

N/A 

11 

CITY OF SANTA ANA 

OS 

N/A 

12 

CLAREMONT TENNIS CLUB 

OS 

N/A 

13 

CO SANITATION DIST-OR CO 

OS 

N/A 

14 

COLMAC ENERGY 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

COMMERCE REFUSE 

OS 

N/A 

2 

CORAM ENERGY GROUP LTD 

OS 

N/A 

3 

CORONA ENERGY PARTNRS LTD 

OS 

N/A 

4 

COSO ENERGY DEVELOPERS 

OS 

N/A 

5 

COSO FINANCE PARTNERS 

OS 

N/A 

6 

COSO POWER DEVELOPERS 

OS 

N/A 

7 

COUNTY SAN DIS OF OC 

OS 

N/A 

8 

CTV PPCT 

OS 

N/A 

9 

CURTIS, EDWIN 

OS 

N/A 

10 

DEEP SPRINGS COLLEGE 

OS 

N/A 

11 

DEL RANCH, LTD/NILAND 2 

OS 

N/A 

12 

DESERT POWER CO 

OS 

N/A 

13 

DESERT WATER AGCY/WHTEWTR 

OS 

N/A 

14 

DESERT WIND I PPCT 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

DESERT WIND II PPCT 

OS 

N/A 

2 

DESERT WIND III PPCT 

OS 

N/A 

3 

DESERT WTR AGCY/SNOWCREEK 

OS 

N/A 

4 

DIFWIND FARMS LTD V 

OS 

N/A 

5 

DIFWIND PARTNERS LTD 

OS 

N/A 

6 

DILLON ENERGY, INC 

OS 

N/A 

7 

DUTCH ENERGY 

OS 

N/A 

8 

ELMORE, LTD/NILAND 3 

OS 

N/A 

9 

ENERGY DEV & CONSTR CORP 

OS 

N/A 

10 

EUI MANAGEMENT PH, INC. 

OS 

N/A 

11 

EXXON COMPANY, USA 

OS 

N/A 

12 

GENERATING RES REC PTNRS 

OS 

N/A 

13 

GEYSERS POWER CO LLC QFID 

OS 

N/A 

14 

GOLETA WATER DISTRICT 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

HEBER GEOTHERMAL CO 

OS 

N/A 

2 

HENWOOD ASSOC/MILLNER CR 

OS 

N/A 

3 

HI HEAD HYDRO, INC 

OS 

N/A 

4 

IMPERIAL VALLEY RES RECOVERY 

OS 

N/A 

5 

IRVINE RANCH WATER DIST 

OS 

N/A 

6 

KAWEAH RIVER POWER AUTH 

OS 

N/A 

7 

KERN RIVER COGENERATION 

OS 

N/A 

8 

L A CO SAN #2 (P HILLS A) 

OS 

N/A 

9 

L A CO SAN #2 (P HILLS B) 

OS 

N/A 

10 

L A CO SAN #2 (P VERDES) 

OS 

N/A 

11 

L A CO SAN #2 (SPADRA) 

OS 

N/A 

12 

L A, COUNTY OF 

OS 

N/A 

13 

LEATHERS, L P (NILAND 4) 

OS 

N/A 

14 

LIBERTY LC 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

LOMA LINDA UNIV #1 

OS 

N/A 

2 

LONG BEACH, CITY OF/SERRF 

OS 

N/A 

3 

LOWER TULE RIVER IRRIG 

OS 

N/A 

4 

LUZ SOLAR PARTNERS III 

OS 

N/A 

5 

LUZ SOLAR PARTNERS IV 

OS 

N/A 

6 

LUZ SOLAR PARTNERS IX 

OS 

N/A 

7 

LUZ SOLAR PARTNERS V 

OS 

N/A 

8 

LUZ SOLAR PARTNERS VI 

OS 

N/A 

9 

LUZ SOLAR PARTNERS VII 

OS 

N/A 

10 

LUZ SOLAR PARTNERS VIII 

OS 

N/A 

11 

MAMMOTH PACIFIC #1 

OS 

N/A 

12 

MAMMOTH PACIFIC #2 

OS 

N/A 

13 

MIDWAY SUNSET COGEN 

OS 

N/A 

14 

MM TAJIGUAS ENERGY LLC 1 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

MOJAVE COGENERATION CO 

OS 

N/A 

2 

MONTE VISTA WATER DIST 

OS 

N/A 

3 

MOSS, RICHARD 

OS 

N/A 

4 

MWD CORONA 

OS 

N/A 

5 

MWD RED MOUNTAIN 

OS 

N/A 

6 

MWD TEMESCAL 

OS 

N/A 

7 

MWD VENICE 

OS 

N/A 

8 

NAWD INC (EAST WINDS PRO) 

OS 

N/A 

9 

OAK CREEK ENGY SYS INC II 

OS 

N/A 

10 

OLS ENERGY - CAMARILLO 

OS 

N/A 

11 

OLS ENERGY - CHINO 

OS 

N/A 

12 

ONTARIO COGENERATION 

OS 

N/A 

13 

ORMESA GEOTHERMAL 1 #310 

OS 

N/A 

14 

OXNARD, E F, INC 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

PAINTED HILLS WIND DEV 

OS 

N/A 

2 

PALM SPRINGS 

OS 

N/A 

3 

PALM SPRINGS 

OS 

N/A 

4 

PROCTER & GAMBLE/OXNARD 2 

OS 

N/A 

5 

RANCHO SIMI PROJ #1 

OS 

N/A 

6 

RANCHO SIMI PROJ #2 

OS 

N/A 

7 

RHODIA, INC 

OS 

N/A 

8 

RIDGETOP ENERGY, LLC I 

OS 

N/A 

9 

RIDGETOP ENERGY, LLC II 

OS 

N/A 

10 

RIMROCK VILLAGE PTNRSHP 

OS 

N/A 

11 

RIO BRAVO JASMIN 

OS 

N/A 

12 

RIPON COGENERATION, INC. 

OS 

N/A 

13 

ROYAL FARMS 

OS 

N/A 

14 

S & L RANCH 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

SALTON SEA IV 

OS 

N/A 

2 

SALTON SEA POWER GEN #1 

OS 

N/A 

3 


OS 

N/A 

4 


OS 

N/A 

5 

SAN BERNARDINO MWD 1 

OS 

N/A 

6 

SAN BERNARDINO MWD 3 

OS 

N/A 

7 

SAN GORGONIO WIND FARMS 

OS 

N/A 

8 

SEC 16-29 TRUST -ALT III 

OS 

N/A 

9 

SEC 7 TRST/WHITEWATER II 

OS 

N/A 

10 

SECOND IMPERIAL GEO CO 

OS 

N/A 

11 

SECTION 20 TRUST 

OS 

N/A 

12 

SECTION 22 TRUST (SN JAC) 

OS 

N/A 

13 

SKY RVR PTNRSHP-WILD I 

OS 

N/A 

14 

SKY RVR PTNRSHP-WILD II 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

SKY RVR PTNRSHP-WILD III 

OS 

N/A 

2 

SO END RACQUET & HLTH 

OS 

N/A 

3 

SUNRAY ENERGY, INC. 

OS 

N/A 

4 

SYCAMORE COGENERATION 

OS 

N/A 

5 

TEHACHAPI PWR PUR TRUST 

OS 

N/A 

6 

THE BANK OF NY TRUST CO 

OS 

N/A 

7 

THE BANK OF NY TRUST CO 

OS 

N/A 

8 

THE TERMO COMPANY 

OS 

N/A 

9 

THREE VALLEYS MWD FULRTN 

OS 

N/A 

10 

THREE VALLEYS MWD MIRAMAR 

OS 

N/A 

11 

THREE VALLEYS MWD WILLMS 

OS 

N/A 

12 

U S BORAX & CHEMICAL 

OS 

N/A 

13 

UNITED WATER CONSERV DST 

OS 

N/A 

14 

VENTURA REGIONAL SANITATION 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

VICTORY GARDEN/PHASE IV 

OS 

N/A 

2 


OS 

N/A 

3 


OS 

N/A 

4 

VULCAN/BN GEOTHERMAL 

OS 

N/A 

5 

W.M. ENERGY SOLUTIONS,INC 

OS 

N/A 

6 

W.M.ENERGY SOLUTIONS,INC. 

OS 

N/A 

7 

WALNUT VALLEY WATER DIST 

OS 

N/A 

8 

WATSON COGENERATION 

OS 

N/A 

9 

WESTWIND TRUST 

OS 

N/A 

10 

WHEELABRATOR NORWALK 

OS 

N/A 

11 

WINDPOWER PTNRS 1993 LP 

OS 

N/A 

12 

WINDPOWER PTNRS/WH WTR 

OS 

N/A 

13 

WINDRIDGE/WILLOW WIND 

OS 

N/A 

14 

WINDSONG ENERGY 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

ZEPHYR PARK, LTD 

OS 

N/A 

2 

AES TEHACHAPI WIND, LLC 85-A 

OS 

N/A 

3 

AES TEHACHAPI WIND, LLC 85-B 

OS 

N/A 

4 

AES TEHACHAPI WIND, LLC 

OS 

N/A 

5 

AES TEHACHAPI WIND, LLC (VG #1) 

OS 

N/A 

6 


OS 

N/A 

7 


OS 

N/A 

8 


OS 

N/A 

9 

CORAM ENERGY LLC (ECT) 

OS 

N/A 

10 

CRIMSON RESOURCE MANAGEMENT 

OS 

N/A 

11 

DCOR, LLC 

OS 

N/A 

12 

EDOM HILLS PROJECT 1, LLC 

OS 

N/A 

13 

FPL ENERGY CABAZON WIND, LLC 

OS 

N/A 

14 

HANSON AGGREGATES WRP, LLC 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

INLAND EMPIRE UTILITIES AGENCY 

OS 

N/A 

2 

LA CO FLOOD CONTROL DISTRICT 

OS 

N/A 

3 

MAMMOTH PACIFIC L.O.1 (PLES) 

OS 

N/A 

4 

MESA WIND POWER CORP 

OS 

N/A 

5 

MOGUL ENERGY PARTNERSHIP I 

OS 

N/A 

6 

MONTECITO WATER DISTRICT 

OS 

N/A 

7 

SAN GORGONIO WESTWINDS II, LLC 

OS 

N/A 

8 

SEARLES VAL MINERALS OPERATIONS, 

OS 

N/A 

9 

SEARLES VAL MINERALS OPERATIONS, 

OS 

N/A 

10 

TERRA-GEN 251 WIND, LLC (MONOLITCH 

OS 

N/A 

11 

TERRA-GEN 251 WIND, LLC (MONOLITCH 

OS 

N/A 

12 

TERRA-GEN 251 WIND,LLC (MONOLITCH 

OS 

N/A 

13 

TERRA-GEN 251 WIND,LLC (MONOLITCH 

OS 

N/A 

14 

TERRA-GEN DIXIE VALLEY, LLC 

OS 

N/A 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

TIN INC dba TEMPLE-INLAND 

OS 

N/A 

2 

TOYON LANDFILL GAS CONVERSION, LLC OS 

N/A 

3 

WEYERHAEUSER CO 

OS 

N/A 

4 

WINDPOWER PARTNERS 193, L.P. 

OS 

N/A 

5 

6 

7 

CALIFORNIA ISO - NET 

8 

INDEPENDENT EVALUATOR COSTS 

9 

VARIOUS ENERGY SETTLEMENT 

10 

REFUNDS 

11 

LEASE CONVERSION 

12 

WECC STATUTORY COSTS 

13 

HEDGING INSTRUMENTS 

14 

ACCRUAL FOR ENERGY EXCHANGE 

Total 







(Mo, Da, Yr) 


04/18/2009 





















year or less. 










Line 

No. 



(a) 

Statistical 


(b) 


Schedule or 

Tariff Number 

(c) 

Average 



(d) 


Average 

Average 


(e) 

(f) 

1 

VARIOUS QF BUYOUTS / BRPU 

2 

SETTLEMENTS 

3 

RENEWABLE ENERGY CREDITS 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

Total 







(Mo, Da, Yr) 


04/18/2009 

PURCHASED POWER(Account 555) (Continued) 




AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting 


4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate 

designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as 

identified 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, enter 

the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the 

average monthly 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 maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand 

during 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 megawatthours 

of 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, including 

out-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 settlement 

amount 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 the 

agreement, 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 be 

reported 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. 


POWER EXCHANGES 


MegaWatt Hours MegaWatt Hours 

Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

188 

1,183 

140 

61 

1,395 

131 

COST/SETTLEMENT OF POWER 

Line 

Demand Charges Energy Charges Other Charges Total (j+k+l) No. 

($) ($) ($) 

of Settlement ($) 

(j) 

(k) 

(l) 

(m) 

1 

13,876 13,876 2 

98,410 98,410 3 

4 

5 

6 

10,800 10,800 7 

37,833 37,833 10 

10,675 10,675 11 

139,525 139,525 12 

14,404 14,404 13 

14 

8 

9 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 





























Purchased 

(g) 

106,442 

11,895 

83,950 



Received 

(h) 


Delivered 

(i) 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

1 

2 

3 

4,820,688 2,472,816 7,293,504 4 

60,479 60,479 5 

930,628 930,628 7 

8 

9 

1,068,936 2,854,026 3,922,962 10 

11 

141,056 213,715 

12 

328,761 14 

6 

13 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 





























Purchased 

(g) 

971,471 

-333 

242,163 

349,165 

5,520 

199,678 

23,607 



Line 

MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) No. 

Received 

Delivered 

($) ($) ($) 


(h) 

(i) 

(j) 

(k) 

(l) 

(m) 

1 

2,042 94 

2 

146,745 11,263,302 11,263,302 3 

77,990,830 7 77,990,837 6 

-1,043,100 -1,043,100 7 

17,372,526 17,372,526 8 

26,496,235 26,496,235 9 

445,880 445,880 10 

16,600,361 16,600,361 11 

12 

13 

343,250 53,662 396,912 14 

4 

5 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

313,972 

179,710 

71,330 

22,110 

6,400 

12,825 

4,250 

10,062 

54 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

26,172,617 26,172,617 1 

14,658,735 14,658,735 2 

5,989,810 5,989,810 3 

1,642,156 1,642,156 4 

540,840 540,840 5 

552,023 552,023 6 

354,800 354,800 7 

923,154 923,154 8 

344 344 9 

10 

11 

-165,872 -165,872 12 

-934,654 -934,654 13 

774,985 774,985 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

356,200 

5,075 

1,400 

72 

78,703 

304,373 

650 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

29,952,980 29,952,980 1 

-40,656 -40,656 2 

116 116 3 

6,003,438 6,003,438 4 

339,400 339,400 7 

86,900 86,900 8 

6,319 6,319 9 

10 

11 

6,073,650 6,073,650 12 

25,859,026 25,859,026 13 

65,227 65,227 14 

5 

6 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

833,829 

20,050 

59,499 

2,135 

929,366 

2,367,527 

19,468 

6,698,160 

2,367 

108,324 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

2,754,000 70,478,786 73,232,786 1 

1,619,616 1,619,616 2 

3,339,064 3,339,064 3 

154,305 154,305 4 

5 

6 

21,334,237 51,265,280 2,148,235 74,747,752 7 

-45,124 -55,425 2,490,504 2,389,955 8 

228,089,337 199,522,358 -60,573,999 367,037,696 9 

1,120,784 1,852,566 -189,576 2,783,774 10 

333,801 333,801 11 

527,355,808 22,087,887 549,443,695 12 

26,553,825 1,857,691 -1,962,579 26,448,937 13 

11,037,443 10,290,534 -760,079 20,567,898 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

955 

838,778 

1,140 

5,916 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

3,420,343 147,287 -4,382 3,563,248 1 

56,130,407 81,275,799 -9,638,726 127,767,480 2 

6,808,949 238,974 10,917 7,058,840 3 

4,009,234 663,322 -36,633 4,635,923 4 

23,497,679 23,497,679 5 

190,885 190,885 8 

138,039 138,039 9 

98,258 98,258 10 

6,875 6,875 11 

2,040,074 2,040,074 12 

272,914 272,914 13 

712 712 14 

6 

7 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

1,808,562 

58,913 

9,000 

177,718 

219,678 

828,763 

68,903 

327,771 

400 

44,260 

170,272 

146,200 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

1 

2 

135,718,288 135,718,288 3 

5,362,550 5,362,550 4 

724,323 724,323 5 

16,212,537 24,418,800 40,631,337 6 

18,061,751 18,061,751 7 

68,662,431 -718,683 67,943,748 8 

5,598,139 5,598,139 9 

29,292,332 29,292,332 10 

34,801 34,801 11 

2,755,629 2,755,629 12 

900,000 13,432,303 14,332,303 13 

14,640,000 12,453,372 27,093,372 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

205,371 

13,600 

8,000 

39,425 

806,915 

66,500 

105,384 

835,808 

36,075 

417,121 

922,048 

282,663 

69,374 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

17,637,893 17,637,893 1 

1,298,120 1,298,120 2 

419,700 419,700 3 

3,473,753 3,473,753 4 

6,420,000 63,310,357 69,730,357 5 

5,530,965 1,384,500 6,915,465 6 

8,352,943 -1,414,498 6,938,445 7 

36,900,000 65,015,930 30,594,672 132,510,602 8 

2,394,823 -4,422,000 -2,027,177 9 

34,996,742 34,996,742 10 

15,195,000 67,649,573 3,853,598 86,698,171 11 

24,756,762 24,756,762 12 

7,500,000 5,733,331 13,233,331 13 

14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

780,700 

60,691 

745 

14,654 

539 

170,057 

139,145 

10,635 

20,901 

2,449 

493 

7,253 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

1 

2 

20,124,355 48,483,411 68,607,766 3 

1,457,890 5,434,845 6,892,735 4 

578 73,058 73,636 5 

6,437 1,279,398 1,285,835 6 

9,855 49,527 59,382 7 

3,971,646 14,679,785 18,651,431 8 

77,648 11,858,065 11,935,713 9 

202,586 995,623 1,198,209 10 

418,375 1,938,900 2,357,275 11 

1,969 223,541 225,510 12 

22,223 50,133 72,356 13 

161,690 651,167 812,857 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

1,400 

16,326 

53,554 

2,305 

143,850 

39,390 

357,417 

16,686 

1,866 

9 

24 

12 

360,172 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

38,067 130,013 168,080 1 

333,460 1,538,621 1,872,081 2 

26,991 4,717,555 4,744,546 3 

1,233 198,439 199,672 4 

2,607,691 8,846,195 11,453,886 5 

753,148 2,419,294 3,172,442 6 

8,220,513 32,372,621 40,593,134 7 

783,684 1,736,492 2,520,176 8 

196 138,333 138,529 9 

1 38 39 10 

1 620 621 11 

2 1,816 1,818 12 

1 980 981 13 

10,299,732 22,331,971 32,631,703 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

70,236 

11,053 

264,478 

498,068 

627,881 

592,250 

344 

33,913 

8 

6 

323,440 

1,322 

635 

83,514 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

1,809,253 6,756,092 8,565,345 1 

98,459 1,024,892 1,123,351 2 

6,834,653 23,266,065 30,100,718 3 

12,215,238 30,912,148 43,127,386 4 

13,619,261 38,866,328 52,485,589 5 

13,540,300 36,608,537 50,148,837 6 

59 24,747 24,806 7 

619,765 3,022,004 3,641,769 8 

2 761 763 9 

1 476 477 10 

7,976,991 20,027,618 28,004,609 11 

6,164 114,893 -16,989 104,068 12 

3,265 42,002 45,267 13 

1,667,141 5,066,164 6,733,305 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

219,294 

86,875 

432 

12,308 

26,832 

115,755 

18,905 

326,634 

30,875 

42,149 

5,585 

14,985 

2,137,630 

525 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

4,447,239 13,070,019 17,517,258 1 

1,982,468 5,303,540 7,286,008 2 

9,763 38,497 48,260 3 

258,667 1,177,476 1,436,143 4 

498,153 2,452,682 2,950,835 5 

6,872,877 6,872,877 6 

457,854 1,791,594 2,249,448 7 

7,953,138 20,227,244 28,180,382 8 

523,210 2,925,779 3,448,989 9 

858,311 2,580,291 3,438,602 10 

2,599 445,931 448,530 11 

8,292 1,331,842 1,340,134 12 

190,899,086 190,899,086 13 

311 47,026 47,337 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

348,995 

839 

2,151 

5,063 

281 

30,529 

1,261,872 

5,421 

383,153 

26,459 

48,645 

180,813 

347,037 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

6,740,198 21,616,291 28,356,489 1 

9,006 41,739 50,745 2 

30,814 128,591 159,405 3 

374,179 -646,340 -272,161 4 

33 24,094 24,127 5 

1,755,166 3,381,450 5,136,616 6 

24,520,695 88,320,401 112,841,096 7 

2,260 334,053 336,313 8 

9,475,388 23,784,264 33,259,652 9 

430,764 1,639,552 2,070,316 10 

1,328,883 3,033,592 4,362,475 11 

4,101,231 15,575,131 19,676,362 12 

7,538,331 21,497,066 29,035,397 13 

-100,000 -100,000 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

3,171 

223,756 

880 

71,717 

71,620 

163,677 

72,176 

73,583 

70,590 

149,139 

41,459 

92,847 

1,722,954 

21,701 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

888 254,235 255,123 1 

4,292,286 21,353,679 25,645,965 2 

33,872 90,128 124,000 3 

4,785,944 5,715,087 10,501,031 4 

4,779,468 5,707,523 10,486,991 5 

16,488,533 13,136,967 29,625,500 6 

5,103,654 5,755,660 10,859,314 7 

5,390,227 5,825,887 11,216,114 8 

5,453,507 5,615,626 11,069,133 9 

14,826,485 12,038,682 26,865,167 10 

783,933 2,565,453 3,349,386 11 

1,578,353 5,664,846 7,243,199 12 

23,362,757 146,169,811 169,532,568 13 

1,563,707 1,563,707 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

353,712 

1,341 

345 

1,764 

3,384 

1,993 

2,102 

7,158 

86,075 

220,360 

212,432 

428,321 

188,611 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

11,113,577 30,195,416 41,308,993 1 

759 120,118 120,877 2 

8,581 29,181 37,762 3 

139,081 139,081 4 

271,321 271,321 5 

157,326 157,326 6 

169,197 169,197 7 

126,924 665,690 792,614 8 

2,027,025 5,310,352 7,337,377 9 

4,893,375 19,392,340 24,285,715 10 

4,678,363 18,490,102 23,168,465 11 

-476,082 -476,082 12 

8,654,141 26,458,176 35,112,317 13 

10,233,496 18,919,069 29,152,565 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

32,843 

318 

2,108 

345,884 

249 

47 

7,546 

159,566 

84,732 

297,126 

166,489 

96 

3 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

371,239 2,028,742 2,399,981 1 

26 22,262 22,288 2 

830 172,798 173,628 3 

11,185,309 30,604,143 41,789,452 4 

72 21,965 22,037 5 

9 4,386 4,395 6 

4,828 678,483 683,311 7 

2,854,572 14,231,397 17,085,969 8 

1,885,708 5,191,893 7,077,601 9 

13 13 10 

7,032,939 18,394,910 25,427,849 11 

6,532,362 15,470,431 22,002,793 12 

39 9,656 9,695 13 

476 476 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

343,003 

81,027 

127,505 

399,313 

452 

270 

7,143 

68,775 

44,491 

283,982 

37,462 

37,807 

85,801 

47,713 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

7,422,496 30,085,619 37,508,115 1 

2,361,688 7,501,862 9,863,550 2 

3,227,749 7,899,841 11,127,590 3 

9,666,656 24,775,813 34,442,469 4 

439 42,983 43,422 5 

129 26,228 26,357 6 

30,097 599,138 629,235 7 

1,328,896 6,254,553 7,583,449 8 

354,779 4,037,100 4,391,879 9 

6,943,471 23,305,059 30,248,530 10 

725,531 3,455,625 4,181,156 11 

735,543 3,582,057 4,317,600 12 

1,358,580 5,204,942 6,563,522 13 

658,712 2,881,598 3,540,310 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

51,274 

1 

42,920 

2,177,240 

124,945 

1,382 

24,178 

76 

993 

1,389 

1,600 

199,896 

728 

103 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

548,898 3,105,393 3,654,291 1 

59 59 2 

5,483,589 1,801,937 7,285,526 3 

27,521,006 167,201,869 194,722,875 4 

2,389,031 7,603,461 9,992,492 5 

55,461 84,733 140,194 6 

326,091 1,488,694 1,814,785 7 

34 6,038 6,072 8 

16,350 84,232 100,582 9 

23,917 119,852 143,769 10 

30,624 138,665 169,289 11 

102,173 16,697,703 16,799,876 12 

597 45,635 46,232 13 

37 9,093 9,130 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

16,821 

14,009 

16,598 

272,989 

13,170 

13,156 

932 

2,343,774 

25,125 

84,122 

16,153 

4,345 

1,540 

4,526 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

242,560 1,043,882 1,286,442 1 

212,975 876,001 1,088,976 2 

196,018 1,021,075 1,217,093 3 

5,511,843 16,912,608 22,424,451 4 

17,002 535,631 552,633 5 

17,241 532,866 550,107 6 

19,544 82,911 102,455 7 

31,204,755 183,345,755 214,550,510 8 

575,046 2,331,920 2,906,966 9 

4,884,412 9,248,367 14,132,779 10 

209,691 997,998 1,207,689 11 

72,437 266,160 -263,972 74,625 12 

1,200 149,164 150,364 13 

26,277 253,918 280,195 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

9,359 

20,971 

29,200 

8,785 

12,620 

10,096 

8,813 

7,984 

27,371 

194 

162 

4,309 

57,221 

9 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

194,941 578,624 773,565 1 

290,979 1,907,780 2,198,759 2 

491,665 2,652,653 3,144,318 3 

121,476 832,845 954,321 4 

131,413 1,145,917 1,277,330 5 

119,278 936,480 1,055,758 6 

118,014 817,184 935,198 7 

101,571 736,627 838,198 8 

12,948 2,519,348 2,532,296 9 

49 16,767 16,816 10 

21 11,240 11,261 11 

22,065 262,712 284,777 12 

762,028 3,543,537 4,305,565 13 

4 935 939 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

1,123 

13,367 

100,635 

51,194 

11,623 

649 

26,016 

3,541 

82,117 

9,750 

9,868 

11,479 

8,412 

384,890 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

643 97,274 97,917 1 

657,296 1,369,752 2,027,048 2 

2,135,190 6,188,162 8,323,352 3 

32,192 4,679,095 4,711,287 4 

1,372,286 1,372,286 5 

18,890 58,655 77,545 6 

513,383 1,589,680 2,103,063 7 

532 228,441 228,973 8 

1,480,516 6,228,749 7,709,265 9 

146,478 861,229 1,007,707 10 

139,545 882,147 1,021,692 11 

167,479 709,097 876,576 12 

116,503 517,185 633,688 13 

10,817,659 23,858,817 34,676,476 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 































Purchased 

Received 

Delivered 

(g) 

(h) 

(i) 

106,595 

14,800 

109,798 

6,547 

1,849,209 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

2,749,279 9,272,742 12,022,021 1 

-21,719 1,294,866 1,273,147 2 

2,643,578 9,682,163 12,325,741 3 

74,194 399,504 473,698 4 

5 

6 

53,742,322 109,560,827 181,560,574 344,863,723 7 

402,521 402,521 8 

-53,710,420 -53,710,420 9 

10 

-816,491 -816,491 11 

3,203,656 3,203,656 12 

810,937,117 810,937,117 13 

-4,547,838 -4,547,838 14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







(Mo, Da, Yr) 


04/18/2009 





























Purchased 

(g) 



Received 

(h) 

Delivered 

(i) 


Line 


($) ($) ($) 


(j) 

(k) 

(l) 

(m) 

6,300,000 6,300,000 1 

10,503,752 10,503,752 3 

2 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

48,709,854 289,843 542,570 980,603,226 3,738,006,400 1,005,598,586 5,724,208,212 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




The following reference table applies to transactions with a statistical class code of "OS" which require footnote 

disclosure as to the nature of the service. To facilitate completion and reduce unnecessary repetition, please 

refer to this table for all "OS" classifications. 

OS1 

OS2 

"Evergreen" Means Minimum of one year, with automatic annual renewal thereafter. The availability and reliability of 

energy delivered is on an as-available basis. 

Long-Term Power Purchase Agreements with Renewable / Alternative Resources. "Long-Term" means five years or 

greater. The availability and reliability of energy delivery must match the dedicated firm MW as specified in the Contract. 

OS3 

OS4 

OS7 

Evergreen Power Purchase Agreement with Renewable / Alternative Resources less than 100 KW. "Evergreen" means 

minimum of one year, with automatic annual renewal thereafter. The availability and reliability or energy delivered is on an 

as-available basis. 


greater. The availability and reliability of energy delivered is on an as available basis. 


greater. The availability and reliability of energy delivery must match the dedicated firm MW as specified in the Contract. 

OS8 

OS9 

OS10 

OS11 

OS12 

OS13 

SCE customers on the fringe of SCE's service area. 

Termination Agreement. 

Replacement for lost energy due to diversion from Mill Creek. 

Settlement for generation deviation from transmission service schedule. 

Quarterly Payments - U.S. Department of Interior, Bureau of Reclamation, Lower Colorado River Multi-Species 

Conservation Program. 

Brokers. 


OS 8 - Please reference page 326 Line 1 Column (b). 



Schedule Page: 326 Line No.: 7 Column: l 

Facility Charges. 

















(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 

Termination Date: 9/30/17 



Schedule Page: 326.1 Line No.: 5 Column: l 

Conservation Program. 




LADWP Returned Energy. 


Expenses related to collateral requirements, trust fund managment, and miscellaneous other expense. 


RA Capicity. 




RA Capacity. 


Sale of Gas. 


Sale of Gas. 


Sale of Gas. 


Transportation. 


Transportation. Sale of Gas. 


Expenses related to collateral requirements, trust fund managment, and miscellaneous other expense. Transportation. 

Sale of Gas. 





Sale of Gas. 






Transportation. 



Sale of Gas. 










Transportation. Sale of Gas. Capital Lease under GAAP. 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Expenses related to collateral requirements, trust fund managment, and miscellaneous other expense. Net Gas 

Purchases Plus Imbalances. 






























RA Capacity. 


Sale of Gas. 


RA Capacity. 


Sale of Gas. 


RA Capacity. 


RA Capacity. 


RA Capacity. 














FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 






















Termination Date: 1/19/36. 






































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 






































Expenses related to collateral requirements, trust fund management, and miscellanous other expense. 





















FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




















California ISO Costs. 


Independent Evaluator Costs. 


Various Energy Settlement Refunds. 


Capital Lease under GAAP. 




Expenses related to collateral requirements, trust fund managment, and miscellaneous other expense. Realized Gain / 

Loss on Financial Futures or Options. Unrealized Gain / Loss on Financial Futures or Options. 







(Mo, Da, Yr) 


04/18/2009 

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) 

(Including transactions referred to as 'wheeling') 



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 or 

public 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 footnote 

any 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 Point 

Transmission Service, OLF - Other Long-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 prior reporting periods. Provide an explanation in a footnote for 

each adjustment. See General Instruction for definitions of codes. 

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 

32 

33 

34 

Payment By 

(Company of Public Authority) 

Energy Received From 


Energy Delivered To 


Statistical 

Classifi- 

(Footnote Affiliation) 



cation 

(a) 

(b) 

(c) 

(d) 

Southern California Water Company Various Southern California Water Company OLF 

Southern California Water Company Southern California Water Company Southern California Water Company OLF 

Southern California Water Company Southern California Water Company Southern California Water Company AD 

City of Azusa Various City of Azusa OLF 

City of Azusa Various City of Azusa AD 




City of Azusa City of Pasadena City of Azusa OLF 



City of Banning Various City of Banning OLF 

City of Banning Various City of Banning AD 





City of Colton Various City of Colton OLF 

City of Colton Various City of Colton AD 





City of Colton Various City of Colton AD 



City of Riverside Various City of Riverside OLF 

City of Riverside Various City of Riverside AD 





City of Vernon Various City of Vernon OLF 

City of Corona Various City of Corona OLF 

TOTAL 







(Mo, Da, Yr) 


04/18/2009 


















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 

32 

33 

34 

Payment By 






Statistical 

Classifi- 




cation 

(a) 

(b) 

(c) 

(d) 



City of Corona Various City of Corona AD 








City of Vernon Various City of Vernon AD 


Southwest Trans Elec Pwr Coop - AEPCO Various Southwest Trans Elec Pwr Coop - A OLF 


Industry Urban Development Agency Various Industry Urban Development Agency OLF 

Industry Urban Development Agency Various Industry Urban Development Agency AD 





City of Moreno Valley Various City of Moreno Valley OLF 









City of Moreno Valley Various City of Moreno Valley AD 



City of Rancho Cucamonga Various City of Rancho Cucamonga OLF 

City of Rancho Cucamonga Various City of Rancho Cucamonga AD 

TOTAL 







(Mo, Da, Yr) 


04/18/2009 


















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 

32 

33 

34 

Payment By 






Statistical 

Classifi- 




cation 

(a) 

(b) 

(c) 

(d) 

Industry Urban Development Agency Various Industry Urban Development Agenc OLF 

Industry Urban Development Agency Various Industry Urban Development Agenc AD 

Arizona Public Service Various Arizona Public Service OLF 

Arizona Public Service Various Arizona Public Service OLF 

Arizona Public Service Various Arizona Public Service AD 

Department of Water Resources Various Department of Water Resources OLF 

Department of Water Resources Various Department of Water Resources AD 





City of Pasadena Various City of Pasadena OLF 

City of Pasadena Various City of Pasadena AD 

City of Pasadena Various City of Pasadena OLF 

Metropolitan Water District Department of Water Resources Metropolitan Water District OLF 

City of Los Angeles Various City of Los Angeles OLF 

Imperial Irrigation District Various Imperial Irrigation District OLF 









M-S-R Public Power Authority Various Pacific Gas & Electric Company OLF 

M-S-R Public Power Authority Various Pacific Gas & Electric Company OLF 

M-S-R Public Power Authority Various Pacific Gas & Electric Company AD 

AES Huntington Beach, LLC AES Huntington Beach, LLC ISO OLF 

Reliant Energy Mandalay, LLC Ocean Vista Power Generation ISO OLF 

Reliant Energy Coolwater, LLC Alta Power Generation ISO OLF 

Reliant Energy Ormond Bch, LLC Ormond Beach Generation ISO OLF 

Southwest Trans Elec Pwr Coop - AEPCO Various Southwest Trans Elec Pwr Coop - A OLF 

High Desert Power Trust Various High Desert Power Trust OLF 

TOTAL 







(Mo, Da, Yr) 


04/18/2009 


















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 

32 

33 

34 

Payment By 






Statistical 

Classifi- 




cation 

(a) 

(b) 

(c) 

(d) 

Inland Empire Energy Center Various Inland Empire Energy Center OLF 

Southern California Water Company Various Southern California Water Company OLF 

Southern California Water Company Various Southern California Water Company AD 


















City of Rancho Cucamonga Various City of Rancho Cucamonga OLF 

City of Rancho Cucamonga Various City of Rancho Cucamonga AD 

Other Revenue N/A N/A 

ISO Wheeling N/A N/A OS 

ISO Congestion N/A N/A OS 

TOTAL 






(Mo, Da, Yr) 



04/18/2009 

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) 

(Including transactions reffered to as 'wheeling') 



5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract 

designations 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 the 

designation 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 the 

contract. 

7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand 

reported 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. 


Schedule of 

Tariff Number 

(e) 

Point of Receipt 

(Subsatation or Other 

Designation) 

(f) 

Point of Delivery 

(Substation or Other 

Designation) 

(g) 

Billing 


(MW) 

(h) 


Received 

(i) 

TRANSFER OF ENERGY 


Delivered 

(j) 

349.8 Various 

Various 1 

Vol. 5, SA #4 Victor / Vista Sub. 

Cottonwood / Zanja 39 152,981 147,704 2 

Vol. 5, SA #4 Victor / Vista Sub. 

Cottonwood / Zanja 39 3 

Vol. 5, SA #2 Rio Hondo 

Azusa 223,794 219,966 4 


Azusa 5 


Azusa 6 

373 Victorville-Lugo 

Rio Hondo 4 7 

372 Mead 

Rio Hondo 4 8 


Rio Hondo 14 9 

375 Mead / Rio Hondo 

Rio Hondo / Mead 8 10 

376 Sylmar 

Rio Hondo 10 11 

Vol. 5, SA #3 Near Devers 

Banning 164,835 159,889 12 

Vol. 5, SA #3 Near Devers 

Banning 13 


Devers 3 14 

381 Devers 

Devers 15 15 

378 Mead 

Devers 2 16 

380 Victorvle-Lugo-Ban 

Victorvle-Lugo-Ban 5 17 

Vol. 5, SA #1 Vista 

City of Colton 327,584 326,143 18 


City of Colton 19 


Vista 3 20 

365 Devers 

Vista 21 

361 Mead 

Vista 3 22 

361, 362, 363 Various 

Various 23 

361, 362, 363 Various 

Various 24 


Vista 18 25 

364 Sylmar / Vista 

Vista / Sylmar 3 26 


Riverside City Limit 2,238,320 2,229,143 27 


Riverside City Limit 28 

393.2 San Onofre 

Vista 42 29 

392.2 Victorville-Lugo 

Vista 12 30 


Vista 156 31 

390.2 Mead 

Vista 30 32 

359.1 Laguna Bell 

Vernon 33 

Vol. 5, SA 151 Mira Loma 

Corona Sunkist 1 3,559 3,467 34 

Line 

No. 

6,324 8,966,079 8,972,037 






(Mo, Da, Yr) 



04/18/2009 










contract. 





Schedule of 

Tariff Number 

(e) 



Designation) 

(f) 



Designation) 

(g) 

Billing 


(MW) 

(h) 


Received 

(i) 



Delivered 

(j) 


Corona Sunkist 1 1 


Corona Dos Lagos 1 19,527 18,232 2 


Corona Dos Lagos 1 3 


Corona Pointe 24,144 23,432 4 


Corona Pointe 5 


Crossing Bus. Ctr. 23,967 22,834 6 


Crossing Bus. Ctr. 7 


Cleargen Sub 8,123 8,037 8 


Cleargen Sub 9 

207.26 Mead 

Laguna Bell 26 10 

207.26 Mead 




131 Mead 

Mountain Center 13 

272.13 Sylmar 


Vol. 5, SA 165 Walnut Sub,220kV bus Industry 2 553 546 15 

Vol. 5, SA 165 Walnut Sub,220kV bus Industry 2 16 

Vol. 5, SA #48 Walnut Sub,230kV bus Industry 27,157 25,826 17 

Vol. 5, SA #48 Chino Sub,230kV bus Industry 18 

Vol. 5, SA 152 Chino Sub,220kV bus Industry 2 6,585 6,222 19 

Vol. 5, SA 152 Chino Sub,220kV bus Industry 2 20 

Vol. 5, SA 103 Valley Sub 

Moreno Valley 1,853 1,822 21 


Moreno Valley 22 


Moreno Valley 1 388 376 23 


Moreno Valley 1 24 






Moreno Valley 1 9,101 8,965 27 








Moreno Valley 12 55,296 55,058 31 



Vol. 5, SA #89 Etiwanda 

City/Rncho Cucamonga 64,687 64,228 33 

Vol. 5, SA #89 Etiwanda 

City/Rncho Cucamonga 34 

Line 

No. 

6,324 8,966,079 8,972,037 






(Mo, Da, Yr) 



04/18/2009 










contract. 





Schedule of 

Tariff Number 

(e) 



Designation) 

(f) 



Designation) 

(g) 

Billing 


(MW) 

(h) 


Received 

(i) 



Delivered 

(j) 

Revised Vol #6 Walnut 

City of Industry 11,777 11,777 1 

Revised Vol #6 Walnut 

City of Industry 13,027 13,027 2 

348 Various 

Various 3,642 3,642 3 

348 Blythe 

Various 4 

348 Blythe 

Various 5 

Vol. 5, SA#56 Vista 

Cherry Valley Statn 237 220 6 


Cherry Valley Statn 7 


Crafton Hills Statn 11,655 11,562 8 


Crafton Hills Statn 9 

Vol. 5, SA#58 San Bernardino 

Greenspot Station 4 9,212 9,043 10 

Vol. 5, SA#58 San Bernardino 

Greenspot Station 4 11 

317 Rio Hondo 

Goodrich 12 

317 Rio Hondo 

Goodrich 13 

55.7 Various 

Goodrich 200 14 

443 Vincent 

Julian Hinds 36,970 15 

219 Various 

Various 368 2,739,175 2,739,175 16 

268 Palo Verde 

Mirage 576 576 17 

342 Mohave 

Vincent 28 18 

113 El Dorado 

Vincent 235 19 

112.3 Devil Canyon 

Calectric 120 20 

Vol. 6, SA#33 Bailey Sub 

Various 72 21 

Vol. 6, SA#35 Bailey-Oso 

Various 17 22 

Vol. 6, SA#34 Pastoria-Pardee 

Various 82 23 

Vol. 6, SA#31 Edmonston-Pastoria Vincent 787 24 

Vol. 6, SA#32 Vincent 

Various 152 25 


Midway 150 322,117 322,117 26 


Midway 150 27 


Midway 150 28 

403 Huntington Beach 

Ellis 29 

401 Mandalay 

Santa Clara 30 

402 Coolwater 

Kramer 31 

404 Ormond Beach 

Moorpark 32 

131 Mead 

Mountain Center 10 33 

Vol. 6, SA #11 Victor Substation 

High Desert 34 

Line 

No. 

6,324 8,966,079 8,972,037 






(Mo, Da, Yr) 



04/18/2009 










contract. 





Schedule of 

Tariff Number 

(e) 



Designation) 

(f) 



Designation) 

(g) 

Billing 


(MW) 

(h) 


Received 

(i) 



Delivered 

(j) 

470 Valley Sub 

Inland Empire Energy 1 

Vol. 5, SA #4 Victor / Vista Sub 

Cottonwood/Zanja Sub 39 57,405 57,405 2 

Vol. 5, SA #4 Victor / Vista Sub 

Cottonwood/Zanja Sub 39 56,482 56,482 3 


Cherry Valley Stn 78 78 4 


Cherry Valley Stn 74 74 5 


Crafton Hills Stn 2,759 2,759 6 


Crafton Hills Stn 3,161 3,161 7 

Vol. 5, SA #58 San Bernardino 


Vol. 5, SA #58 San Bernardino 


Vol. 6, SA #33 Bailey-Oso 

Oso Pumping Plant 72 32,757 32,757 10 

Vol. 6, SA #33 Bailey-Oso 

Oso Pumping Plant 72 36,603 36,603 11 

Vol. 6, SA #32 Edmonston-Pastoria Pearblossom Pumpg Pt 152 37,629 37,629 12 

Vol. 6, SA #32 Edmonston-Pastoria Pearblossom Pumpg Pt 152 20,793 20,793 13 

Vol. 6, SA #31 Vincent 

Edmonston Pumping Pt 787 870,363 870,363 14 

Vol. 6, SA #31 Vincent 

Edmonston Pumping Pt 787 1,114,294 1,114,294 15 

112 Various 

Various 1,011 16 

Vol. 5, SA #77 Mira Loma 

Temescal P.T. Sub 24,895 24,895 17 

Vol. 5, SA #77 Mira Loma 

Temescal P.T. Sub 75,334 75,334 18 


Mrno Valey Iris Ave. 3 19,361 19,361 19 


Mrno Valey Iris Ave. 3 58,976 58,976 20 

Vol. 5, SA #89 Etiwanda Sub 

Arbors Sub 10,976 10,976 21 

Vol. 5, SA #89 Etiwanda Sub 

Arbors Sub 65,904 65,904 22 

N/A N/A 

N/A 23 

N/A N/A 

N/A 24 

N/A N/A 

N/A 25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

Line 

No. 

6,324 8,966,079 8,972,037 






(Mo, Da, Yr) 



04/18/2009 

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) 




9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand 

charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the 

amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including 

out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total 

charge 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 service 

rendered. 

10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report 

purposes only on Page 401, Lines 16 and 17, respectively. 

11. Footnote entries and provide explanations following all required data. 

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

Demand Charges 

($) 

Energy Charges 

($) 

(Other Charges) 

($) 

Total Revenues ($) 

(k+l+m) 

Line 

No. 

(k) 

(l) 

(m) 

(n) 

-11,084 -11,084 1 

595,817 159 595,976 2 

165,848 43 165,891 3 

170,580 51,472 222,052 4 

14,123 4,679 18,802 5 

97,113 97,113 6 

64,800 64,800 7 

64,800 64,800 8 

226,800 226,800 9 

124,200 124,200 10 

162,000 162,000 11 

299,425 26,117 325,542 12 

51,688 4,749 56,437 13 

53,280 53,280 14 

266,400 266,400 15 

35,520 35,520 16 

94,200 94,200 17 

210,918 31,815 242,733 18 

37,912 5,784 43,696 19 

48,600 48,600 20 

227,497 227,497 21 

48,600 48,600 22 

47,939 47,939 23 

15,980 15,980 24 

291,600 291,600 25 

48,600 48,600 26 

1,174,866 14,842 1,189,708 27 

106,806 1,349 108,155 28 

684,112 684,112 29 

194,400 194,400 30 

2,527,200 2,527,200 31 

486,000 486,000 32 

297,875 297,875 33 

13,640 80 13,720 34 

67,463,947 0 

5,105,424 

72,569,371 






(Mo, Da, Yr) 



04/18/2009 











rendered. 





($) 

(k) 




($) 

($) 

(l) 

(m) 


(k+l+m) 

(n) 

1,240 7 1,247 1 

52,173 80 52,253 2 

3,781 7 3,788 3 

56,754 888 57,642 4 

4,484 81 4,565 5 

126,151 57,857 184,008 6 

9,990 5,260 15,250 7 

13,296 84 13,380 8 

1,175 8 1,183 9 

299,603 299,603 10 

27,237 27,237 11 

67,320 67,320 12 

11,399 11,399 13 

18,700 18,700 14 

11,220 81 11,301 15 

2,040 15 2,055 16 

61,776 80 61,856 17 

11,232 14 11,246 18 

40,260 81 40,341 19 

7,320 15 7,335 20 

28,798 79 28,877 21 

5,236 14 5,250 22 

29,040 80 29,120 23 

2,640 7 2,647 24 

21,525 84 21,609 25 

1,215 8 1,223 26 

45,703 84 45,787 27 

2,790 8 2,798 28 

41,763 84 41,847 29 

3,720 8 3,728 30 

131,126 80 131,206 31 

10,440 7 10,447 32 

21,853 107 21,960 33 

3,447 19 3,466 34 

Line 

No. 

67,463,947 0 

5,105,424 

72,569,371 






(Mo, Da, Yr) 



04/18/2009 











rendered. 





($) 

(k) 




($) 

($) 

(l) 

(m) 


(k+l+m) 

(n) 

2,709 2,709 1 

8,598 8,598 2 

97,767 594 98,361 3 

34,039 34,039 4 

3,150 3,150 5 

26,950 103 27,053 6 

7,350 28 7,378 7 

194,953 103 195,056 8 

53,169 28 53,197 9 

305,800 103 305,903 10 

83,400 28 83,428 11 

152 152 12 

85 85 13 

146,160 146,160 14 

15 

5,961,600 5,961,600 16 

176,800 176,800 17 

319,200 319,200 18 

1,522,800 1,522,800 19 

43,200 43,200 20 

71,400 71,400 21 

35,472 35,472 22 

41,172 41,172 23 

93,972 93,972 24 

267,600 267,600 25 

910,500 910,500 26 

29,873 29,873 27 

1,423 1,423 28 

394,388 394,388 29 

160,009 160,009 30 

945,023 945,023 31 

1,732,473 1,732,473 32 

205,200 205,200 33 

242,122 242,122 34 

Line 

No. 

67,463,947 0 

5,105,424 

72,569,371 






(Mo, Da, Yr) 



04/18/2009 











rendered. 





($) 

(k) 




($) 

($) 

(l) 

(m) 


(k+l+m) 

(n) 

103,935 103,935 1 

11,481 11,481 2 

32,760 32,760 3 

6 6 4 

18 18 5 

221 221 6 

759 759 7 

169 169 8 

839 839 9 

2,621 2,621 10 

8,785 8,785 11 

3,009 3,009 12 

4,990 4,990 13 

69,629 69,629 14 

267,431 267,431 15 

16 

5,726 5,726 17 

49,719 49,719 18 

4,453 4,453 19 

38,925 38,925 20 

5,008 5,008 21 

43,497 43,497 22 

8,049 8,049 23 

19,539,326 19,539,326 24 

27,927,701 27,927,701 25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

Line 

No. 

67,463,947 0 

5,105,424 

72,569,371 








(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 


OLF - 2 Yr. notice 

Schedule Page: 328 Line No.: 1 Column: h 

Billing Demand 34/5 



Schedule Page: 328 Line No.: 2 Column: m 

Customer charge per agreement. 


Customer charge per agreement. Revenue received in current year for prior year's service period. 




Billing Demand 48.7 


Customer charge plus facility charge per agreement. 




Customer charge per agreement. Revenue received in current year for prior year's service period. Customer charge plus 

facility charge per agreement. 






















Customer charge plus facility charge per agreement. O & M Metering charge. 




Revenue received in current year for prior year's service period. Customer charge plus facility charge per agreement. 

O & M Metering charge. 











FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




OLF - 1 Yr. Notice 
























Billing Demand N/A 


Reliability Services Charge. 




Reliability Service revenue recieved in current year for prior year's service. 










Customer charge plus facility charge per agreement. O & M Metering charge. 






OLF - 180 days notice. 











FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 










OLF - 6/17/36 




OLF - 6/17/36 

Schedule Page: 328.1 Line No.: 1 Column: m 

Revenue received in current year for prior year's service agreement. 


OLF - 5/1/34 







Schedule Page: 328.1 Line No.: 4 Column: h 



















OLF - 11/12/34 










OLF - Hoover PSC 

Schedule Page: 328.1 Line No.: 11 Column: k 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Revenue received in current year for prior year's service period. 


OLF - 12/31/02 Perm. Removed from Service 


OLF - Upon Notice 




Reliabilty Services Charge. 


OLF - 12/29/42 


OLF - 5/3/37 






OLF - 12/31/32 










OLF - 10/03/36 






OLF - 04/11/2034 






OLF - 04/11/2034 






OLF - 11/13/2035 




OLF - 11/13/2035 








FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 





OLF - 3/5/35 


Billing Demand .5 




OLF - 3/5/35 






OLF - 10/31/34 




OLF - 10/31/34 




OLF - 10/1/34 










OLF - 07/22/37 






OLF - 07/21/53 










OLF - Upon Notice. 


Billing Demand 7.2/2/2 








FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 





Billing Demand 7.2/2/2 


Reliability Services Charge. Reliability Service revenue received in current year for prior year's service. 


OLF - 12/31/07 


Billing Demand .8/.2/3.4 


Telecommunications charge per agreement. 


OLF - 12/31/07 




Scheduling and dispatch fees. 






OLF - Plant Life 


























OLF - Unit Life 










FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 









OLF - 8/4/10 


OLF - 9/30/17 




OLF - Term Service 




Billing Demand 50/100 




OLF - 12/31/20 




OLF - 1/1/2035 


Interconnection Service Charges. 


OLF - 1/1/2035 




OLF - 1/1/2035 




OLF - 1/1/2035 




OLF - 1/1/2035 




OLF - 5 Year Notice 


OLF - 5 Year Notice 


Scheduling and Dispatch Fees. 











(Mo, Da, Yr) 

04/18/2009 



FOOTNOTE DATA 

OLF - 12/31/03 Cust. Termin. 




Monthly Operating & Maintenance and base cost charge per radial lines agreement. 


OLF - 12/31/04/Take Serv. 
























Monthly Recurring Expense Charge. 






Monthly Recurring Expense Charge. 






Reliability Service revenue received in current year for prior year's service. Reliability Services Charge. 
















FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 





















OLF - 1/1/2035 


Revenue Received in current year for prior year's service period. Reliability Service revenue received in current year for 

prior year's servcice. 




OLF - 1/1/2035 






OLF - 1/1/2035 






OLF - 12/31/04 












OLF - 4/11/2034 









FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 






OLF - 7/21/2053 










N/A 




Other Revenue. 


OS - Plant Life 




Edison's share of statewide wheeling collected by the CAISO from scheduling coordinators. 


OS - Plant Life 




Edison's share of statewide congestion charges collected by the CAISO for congestion in the Edison contol area caused 

by scheduling coordinators. 







(Mo, Da, Yr) 


04/18/2009 

TRANSMISSION OF ELECTRICITY BY ISO/RTOs 

6. Report in column (e) the total revenues distributed to the entity listed in column (a). 

Line 

No. 

Payment Received by 

(Transmission Owner Name) 

Statistical 


(a) 

(b) 

FERC Rate Schedule 

or Tariff Number 

(c) 

Total Revenue by Rate 

Schedule or Tarirff 

(d) 



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 – Firm 

Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other 

Long-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 prior 

reporting 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 which 

service, as identified in column (b) was provided. 

5. In column (d) report the revenue amounts as shown on bills or vouchers. 

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 

None 

Total Revenue 

(e) 

40 TOTAL 

FERC FORM NO. 1/3-Q (REV 03-07) 

Page 331






(Mo, Da, Yr) 


04/18/2009 

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) 

(Including transactions referred to as "wheeling") 



1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public 

authorities, 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 the 

transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided 

transmission 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 - Other 

Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission 

Service, 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 the 

demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all 

other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all 

components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no 

monetary 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. 


Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

Name of Company or Public 

Authority (Footnote Affiliations) 

(a) 

Arizona Public Service 

Western Area Power Admn 

- (Western) 

Western Area Power Admn 

- (Western) - Blythe 

L.A. Dept of Water&Pwr 

Imperial Irrigation Dis 

(Salton Sea) 

Statistical 


(b) 


Magawatthours 

hours 

Magawatt- 

Received Delivered 

(c) 

(d) 

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS 

Demand Energy 

Other Total Cost of 

Charges Charges Charges 

($) 

($) 

($) 

Transmission 

($) 

(e) 

(f) 

(g) 

(h) 

OLF 4,963,584 4,963,584 

4,221,735 

4,221,735 

OLF 193,518 

193,518 

OLF 11,556 

11,556 

OLF 7,572 7,572 

424,981 

424,981 

FNS 269,481 

269,481 

TOTAL 

4,971,156 4,971,156 193,518 424,981 4,502,772 5,121,271 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




OLF - 1/1/2017 

Schedule Page: 332 Line No.: 1 Column: g 

Includes Property Taxes for Arizona and New Mexico, Hualapai Tribal Possessory Interest Tax, and Arizona Public 

Service Right of Way Indian Settlement. 


OLF - 7/31/2014 


OLF - 1 Year notice 


Common facilities Operation and Maintenance Charges 


OLF - 5/31/2025 


Scheduling, Transmission Service and Dispatching Fees. 






(1) An Original 

(Mo, Da, Yr) 


X 



04/18/2009 

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) 

Line Description Amount 

No. 

(a) 

(b) 

1 Industry Association Dues 

2,070,873 

2 Nuclear Power Research Expenses 

3 Other Experimental and General Research Expenses 

2,120,597 

4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 

2,880,413 

5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 

6 Credit Line Fees / Bank Charges 

2,094,960 

7 Directors' Fees and Expenses 

2,432,600 

8 Periodic SEC Reports 

159,963 

9 Planning and Development of Communication Systems 

314,457 

10 Consultants/professional Services 

359,403 

11 

12 

13 

Miscellaneous 

Administrative and General Expense Charged or Paid 

260,442 

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 

by others 

-8,709,265 

46 TOTAL 

3,984,443 







(Mo, Da, Yr) 




04/18/2009 

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405) 

(Except amortization of aquisition adjustments) 

1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset 

Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric 

Plant (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 to 

compute 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 changes 

to 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 plant 

included in any sub-account used. 

In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing 

composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the 

method 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 curve 

selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If 

composite 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 at 

the bottom of section C the amounts and nature of the provisions and the plant items to which related. 

A. Summary of Depreciation and Amortization Charges 

Depreciation Amortization of 

Line 

Depreciation Expense for Asset Limited Term Amortization of 

Functional Classification 

Expense Retirement Costs Electric Plant Other Electric 

No. 

(Account 403) (Account 403.1) (Account 404) Plant (Acc 405) 

(a) 

(b) 

(c) 

(d) 

(e) 

1 Intangible Plant 

59,344,527 451,603 

2 Steam Production Plant 

20,633,745 11,582,153 

3 Nuclear Production Plant 

74,075,957 25,243,732 

4 Hydraulic Production Plant-Conventional 

15,633,752 

5 Hydraulic Production Plant-Pumped Storage 

6 Other Production Plant 

11,523,635 

7 Transmission Plant 

126,394,402 1,477,300 

8 Distribution Plant 

554,088,592 

9 Regional Transmission and Market Operation 

10 General Plant 

142,397,684 1,298,125 

11 Common Plant-Electric 

11,473 

12 TOTAL 

944,759,240 59,344,527 40,052,913 

Total 

(f) 

59,796,130 

32,215,898 

99,319,689 

15,633,752 

11,523,635 

127,871,702 

554,088,592 

143,695,809 

11,473 

1,044,156,680 

B. Basis for Amortization Charges 







(Mo, Da, Yr) 


04/18/2009 

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) 



C. Factors Used in Estimating Depreciation Charges 

Line 

Depreciable 

Estimated Net Applied 

No. Account No. 

Plant Base Avg. Service Salvage Depr. rates 

(In Thousands) 

Life 

(Percent) (Percent) 

(a) (b) 

(c) 

(d) (e) 

12 STEAM PRODUCTION 

13 311 23,600 

14 312 414,244 

15 314 55,879 

16 315 14,854 

17 316 24,423 

18 

19 

20 NUCLEAR PRODUCTION 

21 SONGS 2 & 3 

22 321 68,396 

23 322 15,348 

24 323 17,315 

25 324 24,059 

26 325 176,598 

27 

28 

29 PVNGS 1,2 & 3 

30 321 4,041 

31 322 83,701 

32 323 32,900 

33 324 658 

34 325 5,589 

35 

36 

37 HYDRAULIC 

38 331 107,968 

39 332 428,961 

40 333 118,295 

41 334 105,245 

42 335 11,165 

43 336 9,048 

44 

45 

46 OTHER PRODUCTION 

47 341 3,728 

48 342 3,246 

49 343 228,341 

50 344 8,273 

Mortality 

Curve 

Type 

(f) 

Average 

Remaining 

Life 

(g) 







(Mo, Da, Yr) 


04/18/2009 

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) 



C. Factors Used in Estimating Depreciation Charges 

Line 

Depreciable 

Estimated Net Applied 

No. Account No. 

Plant Base Avg. Service Salvage Depr. rates 

(In Thousands) 

Life 

(Percent) (Percent) 

(a) (b) 

(c) 

(d) (e) 

12 345 64,866 

13 346 2,030 

14 

15 

16 TRANSMISSION PLANT 

17 352 219,421 

18 353 2,681,983 

19 354 432,905 

20 355 428,118 

21 356 509,877 

22 357 38,582 

23 358 168,556 

24 359 24,301 

25 

26 

27 DISTRIBUTION PLANT 

28 361 313,708 

29 362 1,235,918 

30 364 1,246,129 

31 365 937,210 

32 366 1,081,706 

33 367 3,264,593 

34 368 2,317,371 

35 369 1,011,472 

36 370 568,270 

37 373 670,295 

38 

39 

40 GENERAL 

41 390 486,040 

42 391.XXX 466,690 

43 392.4,.7 & .8 2,909 

44 393 11,596 

45 394.5 & .6 

46 395 61,092 

47 397 425,428 

48 398 15,069 

49 

50 TOTAL 20,672,010 

Mortality 

Curve 

Type 

(f) 

Average 

Remaining 

Life 

(g) 

FERC FORM NO. 1 (REV. 12-03) Page 337.1






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Includes acct. 108.105 (Plant Held For Future Use) Accum. Depreciation for Easements/Land Rights 







(Mo, Da, Yr) 


04/18/2009 

REGULATORY COMMISSION EXPENSES 

Line 

Description 

Assessed by 

Expenses 

Total 

No. (Furnish name of regulatory commission or body the Regulatory 

of 

Expense for 

docket or case number and a description of the case) Commission Current Year 

Utility 

(b) + (c) 

(a) 

(b) 

(c) 

(d) 

1 REGULATORY COMMISSION ASSESSED EXPENSES 

2 

3 CPUC Applications - Various 39,468 39,468 

4 FERC Order No. 472 4,618,832 4,618,832 

5 Intervener Compensation 701,203 701,203 

6 Miscellaneous -43 -43 

7 

8 OUTSIDE LEGAL SVCS & RELATED EXPENSES 

9 

10 A.07-11-011 

11 2009 GENERAL RATE CASE (LA2006000698) 137,777 137,777 

12 R.04-04-025; R.04-04-003 

13 AVOIDED COST OIR (LA2004000701) 71,126 71,126 

14 CALIFORNIA MUNI LITIGATION (LA2006000235) 767,004 767,004 

15 CANYON FIRE (LA2007000899) 495 495 

16 CASE ADMINISTRATION EXPENSE (LA1996000170) 4,390 4,390 

17 DMM ISSUES (LA2008000389) 657,558 657,558 

18 A.05-04-015 

19 DPV2 CPCN and PEA (LA2003000616) 391,385 391,385 

20 DRAFT LEGISLATION RELATED TO RPS & AB1X 

21 (LA2008000530) 16,776 16,776 

22 RP05-422 

23 EL PASO 2005 GENERAL RATE CASE V) 27,028 27,028 

24 A.07-12-029 

25 EMERGENCY PEAKER APPLICATION OXNARD 

26 (LA2006000634) 148,178 148,178 

27 EL00-98-000; EL00-95-000 

28 FERC INVESTIGATION (LA2000000853) 4,040,826 4,040,826 

29 FERC RATES AND TRANSMISSION INCENTIVES 

30 (LA2006000713) 281,482 281,482 

31 RM07-1 

32 FERC STANDARDS OF CONDUCT (LA2004000567) 41,538 41,538 

33 I.02-11-040 

34 GAS BORDER PRICE INVESTIGATION 

35 (LA2003000001) 67,611 67,611 

36 R.06-04-009 

37 GHG/OMM SECONDMENT (LA2007000780) 60,070 60,070 

38 A.06-08-011; D.07-03-013 

39 ISO/TO/RTO/VARIOUS TRANS & MKT ISSUES 

40 (LA2006000712) 45,996 45,996 

41 MBR GENERAL ADVICE (LA2006000677) 7,132 7,132 

42 RM04-7 

43 MBR NOPR FERC REGULATORY ELECTRIC REG 

44 (LA2006000493) 5,099 5,099 

45 MULTI-CLIENT GEN NUCLEAR (LA1994000005) 22,149 22,149 



1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if 

being 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 amounts 

deferred in previous years. 

Deferred 

in Account 

182.3 at 


(e) 

46 TOTAL 5,359,460 7,265,666 12,625,126 







(Mo, Da, Yr) 


04/18/2009 

REGULATORY COMMISSION EXPENSES 

Line 

Description 

Assessed by 

Expenses 

Total 

No. (Furnish name of regulatory commission or body the Regulatory 

of 

Expense for 

docket or case number and a description of the case) Commission Current Year 

Utility 

(b) + (c) 

(a) 

(b) 

(c) 

(d) 

1 OUTSIDE LEGAL SVCS & RELATED EXPENSES 

2 A.06-11-007 

3 NEW GEN SUMMER 2007 TRACK (LA2006000901) 77 77 

4 NRC GEN. LICENSING MTR (LA1992000676) 83,185 83,185 

5 R.06-04-009 

6 OIR GREENHOUSE GAS EMISSION (LA2006000387) 30,307 30,307 

7 I.06-06-014 

8 PBR OIL (LA2006000583) 240,010 240,010 

9 REGULATORY ADVICE FILE (LA2006000002) 13,409 13,409 

10 R.04-04-26; R.01-10-024 

11 RENEWABLE PROCUREMENT AGMNTS 

12 (LA2002000707) 44,727 44,727 

13 R.08-08-009 

14 RPS OIR (LA2006000240) 68 68 

15 SAN FRANCISCO OFFICE (LA2004001099) 1,254 1,254 

16 CV-08-05403GW(PLAx) 

17 SCE INTERVENTION IN NRDC V. SCAQMD 

18 (LA2008000882) 47,379 47,379 

19 D.07-09-040; D.08-07-048 

20 SCE Vs. PUBLIC UTILITIES COMISSION 

21 (LA2008000741) 655 655 

22 C.07-10-024 

23 SIMMONS, STEVEN Vs. SCE (LA2007000959) 244 244 

24 EC08-413 

25 STARTRANS (LA2008000918) 68 68 

26 TRITON 115/12kV SUBSTATION PROJECT 

27 (LA2007000498) -9,114 -9,114 

28 A.07-06-031 

29 TRTP (LA2007000204) 558 558 

30 TWMI TRANSITIONAL CONSULTING (LA2008000908) 935 935 

31 C.04-05-014 

32 UTILISOURCE Vs. SCE (LA2004000782) 342 342 

33 Opera Plaza 8,909 8,909 

34 Providea, Inc. 534 534 

35 

36 

37 

38 EMPLOYEE SALARIES & EXPENSES RELATED TO 

39 FERC Applications 

40 Minor Items (Less than $25,000) 8,499 8,499 

41 

42 

43 

44 

45 



1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if 

being 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 amounts 

deferred in previous years. 

Deferred 

in Account 

182.3 at 


(e) 

46 TOTAL 5,359,460 7,265,666 12,625,126 







(Mo, Da, Yr) 


04/18/2009 

REGULATORY COMMISSION EXPENSES (Continued) 



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. 

EXPENSES INCURRED DURING YEAR 

AMORTIZED DURING YEAR 

CURRENTLY CHARGED TO 

Deferred to Contra 

Amount 

Deferred in Line 

Department Account 

Amount 

No. 

Account 182.3 Account 

Account 182.3 


(f) (g) 

(h) 

(i) 

(j) 

(k) (l) 

1 

2 

ELECTRIC 928 

39,468 

3 

ELECTRIC 928 

4,618,832 

4 

ELECTRIC 928 

701,203 

5 

ELECTRIC 928 

-43 

6 

7 

8 

9 

10 

ELECTRIC 928 

137,777 

11 

12 

ELECTRIC 928 

71,126 

13 

ELECTRIC 928 

767,004 

14 

ELECTRIC 928 

495 

15 

ELECTRIC 928 

4,390 

16 

ELECTRIC 928 

657,558 

17 

18 

ELECTRIC 928 

391,385 

19 

20 

ELECTRIC 928 

16,776 

21 

22 

ELECTRIC 928 

27,028 

23 

24 

25 

ELECTRIC 928 

148,178 

26 

27 

ELECTRIC 928 

4,040,826 

28 

29 

ELECTRIC 928 

281,482 

30 

31 

ELECTRIC 928 

41,538 

32 

33 

34 

ELECTRIC 928 

67,611 

35 

36 

ELECTRIC 928 

60,070 

37 

38 

39 

ELECTRIC 928 

45,996 

40 

ELECTRIC 928 

7,132 

41 

42 

43 

ELECTRIC 928 

5,099 

44 

ELECTRIC 928 

22,149 

45 

12,625,126 

46 







(Mo, Da, Yr) 


04/18/2009 

REGULATORY COMMISSION EXPENSES (Continued) 



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. 

EXPENSES INCURRED DURING YEAR 

AMORTIZED DURING YEAR 

CURRENTLY CHARGED TO 

Deferred to Contra 

Amount 

Deferred in Line 

Department Account 

Amount 

No. 

Account 182.3 Account 

Account 182.3 


(f) (g) 

(h) 

(i) 

(j) 

(k) (l) 

1 

2 

ELECTRIC 928 

77 

3 

ELECTRIC 928 

83,185 

4 

5 

ELECTRIC 928 

30,307 

6 

7 

ELECTRIC 928 

240,010 

8 

ELECTRIC 928 

13,409 

9 

10 

11 

ELECTRIC 928 

44,727 

12 

13 

ELECTRIC 928 

68 

14 

ELECTRIC 928 

1,254 

15 

16 

17 

ELECTRIC 928 

47,379 

18 

19 

20 

ELECTRIC 928 

655 

21 

22 

ELECTRIC 928 

244 

23 

24 

ELECTRIC 928 

68 

25 

26 

ELECTRIC 928 

-9,114 

27 

28 

ELECTRIC 928 

558 

29 

ELECTRIC 928 

935 

30 

31 

ELECTRIC 928 

342 

32 

ELECTRIC 928 

8,909 

33 

ELECTRIC 928 

534 

34 

35 

36 

37 

38 

39 

ELECTRIC 928 

8,499 

40 

41 

42 

43 

44 

45 

12,625,126 

46 




Line 

No. 


(a) 




(Mo, Da, Yr) 


04/18/2009 

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES 

Description 

(b) 



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.(Identify 

recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to 

others (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 $5,000.) 

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 

1 A. Environmental Research 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 B. Transmission and Distribution (T&D) 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 


(2) Distribution 

EPRI EMF Tailored Collaboration Projects 

EPRI Health & Safety Job Exposure (SF-6, Vault Heat Stress..) 

EPRI Global Climate Policy - P102 

EPRI Greenhouse Gas Reduction - P103 

EPRI Occupational Health and Safety Target 

Biological Benefits of Transmission Line Corridors 

Field Data Capture Demonstration 

Wetlands Bacteria and Water Quality 

Power Line Decision Support System: Spatial Data Resources 

Cloud Seeding Evaluation and Optimization 

Improving Load Tempature Forecasts 

Dust Mitigation in the Desert 

Voltage VAR Control Using PMU Data 

Power Systems Outlook 

Phasor Wind Penetration 

Phasor Black Start Capabilities 

Situational Awareness and Analysis Center 

Power Quality Project (EPRI) 

Broadband Over Power Line 

Ground Molding Demonstration 

Acetylene Monitoring Transformers 

Data Beyond SCADA 

Distribution Harmonics (CSULB) 

CEATI 

Fault Detection (CMD) 

Pole RFID 

Distribution VAR on the Circuit of the Future 

T&D Applications for Smart Connect 

Communications Architecture 

Integrated Crossarm 

Unmanned Aerial Vehicle 

Delta Storage 

Personal Voltage Detector 




Line 

No. 


(a) 




(Mo, Da, Yr) 


04/18/2009 

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES 

Description 

(b) 



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.(Identify 

recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to 

others (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 $5,000.) 

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 


1 

2 C. Regional Transmission and Market Operation 

3 

4 

5 

6 

7 D. Customer Service / End Use 

8 

9 

10 

11 

12 

13 

14 

15 

16 E. Support 

17 

18 

19 Total Research and Development 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

Real Time Grid Monitoring 

Low Voltage Impacts of Air Conditioner Stalling 

Catalina Desalinization Demonstration 

Load Reduction and Demand Response System 

Nanostructured Polymers for Sludge Dewatering 

LED Street Light Demonstration 

Wastewater Efficiency 

Energy Efficient Home 

Research Administration and Project Development 

Billings to California Energy Commission 







(Mo, Da, Yr) 


04/18/2009 

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) 



(2) Research Support to Edison Electric Institute 

(3) Research Support to Nuclear Power Groups 

(4) Research Support to Others (Classify) 

(5) Total Cost Incurred 

3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $5,000 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 $5,000 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. 

Costs Incurred Internally 

Current Year 

(c) 

Costs Incurred Externally 

Current Year 

(d) 

AMOUNTS CHARGED IN CURRENT YEAR 

Account 

(e) 

Amount 

(f) 

Unamortized 

Accumulation 

(g) 

342,322 930 342,322 

2 

27,557 930 27,557 

3 

107,530 930 107,530 

4 

72,655 930 72,655 

5 

170,088 930 170,088 

6 

32,490 930 32,490 

7 

43,958 930 43,958 

8 

37,352 930 37,352 

9 

205,163 930 205,163 

10 

31,530 930 31,530 

11 

72,980 930 72,980 

12 

161,167 930 161,167 

13 

14 

15 

62,458 930 62,458 

16 

269 930 269 

17 

1 930 1 

18 

11,754 930 11,754 

19 

154,581 930 154,581 

20 

21 

16,002 930 16,002 

22 

16,497 930 16,497 

23 

9,339 930 9,339 

24 

11,452 930 11,452 

25 

254 930 254 

26 

25,618 930 25,618 

27 

6,130 930 6,130 

28 

15,243 930 15,243 

29 

13,671 930 13,671 

30 

59,829 930 59,829 

31 

23,370 930 23,370 

32 

5,000 930 5,000 

33 

6,283 930 6,283 

34 

4,515 930 4,515 

35 

16,541 930 16,541 

36 

1,196 930 1,196 

37 

38 

Line 

No. 

1 







(Mo, Da, Yr) 


04/18/2009 

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) 



(2) Research Support to Edison Electric Institute 

(3) Research Support to Nuclear Power Groups 

(4) Research Support to Others (Classify) 

(5) Total Cost Incurred 

3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $5,000 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 $5,000 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. 

Costs Incurred Internally 

Current Year 

(c) 

Costs Incurred Externally 

Current Year 

(d) 

AMOUNTS CHARGED IN CURRENT YEAR 

Account 

(e) 

Amount 

(f) 

Unamortized 

Accumulation 

(g) 

251,471 930 251,471 

2 

3 

4 

5 

6 

26,833 930 26,833 

7 

1,842 930 1,842 

8 

45,876 930 45,876 

9 

102,377 930 102,377 

10 

3,943 930 3,943 

11 

13,518 930 13,518 

12 

36,981 930 36,981 

13 

14 

15 

378,764 930 378,764 

16 

-505,803 930 -505,803 

17 

18 

1,352,695 767,902 2,120,597 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

Line 

No. 

1 







(Mo, Da, Yr) 


04/18/2009 

DISTRIBUTION OF SALARIES AND WAGES 



Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to 

Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns 

provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation 

giving substantially correct results may be used. 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 


(a) 

Electric 

Operation 

Production 

Transmission 

Regional Market 

Distribution 

Customer Accounts 

Customer Service and Informational 

Sales 

Administrative and General 

TOTAL Operation (Enter Total of lines 3 thru 10) 

Maintenance 

Production 

Transmission 

Regional Market 

Distribution 


TOTAL Maintenance (Total of lines 13 thru 17) 

Total Operation and Maintenance 

Production (Enter Total of lines 3 and 13) 

Transmission (Enter Total of lines 4 and 14) 

Regional Market (Enter Total of Lines 5 and 15) 

Distribution (Enter Total of lines 6 and 16) 

Customer Accounts (Transcribe from line 7) 

Customer Service and Informational (Transcribe from line 8) 

Sales (Transcribe from line 9) 

Administrative and General (Enter Total of lines 10 and 17) 

TOTAL Oper. and Maint. (Total of lines 20 thru 27) 

Gas 

Operation 

Production-Manufactured Gas 

Production-Nat. Gas (Including Expl. and Dev.) 

Other Gas Supply 

Storage, LNG Terminaling and Processing 

Transmission 

Distribution 

Customer Accounts 

Customer Service and Informational 

Sales 


TOTAL Operation (Enter Total of lines 31 thru 40) 

Maintenance 

Production-Manufactured Gas 

Production-Natural Gas (Including Exploration and Development) 

Other Gas Supply 

Storage, LNG Terminaling and Processing 

Transmission 

Direct Payroll 

Distribution 

(b) 

165,130,889 

47,979,628 

125,819,410 

111,880,219 

74,849,808 

2,695,258 

239,721,501 

768,076,713 

83,535,545 

17,035,104 

59,219,118 

3,194,551 

162,984,318 

248,666,434 

65,014,732 

185,038,528 

111,880,219 

74,849,808 

2,695,258 

242,916,052 

931,061,031 

261,409 

12,211 

24,875 

153,769 

452,264 

2,002 

Allocation of 

Payroll charged for 

Clearing Accounts 

(c) 

Total 

(d) 

931,061,031 







(Mo, Da, Yr) 


04/18/2009 

DISTRIBUTION OF SALARIES AND WAGES (Continued) 



Line 

No. 

48 

49 

50 

51 

52 

53 

54 

55 

56 

57 

58 

59 

60 

61 

62 

63 

64 

65 

66 

67 

68 

69 

70 

71 

72 

73 

74 

75 

76 

77 

78 

79 

80 

81 

82 

83 

84 

85 

86 

87 

88 

89 

90 

91 

92 

93 

94 

95 

96 


(a) 

Distribution 


TOTAL Maint. (Enter Total of lines 43 thru 49) 

Total Operation and Maintenance 

Production-Manufactured Gas (Enter Total of lines 31 and 43) 

Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 

Other Gas Supply (Enter Total of lines 33 and 45) 

Storage, LNG Terminaling and Processing (Total of lines 31 thru 

Transmission (Lines 35 and 47) 

Distribution (Lines 36 and 48) 

Customer Accounts (Line 37) 

Customer Service and Informational (Line 38) 

Sales (Line 39) 

Administrative and General (Lines 40 and 49) 

TOTAL Operation and Maint. (Total of lines 52 thru 61) 

Other Utility Departments 

Operation and Maintenance 

TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 

Utility Plant 

Construction (By Utility Departments) 


Gas Plant 


TOTAL Construction (Total of lines 68 thru 70) 

Plant Removal (By Utility Departments) 


Gas Plant 


TOTAL Plant Removal (Total of lines 73 thru 75) 

Other Accounts (Specify, provide details in footnote): 

Other Accounts Receivable/Payable 

Other Miscellaneous balance sheet accounts 

Accounts Receivable from associated companies 

Expenditures for certain civic, political and miscellaneous 

TOTAL Other Accounts 

TOTAL SALARIES AND WAGES 

Direct Payroll 

Distribution 

(b) 

10,509 

12,511 

263,411 

22,720 

24,875 

153,769 

464,775 

1,220,335 

932,746,141 

539,030,215 

539,030,215 

560,292 

5,083,679 

101,206,612 

6,021,397 

6,589,795 

119,461,775 

1,591,238,131 

Allocation of 

Payroll charged for 

Clearing Accounts 

(c) 

Total 

(d) 

464,775 

1,220,335 

932,746,141 

539,030,215 

539,030,215 

560,292 

5,083,679 

101,206,612 

6,021,397 

6,589,795 

119,461,775 

1,591,238,131 








(Mo, Da, Yr) 

04/18/2009 


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 by 

accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to 

the 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 accumulated 

provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including 

explanation 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 as 

provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such 

expenses 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 other 

authorization. 

COMMON UTILITY PLANT IN SERVICE 

-------------------------------- 

ACCOUNT BALANCE BEGINNING ADDITIONS RETIREMENTS BALANCE END 

OF YEAR 

OF YEAR 

Structures and Improvements $ 1,055,278 $ (59,254) $ 7,722 $ 1,003,706 

Office Furniture and Equipment 44,072 - - 44,072 

Transportation Equipment - - - - 

Stores Equipment 11,113 - - 11,113 

Tools, Shop and Garage Equipment 49,234 - - 49,234 

Communication Equipment 11,064 - - 11,064 

Miscellaneous Equipment - - - - 

______________ ____________ ___________ _____________ 

Total Common Utility 

Plant in Service 1,170,761 (59,294) 7,722 1,119,189 

Construction Work 

in Progress - - - - 

______________ _____________ ___________ ____________ 

Total Common 

Utility Plant $ 1,170,761 $ (59,294) $ 7,722 $ 1,119,189 

============= ============= =========== ============ 








(Mo, Da, Yr) 

04/18/2009 


End of 














CONSTRUCTION WORK in PROGRESS - COMMON UTILITY PLANT 

___________________________________________________ 

Balance 

Description of Project 

End of Year 

---------------------- ------------ 

Structures and Improvements $ 553,208 

Office Furniture and Equipment Acquisitions - 

Transportation Equipment - 

Stores Equipment - 

Tools and Equipment Acquisitions - 

Communication Equipment - 

Miscellaneous Equipment - 

____________ 

Total Construction Work in Progress 

Common Utility Plant $ 553,208 

============= 

DEPARTMENTAL ALLOCATION OF COMMON UTILITY 

PLANT MADE ON REVENUE BASIS 

_________________________________________ 

Total Common Utility Plant,Page 201,line 13 $ 1,119,189 

_________ 

Electric Department 60% 671,514 

Gas Department 15% 167,878 

Water Department 25% 279,797 

_________ 

$ 1,119,189 

========== 








(Mo, Da, Yr) 

04/18/2009 


End of 














DEPARTMENTAL ALLOCATION OF COMMON UTILITY 

PLANT MADE ON REVENUE BASIS 

_________________________________________ 

Total Common CWIP,Page 201,line 13 $ 553,208 

_________ 




________ 

$ 553,208 

========== 

Accumulated Provision for Depreciation of 

Common Utility Plant 

General Plant 

General Other 

Account 119.300 Account 119.400 Total 

=============== =============== ======== 

Balance Beginning of the Year $ 363,417 $ 27,930 $ 391,347 

Depreciation Provision for Year 

Charged to: 

Depreciation Expense 19,121 0 19,121 

Other Clearing Accounts 0 4,923 4,923 

Net Charges for Plant Retired: 

Book Cost of Plant Retired 7,722 0 7,722 

Cost of Removal 0 0 0 

Salvage 0 0 0 

------------ ------------- ------------ 

Net Charged for Plant Retired 7,722 0 7,722 

Other Credits (1,047) 0 (1,047) 

----------- ------------- ------------- 

Total Charged to Depreciation 25.796 4,923 30,720 

----------- ------------- ------------- 

Balance End of the Year $ 389,214 $ 32,853 $ 422,067 








(Mo, Da, Yr) 

04/18/2009 


End of 














========== ============= ============= 

Departmental Allocation of Accumulated Provision 

For Depreciation, Common Utility Plant Made on 

a Revenue Basis 

Accumulated Provision for Depreciation, 

Page 201, line 14 $ 422,067 

============ 




------------ 

$ 422,067 

============= 

Note: The accumulated provision for depreciation referred to above is 

classified as depreciation on general plant. 








(Mo, Da, Yr) 

04/18/2009 



AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS 

1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for 

Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market 

for 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 determining 

whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and 

separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively. 

Line 

Description of Item(s) 

Balance at End of Balance at End of Balance at End of Balance at End of 

No. 

Quarter 1 Quarter 2 

Quarter 3 

Year 

(a) 

(b) 

(c) 

(d) 

(e) 

1 Energy 

2 Net Purchases (Account 555) 

18,026,535 49,719,146 79,321,531 109,073,775 

3 Net Sales (Account 447) 

( 44,880,085) ( 108,713,835) ( 167,090,210) ( 229,491,436) 

4 Transmission Rights 

39,226,083 39,226,083 39,226,083 39,226,083 

5 Ancillary Services 

5,493,110 13,983,979 29,893,470 39,192,856 

6 Other Items (list separately) 

7 Congestion Revenue Rights 

( 1,238,044) ( 159,271) 13,229 

13,249 

8 Bid Cost Recovery 

240,464 624,914 896,164 

1,249,696 

9 Congestion 

25,486,936 30,995,506 33,822,109 40,194,169 

10 Minimum Load Costs 

2,613,737 8,679,367 5,585,219 13,623,181 

11 Other 

4,221,329 7,792,889 20,959,007 25,029,754 

12 Startup 

376,525 275,032 200,287 

101,632 

13 Transmission Losses 

33,952,559 81,759,338 126,285,718 178,312,195 

14 UFE 

( 4,005,344) ( 5,910,398) ( 10,559,158) ( 33,626,480) 

15 Wheeling 

233,837 514,061 636,825 

819,829 

16 GMC 

12,612,827 24,884,173 38,950,567 55,268,797 

17 Ferc Fees 

932,843 1,859,441 2,860,038 

4,055,136 

18 NERC/WECC 

3,203,656 3,203,656 6,431,139 10,762,152 

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 

96,496,968 148,734,081 207,432,018 

253,804,588 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




(1) Amounts in Columns (b, c, d & e) are shown at 100%, but only a portion of these amounts are SCE's ISO revenue and 

expenses. Amounts are shown at 100% to tie out with ISO Settlement Statements. 

(2) These charges are recorded to A/C 555, but are not included in line #2. 

(3) Amount shown is Net Revenue & Expense. 


Footnote (1). Please reference Line 1 Column b. 








































Footnote (1)(2). Please reference Line 1 Column b. 









FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




























































FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 










































(Mo, Da, Yr) 


04/18/2009 

PURCHASES AND SALES OF ANCILLARY SERVICES 



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 the 

respondents 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 sold 

during 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 sold 

during 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 services 

purchased 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 during 

the year. Include in a footnote and specify the amount for each type of other ancillary service provided. 

Line 

No. 

Type of Ancillary Service 

(a) 

1 Scheduling, System Control and Dispatch 

2 Reactive Supply and Voltage 

3 Regulation and Frequency Response 

4 Energy Imbalance 

5 Operating Reserve - Spinning 

6 Operating Reserve - Supplement 

7 Other 

8 Total (Lines 1 thru 7) 

Amount Purchased for the Year 

Usage - Related Billing Determinant 

Unit of 

Number of Units Measure Dollars 

(b) (c) (d) 

1,145,971 MWh 

2,296,793 MW 

1,874,990 MWH 

2,165,331 MW 

1,017,426 MW 

8,500,511 

MW 

69,943,542 

38,355,578 

145,496,033 

17,844,414 

3,374,132 

275,013,699 

Amount Sold for the Year 

Usage - Related Billing Determinant 

Unit of 

Number of Units Measure Dollars 

(e) (f) (g) 

1,319,128 

672,152 

3,394,826 

1,484,894 

1,187,694 

8,058,694 

MWh 

MW 

MWh 

MW 

MW 

MW 

104,301,850 

12,454,161 

220,334,168 

4,615,338 

1,482,275 

343,187,792 

FERC FORM NO. 1 (New 2-04) Page 398






FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




1) Scheduling, System Control and Dispatch includes Instructed Energy at the ISO, charge type 4401. 

2) ISO charges for No-Pay, Rational Buyer and Pre-empted AS and other AS related uplift charges are excluded. 


1) Regulation and Frequency Response includes the Regulation Up and Regulation Down at the ISO, Charge Types 5, 6, 

55, 56, 115 and 116. 



1) Energy Imbalance includes Uninstructed Energy at the ISO, charge type 4407. 


3) Energy Imbalance contains only the SCE share of ISO imbalance energy sales. 

4) Energy Imbalance is aggregated at the 10 minute interval level. 


1) Operating Reserve - Spinning includes Spinning Reserve at the ISO, charge types 1, 51 and 111. 



1) Operating Reserve - Supplement includes Non-Spinning Reserve at the ISO, charge types 2, 52 and 112. 



1) Other includes Replacement Reserve at the ISO charge type 114. 








(Mo, Da, Yr) 


04/18/2009 

MONTHLY TRANSMISSION SYSTEM PEAK LOAD 



(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically 

integrated, 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 for 

the definition of each statistical classification. 

NAME OF SYSTEM: 

SOUTHERN CALIFORNIA EDISON COMPANY 

Line 

No. 

1 January 

Month 

(a) 

2 February 

3 March 

4 Total for Quarter 1 

5 April 

6 May 

7 June 


9 July 

10 August 

11 September 


13 October 

14 November 

15 December 


Monthly Peak 

MW - Total 

(b) 

15,018 

14,169 

14,088 

43,275 

17,715 

20,187 

22,240 

60,142 

19,873 

21,148 

20,596 

61,617 

20,650 

14,693 

15,479 

50,822 

Day of 

Monthly 

Peak 

(c) 

23 

4 

24 

28 

19 

20 

16 

25 

3 

1 

17 

17 

Hour of 

Monthly 

Peak 

(d) 

1800 

1900 

1300 

1600 

1600 

1600 

1600 

1600 

1600 

1600 

1800 

1800 

Firm Network 

Service for Self 

(e) 

14,210 

13,530 

13,242 

40,982 

16,703 

19,319 

21,130 

57,152 

18,840 

20,158 

19,787 

58,785 

19,890 

14,135 

14,923 

48,948 

Firm Network 

Service for 

Others 

(f) 

Long-Term Firm 

Point-to-point 

Reservations 

(g) 

Other Long- 

Term Firm 

Service 

(h) 

808 

639 

846 

2,293 

1,012 

868 

1,110 

2,990 

1,033 

990 

809 

2,832 

760 

558 

556 

1,874 

Short-Term Firm 

Point-to-point 

Reservation 

(i) 

Other 

Service 

(j) 

17 Total Year to 

Date/Year 

215,856 

205,867 

9,989 







(Mo, Da, Yr) 


04/18/2009 

MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD 



(1) Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically 

integrated, 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 in 

Column (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). 

NAME OF SYSTEM: 

Line 

No. 

1 January 

Month 

(a) 

Monthly Peak 

MW - Total 

(b) 

Day of 

Monthly 

Peak 

(c) 

Hour of 

Monthly 

Peak 

(d) 

Imports into 

ISO/RTO 

(e) 

Exports from 

ISO/RTO 

(f) 

Through and 

Out Service 

(g) 

Network 

Service Usage 

(h) 

Point-to-Point 

Service Usage 

(i) 

Total Usage 

(j) 

2 February 

3 March 


5 April 

6 May 

7 June 


9 July 

10 August 

11 September 


13 October 

14 November 

15 December 


17 Total Year to 

Date/Year 

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a






(Mo, Da, Yr) 




04/18/2009 

ELECTRIC ENERGY ACCOUNT 

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year. 

Line 

No. 

Item 

(a) 

1 SOURCES OF ENERGY 

2 Generation (Excluding Station Use): 

3 Steam 

4 Nuclear 

5 Hydro-Conventional 

6 Hydro-Pumped Storage 

7 Other 

8 Less Energy for Pumping 

9 Net Generation (Enter Total of lines 3 

through 8) 

10 Purchases 

11 Power Exchanges: 

12 Received 

13 Delivered 

14 Net Exchanges (Line 12 minus line 13) 

15 Transmission For Other (Wheeling) 

16 Received 

17 Delivered 

18 Net Transmission for Other (Line 16 minus 

line 17) 

19 Transmission By Others Losses 

20 TOTAL (Enter Total of lines 9, 10, 14, 18 

and 19) 


Line 

Item MegaWatt Hours 

No. 

(b) 

(a) 

(b) 

21 DISPOSITION OF ENERGY 

22 Sales to Ultimate Consumers (Including 

58,686,936 

4,959,150 Interdepartmental Sales) 

16,659,055 23 Requirements Sales for Resale (See 

2,410,210 instruction 4, page 311.) 

255,743 24 Non-Requirements Sales for Resale (See 

8,768,588 

48,173 instruction 4, page 311.) 

242,292 25 Energy Furnished Without Charge 

24,090,039 26 Energy Used by the Company (Electric 

129,903 

Dept Only, Excluding Station Use) 

48,709,854 

289,843 

542,570 

-252,727 

8,966,079 

8,972,037 

-5,958 

72,541,208 

27 Total Energy Losses 

28 TOTAL (Enter Total of Lines 22 Through 

27) (MUST EQUAL LINE 20) 

4,955,781 

72,541,208 

FERC FORM NO. 1 (ED. 12-90) Page 401a



This 

(1) 


X 

Is: 

An Original 


MONTHLY PEAKS AND OUTPUT 


(Mo, Da, Yr) 

04/18/2009 



(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required 

information for each non- integrated system. 

(2) Report on line 2 by month the system's output in Megawatt hours for each month. 

(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. 

(4) Report on line 4 by month the system's monthly maximum megawatt load (60 minute integration) associated with the system. 

(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4. 

NAME OF SYSTEM: SOUTHERN CALIFORNIA EDISON COMPANY 

Monthly Non-Requirments 

Line 

MONTHLY PEAK 

Sales for Resale & 

No. Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4) Day of Month 

Hour 

(a) 

(b) 

(c) 

(d) 

(e) 

(f) 

29 January 

5,448,526 

809,011 14,560 

23 

1900 

30 February 

5,321,014 

895,220 13,954 

4 

1900 

31 March 

5,405,047 

1,111,356 13,690 

24 

1500 

32 April 

5,194,853 

721,273 17,088 

28 

1600 

33 May 

5,950,238 

617,057 19,881 

19 

1600 

34 June 

6,836,091 

465,534 21,652 

20 

1600 

35 July 

7,385,612 

538,510 19,405 

16 

1500 

36 August 

7,458,903 

660,342 20,721 

25 

1500 

37 September 

7,055,312 

728,215 20,256 

3 

1600 

38 October 

6,042,461 

819,237 20,658 

1 

1600 

39 November 

5,218,705 

788,392 14,605 

17 

1800 

40 December 

5,224,446 

614,440 15,262 

17 

1800 

41 TOTAL 72,541,208 8,768,587 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Excludes 8,852,591 direct access and 22,269,237 CDWR megawatthours. 








(Mo, Da, Yr) 

04/18/2009 


End of 


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 in 

this 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 operated 

as 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 attend 

more 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 a 

therm 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 cost 

per 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 one 

fuel is burned in a plant furnish only the composite heat rate for all fuels burned. 

Line 

No. 

Item 

(a) 

Plant 

Name: Mohave 

(b) 

Plant 

Name: Four Corners 

(c) 

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 

17 Total Cost 

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 

Steam 

Steam 

Outdoor 

Semi-Outdoor 

1971 

1969 

1971 

1970 

916.30 

785.40 

0 

1572 

0 

8403 

0 

0 

1580 

1500 

0 

0 

22 

182 

-4309000 

4963459000 

652772 

0 

33876898 

22207500 

279289598 

508340380 

0 

314397 

313819268 

530862277 

342.4853 

675.9133 

876620 

1699258 

5723024 

90357553 

0 

0 

412487 

7721391 

0 

0 

0 

0 

82893 

769783 

9536639 

5596552 

-36441 

-40188 

0 

0 

89809 

649367 

513796 

639475 

155239 

15657744 

65661 

4345577 

69680 

5105341 

17489407 

132501853 

-4.0588 

0.0267 

COAL GAS COAL GAS 

TONS MCF TONS MCF 

0 0 0 2703057 111014 0 

0 0 0 8929 1080 0 

0.000 0.000 0.000 0.000 16.119 0.000 

0.000 0.000 0.000 32.766 16.119 0.000 

0.000 0.000 0.000 1.835 14.925 0.000 

0.000 0.000 0.000 0.000 0.018 0.000 

0.000 0.000 0.000 0.000 9750.000 0.000 








(Mo, Da, Yr) 

04/18/2009 


End of 


STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 








Line 

No. 

Item 

(a) 

Plant 

Name: Palo Verde 

(b) 

Plant 

Name: Residual and Other 

(c) 

















17 Total Cost 



20 Fuel 







27 Rents 

28 Allowances 

















Nuclear 

Semi-Outdoor 

1986 

1988 

665.00 

0.00 

661 

0 

7464 

0 

0 

0 

623 

0 

0 

0 

376 

0 

4621109582 

0 

1208928 

0 

433379473 

0 

1301423095 

0 

0 

0 

1736011496 

0 

2610.5436 

0.0000 

10710246 

67757 

23564764 

0 

2281681 

0 

7321086 

0 

0 

0 

0 

0 

5580404 

0 

23520300 

7420549 

3602845 

732824 

0 

0 

6184222 

150018 

1677252 

-51736 

14162262 

0 

8814969 

67116 

3468535 

266774 

110888566 

8653302 

0.0240 

0.0000 

NUCLEAR 

Grams of URANIUM 

0 715400 0 0 0 0 

0 66157105 0 0 0 0 

0.000 32.939 0.000 0.000 0.000 0.000 

0.000 32.939 0.000 0.000 0.000 0.000 

0.000 0.498 0.000 0.000 0.000 0.000 

0.000 0.005 0.000 0.000 0.000 0.000 

0.000 10242.000 0.000 0.000 0.000 0.000 








(Mo, Da, Yr) 

04/18/2009 


End of 










Line 

No. 

Item 

(a) 

Plant 

Name: Mira Loma Sub Peaker 

(b) 

Plant 

Name: 

(c) 

















17 Total Cost 



20 Fuel 







27 Rents 

28 Allowances 

















Gas Turbine 

Outdoor 

2007 

2007 

60.50 

0.00 

49 

0 

119 

0 

0 

0 

46 

0 

0 

0 

7 

0 

4450688 

0 

0 

0 

141564 

0 

58939433 

0 

0 

0 

59080997 

0 

976.5454 

0.0000 

0 

0 

455932 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

0 

853469 

0 

17762 

0 

0 

0 

46725 

0 

0 

0 

0 

0 

452379 

0 

219974 

0 

2046241 

0 

0.4598 

0.0000 

GAS 

MCF 

51817 0 0 0 0 0 

1030 0 0 0 0 0 

8.799 0.000 0.000 0.000 0.000 0.000 

8.799 0.000 0.000 0.000 0.000 0.000 

8.542 0.000 0.000 0.000 0.000 0.000 

0.102 0.000 0.000 0.000 0.000 0.000 

11993.000 0.000 0.000 0.000 0.000 0.000 






(Mo, Da, Yr) 



04/18/2009 


9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load 

Dispatching, 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 plants 

designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear 

steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined 

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by 

footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units 

used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the 

report period and other physical and operating characteristics of plant. 

Plant 

Name: 

Fuel Facilities 

(d) 

Plant 

Name: 

San Onofre Unit 1 

(e) 

Plant 

Name: 

San Onofre Unit 2&3 

(f) 


End of 


Line 

No. 

Nuclear Nuclear 1 

Storage/Pipelines Semi-Outdoor Semi-Outdoor 2 

1967 1983 3 

1968 1984 4 

0.00 0.00 1763.00 5 

0 0 1682 6 

0 0 8784 7 

0 0 1682 8 

0 0 1682 9 

0 0 0 10 

0 0 1669 11 

0 0 12037945781 12 

8555 0 1100754 13 

1392138 0 1174436920 14 

0 0 3233578008 15 

0 0 0 16 

1400693 0 4409115682 17 

0.0000 0.0000 2500.9164 18 

0 0 59333359 19 

0 0 64397110 20 

0 0 1361952 21 

0 0 23289089 22 

0 0 0 23 

0 0 0 24 

0 0 5309145 25 

0 3837315 81870411 26 

0 0 1391861 27 

0 0 0 28 

55004 0 26383210 29 

0 0 11122920 30 

0 0 37883786 31 

0 0 18731231 32 

0 0 31970409 33 

55004 3837315 363044483 34 

0.0000 0.0000 0.0302 35 

NUCLEAR NUCLEAR 

36 

Grams of Uranium Grams of URANIUM 

37 

0 0 0 0 0 0 0 2211200 0 

38 

0 0 0 0 0 0 0 57921983 0 

39 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 29123.000 0.000 

40 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 29123.000 0.000 

41 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.503 0.000 

42 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.005 0.000 

43 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 10639.000 0.000 

44 






(Mo, Da, Yr) 



04/18/2009 











Plant 

Name: 

Barre Sub-Peaker 

(d) 

Plant 

Name: 

Center Sub-Peaker 

(e) 

Plant 

Name: 

Grapeland Sub-Peaker 

(f) 


End of 


Line 

No. 

GAS 

MCF 

Gas Turbine Gas Turbine Gas Turbine 1 

Outdoor Outdoor Outdoor 2 

2007 2007 2007 3 

2007 2007 2007 4 

60.50 60.50 60.50 5 

49 49 49 6 

118 120 125 7 

0 0 0 8 

47 47 46 9 

0 0 0 10 

8 8 7 11 

4726768 4711752 3681232 12 

0 1815 0 13 

223003 552196 871531 14 

65766543 67829917 62120939 15 

0 0 0 16 

65989546 68383928 62992470 17 

1090.7363 1130.3129 1041.1979 18 

0 1175448 0 19 

510700 453630 413435 20 

0 0 0 21 

0 0 0 22 

0 0 0 23 

0 0 0 24 

0 0 0 25 

1966352 568524 720338 26 

36187 203904 92556 27 

0 0 0 28 

46725 46725 46725 29 

0 0 0 30 

0 0 0 31 

333519 223447 350726 32 

210960 157110 196773 33 

3104443 2828788 1820553 34 

0.6568 0.6004 0.4945 35 

GAS GAS 

36 

MCF MCF 

37 

55430 0 0 48684 0 0 43246 0 0 

38 

1028 0 0 1025 0 0 1030 0 0 

39 

9.213 0.000 0.000 9.318 0.000 0.000 9.560 0.000 0.000 

40 

9.213 0.000 0.000 9.318 0.000 0.000 9.560 0.000 0.000 

41 

8.959 0.000 0.000 9.094 0.000 0.000 9.279 0.000 0.000 

42 

0.108 0.000 0.000 0.096 0.000 0.000 0.112 0.000 0.000 

43 

12060.000 0.000 0.000 10587.000 0.000 0.000 12104.000 0.000 0.000 

44 






(Mo, Da, Yr) 



04/18/2009 












Plant 

Name: 

(d) 

Plant 

Name: 

(e) 

Plant 

Name: 

(f) 

End of 


Line 

No. 

0.00 0.00 0.00 5 

0 0 0 6 

0 0 0 7 

0 0 0 8 

0 0 0 9 

0 0 0 10 

0 0 0 11 

0 0 0 12 

0 0 0 13 

0 0 0 14 

0 0 0 15 

0 0 0 16 

0 0 0 17 

0.0000 0.0000 0.0000 18 

0 0 0 19 

0 0 0 20 

0 0 0 21 

0 0 0 22 

0 0 0 23 

0 0 0 24 

0 0 0 25 

0 0 0 26 

0 0 0 27 

0 0 0 28 

0 0 0 29 

0 0 0 30 

0 0 0 31 

0 0 0 32 

0 0 0 33 

0 0 0 34 

0.0000 0.0000 0.0000 35 

0 0 0 0 0 0 0 0 0 

38 

0 0 0 0 0 0 0 0 0 

39 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

40 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

41 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

42 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

43 

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

44 

1 

2 

3 

4 

36 

37 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 402 Line No.: -1 Column: b 

Data is reported on an SCE-Share basis, except for line 6 "Net Peak Demand on Plant" which is based on the full capability of the 

plant. 

Schedule Page: 402 Line No.: -1 Column: c 

Data is reported on an SCE-Share basis, except for line 6 "Net Peak Demand on Plant" which is based on the full capability of the 

plant. 

Schedule Page: 402 Line No.: -1 Column: e 

The data reported is on an SCE-share basis, which is consistent with nuclear industry practice. 

Schedule Page: 402 Line No.: -1 Column: f 



San Onofre Unit 2&3: 

Data reported for total installed Capacity reported SCE-share basis. SCE was a 75.05% owner of SONGS 2 and 3 until December 29, 2006 and then 

became a 78.21% owner of SONGS 2 and 3 due to the transfer of Anaheim's share of the plants to SCE (i.e. this number reflects 3 days of SCE 

ownership at the 78.21% level). 



Data reported for Net Peak Demand reported SCE-share basis, SCE is a 78.21% owner of SONGS 2 and 3. 



Data reported for Tatal Plant Hours Connected to Load reported 100% Basis. 



Data reported for total Net Continuous Plant Capability reported SCE-share basis. SCE was a 75.05% owner of SONGS 2 and 3 until December 29, 

2006 and then became a 78.21% owner of SONGS 2 and 3 due to the transfer of Anaheim's share of the plants to SCE (i.e. this number reflects 3 days 

of SCE ownership at the 78.21% level). 


Not applicable. 




San Onofre Unit 1: Not applicable. 




San Onofre Unit 1: Not applicable. 


Average Number of Employees is reported at 100% level. 


Mohave: Represents station usage only. Plant is standstill status effective January 1, 2006. 


San Onofre Unit 2&3: Data reported for total Net Generation, Exclusive of Plant Use KWh-reported SCE share basis. 

SCE is a 78.21% owner of Songs 2 and 3. 

Schedule Page: 402.1 Line No.: -1 Column: b 


Schedule Page: 402.1 Line No.: -1 Column: d 

Barre: The unit has a total operating capacity in excess of 10,000 Kw per unit (Name Plate Rating). However, the unit 

does not run consistently and is only on-line during peak summer hours as the need requires. Projected Annual Kw usage 

is 10% of total capacity during operation requirements. 

Schedule Page: 402.1 Line No.: -1 Column: e 

Center Sub-Peaker: The unit has a total operating capacity in excess of 10,000 Kw per unit (Name Plate Rating). 

However, the unit does not run consistently and is only on-line during peak summer hours as the need requires. Projected 

Annual Kw usage is 10% of total capacity during operation requirements. 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 402.1 Line No.: -1 Column: f 

Grapeland Sub Peaker: The unit has a total operating capacity in excess of 10,000 Kw per unit (Name Plate Rating). 

However, the unit does not run consistently and is only on-line during peak summer hours as the need requires. Projected 

Annual Kw usage is 10% of total capacity during operation requirements. 


Palo Verde: Data reported for Installed Capacity reported SCE-share basis. SCE is a 15.8% owner of Palo Verde 1, 2, and 3. 


Barre: Generator Name Plate Rating is 60.5 MW at 15 degrees C and 0.85 Power Factor. Plant output is limited by the 

gas turbine. 


Center Sub-Peaker: Generator Name Plate Rating is 60.5 MW at 15 degrees C and 0.85 Power Factor. Plant output is 

limited by the gas turbine. 


Grapeland Peaker: Generator Name Plate Rating is 60.5 MW at 15 degrees C and 0.85 Power Factor. Plant output is 

limited by the gas turbine. 


Palo Verde: Data reported for Net Peak Demand reported SCE-share Basis. SCE is a 15.8% owner of Palo Verde 1, 2 

and 3. 


Palo Verde: Data reported for Total Plant Hours Connected to Load reported 100% basis. 


Data reported for total When Not Limited by Condenser Water reported SCE share basis. SCE is a 15.8% owner of Palo Verde 1, 2, and 3. 










Average Number of Employees is reported at 100% level. 


Palo Verde: Data reported for Net Generation Exclusive of Plant Use KWh-reported. SCE is a 15.8% owner of Palo 

Verde 1, 2, and 3. 


Other: Costs included in this column primarly represent unbilled Mountain View expense, and the costs for the plant which 

is still under construction. 


Other: Costs included in this column primarly represent corporate environmental health and safety and other. 


Barre Sub-Peaker: Reported data includes Generation Cost: $691,796. 


Center Sub-Peaker: Reported data includes Generation Cost: $360,696. 


Grapeland Peaker: Reported data includes Generation Cost: $557,771. 


Other: Costs included in this column primarly represent residual overhead expense. 


Other: Costs included in this column primarly represent unbilled Mountain View expense, and costs for the plant which is 

still under construction. 


Other: Costs included in this column primarly represent unbilled Mountain View expense. 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Other: Costs included in this column primarly represent unbilled Mountain View expense, and cost for the plant which is 

still under construction. 


Other: Costs included in this column primarly represent the plant which is still underconstruction, and unbilled Mountain 

View expense. 

Schedule Page: 402.2 Line No.: -1 Column: b 

Mira Loma Sub Peaker: The unit has a total operating capacity in excess of 10,000 Kw per unit (Name Plate Rating). However, the unit does not run 

consistently and is only on-line during peak summer hours as the need requires. Projected Annual Kw usage is 10% of total capacity during operation 

requirements. 


Mira Loma Sub Peaker: Generator Name Plate Rating is 60.5 MW at 15 degrees C and 0.85 Power Factor. Plant output is limited by the gas turbine. 




Mira Loma Sub Peaker: Reported data includes Generation Cost of $482,396. 

Schedule Page: 402 Line No.: 43 Column: b1 

Mohave: Plant is standstill status effective January 1, 2006. 

Schedule Page: 402 Line No.: 43 Column: c1 

Four Corners: Composite rates are for total fuel consumed. 

Schedule Page: 402 Line No.: 44 Column: b1 

Mohave: Plant is standstill status effective January 1, 2006. 

Schedule Page: 402 Line No.: 44 Column: c1 

Four Corners: Composite rates are for total fuel consumed. 


FERC FORM NO. 1 (REV. 12-03) Page 406 






(Mo, Da, Yr) 


04/18/2009 

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) 


End of 


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 in 

a 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 each 

plant. 

Line 

No. 

Item 

(a) 

FERC Licensed Project No. 2175 

Plant Name: Big Creek No. 1 

(b) 



(c) 

1 Kind of Plant (Run-of-River or Storage) 

Storage Storage 

2 Plant Construction type (Conventional or Outdoor) 

Conventional Conventional 


1913 1913 


1925 1925 

5 Total installed cap (Gen name plate Rating in MW) 

88.40 66.50 

6 Net Peak Demand on Plant-Megawatts (60 minutes) 

92 72 

7 Plant Hours Connect to Load 

8,784 8,784 

8 Net Plant Capability (in megawatts) 

9 (a) Under Most Favorable Oper Conditions 

83 67 

10 (b) Under the Most Adverse Oper Conditions 

83 67 


60 0 

12 Net Generation, Exclusive of Plant Use - Kwh 

411,375,607 360,279,891 

13 Cost of Plant 

14 Land and Land Rights 

0 1,344 


13,459,447 1,684,995 

16 Reservoirs, Dams, and Waterways 

4,178,201 4,143,522 


22,237,780 20,494,530 

18 Roads, Railroads, and Bridges 

790,229 541,102 


0 0 

20 TOTAL cost (Total of 14 thru 19) 

40,665,657 26,865,493 

21 Cost per KW of Installed Capacity (line 20 / 5) 

460.0187 403.9924 

22 Production Expenses 

23 Operation Supervision and Engineering 

446,708 327,890 

24 Water for Power 

14,512 4,245 

25 Hydraulic Expenses 

183,626 165,164 


497,320 248,241 

27 Misc Hydraulic Power Generation Expenses 

1,918,362 1,224,655 

28 Rents 

-31,531 -34,353 


208,242 182,377 


641,398 60,587 

31 Maintenance of Reservoirs, Dams, and Waterways 

273,244 203,564 


290,137 233,717 

33 Maintenance of Misc Hydraulic Plant 

385,186 225,532 

34 Total Production Expenses (total 23 thru 33) 

4,827,204 2,841,619 

35 Expenses per net KWh 

0.0117 0.0079

FERC FORM NO. 1 (REV. 12-03) Page 406.1 






(Mo, Da, Yr) 


04/18/2009 



End of 







plant. 

Line 

No. 

Item 

(a) 

FERC Licensed Project No. 


(b) 

67 


Plant Name: Portal Power Plant 

(c) 






1921 1956 


1929 1956 


75.00 10.80 


58 10 


8,773 8,784 



65 11 


65 11 


23 0 


128,314,327 20,642,509 



0 34,761 


2,434,093 628,174 


3,252,957 1,369,824 


12,673,946 3,773,490 


566,199 176,448 


0 0 


18,927,195 5,982,697 


252.3626 553.9534 



126,168 54,366 


96,723 89,778 


62,320 10,497 


231,534 85,310 


458,771 74,444 

28 Rents 

25,548 9,417 


64,954 10,449 


7,752 -7,959 


194,970 23,923 


206,841 126,292 


101,404 40,805 


1,576,985 517,322 


0.0123 0.0251







(Mo, Da, Yr) 


04/18/2009 



End of 







plant. 

Line 

No. 

Item 

(a) 


Plant Name: Poole Plant 

(b) 

1388 


Plant Name: Borel 

(c) 

382 


Storage Run-of-River 




1924 1904 


1924 1932 


11.30 12.00 


11 11 


7,169 5,996 



11 11 


11 11 


0 0 


22,112,561 45,357,587 



75,235 112,464 


304,975 578,842 


405,831 12,043,725 


2,533,745 2,904,337 


0 25,609 


0 0 


3,319,786 15,664,977 


293.7864 1,305.4148 



179,386 264,627 


-2,614 5,746 


31,893 139,312 


32,623 60,382 


111,530 400,301 

28 Rents 

54,142 9,385 


8,050 57,627 


221 2,773 


15,633 186,782 


5,519 91,905 


15,050 20,590 


451,433 1,239,430 


0.0204 0.0273







(Mo, Da, Yr) 


04/18/2009 



End of 







plant. 

Line 

No. 

Item 

(a) 


Plant Name: Big Crk Wtr Coll Fac 

(b) 


Plant Name: Other Costs 

(c) 

0 




0 


0 


0.00 0.00 


0 0 


0 0 



0 0 


0 0 


0 0 


0 0 



3,542,088 0 


5,777,231 0 


92,010,165 0 


459,096 0 


250,064 0 


0 87,320 


102,038,644 87,320 


0.0000 0.0000 



0 0 


0 0 


0 0 


0 0 


0 0 

28 Rents 

0 0 


0 0 


0 0 


0 0 


0 0 


0 0 


0 0 


0.0000 0.0000





(Mo, Da, Yr) 



04/18/2009 

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 


End of 


5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses 

do 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. 


FERC Licensed Project No. 120 FERC Licensed Project No. 

Plant Name: Big Creek No. 2A Plant Name: Big Creek No. 3 


(d) 

(e) 

(f) 

2017 

Line 

No. 


Storage 1 


Conventional 2 

1928 1923 1951 3 

1928 1980 1951 4 

110.00 174.50 100.00 5 

92 150 100 6 

2,321 8,445 8,781 7 

99 182 100 9 

99 182 100 10 

0 29 0 11 

17,683,804 486,575,568 297,172,438 12 

0 6,142 104,451 14 

1,524,555 6,861,968 2,083,789 15 

4,664,338 18,909,294 15,154,902 16 

14,853,389 29,589,384 14,018,068 17 

13,269 1,122,974 82,645 18 

0 0 0 19 

21,055,551 56,489,762 31,443,855 20 

191.4141 323.7236 314.4386 21 

23,868 496,545 307,099 23 

264,067 189,697 89,831 24 

15,654 212,289 131,548 25 

71,375 372,299 176,308 26 

69,223 1,774,979 1,125,737 27 

122,690 -118,573 -6,245 28 

8,952 246,309 150,431 29 

1,305 67,526 3,997 30 

217,121 224,515 114,785 31 

95,535 666,017 149,221 32 

113,774 498,195 184,051 33 

1,003,564 4,629,798 2,426,763 34 

0.0568 0.0095 0.0082 35 

8 

13 

22 






(Mo, Da, Yr) 



04/18/2009 



End of 






Plant Name: Kern River No. 1 

(d) 


Plant Name: Kern River No. 3 

(e) 


Plant Name: Mammoth Pool 

(f) 

2085 

Line 

No. 

Run-of-River Run-of-River 

Storage 1 


Outdoor 2 

1907 1921 1960 3 

1907 1921 1960 4 

26.30 40.20 190.00 5 

24 19 90 6 

5,081 5,151 8,278 7 

25 37 187 9 

25 37 187 10 

0 21 0 11 

44,254,594 69,422,681 296,340,712 12 

120,432 266,104 161,028 14 

960,396 1,874,138 2,404,765 15 

19,411,544 12,600,147 18,410,734 16 

8,586,574 8,017,686 15,245,825 17 

55,190 120,673 534,186 18 

0 0 0 19 

29,134,136 22,878,748 36,756,538 20 

1,107.7618 569.1231 193.4555 21 

258,192 386,843 271,573 23 

16,459 -9,308 99,493 24 

93,601 108,127 126,713 25 

68,652 203,118 228,936 26 

391,333 388,795 1,026,388 27 

-7,388 -2,768 35,307 28 

56,225 41,828 150,010 29 

21,272 23,245 133,591 30 

93,279 38,784 105,505 31 

47,671 630,014 1,420,781 32 

68,341 79,967 238,160 33 

1,107,637 1,888,645 3,836,457 34 

0.0250 0.0272 0.0129 35 

8 

13 

22 






(Mo, Da, Yr) 



04/18/2009 



End of 






Plant Name: Poole Res Fac 

(d) 

1388 


Plant Name: Rush Crk Res Fac 

(e) 


Plant Name: Bishop Plt Res Fac 

(f) 

Line 

No. 

1 

2 

3 

4 

0.00 0.00 0.00 5 

0 0 0 6 

0 0 0 7 

0 0 0 9 

0 0 0 10 

0 0 0 11 

0 0 0 12 

7,744 0 140,925 14 

9,916 56,688 105,285 15 

2,085,557 3,990,255 6,930,222 16 

0 18,267 611,720 17 

0 268,727 194,511 18 

0 0 0 19 

2,103,217 4,333,937 7,982,663 20 

0.0000 0.0000 0.0000 21 

0 0 0 23 

0 0 0 24 

0 0 0 25 

0 0 0 26 

0 0 0 27 

0 0 0 28 

0 0 0 29 

0 0 0 30 

0 0 0 31 

0 0 0 32 

0 0 0 33 

0 0 0 34 

0.0000 0.0000 0.0000 35 

8 

13 

22 






(Mo, Da, Yr) 



04/18/2009 



End of 






Plant Name: 

(d) 

0 FERC Licensed Project No. 0 


Plant Name: 

Plant Name: 

(e) 

(f) 

Line 

No. 

1 

2 

3 

4 

0.00 0.00 0.00 5 

0 0 0 6 

0 0 0 7 

0 0 0 9 

0 0 0 10 

0 0 0 11 

0 0 0 12 

0 0 0 14 

0 0 0 15 

0 0 0 16 

0 0 0 17 

0 0 0 18 

0 0 0 19 

0 0 0 20 

0.0000 0.0000 0.0000 21 

0 0 0 23 

0 0 0 24 

0 0 0 25 

0 0 0 26 

0 0 0 27 

0 0 0 28 

0 0 0 29 

0 0 0 30 

0 0 0 31 

0 0 0 32 

0 0 0 33 

0 0 0 34 

0.0000 0.0000 0.0000 35 

8 

13 

22 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Operated by remote control from Big Creek No. 3. 










Operate by remote control from Poole Plant. Includes Saddlebags, Tioga, Rhinedollar. Expenses incurred at Poole and 

Rush Creek Reservoir Facilities are allocated to Poole and Rush Creek Plants. 

These locations contain both Federal Project and Non-Project costs. 


Includes Rush Meadows Reservoir, Gem Lake and Agnew Lake. 

Expenses incurred at Poole and Rush Creek Reservoir Facilities are allocated to Poole and Rush Creek Plants. 

These allocations contain both Federal Project and Non-Project costs. 


Includes Equalizing Reservoir, South Lake, Sabrina Lake, Birch and McGee Creeks Diversion and miscellaneous Bishop 

Creek water rights. 

Expenses incurred at Bishop Plant Reservoir Facilities are prorated at the end of the year to the Bishop Creek Plants. 

These locations contain both Federal Project and Non-Project costs. 


Includes Huntington Lake (Reservoir), Shaver Lake (Reservoir), Florence Lake, Lake Thomas A. Edison, Mammoth Pool 

Lake and miscellaneous Big Creek water rights which are operated under licenses from the Federal Energy Regulatory 

Commission. Expenses incurred at Big Creek Water Collecting Facilities are prorated at the end of the year to Big Creek 

plants of which same operate under Federal license. 







(Mo, Da, Yr) 


04/18/2009 

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) 


End of 


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 in 

a footnote. Give project number. 

3. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 


plant. 


do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." 

Line 

No. 

Item 

(a) 


Plant Name: 

(b) 

67 

Eastwood 

1 Type of Plant Construction (Conventional or Outdoor) Conventional 

2 Year Originally Constructed 1987 

3 Year Last Unit was Installed 1987 

4 Total installed cap (Gen name plate Rating in MW) 200 

5 Net Peak Demaind on Plant-Megawatts (60 minutes) 207 

6 Plant Hours Connect to Load While Generating 8,641 

7 Net Plant Capability (in megawatts) 207 


9 Generation, Exclusive of Plant Use - Kwh 255,742,816 

10 Energy Used for Pumping 242,291,495 

11 Net Output for Load (line 9 - line 10) - Kwh 13,451,321 



14 Structures and Improvements 49,508,313 

15 Reservoirs, Dams, and Waterways 158,595,711 

16 Water Wheels, Turbines, and Generators 31,349,877 

17 Accessory Electric Equipment 15,055,009 

18 Miscellaneous Powerplant Equipment 5,767,257 

19 Roads, Railroads, and Bridges 2,062,781 


21 Total cost (total 13 thru 20) 262,338,948 

22 Cost per KW of installed cap (line 21 / 4) 1,311.6947 


24 Operation Supervision and Engineering 45,127 

25 Water for Power 113,753 

26 Pumped Storage Expenses 14,540 

27 Electric Expenses 180,788 

28 Misc Pumped Storage Power generation Expenses 139,439 

29 Rents 63,118 

30 Maintenance Supervision and Engineering 6,809 

31 Maintenance of Structures 50,325 

32 Maintenance of Reservoirs, Dams, and Waterways 58,057 

33 Maintenance of Electric Plant 505,523 

34 Maintenance of Misc Pumped Storage Plant 185,149 

35 Production Exp Before Pumping Exp (24 thru 34) 1,362,628 

36 Pumping Expenses 

37 Total Production Exp (total 35 and 36) 1,362,628 

38 Expenses per KWh (line 37 / 9) 0.0053 






(Mo, Da, Yr) 



04/18/2009 

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued) 


End of 


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, 37 

and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each 

station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as 

reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping 

energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract. 


Plant Name: 

(c) 

0 FERC Licensed Project No. 

0 FERC Licensed Project No. 

0 

Plant Name: 

Plant Name: 

(d) 

(e) 

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 

32 

33 

34 

35 

36 

37 

38 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Entire Plant is underground in a cavern. 


Generation Equipment installed in 1987; Pumpback Equipment installed in 1990. 


Operated by remote control from Big Creek No. 3 Hyroelectric Generating Plant. 







(Mo, Da, Yr) 


04/18/2009 

GENERATING PLANT STATISTICS (Small Plants) 



1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped 

storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from 

the 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. 

Year Installed Capacity Net Peak 

Line 

Net Generation 

Name of Plant 

Orig. Name Plate Rating Demand 

Excluding Cost of Plant 

No. 

Const. (In MW) 

MW 

(60 min.) 

Plant Use 

(a) 

(b) (c) 

(d) 

(e) 

(f) 

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 

Other Production 

Santa Catalina Island 

Unit 7 Diesel 

Unit 8 Diesel 

Unit 10 Diesel 




TOTAL 

Hydro 

Kaweah No.1 

Kaweah No.2 

Kaweah No.3 

Santa Ana No.1 

Santa Ana No.3 

Lower Tule 

Mill Creek No.1 

Mill Creek No.2 & 3 

Lytle Creek 

Fontana 

Sierra 

Ontario No.1 

Ontario No.2 

Mammoth Pool 

(Fish Water Unit) 

Big Creek No.4 (Dam 7) 

Bishop Creek No. 2 





Rush Creek 

San Gorgonio No. 1 & 2 

Lundy 

1958 

1963 

1966 

1976 

1986 

1995 

1929 

1929 

1913 

1899 

1999 

1909 

1893 

1903 

1904 

1917 

1922 

1902 

1963 

1960 

1951 

1908 

1913 

1905 

1919 

1913 

1916 

1923 

1911 

1.00 

1.50 

1.10 

1.60 

1.40 

2.80 

9.40 5.0 30,602,400 36,614,341 

2.30 2.0 8,955,823 3,935,471 

1.80 2.0 10,954,525 3,246,254 

4.80 5.0 18,264,713 4,637,433 

3.20 3.0 5,160,340 3,538,610 

3.10 3.0 2,701,266 8,986,522 

2.50 3.0 14,387,479 15,313,720 

0.80 1.0 1,900,231 721,565 

3.30 3.0 10,730,611 1,825,070 

0.50 1.0 3,079,621 2,180,395 

3.00 2.0 6,496,446 599,188 

0.50 1.0 3,442,475 753,205 

0.60 1.0 4,477,581 1,361,855 

0.30 1,066,842 391,058 

0.90 

0.40 

7.30 8.0 22,278,782 10,374,008 

7.80 8.0 23,923,939 5,946,034 

8.00 8.0 32,826,730 5,388,062 

4.50 4.0 12,083,469 3,889,977 

1.60 2.0 6,982,537 3,140,669 

13.00 12.0 16,070,222 8,688,664 

2.40 2.0 5,808,693 

3.00 3.0 4,893,997 2,147,805 







(Mo, Da, Yr) 




04/18/2009 

GENERATING PLANT STATISTICS (Small Plants) (Continued) 

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 with 

combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas 

turbine 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 Asset Operation 

Production Expenses 

Fuel Costs (in cents 

Line 

Retire. Costs) Per MW Exc'l. Fuel 

Fuel 

Maintenance 

Kind of Fuel (per Million Btu) 

No. 

(g) (h) 

(i) 

(j) (k) (l) 

1 

2 

Diesel 

3 

Diesel 

4 

Diesel 

5 

Diesel 

6 

Diesel 

7 

Diesel 

8 

3,895,143 3,626,358 

8,302,909 

1,385,005 Diesel 

2,670 9 

10 

11 

12 

13 

1,711,074 248,601 

277,867 

14 

1,803,474 268,181 

103,922 

15 

966,132 357,752 

197,987 

16 

17 

1,105,816 142,311 

151,411 

18 

2,898,878 117,754 

74,546 

19 

6,125,488 341,391 

308,683 

20 

901,956 63,444 

106,902 

21 

553,052 268,433 

255,940 

22 

4,360,790 119,139 

87,344 

23 

199,729 101,925 

52,765 

24 

1,506,410 145,022 

59,836 

25 

2,269,758 131,419 

140,749 

26 

1,303,527 50,664 

105,421 

27 

28 

29 

30 

1,421,097 480,647 

183,859 

31 

762,312 486,228 

179,514 

32 

673,508 841,260 

359,658 

33 

864,439 1,005,066 

61,990 

34 

1,962,918 157,496 

37,573 

35 

668,359 380,165 

128,136 

36 

2,420,289 42,376 

29,343 

37 

715,935 136,405 

199,659 

38 

39 

40 

41 

42 

43 

44 

45 

46 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Santa Ana #1 Project No. 1933 


Santa Ana #3 Project No. 1933 


Lower Tule Project No. 372 


Licensed Projects: 

Mill Creek # 2 & 3 Project No. 1934 


Lytle Creek Project No. 1932 


Mammoth Pool Project No. 2085 


Big Creek # 4 Project No. 2017 


Bishop Creek # 2 Project No. 1394 








Rush Creek Project No. 1389 


San Gorgonio # 1 & 2 Project No. 344 


Lundy Project No. 1390 







(Mo, Da, Yr) 


04/18/2009 

TRANSMISSION LINE STATISTICS 



1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 

kilovolts 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 report 

substation 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 construction 

by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the 

remainder 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 is 

reported 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. Report 

pole 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 with 

respect to such structures are included in the expenses reported for the line designated. 

Line 

No. 

DESIGNATION 

VOLTAGE (KV) 

(Indicate where 

Type of 

other than 

60 cycle, 3 phase) 

Supporting 

From 

To 

Operating Designed Structure 

(a) (b) 

(c) 

(d) (e) 

1 800 KV Lines 

2 

3 Sylmar Celilo (CA) 

4 Sylmar Celilo (NV) 

5 


7 

8 Midway Vincent #1 & #2 

9 Lugo Vincent #1 & #2 

10 Lugo Mohave (NV) 

11 El Dorado Lugo (CA) 

12 El Dorado Lugo (NV) 

13 Lugo Mira Loma #2, 3 

14 Lugo Mohave (CA) 

15 El Dorado Mohave (NV) 

16 El Dorado Border (NV) 

17 Mira Loma Serrano 

18 Lugo Victorville 

19 Midway Vincent #3 

20 Devers Palo Verde (CA) 

21 Devers Palo Verde (AZ) 

22 Devers Valley 

23 Serrano Valley 

24 


26 

27 Pardee Sylmar #1 & #2 

28 Eagle Rock Sylmar 

29 Pardee Vincent 

30 Santa Clara Vincent 

31 Rio Hondo Vincent #2 

32 Pardee Various 

33 Cogen/Renew. Energy Various 

34 Devers Various 

35 Antelope Various 

LENGTH (Pole miles) 

(In the case of 

underground lines 

report circuit miles) 

On Structure On Structures 

of Line of Another 

Designated Line 

(f) 

(g) 

Number 

Of 

Circuits 

1,000.00 800.00 Steel Tower 

168.09 2 

1,000.00 800.00 Steel Tower 

144.86 1 

500.00 500.00 Steel Tower 

225.49 2 

500.00 500.00 Steel Tower 

94.39 2 

500.00 500.00 Steel Tower 

9.85 1 

500.00 500.00 Steel Tower 

150.67 1 

500.00 500.00 Steel Tower 

26.51 1 

500.00 500.00 Steel Tower 

82.47 13.41 3 

500.00 500.00 Steel Tower 

165.96 1 

500.00 500.00 Steel Tower 

19.93 1 

500.00 500.00 Steel Tower 

29.65 1 

500.00 500.00 Steel Tower 

31.23 7.21 2 

500.00 500.00 Steel Tower 

7.57 1 

500.00 500.00 Steel Tower 

52.62 1 

500.00 500.00 Steel Tower 

126.45 1 

500.00 500.00 Steel Tower 

112.05 1 

500.00 500.00 Steel Tower 

41.60 1 

500.00 500.00 Steel Tower 

40.52 1 

220.00 220.00 Steel Tower 

6.53 6.47 2 

220.00 220.00 Steel Tower 

0.04 1.75 1 

220.00 220.00 Steel Tower 

7.35 2 

220.00 220.00 Steel Tower 

2.74 1 

220.00 220.00 Steel Tower 

4.65 1 

220.00 220.00 Steel Tower 

319.41 34.87 20 

220.00 220.00 Steel Tower 

3.57 4.85 6 

220.00 220.00 Steel Tower 

127.00 16.69 10 

220.00 220.00 Steel Tower 

255.30 15.49 10 

(h) 

36 TOTAL 9,901.50 2,362.95 1,200 







(Mo, Da, Yr) 


04/18/2009 


















Line 

DESIGNATION 

VOLTAGE (KV) 


Type of 


(In the case of Number 

No. 

other than 



Supporting report circuit miles) Of 


From 

To 

Operating Designed Structure of Line of Another 

Circuits 


(a) (b) 

(c) 

(d) (e) (f) 

(g) (h) 

1 Chino Various 

220.00 220.00 Steel Tower 

85.49 84.09 6 

2 Big Creek #3 Big Creek #4 

220.00 220.00 Steel Tower 

5.79 1 

3 Big Creek #3 Springville 

220.00 220.00 Steel Tower 

128.32 2 

4 Laguna Bell Various 

220.00 220.00 Steel Tower 

89.57 39.98 13 

5 Hinson Various 

220.00 220.00 Steel Tower 

15.30 11.77 4 

6 El Nido Various 

220.00 220.00 Steel Tower 

57.52 33.89 13 

7 Pisgah #2 Various 

220.00 220.00 Steel Tower 

305.19 5 

8 Mira Loma Various 

220.00 220.00 Steel Tower 

89.75 66.00 16 

9 Center Various 

220.00 220.00 Steel Tower 

83.57 54.08 9 

10 Alamitos Various 

220.00 220.00 Steel Tower 

84.63 40.04 14 

11 Big Creek #4 Magunden 

220.00 220.00 Steel Tower 

135.41 2 

12 Moorpark Various 

220.00 220.00 Steel Tower 

221.67 193.08 15 

13 Cima Pisgah (NV) 

220.00 220.00 Steel Tower 

84.46 0.63 4 

14 Kramer Various 

220.00 220.00 Steel Tower 

153.63 101.99 6 

15 El Dorado Meade (NV) 

220.00 220.00 Steel Tower 

16.76 2 

16 Santa Clara Vincent 

220.00 220.00 Steel Tower 

27.48 1 

17 Pearblossom Vincent 

220.00 220.00 Wood-H Frame 

13.13 1 

18 Ellis Santiago #1 & #2 

220.00 220.00 Steel Tower 

14.93 14.56 3 

19 Rio Hondo Vincent 

220.00 220.00 Steel Tower 

20.35 1 

20 Big Creek #2 Big Creek #8 

220.00 220.00 Steel Tower 

9.03 2 

21 Big Creek #3 Mammoth Pool 

220.00 220.00 Steel Tower 

6.50 1 

22 Big Creek Various 

220.00 220.00 Steel Tower 

290.35 7.27 9 

23 Serrano Villa Park #1-3 

220.00 220.00 Steel Tower 

3.39 3.11 2 

24 Big Creek #1 Eastwood 

220.00 220.00 Steel Tower 

4.66 1 

25 Devers Various 

220.00 220.00 Steel Tower 

80.58 39.72 3 

26 

27 


29 

30 Blythe - Eagle Mountain 

161.00 161.00 Wood H Frame 

52.35 0.10 1 

31 


33 

115.00 115.00 Steel Pole 

94.06 

55.91 

34 

115.00 115.00 Steel Tower 

419.54 158.11 

35 

115.00 115.00 Wood H Frame 407.65 

10.51 

36 TOTAL 9,901.50 2,362.95 1,200 







(Mo, Da, Yr) 


04/18/2009 


















Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

DESIGNATION 

VOLTAGE (KV) 


Type of 



other than 



Supporting report circuit miles) 


From 

To 

Operating Designed Structure of Line of Another 


(a) (b) 

(c) 

(d) (e) (f) 

(g) 

115.00 115.00 Wood Pole 

644.08 

46.61 

9 Total 115 KV Lines 

10 


12 

13 

14 

15 

16 

17 Total 66KV Lines 

18 


20 

21 

22 

23 


25 


27 

28 

29 

30 

31 


33 

34 

35 

115.00 115.00 Underground 

8.56 

5.24 

66.00 115.00 Steel Pole 

0.36 

0.18 

66.00 115.00 Steel Tower 

5.06 

0.02 

66.00 115.00 Wood H Frame 

0.49 

66.00 115.00 Wood Pole 

5.25 

0.09 


1.41 

55.00 115.00 Wood Pole 

0.31 

66.00 66.00 Steel Pole 

288.80 122.05 

66.00 66.00 Wood Pole 

2,619.41 568.59 


634.69 414.33 

66.00 66.00 Wood H Frame 128.67 

34.84 


175.57 140.80 

55.00 55.00 Steel Pole 

0.19 

55.00 55.00 Wood Pole 

96.05 

55.00 55.00 Wood H Frame 

1.38 

55.00 

55.00 Steel Tower 

33.00 33.00 Steel Pole 

5.02 

0.78 


1.24 

0.27 

33.00 33.00 Wood Pole 

17.81 

13.31 


9.26 

33.00 33.00 Wood H Frame 

0.33 

0.26 

Number 

Of 

Circuits 

(h) 

121 

847 

9 

9 

36 TOTAL 9,901.50 2,362.95 1,200 







(Mo, Da, Yr) 


04/18/2009 


















Line 

No. 

DESIGNATION 

VOLTAGE (KV) 


Type of 

other than 


Supporting 

From 

To 

Operating Designed Structure 

(a) (b) 

(c) 

(d) (e) 

1 33 & 66 KV Lines 

2 Total 33 & 66 KV Lines 

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 




report circuit miles) 


of Line of Another 


(f) 

(g) 

Number 

Of 

Circuits 

(h) 

36 TOTAL 9,901.50 2,362.95 1,200 







(Mo, Da, Yr) 


04/18/2009 

TRANSMISSION LINE STATISTICS (Continued) 



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 if 

you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the 

pole 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, for 

which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the 

arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing 

expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or 

other 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 how 

determined. 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. 

COST OF LINE (Include in Column (j) Land, 

EXPENSES, EXCEPT DEPRECIATION AND TAXES 

Size of Land rights, and clearing right-of-way) 

Conductor 

and Material 

Land Construction and Total Cost Operation Maintenance Rents Total 

Other Costs 

Expenses Expenses 

Expenses 

(i) (j) (k) (l) (m) (n) (o) (p) 

1 

2 

136,841 37,490,070 37,626,911 

170,787 72,082 118,852 361,721 3 

668,871 13,330,575 13,999,446 

4 

5 

6 

7 

3,706,357 41,924,446 45,630,803 

27,252 266,021 

293,273 8 

1,736,812 14,917,410 16,654,222 

12,528 64,127 

76,655 9 

177,040 938,088 1,115,128 

10 

1,448,120 22,610,692 24,058,812 

2,779 2,779 11 

36,677 3,812,074 3,848,751 

12 

10,223,088 40,584,128 50,807,216 

14,365 481,691 

2,741 498,797 13 

607,445 19,487,987 20,095,432 

14,317 24,704 

39,021 14 

132,116 2,406,897 2,539,013 

9,083 36,470 

45,553 15 

151,231 4,468,801 4,620,032 

1,994 2,600 

4,594 16 

1,949,720 26,205,300 28,155,020 

23,035 257,414 

79 280,528 17 

751,549 1,917,202 2,668,751 

980 7,192 

8,172 18 

3,144,755 12,122,164 15,266,919 

6,559 -82,248 

-75,689 19 

12,998,056 50,476,579 63,474,635 

24,793 -208,573 

-183,780 20 

1,341,580 42,144,626 43,486,206 

969 33,426 

34,395 21 

15,234,409 32,973,763 48,208,172 

13,744 66,351 

80,095 22 

5,348,634 38,266,158 43,614,792 

18,051 95,391 

113,442 23 

24 

26 

217,137 1,154,799 1,371,936 

1,330 3,404 

4,734 27 

186,657 276,517 

463,174 

74 3,122 

3,196 28 

145,317 521,234 

666,551 

29 

33,955 536,006 

569,961 

6,639 -4,623 

2,016 30 

72,932 576,910 

649,842 

31 

2,626,035 54,459,952 57,085,987 1,719,495 363,764 

5,786 2,089,045 32 

1,466,128 3,976,672 5,442,800 

35,678 39,512 -227,083 -151,893 33 

1,561,732 9,346,572 10,908,304 

46,751 430,289 

477,040 34 

3,476,092 16,005,523 19,481,615 

74,306 273,352 

347,658 35 

Line 

No. 

25 

190,252,465 1,573,636,393 1,763,888,858 7,683,082 15,691,159 1,903,818 25,278,059 36 







(Mo, Da, Yr) 


04/18/2009 



















Conductor 



Other Costs 


Expenses 

(i) (j) (k) (l) (m) (n) (o) (p) 

8,522,121 32,853,710 41,375,831 

40,899 231,389 

12,794 285,082 1 

31,372 289,443 

320,815 

6,785 22,409 

1,285 

30,479 2 

1,276,371 3,359,869 4,636,240 

144,460 364,625 

3,378 512,463 3 

3,514,758 24,557,832 28,072,590 

32,072 246,975 

279,047 4 

1,634,441 6,623,768 8,258,209 

4,024 82,619 

86,643 5 

3,608,180 16,415,807 20,023,987 

44,222 181,988 

226,210 6 

1,156,671 7,718,039 8,874,710 

34,944 70,090 

105,034 7 

5,822,487 26,820,202 32,642,689 

70,202 354,058 

424,260 8 

2,152,210 22,916,345 25,068,555 

23,523 123,256 

146,779 9 

4,303,674 13,218,231 17,521,905 

182,659 286,211 

468,870 10 

449,753 4,101,257 4,551,010 

47,401 71,228 

118,629 11 

13,195,775 47,364,055 60,559,830 

204,548 410,170 

614,718 12 

25,048 1,197,458 1,222,506 

2,525 2,525 13 

2,325,416 17,690,412 20,015,828 

903 86,889 

87,792 14 

11,017 902,889 

913,906 

3,859 882 

405 

5,146 15 

3,985,983 6,009,440 9,995,423 

9,013 2,172 

11,185 16 

332,719 1,148,511 1,481,230 

1,010 3,697 

4,707 17 

12,063,552 8,547,450 20,611,002 

12,022 52,017 

64,039 18 

642,632 5,598,177 6,240,809 

19 

9,035 300,481 

309,516 

7,466 28,486 

2,818 

38,770 20 

42,221 434,944 

477,165 

1,666 61,821 

5,032 

68,519 21 

3,630,754 11,924,764 15,555,518 

121,267 859,267 

6,066 986,600 22 

77,061 2,918,602 2,995,663 

5,388 18,492 

23,880 23 

6,392,921 6,392,921 

3,616 30,633 

34,249 24 

1,198,858 12,131,574 13,330,432 

25 

26 

27 

28 

29 

38,155 2,341,175 2,379,330 

10,345 2,191 

228 

12,764 30 

31 

Line 

No. 

32 

33 

34 

35 

190,252,465 1,573,636,393 1,763,888,858 7,683,082 15,691,159 1,903,818 25,278,059 36 







(Mo, Da, Yr) 


04/18/2009 



















Conductor 



Other Costs 


Expenses 

(i) (j) (k) (l) (m) (n) (o) (p) 

1 

2 

3 

4 

5 

6 

7 

8 

16,288,248 134,274,052 150,562,300 

533,889 959,506 

39,274 1,532,669 9 

10 

16 

34,322,272 661,271,963 695,594,235 2,858,441 5,963,874 1,830,520 10,652,835 17 

18 

23 

10,585 661,665 

672,250 

219,283 384,524 

603,807 24 

25 

31 

1,810 720,212 

722,022 

32 

33 

34 

35 

Line 

No. 

11 

12 

13 

14 

15 

19 

20 

21 

22 

26 

27 

28 

29 

30 

190,252,465 1,573,636,393 1,763,888,858 7,683,082 15,691,159 1,903,818 25,278,059 36 







(Mo, Da, Yr) 


04/18/2009 



















Conductor 



Other Costs 


Expenses 

(i) (j) (k) (l) (m) (n) (o) (p) 

Line 

No. 

837,348 2,656,980 

4,678 

1 

3,499,006 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 

190,252,465 1,573,636,393 1,763,888,858 7,683,082 15,691,159 1,903,818 25,278,059 36 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 




Edison's share only. Joint ownership with Los Angeles Department of Water and Power, which owns 50%. Expenses 

shared on ownership basis and charged to accounts 560-573. 


Edison's share only. Joint ownership with Los Angeles Department of Water and Power, which owns 50%. Expenses 

shared on ownership basis and charged to accounts 560-573. 


Edison's share only. Joint ownership with Los Angeles Department of Water and Power, Salt River Project, Agricultural 

Improvement and Power District, and Nevada Power Company, which own 30.20%, 15.10% and 21.14%,respectively. 

Expenses shared on ownership basis and charged to Accounts 560-573. 


Edison's share only. Joint ownership with Salt River Project Agricultural Improvement and Power District, and Nevada 

Power 

Company, which own 18.875% and 26.425%, respectively. Expenses shared on ownership basis and charged to 

Accounts 560-573. 


Eastern and Northern Divisions' cost accounting merged for 33KV and 66KV lines. Mileage included in the detail for 33KV 

and 66KV lines. 

Schedule Page: 422.3 Line No.: 1 Column: g 

Eastern and Northern Divisions' cost accounting merged for 33KV and 66KV lines. Mileage included in the detailfor 33KV 

and 66KV lines. 

Schedule Page: 422.3 Line No.: 2 Column: j 

Eastern and Northern Divisions' cost accounting merged for 33KV and 66KV lines. Cost of lines included in the detail for 

33KV and 66KV lines. 













(Mo, Da, Yr) 




04/18/2009 

TRANSMISSION LINES ADDED DURING YEAR 

1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report 

minor revisions of lines. 

2. Provide separate subheadings for overhead and underground construction and show each transmission line separately. If actual 

costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the 

Line 

LINE DESIGNATION 

Line SUPPORTING STRUCTURE CIRCUITS PER STRUCTURE 

Length 

Average 

No. 

From 

To 

in 

Type 

Number per Present Ultimate 

Miles 

Miles 

(a) (b) 

(c) 

(d) (e) 

(f) 

(g) 

1 Overhead Construction 

2 

3 Etiwanda Ameron-Grapeland-Pipe 

OH 1 1 

4 Antelope Oasis-Palmdale-Quartz Hill 5.70 WP/OH 26.00 

2 2 

5 Antelope Quartz Hill-Shuttle 1.61 WP/OH 26.00 

2 2 

6 Antelope Shuttle 5.11 WP/OH 26.00 

2 2 

7 

8 Underground Construction 

9 

10 Kern River McMeil 0.10 UG 1 2 

11 Saugus North Oaks-Tengen 1.37 UG 1 2 

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 

13.89 78.00 9 11 







(Mo, Da, Yr) 




04/18/2009 

TRANSMISSION LINES ADDED DURING YEAR (Continued) 

costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and 

Trails, 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. 

CONDUCTORS 

Voltage 

LINE COST 

Line 

Size Specification Configuration KV Land and Poles, Towers Conductors Asset 

Total No. 

and Spacing (Operating) Land Rights and Fixtures and Devices Retire. Costs 

(h) (i) 

(j) 

(k) 

(l) (m) 

(n) 

(o) 

(p) 

1 

2 

954.0 SAC 

SCP 

66 45,579 28,145 73,724 3 

954.0 SAC 

DCC 

66 157,987 844,915 1,002,902 4 

954.0 SAC 

DCC 

66 44,625 238,651 283,276 5 

954.0 SAC 

DCC 

66 141,634 757,459 899,093 6 

1750 KCM 

SDG 

66 100,801 363,111 463,912 10 

1750 KCM 

SDG 

66 167,395 2,210,728 2,378,123 11 

7 

8 

9 

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 

658,021 

4,443,009 

5,101,030 

44 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 



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 according 

to 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 whether 

attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in 

column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 

VOLTAGE (In MVa) 

Name and Location of Substation 

Character of Substation 

Primary Secondary Tertiary 

(a) 

(b) 

(c) 

(d) 

(e) 

ALESSANDRO SAN JACINTO TU 

115.00 33.00 

ALESSANDRO SAN JACINTO TU 

115.00 12.00 

ANTELOPE LANCASTER TU 

220.00 66.00 

ANTELOPE LANCASTER TU 

66.00 12.00 

APPLE VALLEY HI DESERT TU 

115.00 12.00 

AQUEDUCT HI DESERT TU 

115.00 12.00 

ARROWHEAD ARROWHEAD TU 

115.00 33.00 

ARROWHEAD ARROWHEAD TU 

33.00 12.00 

AULD SAN JACINTO TU 

115.00 33.00 


115.00 12.00 


33.00 12.00 

BAILEY LANCASTER TU 

220.00 66.00 

BAKER HI DESERT TU 

115.00 12.00 

BAKER HI DESERT TU 

115.00 33.00 

BANNING INLAND TU 

115.00 33.00 

BARRE FULLERTON TU 

220.00 66.00 

BARRE FULLERTON TU 

66.00 12.00 

BLYTHE (WALC) BLYTHE TU 

161.00 33.00 

BUNKER SAN JACITO TU 

115.00 12.00 

CAJALCO SAN JACINTO TU 

115.00 12.00 

CALECTRIC INLAND TU 

115.00 33.00 

CAMINO TWENTY-NINE PALMS TU 

220.00 66.00 

CAMINO TWENTY-NINE PALMS TU 

66.00 16.00 

CARODEAN TWENTY-NINE PALMS TU 

115.00 12.00 

CASA DIABLO BISHOP TU 

115.00 33.00 

CASA DIABLO BISHOP TU 

33.00 12.00 

CENTER WHITTIER TU 

220.00 66.00 

CENTER WHITTIER TU 

66.00 12.00 

CHINO ONTARIO TU 

220.00 66.00 


66.00 12.00 


66.00 13.00 

CIMA HI DESERT TU 

220.00 66.00 

CIMA HI DESERT TU 

220.00 16.00 

CONCHO PALM SPRINGS TU 

115.00 12.00 

CONTROL BISHOP TA 

115.00 115.00 

CONTROL BISHOP TA 

115.00 55.00 

COTTONWOOD HI DESERT TU 

115.00 33.00 

DEL AMO LONG BEACH TU 

220.00 66.00 

DEL AMO LONG BEACH TU 

66.00 66.00 

DEVERS PALM SPRINGS TA 

500.00 220.00 13.80 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

DEVERS PALM SPRINGS TA 

220.00 115.00 

DUNN SIDING HI DESERT TU 

115.00 12.00 

EAGLE MOUNTAIN BLYTHE TU 

220.00 66.00 


220.00 161.00 


66.00 12.00 

EAGLE ROCK MONROVIA TU 

220.00 66.00 

EDWARDS RIDGECREST TU 

115.00 33.00 

EISENHOWER PALM SPRINGS TU 

115.00 33.00 

EISENHOWER PALM SPRINGS TU 

115.00 12.00 

EL NIDO INGLEWOOD TA 

220.00 66.00 

EL NIDO INGLEWOOD TA 

66.00 16.00 

ELDORADO CLARK CO., NEVADA TA 

500.00 220.00 13.80 

ELDORADO CLARK CO., NEVADA TA 

220.00 115.00 11.50 

ELLIS HUNTINGTON BEACH TA 

220.00 66.00 

ELLIS HUNTINGTON BEACH TA 

66.00 12.00 

ELSINORE SAN JACINTO TU 

115.00 33.00 


115.00 12.00 


33.00 2.00 

FARRELL PALM SPRINGS TU 

115.00 12.00 

FISH LAKE VALLEY BISHOP TU 

55.00 55.00 

GALE HI DESERT TU 

115.00 33.00 

GARNET PALM SPRINGS TU 

115.00 33.00 

GARNET PALM SPRINGS TU 

33.00 12.00 

GOLETA SANTA BARBARA TU 

220.00 66.00 

GOLETA SANTA BARBARA TU 

66.00 16.00 

GOULD MONROVIA TU 

220.00 66.00 


66.00 16.00 


16.00 33.00 

HESPERIA HI DESERT TU 

115.00 12.00 

HI DESERT TWENTY-NINEPALMS TU 

115.00 33.00 

HI DESERT TWENTY-NINEPALMS TU 

33.00 25.00 

HINSON LONG BEACH TU 

220.00 66.00 

HOLGATE BORON TU 

33.00 12.00 

HOMART INLAND TU 

115.00 12.00 

INDIAN WELLS PALM SPRINGS TU 

115.00 12.00 

INYO BISHOP TU 

220.00 115.00 

INYOKERN RIDGECREST TU 

115.00 33.00 

INYOKERN RIDGECREST TU 

33.00 12.00 

IVYGLEN ONTARIO TU 

115.00 12.00 

JOHANNA SANTA ANA TU 

220.00 66.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

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16 

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21 

22 

23 

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25 

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33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

JOHANNA SANTA ANA TU 

66.00 12.00 

KRAMER RIDGECREST TU 

115.00 33.00 


220.00 115.00 


33.00 2.00 

LA CIENEGA SANTA MONICA TU 

220.00 66.00 

LA FRESA REDONDO TU 

220.00 66.00 


66.00 16.00 


66.00 12.00 

LAGUNA BELL MONTEBELLO TU 

220.00 66.00 


66.00 16.00 


66.00 12.00 

LEE VINING BISHOP TA 

115.00 55.00 

LEE VINING BISHOP TA 

55.00 2.00 

LIGHTHIPE LONG BEACH TA 

220.00 66.00 


66.00 12.00 


66.00 12.00 


66.00 13.00 

LUGO HI DESERT TA 

500.00 220.00 13.80 

MAGUNDEN KERN TU 

220.00 220.00 

MARASCHINO INLAND TU 

115.00 12.00 

MAXWELL SAN JACINTO TU 

115.00 12.00 

MAYBERRY SAN JACINTO TU 

115.00 12.00 

MENTONE INLAND TU 

115.00 12.00 

MESA MONTEBELLO TA 

220.00 66.00 


69.00 13.00 


66.00 16.00 

MIRA LOMA ONTARIO TA 

500.00 220.00 13.80 


220.00 66.00 


66.00 12.00 

MIRAGE PALM SPRINGS TU 

115.00 92.00 

MIRAGE PALM SPRINGS TU 

220.00 115.00 

MOORPARK THOUSAND OAKS TA 

220.00 66.00 

MOORPARK THOUSAND OAKS TA 

66.00 16.00 

MORAGA TEMECULA TU 

115.00 12.00 


115.00 115.00 


33.00 33.00 

MORENO SAN JACINTO TU 

115.00 12.00 

MOUNTAIN PASS HI DESERT TU 

115.00 33.00 

MOUNTAIN PASS HI DESERT TU 

33.00 12.00 

NELSON SAN JACINTO TU 

115.00 33.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

Line 

No. 

1 

2 

3 

4 

5 

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37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

NELSON SAN JACINTO TU 

115.00 12.00 

NEWCOMB SAN JACINTO TU 

115.00 12.00 

OLINDA FULLERTON TU 

220.00 66.00 

OLINDA FULLERTON TU 

66.00 12.00 

PADUA FOOTHILL TU 

220.00 66.00 

PADUA FOOTHILL TU 

66.00 12.00 

PARDEE SAN FERNANDO TU 

220.00 220.00 

PASTORIA KERN COUNTY TU 

220.00 66.00 

PAUBA SAN JACINTO TU 

115.00 12.00 

PECHANGA SAN JACINTO TU 

115.00 33.00 

PECHANGA SAN JACINTO TU 

115.00 12.00 

PEPPER INLAND TU 

115.00 12.00 

PHELAN HI DESERT TU 

115.00 33.00 

PHELAN HI DESERT TU 

115.00 12.00 

PISGAH HI DESERT TU 

220.00 220.00 

RANDSBURG RIDGECREST TU 

115.00 33.00 

RECTOR VISALIA TA 

220.00 66.00 

RECTOR VISALIA TA 

66.00 12.00 

RENWIND PALM SPRINGS TU 

115.00 12.00 

RIO HONDO MONROVIA TU 

220.00 66.00 


66.00 12.00 


66.00 16.00 

ROADWAY HI DESERT TU 

115.00 12.00 

SAN BERNARDINO INLAND TU 

220.00 66.00 


66.00 12.00 


66.00 1.00 

SANTA CLARA VENTURA TU 

220.00 66.00 

SANTA ROSA PALM SPRINGS TU 

115.00 33.00 

SANTA ROSA PALM SPRINGS TU 

115.00 12.00 

SANTIAGO EL TORO TU 

220.00 66.00 

SANTIAGO EL TORO TU 

66.00 12.00 

SANWIND PALM SPRINGS TU 

115.00 12.00 

SAUGUS SAN FERNANDO TU 

220.00 66.00 

SAUGUS SAN FERNANDO TU 

66.00 16.00 

SAVAGE HESPERIA TU 

115.00 12.00 

SAVAGE HESPERIA TU 

115.00 115.00 

SEARLES RIDGECREST TU 

115.00 33.00 

SERRANO ORANGE TU 

500.00 220.00 13.80 

SHANDIN INLAND TU 

115.00 12.00 

SKYLARK SAN JACINTO TU 

115.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

Line 

No. 

1 

2 

3 

4 

5 

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34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

SPRINGVILLE PORTERVILLE TU 

220.00 66.00 

SPRINGVILLE PORTERVILLE TU 

66.00 12.00 

STADLER SAN JACINTO TU 

115.00 12.00 

STETSON SAN JACINTO TU 

115.00 12.00 

SUN CITY SAN JACINTO TU 

115.00 12.00 

TAMARISK PALM SPRINGS TU 

115.00 12.00 

THORNHILL PALM SPRINGS TU 

115.00 12.00 

TIEFORT HI DESERT TU 

115.00 33.00 

TORTILLA HI DESERT TU 

33.00 12.00 

TORTILLA HI DESERT TU 

115.00 33.00 

VALLEY SAN JACINTO TA 

115.00 12.00 

VALLEY SAN JACINTO TA 

500.00 115.00 13.80 

VENWIND PALM SPRINGS TU 

115.00 12.00 

VESTAL DELANO TU 

220.00 66.00 

VESTAL DELANO TU 

66.00 12.00 

VICTOR HI DESERT TU 

220.00 115.00 


115.00 12.00 


115.00 33.00 

VIEJO LAKE FOREST TU 

220.00 66.00 

VIEJO LAKE FOREST TU 

66.00 12.00 

VILLA PARK SANTA ANA TA 

220.00 66.00 

VILLA PARK SANTA ANA TA 

66.00 12.00 

VINCENT LANCASTER TA 

500.00 220.00 13.80 

VISTA INLAND TA 

220.00 66.00 


220.00 115.00 


66.00 13.00 

WALNUT COVINA TA 

220.00 66.00 

WALNUT COVINA TA 

66.00 12.00 

YUCCA TWENTY-NINE PALMS TU 

115.00 12.00 

ZANJA INLAND TU 

115.00 33.00 

MAIN STATION TRANSFORMERS AT GENERATING STAT 

BIG CREEK 1 BIG CREEK TA 

7.00 7.00 


12.00 220.00 


33.00 12.00 


33.00 33.00 

BIG CREEK 2 NR. BIG CREEK TU 

220.00 12.00 

BIG CREEK 2 NR. BIG CREEK TU 

12.00 7.00 

BIG CREEK 2A NR. BIG CREEK TU 

12.00 220.00 

BIG CREEK 2 P.H. NR. BIG CREEK TU 

7.00 220.00 

BIG CREEK 3 NR. AUBERRY TA 

12.00 220.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

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36 

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38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 


1.00 2.00 


12.00 12.00 

BIG CREEK 4 NR. AUBERRY TU 

12.00 220.00 

BIG CREEK 4 NR. AUERRY TU 

1.00 12.00 

BIG CREEK 8 NR. BIG CREEK TA 

12.00 220.00 

BIG CREEK 8 NR. BIG CREEK TA 

1.00 12.00 

BOREL LAKE ISABELLA TU 

2.00 66.00 

EASTWOOD SHAVER LAKE TA 

12.00 220.00 

ETIWANDA ETIWANDA TU 

220.00 66.00 

ETIWANDA ETIWANDA TU 

66.00 12.00 

GRAPELAND ETIWANDA TU 

66.00 66.00 

HOOVER S.C.E BOULDER CANYON TA 

12.00 220.00 

HOOVER BOULDER CANYON TA 

12.00 220.00 

KAWEAH 1 THREE RIVERS TU 

12.00 66.00 


12.00 66.00 


12.00 66.00 

KERN RIVER 1 KERN CANYON TU 

66.00 2.00 

KERN RIVER 3 KERNVILLE TA 

12.00 66.00 

LUNDY P.H. NR. LEE VINING TU 

2.00 55.00 

LUNDY NR. LEE VINING TU 

55.00 16.00 

MAMMOTH BIG CREEK TU 

12.00 220.00 

MAMMOTH POOL (DAM) BIG CREEK TU 

2.00 12.00 

MCGRATH BEACH OXNARD TU 

66.00 66.00 

MILL CREEK NO.1 INLAND TU 

1.00 12.00 

MILL CREEK NO.2,3 INLAND TU 

1.00 12.00 

MOHAVE LAUGHLIN, NE TA 

12.00 500.00 

ONTARIO PH.2 SAN ANTONIO CANYON TU 

12.00 12.00 

PALO VERDE WEST OF BUCKEYE TA 

25.00 525.00 

PALO VERDE WEST OF BUCKEYE TA 

23.00 525.00 13.00 

PALO VERDE 2 WEST OF BUCKEYE TA 

25.00 525.00 


23.00 525.00 13.00 


25.00 525.00 


23.00 525.00 13.00 

PLANT 2 NR. BISHOP TU 

55.00 12.00 


2.00 55.00 


2.00 12.00 


2.00 115.00 

PLANT 4 NR. BISHOP TA 

115.00 2.00 


2.00 55.00 


2.00 55.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

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19 

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22 

23 

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25 

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33 

34 

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38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

POOLE NR. LEE VINING TA 

115.00 12.00 

POOLE NR. LEE VINING TA 

12.00 7.00 

PORTAL BIG CREEK TU 

4.00 33.00 

RUSH CREEK NR. JUNE LAKE TA 

115.00 2.00 

RUSH CREEK NR. JUNE LAKE TA 

2.00 4.00 

SAN GORGONIO 1 INLAND TU 

2.00 33.00 

SAN GORGONIO 2 INLAND TU 

2.00 33.00 

SAN ONOFRE NR. SAN CLEMENTE TA 

220.00 12.00 

SANTA ANA RIVER 1 FOOTHILL TU 

2.00 33.00 


1.00 33.00 


33.00 2.00 

STADIUM LONG BEACH DU 

66.00 12.00 

TIMBERWINE BIG CREEK DU 

33.00 12.00 

TULE NR. SPRINGVILLE TU 

12.00 66.00 

MAIN TRANSFORMERS AT DISTRIBUTION SUBSTATION 

ACTON SAN JACINTO DU 

66.00 12.00 

ALDER FOOTHILL DU 

66.00 12.00 

ALHAMBRA MONTEBELLO DU 

66.00 16.00 

ALHAMBRA MONTEBELLO DU 

66.00 4.00 

ALLEN MONROVIA DU 

16.00 4.00 

ALON COMPTON DU 

66.00 12.00 

AMADOR MONTEBELLO DU 

66.00 4.00 

AMADOR MONTEBELLO DU 

66.00 16.00 

AMALIA MONTEBELLO DU 

16.00 4.00 

AMARGO RIDGECREST DU 

33.00 4.00 

AMBOY TWENTY-NINE PALMS DU 

33.00 12.00 

ANAVERDE LANCASTER DU 

66.00 12.00 

ANITA MONROVIA DU 

66.00 16.00 

ANITA MONROVIA DU 

66.00 4.00 

ARABY PALM SPRINGS DU 

33.00 4.00 

ARCADIA MONROVIA DU 

66.00 16.00 

ARCADIA MONROVIA DU 

66.00 4.00 

ARCH BEACH EL TORO DU 

12.00 4.00 

ARCHIBALD FOOTHILL DU 

66.00 12.00 

ARCHLINE ONTARIO DU 

66.00 12.00 

ARRO INLAND DU 

33.00 4.00 

ARROYO MONROVIA DU 

66.00 16.00 

ARROYO MONROVIA DU 

16.00 4.00 

ARTESIA LONG BEACH DU 

12.00 4.00 

ATHENS COMPTON DU 

16.00 4.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

ATWOOD FULLERTON DU 

66.00 12.00 

BADILLO COVINA DU 

12.00 4.00 

BAIN MIRA LOMA DU 

66.00 12.00 

BAIN MIRA LOMA DU 

12.00 1.00 

BANDINI COMPTON DU 

66.00 16.00 

BANDINI COMPTON DU 

66.00 4.00 

BANNING HEIGHTS INLAND DU 

33.00 2.00 

BARSTOW HI DESERT DU 

33.00 12.00 

BARTOLO WHITTIER DU 

12.00 4.00 

BASSETT COVINA DU 

66.00 12.00 

BASTA FULLERTON DU 

12.00 4.00 

BAYSIDE HUNTINGTON BEACH DU 

66.00 12.00 

BEAUMONT INLAND DU 

12.00 4.00 

BEDFORD SANTA MONICA DU 

16.00 4.00 

BELDING PALM SPRINGS DU 

33.00 4.00 

BELMONT LONG BEACH DU 

12.00 4.00 

BELVEDERE MONTEBELLO DU 

16.00 4.00 

BEVERLY SANTA MONICA DU 

66.00 16.00 

BEVERLY SANTA MONICA DU 

66.00 4.00 

BICKNELL MONTEBELLO DU 

16.00 4.00 

BIXBY LONG BEACH DU 

12.00 4.00 

BLISS TULARE DU 

66.00 12.00 

BLOOMINGTON FOOTHILL DU 

66.00 12.00 

BLUFF COVE REDONDO DU 

16.00 4.00 

BLYTHE BLYTHE DU 

33.00 5.00 


33.00 12.00 


33.00 33.00 

BODIE BISHOP DU 

55.00 7.00 

BOLSA HUNTINGTON BEACH DU 

66.00 12.00 

BORREGO EL TORO DU 

66.00 12.00 

BOVINE LONG BEACH DU 

66.00 12.00 

BOWL LONG BEACH DU 

66.00 4.00 

BOWL LONG BEACH DU 

66.00 12.00 

BOXWOOD PORTERVILLE DU 

66.00 12.00 

BRADBURY MONROVIA DU 

66.00 16.00 

BREA FULLERTON DU 

66.00 12.00 

BREEZE LANCASTER DU 

66.00 12.00 

BREWSTER COMPTON DU 

16.00 4.00 

BRIDGE REDONDO DU 

66.00 4.00 

BRIDGEPORT BISHOP DU 

16.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

BRIDGEPORT BISHOP DU 

16.00 16.00 

BRIGHTON REDONDO DU 

66.00 16.00 

BRISTOL SANTA ANA DU 

12.00 4.00 

BROADWAY LONG BEACH DU 

66.00 12.00 

BROADWAY LONG BEACH DU 

12.00 4.00 

BROOKHURST HUNTINGTON BEACH DU 

66.00 12.00 

BROWNING DELANO DU 

66.00 12.00 

BRYAN SANTA ANA DU 

66.00 12.00 

BRYMAN HI DESERT DU 

33.00 4.00 

BULLIS COMPTON DU 

66.00 4.00 

BULLIS COMPTON DU 

66.00 16.00 

BURNT MILL LAKE ARROWHEAD DU 

33.00 12.00 

BURNT MILL LAKE ARROWHEAD DU 

33.00 33.00 

CABAZON PALM SPRINGS DU 

33.00 12.00 

CABRILLO EL TORO DU 

66.00 12.00 

CADY HI DESERT DU 

33.00 12.00 

CALCITY CAL CITY DU 

33.00 12.00 

CALCITY CAL CITY DU 

33.00 33.00 

CALDEN COMPTON DU 

66.00 16.00 

CAMAR VENTURA DU 

16.00 4.00 

CAMARILLO VENTURA DU 

66.00 16.00 

CAMDEN SANTA ANA DU 

66.00 12.00 

CAMERON LONG BEACH DU 

66.00 12.00 

CANTIL RIDGECREST DU 

33.00 12.00 

CANYON FULLERTON DU 

66.00 12.00 

CANYON LAKE SAN JACINTO DU 

33.00 12.00 

CAPITAN SANTA BARBARA DU 

66.00 16.00 

CARDIFF INLAND DU 

66.00 33.00 

CARDIFF INLAND DU 

66.00 12.00 

CARMENITA WHITTIER DU 

66.00 12.00 

CAROLINA FULLERTON DU 

66.00 12.00 

CARPINTERIA SANTA BARBARA DU 

66.00 16.00 

CARPINTERIA SANTA BARBARA DU 

16.00 4.00 

CARSON COMPTON DU 

66.00 16.00 

CASITAS VENTURA DU 

66.00 16.00 

CATHEDRAL CITY PALM SPRINGS DU 

33.00 5.00 

CEDARWOOD HUNTINGTON BEACH DU 

12.00 4.00 

CHANNEL ISLAND VENTURA DU 

66.00 16.00 

CHASE ONTARIO DU 

66.00 12.00 

CHATHAM VISALIA DU 

66.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

CHATSWORTH THOUSAND OAKS DU 

66.00 16.00 

CHERRY LONG BEACH DU 

66.00 12.00 

CHESTNUT SANTA ANA DU 

66.00 12.00 

CHIQUITA EL TORO DU 

66.00 12.00 

CITRUS COVINA DU 

66.00 12.00 

CLARK LONG BEACH DU 

66.00 4.00 

CLAREMONT CLAREMONT DU 

66.00 4.00 

COFFEE PALM SPRINGS DU 

33.00 12.00 

COLONIA VENTURA DU 

66.00 16.00 

COLORADO SANTA MONICA DU 

66.00 16.00 

COLORADO SANTA MONICA DU 

66.00 4.00 

COLTON FOOTHILL DU 

66.00 12.00 

COLUMBINE DELANO DU 

66.00 12.00 

COMPTON COMPTON DU 

16.00 4.00 

CONVERSE FLATS INLAND DU 

33.00 12.00 

CORNUTA COMPTON DU 

66.00 12.00 

CORONA ONTARIO DU 

66.00 33.00 


66.00 12.00 


33.00 4.00 

CORTEZ COVINA DU 

66.00 12.00 

CORUM LANCASTER DU 

66.00 12.00 

COSTA MESA HUNTINGTON BEACH DU 

12.00 4.00 

COVINA COVINA DU 

12.00 4.00 

CRATER THOUSAND OAKS DU 

66.00 16.00 

CREST REDONDO DU 

66.00 16.00 

CROWN HUNTINGTON BEACH DU 

66.00 12.00 

CUCAMONGA FOOTHILL DU 

66.00 12.00 

CUDAHY COMPTON DU 

66.00 16.00 

CUDAHY COMPTON DU 

66.00 4.00 

CULVER SANTA MONICA DU 

66.00 16.00 

CULVER SANTA MONICA DU 

66.00 4.00 

CUMMINGS LANCASTER DU 

66.00 12.00 

CYPRESS FULLERTON DU 

66.00 12.00 

CYPRESS FULLERTON DU 

12.00 4.00 

DAGGETT BARSTOW DU 

33.00 4.00 

DAISY LONG BEACH DU 

12.00 4.00 

DALTON MONROVIA DU 

66.00 12.00 

DAVIDSON CITY LONG BEACH DU 

12.00 4.00 

DECLEZ FOOTHILL DU 

66.00 12.00 

DECLEZ FOOTHILL DU 

12.00 4.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

Line 

No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

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21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

DEEP SPRINGS BISHOP DU 

55.00 2.00 

DEFRAIN BLYTHE DU 

33.00 12.00 

DEL ROSA INLAND DU 

66.00 12.00 

DEL SUR LANCASTER DU 

66.00 12.00 

DELANO DELANO DU 

66.00 12.00 

DELANO DELANO DU 

66.00 4.00 

DESERT OUTPOST CATHEDRAL CITY DU 

33.00 12.00 

DIAMOND BAR COVINA DU 

66.00 12.00 

DIKE LONG BEACH DU 

66.00 12.00 

DITMAR REDONDO DU 

66.00 16.00 

DITMAR REDONDO DU 

16.00 4.00 

DIVISADERO VISALIA DU 

12.00 4.00 

DOHENY SANTA MONICA DU 

16.00 4.00 

DOWNEY WHITTIER DU 

12.00 4.00 

DOWNS RIDGECREST DU 

33.00 12.00 

DUARTE MONROVIA DU 

16.00 4.00 

DUNES BLYTHE DU 

33.00 12.00 

EARLIMART DELANO DU 

66.00 12.00 

EAST BARSTOW HI DESERT DU 

33.00 4.00 

EATON MONROVIA DU 

66.00 16.00 

EDGEMONT SAN JACINTO DU 

33.00 4.00 

EDGEWATER HUNTINGTON BEACH DU 

12.00 4.00 

EDINGER SANTA ANA DU 

12.00 4.00 

EL PORTO REDONDO DU 

16.00 4.00 

EL SOBRANTE ONTARIO DU 

33.00 12.00 

ELCANS VISALIA DU 

66.00 12.00 

ELIZABETH LAKE SAN FERNANDO DU 

66.00 16.00 

ELY FULLERTON DU 

66.00 12.00 

ERIC LONG BEACH DU 

66.00 12.00 

ESTERO VENTURA DU 

66.00 16.00 

ESTRELLA EL TORO DU 

66.00 12.00 

EUCLID ONTARIO DU 

12.00 4.00 

EXETER VISALIA DU 

12.00 4.00 

FAIR OAKS MONROVIA DU 

16.00 4.00 

FAIRFAX SANTA MONICA DU 

66.00 16.00 

FAIRFAX SANTA MONICA DU 

16.00 4.00 

FAIRVIEW SANTA ANA DU 

66.00 12.00 

FELTON INGLEWOOD DU 

16.00 4.00 

FELTON INGLEWOOD DU 

66.00 16.00 

FERNWOOD COMPTON DU 

66.00 16.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

FILLMORE VENTURA DU 

66.00 16.00 

FILLMORE VENTURA DU 

16.00 4.00 

FIREHOUSE ONTARIO DU 

66.00 12.00 

FLANCO FOOTHILL DU 

12.00 4.00 

FLORADAY WHITTIER DU 

12.00 4.00 

FOREST HOME INLAND DU 

33.00 2.00 

FRANCIS ONTARIO DU 

66.00 12.00 

FRAZIER PARK LANCASTER DU 

66.00 12.00 

FREMONT COMPTON DU 

66.00 16.00 

FREMONT COMPTON DU 

16.00 4.00 

FRIENDLY HILLS WHITTIER DU 

12.00 4.00 

FRUITLAND COMPTON DU 

66.00 16.00 

FRUITLAND COMPTON DU 

66.00 4.00 

FULLERTON FULLERTON DU 

66.00 12.00 

FULLERTON FULLERTON DU 

66.00 4.00 

GAGE COMPTON DU 

16.00 4.00 

GALLATIN WHITTIER DU 

66.00 12.00 

GANESHA COVINA DU 

66.00 12.00 

GANESHA COVINA DU 

12.00 4.00 

GARFIELD PASADENA DU 

66.00 4.00 

GARFIELD PASADENA DU 

66.00 16.00 

GARVEY MONTEBELLO DU 

16.00 4.00 

GAVILAN SAN JACINTO DU 

33.00 12.00 

GAVIOTA SANTA BARBARA DU 

66.00 16.00 

GEORGE A.F.B. HI DESERT DU 

33.00 4.00 

GENAMIC RANCHO CUCAMONGA DU 

66.00 12.00 

GILBERT FULLERTON DU 

66.00 12.00 

GISLER HUNTINGTON BEACH DU 

66.00 12.00 

GLEN AVON ONTARIO DU 

66.00 12.00 

GLEN IVY ONTARIO DU 

33.00 12.00 

GLENNVILLE DELANO DU 

66.00 12.00 

GOLDSTONE HI DESERT DU 

33.00 12.00 

GOLDTOWN LANCASTER DU 

66.00 12.00 

GONZALES VENTURA DU 

66.00 16.00 

GORMAN LANCASTER DU 

66.00 12.00 

GOSHEN VISALIA DU 

66.00 12.00 

GRAHAM COMPTON DU 

16.00 4.00 

GRANADA MONTEBELLO DU 

16.00 4.00 

GRANGEVILLE HANFORD DU 

12.00 4.00 

GREAT LAKES ROSAMOND DU 

66.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

GREENHORN DELANO DU 

66.00 2.00 

GREENING LONG BEACH DU 

66.00 12.00 

GRISWOLD SAN FERNANDO DU 

16.00 4.00 

HAMILTON HUNTINGTON BEACH DU 

66.00 12.00 

HANFORD HANFORD DU 

66.00 4.00 

HANFORD HANFORD DU 

66.00 12.00 

HARDING MONTEBELLO DU 

16.00 4.00 

HARPER LAKE HI DESERT DU 

33.00 5.00 

HARVARD HI DESERT DU 

33.00 12.00 

HASKELL SAN FERNANDO DU 

66.00 16.00 

HATHAWAY LONG BEACH DU 

66.00 12.00 

HATHAWAY LONG BEACH DU 

66.00 4.00 

HAVASU BLYTHE DU 

66.00 16.00 

HAVEDA REDONDO DU 

16.00 4.00 

HAVILAH KERNVILLE DU 

66.00 12.00 

HEDDA LONG BEACH DU 

12.00 4.00 

HELENDALE HI DESERT DU 

33.00 12.00 

HEMET SAN JACINTO DU 

33.00 12.00 

HEMET SAN JACINTO DU 

33.00 5.00 

HIGHLAND INLAND DU 

66.00 12.00 

HINKLEY HI DESERT DU 

33.00 12.00 

HOLIDAY PALM SPRINGS DU 

33.00 4.00 

HOWARD INGLEWOOD DU 

66.00 4.00 

HOYT MONTEBELLO DU 

16.00 4.00 

HUNTINGTON PARK COMPTON DU 

16.00 4.00 

HUSTON ARROWHEAD DU 

33.00 2.00 

HUSTON ARROWHEAD DU 

33.00 12.00 

IDYLLWILD SAN JACINTO DU 

33.00 2.00 

IDYLLWILD SAN JACINTO DU 

33.00 12.00 

IMPERIAL WHITTIER DU 

66.00 12.00 

IMPERIAL WHITTIER DU 

66.00 4.00 

INDUSTRY COVINA DU 

66.00 12.00 

INGLEWOOD INGLEWOOD DU 

66.00 16.00 

INGLEWOOD INGLEWOOD DU 

66.00 4.00 

INYOKERN TOWN RIDGECREST DU 

33.00 5.00 

IRON MT. (SCE) BLYTHE DA 

7.00 16.00 

IRVINE EL TORO DU 

66.00 12.00 

ISABELLA KERNVILLE DU 

66.00 12.00 

ISLA VISTA SANTA BARBARA DU 

66.00 16.00 

IVAR MONTEBELLO DU 

16.00 4.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

JEFFERSON ONTARIO DU 

66.00 12.00 

JERSEY COMPTON DU 

66.00 16.00 

JOSHUA TREE TWENTY-NINE PALMS DU 

33.00 12.00 

JUNCTION SHOSHONE DU 

33.00 33.00 

JUNE LAKE JUNE LAKE DU 

2.00 12.00 

KEMPSTER FOOTHILL DU 

33.00 4.00 

KERNVILLE KERNVILLE DU 

66.00 16.00 


66.00 12.00 


16.00 12.00 

LA CANADA MONROVIA DU 

66.00 16.00 

LA CANADA MONROVIA DU 

16.00 4.00 

LA HABRA FULLERTON DU 

66.00 12.00 

LA MIRADA WHITTIER DU 

66.00 12.00 

LA PALMA FULLERTON DU 

66.00 12.00 

LA VETA SANTA ANA DU 

66.00 12.00 

LAFAYETTE HUNTINGTON BEACH DU 

66.00 12.00 

LAKEWOOD LONG BEACH DU 

66.00 4.00 

LAMPSON SANTA ANA DU 

66.00 12.00 

LANCASTER LANCASTER DU 

66.00 12.00 

LANCASTER LANCASTER DU 

12.00 4.00 

LANDING BLYTHE DU 

66.00 16.00 

LARDER LONG BEACH DU 

12.00 4.00 

LARK ELLEN COVINA DU 

66.00 12.00 

LATIGO THOUSAND OAKS DU 

66.00 16.00 

LAUREL TULARE DU 

66.00 12.00 

LAWNDALE INGLEWOOD DU 

16.00 4.00 

LAYFAIR COVINA DU 

66.00 4.00 

LAYFAIR COVINA DU 

66.00 12.00 

LEMON COVE VISALIA DU 

66.00 12.00 

LENNOX INGLEWOOD DU 

66.00 16.00 

LENNOX INGLEWOOD DU 

16.00 4.00 

LEVY VENTURA DU 

66.00 16.00 

LIBERTY VISALIA DU 

66.00 12.00 

LIMESTONE EL TORO DU 

66.00 12.00 

LINDEN LONG BEACH DU 

12.00 4.00 

LINDSAY PORTERVILLE DU 

66.00 12.00 

LINDSAY PORTERVILLE DU 

66.00 4.00 

LINE CREEK BIG CREEK DU 

33.00 4.00 

LITTLE LAKE RIDGECREST DU 

33.00 12.00 

LITTLE ROCK LANCASTER DU 

66.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

LIVE OAK COVINA DU 

66.00 12.00 

LOCUST LONG BEACH DU 

12.00 4.00 

LOCKHEED SAUGUS DU 

66.00 16.00 

LONGDON COMPTON DU 

16.00 4.00 

LORAINE LANCASTER DU 

66.00 12.00 

LOS CERRITOS LONG BEACH DU 

66.00 12.00 

LOS CERRITOS LONG BEACH DU 

12.00 4.00 

LUCAS LONG BEACH DU 

66.00 4.00 

LUCAS LONG BEACH DU 

66.00 12.00 

LUCERNE HI DESERT DU 

33.00 12.00 

LUNADA REDONDO DU 

16.00 4.00 

LUNAR LAKESHORE DU 

33.00 12.00 

LYNWOOD COMPTON DU 

16.00 4.00 

MACARTHUR HUNTINGTON BEACH DU 

66.00 12.00 

MACNEIL BURBANK DU 

66.00 16.00 

MADRID REDONDO DU 

16.00 4.00 

MALIBU THOUSAND OAKS DU 

66.00 16.00 

MANHATTAN REDONDO DU 

16.00 4.00 

MARINE SANTA MONICA DU 

66.00 16.00 

MARION FULLERTON DU 

66.00 12.00 

MARIPOSA DELANO DU 

66.00 12.00 

MARYMOUNT REDONDO DU 

66.00 16.00 

MAYFLOWER MONROVIA DU 

16.00 4.00 

MAYWOOD COMPTON DU 

16.00 4.00 

MERCED COVINA DU 

66.00 12.00 

MICHILLINDA MONROVIA DU 

16.00 4.00 

MIDWIND LANCASTER DU 

66.00 12.00 

MILLIKEN INLAND DU 

66.00 12.00 

MINARET BISHOP DU 

33.00 12.00 

MINNEOLA HI DESERT DU 

33.00 12.00 

MODENA SANTA ANA DU 

66.00 12.00 

MODOC SANTA BARBARA DU 

16.00 4.00 

MONETA REDONDO DU 

16.00 4.00 

MONO BISHOP DU 

55.00 7.00 

MONOLITH LANCASTER DU 

66.00 12.00 

MONROVIA MONROVIA DU 

16.00 4.00 

MONTEBELLO MONTEBELLO DU 

16.00 4.00 

MONTECITO SANTA BARBARA DU 

16.00 4.00 

MOONEY VISALIA DU 

12.00 4.00 

MORGAN BISHOP DU 

55.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

MORNINGSIDE INGLEWOOD DU 

16.00 4.00 

MORRO EL TORO DU 

66.00 12.00 

MOULTON EL TORO DU 

66.00 12.00 

MOVAL MORENO VALLEY TU 

115.00 12.00 

MOVIE CULVER CITY DU 

66.00 16.00 

MT. TOM BISHOP DU 

55.00 12.00 

MT. VERNON INLAND DU 

33.00 4.00 

MT. WILSON MONROVIA DU 

16.00 4.00 

MURPHY WHITTIER DU 

66.00 12.00 

MURRIETTA 2 SAN JACINTO DU 

33.00 12.00 

MUSCOY INLAND DU 

33.00 4.00 

NAOMI COMPTON DU 

16.00 4.00 

NAPLES LONG BEACH DU 

12.00 4.00 

NAROD ONTARIO DU 

66.00 12.00 

NARROWS WHITTIER DU 

66.00 12.00 

NEENACH LANCASTER DU 

66.00 12.00 

NEPTUNE LONG BEACH DU 

66.00 12.00 

NEPTUNE LONG BEACH DU 

66.00 4.00 

NEWBURY THOUSAND OAKS DU 

66.00 16.00 

NEWHALL SAN FERNANDO DU 

66.00 16.00 

NEWMARK MONTEBELLO DU 

66.00 16.00 

NEWMARK MONTEBELLO DU 

66.00 4.00 

NIGUEL EL TORO DU 

66.00 12.00 

NIGUEL EL TORO DU 

66.00 4.00 

NOGALES COVINA DU 

66.00 12.00 

NOLA COMPTON DU 

66.00 16.00 

NORCO ONTARIO DU 

12.00 4.00 

NORTH INTAKE BLYTHE DU 

33.00 12.00 

NORTH MUROC RIDGECREST DU 

33.00 12.00 

NORTH OAKS SAN FERNANDO DU 

66.00 16.00 

NORTHWIND LANCASTER DU 

66.00 12.00 

NUEVO SAN JACINTO DU 

33.00 12.00 

NUGGET TWENTY-NINE PALMS DU 

33.00 25.00 

OAK GROVE VISALIA DU 

66.00 12.00 

OAK PARK THOUSAND OAKS DU 

66.00 16.00 

OASIS LANCASTER DU 

66.00 12.00 

OCEAN PARK SANTA MONICA DU 

16.00 4.00 

OCEANVIEW HUNTINGTON BEACH DU 

66.00 12.00 

OCTOL TULARE DU 

66.00 12.00 

OJAI VENTURA DU 

66.00 16.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

OLDFIELD LONG BEACH DU 

12.00 4.00 

OLIVE LAKE BLYTHE DU 

33.00 12.00 

OLYMPIC SANTA MONICA DU 

16.00 4.00 

O'NEILL MISSION VIEJO DU 

66.00 12.00 

ONTARIO ONTARIO DU 

12.00 4.00 

ORANGE SANTA ANA DU 

66.00 12.00 

ORDWAY HI DESERT DU 

33.00 12.00 

ORO GRANDE HI DESERT DU 

33.00 12.00 

ORTEGA SANTA BARBARA DU 

66.00 33.00 

OXNARD VENTURA DU 

16.00 4.00 

PALM CANYON PALM SPRINGS DU 

33.00 4.00 

PALM CANYON PALM SPRINGS DU 

33.00 12.00 

PALM SPRINGS PALM SPRINGS DU 

33.00 4.00 

PALM VILLAGE PALM SPRINGS DU 

33.00 12.00 

PALM VILLAGE PALM SPRINGS DU 

33.00 5.00 

PALMDALE LANCASTER DU 

66.00 12.00 

PALOS VERDES REDONDO DU 

16.00 4.00 

PARKWOOD FULLERTON DU 

66.00 12.00 

PASSONS WHITTIER DU 

66.00 12.00 

PAULARINO HUNTINGTON BEACH DU 

12.00 4.00 

PEARL SANTA MONICA DU 

16.00 4.00 

PEDLEY ONTARIO DU 

66.00 12.00 

PEERLESS RIDGECREST DU 

33.00 12.00 

PEREZ ONTARIO DU 

33.00 4.00 

PERRY REDONDO DU 

16.00 4.00 

PEYTON ONTARIO DU 

66.00 12.00 

PICO LONG BEACH DU 

66.00 12.00 

PIERPONT VENTURA DU 

16.00 4.00 

PIONEER WHITTIER DU 

66.00 12.00 

PIONEER WHITTIER DU 

12.00 4.00 

PIPE ETIWANDA DU 

66.00 12.00 

PITMAN BIG CREEK DU 

33.00 12.00 

PIUTE LANCASTER DU 

66.00 12.00 

PIXLEY DELANO DU 

66.00 12.00 

PLACENTIA FULLERTON DU 

66.00 12.00 

PLAYA SANTA BARBARA DU 

16.00 4.00 

POMONA COVINA DU 

12.00 4.00 

POPLAR PORTERVILLE DU 

66.00 12.00 

PORTER SAN FERNANDO DU 

16.00 4.00 

PORTERVILLE PORTERVILLE DU 

66.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

PORTERVILLE PORTERVILLE DU 

66.00 4.00 

POTRERO THOUSAND OAKS DU 

66.00 16.00 

PROCTOR COVINA DU 

66.00 12.00 

PUENTE COVINA DU 

66.00 12.00 

QUARTZ HILL LANCASTER DU 

66.00 12.00 

QUINN DELANO DU 

66.00 12.00 

RAILROAD COVINA DU 

66.00 12.00 

RAMONA MONTEBELLO DU 

66.00 4.00 

RANCHO HI DESERT DU 

33.00 12.00 

RANDALL FOOTHILL DU 

66.00 12.00 

RANDOLPH COMPTON DU 

66.00 16.00 

RAVENDALE MONTEBELLO DU 

66.00 16.00 

RAVENDALE MONTEBELLO DU 

66.00 4.00 

REDLANDS INLAND DU 

66.00 12.00 

REDLANDS INLAND DU 

66.00 4.00 

REDMAN LANCASTER DU 

66.00 12.00 

REDONDO REDONDO DU 

16.00 4.00 

REPETTO MONTEBELLO DU 

66.00 16.00 

REPETTO MONTEBELLO DU 

66.00 4.00 

RIALTO FOOTHILL DU 

33.00 12.00 

RIALTO FOOTHILL DU 

33.00 4.00 

RIDGECREST RIDGECREST DU 

33.00 5.00 

RINDGE THOUSAND OAKS DU 

16.00 4.00 

RIPLEY BLYTHE DU 

33.00 12.00 

RIVERA WHITTIER DU 

12.00 4.00 

RIVERWAY VISALIA DU 

66.00 16.00 

ROLLING HILLS REDONDO DU 

66.00 16.00 

ROLLING HILLS REDONDO DU 

66.00 4.00 

ROSAMOND LANCASTER DU 

66.00 12.00 

ROSEMEAD MONTEBELLO DU 

66.00 16.00 

ROYAL THOUSAND OAKS DU 

66.00 16.00 

RUBIDOUX RUBIDOUX DU 

33.00 4.00 


33.00 12.00 


33.00 33.00 

RUNNING SPRINGS ARROWHEAD DU 

33.00 12.00 

RUSH MONTEBELLO DU 

66.00 16.00 

SAN ANTONIO COVINA DU 

66.00 12.00 

SAN DIMAS COVINA DU 

66.00 12.00 

SAN FERNANDO SAN FERNANDO DU 

66.00 16.00 

SAN GABRIEL MONTEBELLO DU 

66.00 4.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

SAN JACINTO SAN JACINTO DU 

33.00 5.00 

SAN MARCOS SANTA BARBARA DU 

66.00 16.00 

SAN MARINO MONROVIA DU 

16.00 4.00 

SAN MIGUEL VENTURA DU 

66.00 16.00 

SAN VICENTE SANTA MONICA DU 

16.00 4.00 

SANGAR MONROVIA DU 

16.00 4.00 

SANTA ANA SANTA ANA DU 

12.00 4.00 

SANTA BARBARA SANTA BARBARA DU 

66.00 16.00 

SANTA BARBARA SANTA BARBARA DU 

66.00 4.00 

SANTA FE SPRINGS WHITTIER DU 

66.00 12.00 

SANTA MONICA SANTA MONICA DU 

66.00 16.00 

SANTA MONICA SANTA MONICA DU 

66.00 4.00 

SANTA SUSANA THOUSAND OAKS DU 

66.00 16.00 

SATICOY VENTURA DU 

66.00 16.00 

SAWTELLE SANTA MONICA DU 

66.00 16.00 

SEABRIGHT LONG BEACH DU 

66.00 12.00 

SECOND AVENUE BLYTHE DU 

33.00 12.00 

SEPULVEDA INGLEWOOD DU 

66.00 16.00 

SEPULVEDA INGLEWOOD DU 

16.00 4.00 

SHARON MONROVIA DU 

16.00 4.00 

SHAWNEE HUNTINGTON BEACH DU 

66.00 12.00 

SHERWIN TOM'S PLACE DU 

115.00 12.00 

SHUTTLE LANCASTER DU 

66.00 12.00 

SIERRA MADRE MONROVIA DU 

16.00 4.00 

SIGNAL HILL LONG BEACH DU 

66.00 12.00 

SIGNAL HILL LONG BEACH DU 

12.00 4.00 

SILVER SPUR PALM SPRINGS DU 

33.00 12.00 

SIXTEENTH STREET INLAND DU 

33.00 12.00 

SKILAND BISHOP DU 

33.00 12.00 

SLATER HUNTINGTON BEACH DU 

66.00 12.00 

SMILEY INLAND DU 

12.00 4.00 

SOLEMINT SAN FERNANDO DU 

66.00 16.00 

SOMERSET COMPTON DU 

66.00 12.00 

SOMERSET COMPTON DU 

66.00 4.00 

SOMIS VENTURA DU 

66.00 16.00 

SOQUEL ONTARIO DU 

66.00 12.00 

SOUTH GATE COMPTON DU 

16.00 4.00 

SOUTHWIND LANCASTER DU 

66.00 12.00 

STATE STREET LONG BEACH DU 

66.00 12.00 

STEWART WHITTIER DU 

66.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

STIRRUP REDONDO DU 

16.00 4.00 

STODDARD INLAND DU 

33.00 4.00 

STRATHMORE PORTERVILLE DU 

66.00 12.00 

SULLIVAN SANTA ANA DU 

66.00 12.00 

SULLIVAN SANTA ANA DU 

66.00 4.00 

SUNNY DUNES PALM SPRINGS DU 

33.00 4.00 

SUNNYSIDE LONG BEACH DU 

66.00 12.00 

SUNNYSIDE LONG BEACH DU 

66.00 4.00 

TAHITI SANTA MONICA DU 

66.00 16.00 

TALBERT SANTA ANA DU 

66.00 12.00 

TAPIA THOUSAND OAKS DU 

66.00 16.00 

TEAM WESTMINSTER DU 

66.00 12.00 

TELEGRAPH WHITTIER DU 

66.00 12.00 

TEMESCAL ONTARIO DU 

33.00 4.00 

TEMPLE MONROVIA DU 

16.00 4.00 

TENNESSEE INLAND DU 

66.00 12.00 

TERRA BELLA PORTERVILLE DU 

66.00 12.00 

TERRACE MONTEBELLO DU 

16.00 4.00 

THOUSAND OAKS THOUSAND OAKS DU 

66.00 16.00 

THREE RIVERS VISALIA DU 

66.00 12.00 

THUNDERBIRD PALM SPRINGS DU 

33.00 5.00 

TIMOTEO INLAND DU 

66.00 12.00 

TIPPECANOE INLAND DU 

12.00 4.00 

TIPTON TULARE DU 

66.00 12.00 

TOPANGA THOUSAND OAKS DU 

16.00 4.00 

TOPAZ REDONDO DU 

66.00 4.00 

TORRANCE REDONDO DU 

66.00 16.00 

TRASK SANTA ANA DU 

66.00 12.00 

TRONA RIDGECREST DU 

33.00 12.00 

TROPHY COVINA DU 

66.00 12.00 

TULARE TULARE DU 

66.00 12.00 

TULARE TULARE DU 

66.00 4.00 

TWENTYNINE PALMS TWENTY-NINE PALMS DU 

33.00 5.00 

TWENTYNINE PALMS TWENTY-NINE PALMS DU 

33.00 12.00 

UNIVERSAL UNIVERSAL CITY DU 

66.00 12.00 

UPLAND FOOTHILL DU 

66.00 4.00 

UPLAND FOOTHILL DU 

66.00 12.00 

VAIL MONTEBELLO DU 

66.00 16.00 

VALDEZ THOUSAND OAKS DU 

66.00 16.00 

VALENCIA INLAND DU 

12.00 4.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

VEGAS SANTA BARBARA DU 

66.00 16.00 

VENICE HILL VISALIA DU 

66.00 12.00 

VENIDA VISALIA DU 

66.00 12.00 

VENT ONTARIO DU 

33.00 4.00 

VENTURA VENTURA DU 

16.00 4.00 

VERA SANTA ANA DU 

66.00 12.00 

VERDANT BLYTHE DU 

33.00 12.00 

VICTORIA REDONDO DU 

66.00 16.00 

VICTORVILLE HI DESERT DU 

33.00 12.00 


33.00 4.00 


33.00 33.00 

VISALIA VISALIA DU 

66.00 12.00 

VISALIA VISALIA DU 

66.00 4.00 

WABASH MONTEBELLO DU 

66.00 16.00 

WAKEFIELD VENTURA DU 

66.00 16.00 

WALKER BASIN KERNVILLE DU 

66.00 12.00 

WALTERIA REDONDO DU 

66.00 16.00 

WALTERIA REDONDO DU 

66.00 4.00 

WASHINGTON SANTA ANA DU 

66.00 12.00 

WASHINGTON SANTA ANA DU 

12.00 4.00 

WATSON COMPTON DU 

66.00 12.00 

WAVE HUNTINGTON BEACH DU 

66.00 12.00 

WAVE HUNTINGTON BEACH DU 

12.00 4.00 

WELDON KERNVILLE DU 

66.00 12.00 

WEST BARSTOW HI DESERT DU 

33.00 4.00 

WEST RIVERSIDE ONTARIO DU 

33.00 12.00 

WEST RIVERSIDE ONTARIO DU 

33.00 33.00 

WESTGATE WHITTIER DU 

12.00 4.00 

WHEATLAND DELANO DU 

66.00 12.00 

WHIPPLE BLYTHE DU 

66.00 33.00 

WHITE MT. BISHOP DU 

55.00 2.00 

WHITEWATER PALM SPRINGS DU 

33.00 4.00 

WILDE HI DESERT DU 

33.00 4.00 

WILSONA LANCASTER DU 

66.00 12.00 

WIMBLEDON FOOTHILL DU 

66.00 12.00 

WINDSOR HILLS INGLEWOOD DU 

66.00 16.00 

WINDSOR HILLS INGLEWOOD DU 

16.00 4.00 

WOODRUFF COMPTON DU 

12.00 4.00 

WOODLAKE WOODLAKE DU 

12.00 12.00 

WOODVILLE PORTERVILLE DU 

66.00 12.00 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS 


(Mo, Da, Yr) 

04/18/2009 









column (f). 

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 

32 

33 

34 

35 

36 

37 

38 

39 

40 





(a) 

(b) 

(c) 

(d) 

(e) 

WRIGHTWOOD HI DESERT DU 

33.00 12.00 

WRIGHTWOOD HI DESERT DU 

12.00 2.00 

YERMO HI DESERT DU 

33.00 12.00 

YORBA LINDA FULLERTON DU 

66.00 12.00 

YUCAIPA INLAND DU 

66.00 12.00 

YUKON INGLEWOOD DU 

66.00 16.00 

YUKON INGLEWOOD DU 

66.00 4.00 

ZACK BISHOP DU 

55.00 12.00 

ZUMA THOUSAND OAKS DU 

16.00 4.00 

Rounding Adjustment due to 

Foss Software Rounding in Column # 

Total 57395.00 21580.00 147.10 

Note: 

D - Distribution 

T - Transmission 

A - Attended 

U - Unattended 

Summary: Capacity: 

59 TA 38,020.17 

180 TU 30,057.48 

1 DA 2.5 

589 DU 19,552.45 




This 

(1) 


X 

Is: 

An Original 


SUBSTATIONS (Continued) 


(Mo, Da, Yr) 

04/18/2009 



5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for 

increasing capacity. 

6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by 

reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and 

period of lease, and annual rent. For any substation or equipment 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. 

Capacity of Substation 

Number of Number of 

CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line 

Transformers 

Spare 

(In Service) (In MVa) In Service Transformers 

Type of Equipment 

Number of Units Total Capacity No. 

(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

50 6 2 1 

101 4 2 

1120 4 3 

8 1 4 

84 3 5 

56 2 6 

56 2 7 

5 3 1 8 

56 2 9 

84 3 10 

45 2 11 

150 4 1 12 

5 3 1 13 

8 1 14 

101 3 15 

840 3 16 

136 6 ADDED 75MVA PEAKE 17 

195 3 18 

56 2 19 

45 2 20 

120 3 21 

36 3 1 22 

6 3 1 23 

14 1 24 

84 4 25 

5 3 1 26 

770 8 27 


840 3 29 

84 4 30 

3 CONDENSER 1 

60 31 

36 3 32 

11 1 33 

56 2 34 

28 1 35 

28 1 36 

56 2 37 

840 3 38 

2238 6 1 40 

39 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

840 3 1 

6 3 2 

133 1 3 

280 1 4 

9 3 1 5 

240 6 1 6 

53 4 7 

112 2 8 

45 2 9 

560 2 10 

82 4 11 

1120 6 1 12 

102 1 13 

840 3 14 

45 2 15 

106 2 1 16 

56 2 17 

2 3 18 

79 3 19 

METERING ONLY 20 

56 2 21 

100 2 22 

11 1 23 

560 2 24 

11 3 1 25 

200 6 26 

28 2 27 

14 1 28 

51 6 1 29 

49 6 1 30 

5 3 1 31 

840 3 32 

5 1 33 

56 3 34 

112 4 35 

100 2 36 

112 2 37 

11 6 1 38 

56 2 39 

560 2 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

73 3 1 

56 2 2 

530 2 3 

2 3 1 4 

560 2 5 

750 3 6 

112 2 7 

3 CONDENSER #1 1 

72 8 

1060 4 9 

56 2 10 

50 3 1 CONDENSER #4 1 

60 11 

19 2 12 

2 3 1 13 

840 3 14 

45 2 15 

6 1 CONDS. 2-3 2 

120 16 


72 17 

2238 6 1 18 

SWITCHING STATION 19 

84 3 20 

101 4 21 

67 3 22 

28 2 23 

840 3 24 


72 25 

56 2 26 

4476 12 1 27 

840 3 1 28 


70 1 3 30 

560 31 

1120 4 32 

73 3 33 

112 4 34 

45 2 37 

27 4 1 38 

11 2 39 

111 2 40 

35 

36 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

73 3 1 

112 4 2 

680 5 1 3 

28 2 4 

840 3 5 

101 4 6 



56 3 9 

56 1 10 

84 3 11 

48 2 12 

28 1 13 

22 1 14 


14 6 1 16 

861 6 1 17 

57 12 2 18 

22 1 19 

720 18 20 

70 3 21 

45 2 22 

28 2 23 

780 3 24 

56 2 25 

560 2 27 

112 2 28 

101 4 29 

1090 4 30 

129 5 31 

28 3 32 

840 3 33 

112 3 34 

89 4 35 

25 3 1 37 

3360 9 1 REACTOR 4 

180 38 

84 3 39 

73 3 40 

26 

36 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

480 7 1 


39 2 

84 3 3 

73 3 4 

28 1 5 

101 4 6 

45 2 7 

56 2 8 

56 2 9 

106 2 10 

44 2 11 

2240 4 12 

56 2 13 

200 6 14 

18 6 15 

560 2 16 

84 3 17 

162 3 18 

560 2 19 

56 2 20 

840 3 21 

90 4 22 

4476 12 1 23 

1120 4 24 

560 2 25 

3 CONDENSER 1 

75 26 

840 3 27 

82 6 1 28 

45 2 29 

13 3 1 30 

60 1 32 

56 1 33 

10 1 34 

14 1 35 

120 6 1 36 

4 5 1 37 

120 1 38 

122 1 40 

31 

39 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

134 1 1 

49 1 2 

133 1 3 3 

1 3 4 

75 1 1 5 

12 3 1 7 

250 1 8 

1090 4 9 

56 2 10 


300 7 1 **TRANSFORMERS OW 12 

40 3 1 **TRANSFORMERS OW 13 

3 3 1 14 

2 1 15 

4 3 1 16 

24 4 17 

36 6 1 18 

4 1 19 

5 3 1 20 

180 2 1 21 

1 1 22 


1 3 24 

3 1 25 

1650 2 1 56% OWNER 26 

3 27 

1533 3 1 15.8% OWNER 28 

126 15.8% OWNER 29 

1533 3 15.8% OWNER 30 

126 15.8% OWNER 31 

1533 3 15.8% OWNER 32 

126 15.8% OWNER 33 

5 1 34 

10 1 35 

1 3 36 

6 3 1 37 

10 1 38 

4 1 39 

4 1 40 

6 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

14 1 1 1 

2 3 1 2 

10 1 3 

14 1 4 

6 4 5 

2 3 6 

1 3 7 

2460 2 1 8 

4 1 9 

3 10 

10 1 11 

79 6 12 

14 1 13 

3 3 1 14 

28 2 16 

129 5 17 

106 4 18 

14 6 1 19 

13 2 20 

56 2 21 

18 6 1 22 

67 5 23 

15 2 24 

2 3 1 25 

3 1 26 

101 4 27 

78 3 28 

15 6 29 

4 3 30 

101 4 31 

25 2 32 

5 2 33 

45 2 1 34 

101 4 35 

25 2 36 

39 9 37 

3 3 1 38 

6 1 39 

6 1 40 

15 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

50 2 1 

8 3 1 2 

84 4 3 

65 12 1 5 

6 3 1 6 

1 3 1 7 

10 2 8 

6 3 1 9 

65 4 1 10 

8 3 1 11 

68 3 12 

3 3 1 13 

25 4 14 

9 1 1 15 

10 1 16 

8 3 1 17 

125 6 18 

38 3 19 

6 6 20 

8 1 21 

12 6 22 

84 3 23 

8 3 1 24 

9 1 25 

28 2 26 

5 3 1 27 

1 1 28 

40 2 29 

55 2 30 

54 2 31 

12 6 32 

35 7 33 

11 6 34 

65 3 35 

36 2 36 

45 2 37 

9 9 38 

19 2 39 

2 6 40 

4 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

1 

50 2 2 

4 2 3 

45 2 4 

5 2 5 

45 2 6 

12 6 1 7 

101 4 8 

1 3 1 9 

10 6 10 

69 7 11 

11 2 12 

10 2 14 

124 5 15 

5 3 1 16 

25 3 17 

28 2 19 

3 3 20 

73 3 21 

43 2 22 

56 2 23 

4 3 1 24 

45 2 25 

14 1 26 

28 2 27 

74 6 1 28 

84 4 29 

62 7 1 30 

67 3 31 

42 2 32 

2 3 1 33 

66 3 34 

37 6 35 

10 6 36 

6 3 1 37 

56 2 38 

99 4 39 

13 3 1 40 

13 

18 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

37 5 1 

45 2 2 

90 4 3 

103 4 4 

95 4 5 

20 2 6 

28 1 7 

55 4 8 

56 2 9 

50 2 1 10 

9 3 1 11 

31 6 1 12 

9 3 13 

13 2 14 

1 3 1 15 

44 2 16 

112 2 17 

128 9 18 

3 3 1 19 

101 4 20 

6 3 1 21 

15 2 22 

9 2 23 

28 2 24 

41 4 25 

92 6 26 

118 5 27 

68 3 28 

21 7 29 

69 5 30 

23 6 1 31 

19 3 1 32 

45 2 33 

3 6 34 

1 3 1 35 

6 3 1 36 

56 2 37 

6 3 1 38 

101 4 39 

7 1 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

1 3 1 

6 1 2 

104 4 3 

56 2 4 

56 2 5 

6 3 1 6 

11 2 7 

45 2 8 

45 2 9 

44 2 10 

12 4 11 

3 2 12 

7 3 13 

15 4 14 

43 2 1 15 

6 6 16 

14 1 17 

23 4 1 18 

4 3 19 

56 2 1 20 

2 3 1 21 

10 4 22 

10 2 23 

7 2 24 

16 3 25 

11 1 26 

56 2 1 27 

61 3 28 

74 3 29 

44 2 30 

89 4 31 

8 3 1 32 

3 6 1 33 

15 2 34 

62 3 35 

12 6 36 

95 4 37 

9 4 38 

45 2 39 

48 2 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

29 4 1 1 

3 6 1 2 

101 3 3 

6 3 1 4 

13 2 5 

1 3 1 6 

85 3 7 

19 3 1 8 

64 3 9 

9 6 10 

18 2 11 

30 6 12 

9 3 1 13 

67 3 14 

9 3 1 15 

8 3 1 16 

45 2 17 

73 3 18 

6 3 1 19 

9 3 1 20 

1 1 21 

13 4 22 

28 2 23 

34 4 1 24 

17 2 25 

41 2 26 

90 4 27 

72 3 28 

46 2 29 

7 1 30 

4 3 1 31 

4 1 32 

21 6 33 

56 2 34 

6 6 1 35 

13 3 1 36 

6 3 1 37 

9 6 38 

3 3 1 39 

40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

1 3 1 1 

45 2 2 

6 3 3 

38 6 4 

12 6 1 5 

115 6 6 

8 3 7 

3 3 8 

4 1 9 

73 3 10 

40 2 11 

9 3 1 12 

6 3 1 13 

6 3 1 14 

2 3 1 15 

6 3 16 

25 2 17 

25 2 18 

9 1 1 19 

101 4 20 

3 3 1 21 

16 4 22 

28 2 23 

13 7 24 

21 6 25 

3 3 26 

16 3 27 

2 3 1 28 

11 1 1 29 

48 2 30 

12 6 31 

81 8 32 

56 2 33 

19 6 34 

2 3 1 35 

3 3 36 

80 3 37 

15 3 1 38 

45 2 39 

8 3 1 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

101 4 1 

78 3 2 

5 1 3 


8 2 5 

5 6 6 

9 3 1 7 

9 3 1 8 

1 1 9 

44 2 10 

15 2 11 

85 4 12 

48 5 13 

41 4 14 

62 3 15 

45 2 16 

25 2 17 

50 2 18 

89 4 19 

6 6 1 20 

15 3 1 21 

6 3 22 

56 2 23 

34 4 1 24 

12 6 25 

6 3 26 

6 6 27 

74 3 28 

6 3 2 29 

43 2 30 

12 9 31 

39 2 32 

112 4 33 

145 6 34 

6 3 1 35 

40 4 1 36 

3 3 1 37 

1 3 1 38 

1 3 1 39 

20 6 1 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

47 2 1 

16 4 2 

56 2 3 

8 6 1 4 

3 3 5 

45 2 6 

8 3 7 

15 6 8 

56 2 9 

28 2 10 

6 3 1 11 

4 1 12 

12 6 13 

140 6 14 

2 15 

8 3 1 16 

55 2 17 

8 3 1 18 

56 2 19 

79 4 20 

9 9 21 

22 2 22 

9 6 1 23 

18 8 24 

62 3 25 

15 2 26 

14 1 27 

112 4 28 

21 2 29 

10 2 30 

67 3 31 

12 6 1 32 

15 6 33 

1 3 1 34 

28 2 35 

15 2 36 

8 3 1 37 

6 3 1 38 

6 6 1 39 

11 2 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

6 3 1 

24 4 2 

88 4 3 


45 2 5 

23 4 1 6 

28 2 7 

8 5 8 

44 2 9 

28 2 10 

4 6 1 11 

6 3 1 12 

11 6 13 

84 4 14 

62 3 15 

15 3 1 16 

45 2 17 

25 2 18 

80 4 19 

112 4 20 

18 6 21 

15 6 1 22 

70 3 23 

11 1 24 

72 3 25 

45 2 26 

3 3 1 27 

5 1 3 28 

2 3 1 29 

100 4 30 

13 3 31 

14 1 32 

14 6 1 33 

101 4 34 

56 3 35 

45 2 36 

15 2 37 

48 2 38 

25 4 1 39 

47 4 1 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

15 2 1 

10 2 2 

13 7 3 

84 3 4 

17 4 1 5 

79 4 6 

10 2 7 

3 3 1 8 

28 3 1 9 

14 6 10 

5 3 1 11 

28 2 12 

21 2 13 

45 2 14 

6 3 15 

90 4 16 

8 1 1 17 

45 2 18 

45 2 19 

5 2 20 

4 6 21 

56 2 22 

2 3 1 23 

3 3 1 24 

12 7 25 

101 4 26 

84 2 27 

15 2 28 

44 2 29 

15 2 30 

39 2 31 

7 3 1 32 

9 3 1 33 

56 2 34 

65 3 35 

7 5 1 36 

12 6 37 

44 10 38 

8 3 1 39 

112 4 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

9 6 2 1 

100 4 2 

48 2 3 

56 2 4 

56 2 1 5 

19 3 1 6 

93 4 7 

32 2 8 

44 2 9 

101 4 10 

50 12 11 

104 8 1 12 

9 3 1 13 

56 2 14 

12 6 15 

6 3 1 16 

12 6 17 

73 3 18 

6 3 19 

11 1 20 

8 4 21 

6 3 22 

3 3 1 23 

7 1 1 24 

11 12 25 

56 2 26 

37 6 27 

9 3 1 28 

20 6 1 29 

88 4 30 

106 4 31 

2 3 1 32 

11 1 33 

11 2 35 

101 4 36 

101 4 37 

67 3 38 

106 4 39 

25 2 40 

34 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

6 3 1 

44 4 2 

9 3 1 3 

67 3 4 

6 3 1 5 

6 3 1 6 

12 6 7 

60 7 8 

15 6 1 9 

76 6 10 

55 2 11 

25 2 12 

104 4 13 

44 2 14 

22 2 15 

38 6 16 

6 3 1 17 

89 4 18 

5 6 19 

10 6 20 

49 3 21 

5 1 22 

101 4 23 

8 3 1 24 

19 3 25 

8 3 26 

28 2 27 

28 2 28 

45 2 29 

56 3 30 

3 3 1 31 

56 2 32 

45 2 33 

12 6 34 

28 2 35 

56 2 36 

12 6 1 37 

14 1 38 

47 5 1 39 

40 2 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

17 2 1 

28 2 2 

23 9 3 

59 4 1 4 

6 3 5 

11 2 6 

59 3 7 

15 6 8 

22 2 9 

54 3 10 

27 2 11 

45 2 12 

88 4 13 

5 3 14 

6 6 15 

56 2 16 

26 4 1 17 

7 1 18 

112 4 19 

9 3 1 20 

5 3 21 

100 4 22 

6 6 1 23 

28 2 24 

3 3 1 25 

25 2 26 

84 4 27 

84 4 28 

6 3 1 29 

47 2 30 

101 3 31 

9 9 1 32 

5 3 33 

11 1 1 34 

22 2 35 

13 2 36 

70 3 37 

96 6 1 38 

95 4 39 

5 2 40 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

69 5 1 

45 2 2 

24 9 3 

4 3 1 4 

9 9 1 5 

40 2 6 

5 1 7 

68 4 8 

24 2 9 

5 3 1 10 

56 2 12 

12 9 1 13 

18 6 1 14 

22 2 15 

3 16 

56 2 17 

19 2 18 

45 2 19 

8 3 1 20 

33 9 21 

41 2 22 

4 6 23 

9 3 1 24 

3 3 1 25 

14 1 1 26 

6 3 1 28 

13 3 29 

27 3 1 30 

2 31 

1 1 32 

2 3 1 33 

6 6 34 

76 3 35 

28 2 36 

14 6 37 

15 4 1 38 

12 6 40 

11 

27 

39 




This 

(1) 


X 

Is: 

An Original 




(Mo, Da, Yr) 

04/18/2009 













Transformers 

Spare 




(In MVa) 

(f) 

(g) 

(h) 

(i) 

(j) 

(k) 

28 2 1 

4 3 1 2 

5 1 3 

84 3 4 

73 3 5 

66 6 6 

25 2 7 

3 3 1 8 

5 3 9 

-46 11 

87633 2692 227 13 750 12 

10 

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 







FOOTNOTE DATA 


(Mo, Da, Yr) 

04/18/2009 



Schedule Page: 426 Line No.: 17 Column: i 

Added 75 MVA Peaker in 2007 

Schedule Page: 426 Line No.: 28 Column: i 

Added 75 MVA Peaker in 2007 


Station jointly owned with others. 


Station jointly owned with others. 

Schedule Page: 426.2 Line No.: 29 Column: i 

Added 75 MVA Peaker in 2007. 




Transformers owned by U.S. Government. 


Transformers owned by U.S. Government. 




These values represent the total capacity of each unit, of which SCE is a 56% joint owner. 


These values represent the total capacity of each unit, of which SCE is a 15.8% joint owner. 


Each transformer bank represents the number of single-phase transformers per generating unit. 


Palo Verde Generating Station only has one spare transformer to service the station. 
















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 2


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 3


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 4


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 


Index 5

2008 FERC Form 1 and 2008 CPUC Annual Report - Edison ...

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