THIS FILING IS

Item 1: An Initial (Original)

Submission

OR Resubmission No. ____

Form 1 Approved

OMB No. 1902-0021

(Expires 12/31/2011)

Form 1-F Approved

OMB No. 1902-0029

(Expires 12/31/2011)

Form 3-Q Approved

OMB No. 1902-0205

(Expires 1/31/2012)

X

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

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

Exact Legal Name of Respondent (Company) Year/Period of Report

PacifiCorp End of 2010/Q4
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.

 “In connection with our regular examination of the financial statements of for the year ended on which we have

reported separately under date of , we have also reviewed schedules 

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

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:

FERC FORM 1 & 3-Q (ED. 03-07) ii
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and

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

141.400). 

V. Where to Send Comments on Public Reporting Burden.

 The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144

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)).

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

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

FERC FORM 1 & 3-Q (ED. 03-07) iv 
termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to 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.

FERC FORM 1 & 3-Q (ED. 03-07) v
EXCERPTS FROM THE LAW

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

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

 (3) ’Corporation' means any corporation, joint-stock company, partnership, association, business trust,

organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of 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

FERC FORM 1 & 3-Q (ED. 03-07) vi
"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind 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). 

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

FERC FORM NO. 1/3-Q:

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Douglas K. Stuver

825 N.E. Multnomah, Suite 1900, Portland, OR 97232

2010/Q4

825 N.E. Multnomah, Suite 1900, Portland, OR 97232

01 Exact Legal Name of Respondent

(1) An Original (2) A Resubmission X

02 Year/Period of Report

PacifiCorp End of

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

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

05 Name of Contact Person 06 Title of Contact Person

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

08 Telephone of Contact Person,Including

Area Code

09 This Report Is 10 Date of Report

(Mo, Da, Yr)

01 Name

02 Title

03 Signature 04 Date Signed

(Mo, Da, Yr)

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any

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

 / /

Henry E. Lay Corporate Controller

(503) 813-6179 04/18/2011

Douglas K. Stuver

Senior VP & Chief Financial Officer 04/18/2011

ANNUAL CORPORATE OFFICER CERTIFICATION

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct 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.

FERC FORM No.1/3-Q (REV. 02-04) Page 1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

LIST OF SCHEDULES (Electric Utility)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 1 General Information 101

 2 Control Over Respondent 102

 3 Corporations Controlled by Respondent 103

 4 Officers 104

 5 Directors 105

 6 Information on Formula Rates 106(a)(b)

 7 Important Changes During the Year 108-109

 8 Comparative Balance Sheet 110-113

 9 Statement of Income for the Year 114-117

 10 Statement of Retained Earnings for the Year 118-119

 11 Statement of Cash Flows 120-121

 12 Notes to Financial Statements 122-123

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

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

 15 Nuclear Fuel Materials 202-203 N/A

 16 Electric Plant in Service 204-207

 17 Electric Plant Leased to Others 213 N/A

 18 Electric Plant Held for Future Use 214

 19 Construction Work in Progress-Electric 216

 20 Accumulated Provision for Depreciation of Electric Utility Plant 219

 21 Investment of Subsidiary Companies 224-225

 22 Materials and Supplies 227

 23 Allowances 228(ab)-229(ab)

 24 Extraordinary Property Losses 230 N/A

 25 Unrecovered Plant and Regulatory Study Costs 230

 26 Transmission Service and Generation Interconnection Study Costs 231

 27 Other Regulatory Assets 232

 28 Miscellaneous Deferred Debits 233

 29 Accumulated Deferred Income Taxes 234

 30 Capital Stock 250-251

 31 Other Paid-in Capital 253

 32 Capital Stock Expense 254

 33 Long-Term Debt 256-257

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

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

 36 Accumulated Deferred Investment Tax Credits 266-267

FERC FORM NO. 1 (ED. 12-96) Page 2
LIST OF SCHEDULES (Electric Utility) (continued)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 37 Other Deferred Credits 269

 38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273

 39 Accumulated Deferred Income Taxes-Other Property 274-275

 40 Accumulated Deferred Income Taxes-Other 276-277

 41 Other Regulatory Liabilities 278

 42 Electric Operating Revenues 300-301

 43 Sales of Electricity by Rate Schedules 304

 44 Sales for Resale 310-311

 45 Electric Operation and Maintenance Expenses 320-323

 46 Purchased Power 326-327

 47 Transmission of Electricity for Others 328-330

 48 Transmission of Electricity by ISO/RTOs 331 N/A

 49 Transmission of Electricity by Others 332

 50 Miscellaneous General Expenses-Electric 335

 51 Depreciation and Amortization of Electric Plant 336-337

 52 Regulatory Commission Expenses 350-351

 53 Research, Development and Demonstration Activities 352-353

 54 Distribution of Salaries and Wages 354-355

 55 Common Utility Plant and Expenses 356 N/A

 56 Amounts included in ISO/RTO Settlement Statements 397 N/A

 57 Purchase and Sale of Ancillary Services 398

 58 Monthly Transmission System Peak Load 400

 59 Monthly ISO/RTO Transmission System Peak Load 400a N/A

 60 Electric Energy Account 401

 61 Monthly Peaks and Output 401

 62 Steam Electric Generating Plant Statistics 402-403

 63 Hydroelectric Generating Plant Statistics 406-407

 64 Pumped Storage Generating Plant Statistics 408-409 N/A

 65 Generating Plant Statistics Pages 410-411

 66 Transmission Line Statistics Pages 422-423

FERC FORM NO. 1 (ED. 12-96) Page 3
LIST OF SCHEDULES (Electric Utility) (continued)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 67 Transmission Lines Added During the Year 424-425

 68 Substations 426-427

 69 Transactions with Associated (Affiliated) Companies 429

 70 Footnote Data 450

Stockholders' Reports Check appropriate box:

X Two copies will be submitted

No annual report to stockholders is prepared

FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

Year/Period of Report

End of

GENERAL INFORMATION

PacifiCorp X

04/18/2011 2010/Q4

Douglas K. Stuver, Senior Vice President and Chief Financial Officer Corporate Books are kept at:

825 N.E. Multnomah, Suite 1900 825 N.E. Multnomah, Suite 1900

Portland, OR 97232-4116 Portland, OR 97232-4116

 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.

 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.

 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.

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

the respondent operated.

 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) No X

Not applicable

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric company

serving 1.7 million retail customers, including residential, commercial, industrial and other customers

in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp

delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power

and to customers in Oregon, Washington and California under the trade name Pacific Power. PacifiCorp's

electric generation, commercial and trading, and coal mining functions are operated under the trade name

PacifiCorp Energy.

FERC FORM No.1 (ED. 12-87) PAGE 101
Schedule Page: 101 Line No.: 1 Column: Item 2

PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under the name Pacific Power & Light Company. In

1984, Pacific Power & Light Company changed its name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, a

Utah corporation, in a transaction wherein both corporations merged into a newly formed Oregon corporation. The resulting Oregon

corporation was re-named PacifiCorp, which is the operating entity today.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

Year/Period of Report

End of

CONTROL OVER RESPONDENT

PacifiCorp X

04/18/2011 2010/Q4

 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.

Berkshire Hathaway Inc.(a)

MidAmerican Energy Holdings Company (100%)

 PPW Holdings LLC (100% controlled by MidAmerican Energy Holdings Company)

 PacifiCorp (100% of common stock held by PPW Holdings LLC)

(a) Berkshire Hathaway Inc. owns 89.85%, Walter Scott, Jr. (1) (along with family members and related entities) owns 5.63% and

Gregory E. Abel owns 0.80% of MEHC's common stock.

(1) Excludes 2,778,000 shares held by family members and family controlled trusts and corporations, or Scott Family Interests, as to

which Mr. Scott disclaims beneficial ownership.

FERC FORM NO. 1 (ED. 12-96) Page 102
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CORPORATIONS CONTROLLED BY RESPONDENT

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company Controlled Kind of Business Percent Voting

Stock Owned

(a) (b) (c)

Footnote

Ref.

(d)

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.

 1 Centralia Mining Company Mining 100

 2 Energy West Mining Company Mining 100

 3 Glenrock Coal Company Mining 100

 4 Interwest Mining Company Management Services 100

 5 Pacific Minerals, Inc. Management Services 100

 6 Bridger Coal Company Mining 66.67

 7 PacifiCorp Environmental Remediation Company Environmental Services 100

 8 PacifiCorp Investment Management, Inc. Management Services 100

 9 Trapper Mining Inc. Mining 21.40

 10 PacifiCorp Foundation Non-profit foundation

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

FERC FORM NO. 1 (ED. 12-96) Page 103
Schedule Page: 103 Line No.: 1 Column: a

In May 2000, the assets of Centralia Mining Company were sold to TransAlta. The entity is no longer active. Centralia Mining

Company is consolidated for reporting purposes in this annual report on Form No. 1.

Schedule Page: 103 Line No.: 2 Column: a

Energy West Mining Company is consolidated for reporting purposes in this annual report on Form No. 1. 

Schedule Page: 103 Line No.: 3 Column: a

Glenrock Coal Company ceased mining operations in October 1999. Glenrock Coal Company is consolidated for reporting purposes in

this annual report on Form No. 1.

Schedule Page: 103 Line No.: 4 Column: a

Interwest Mining Company is consolidated for reporting purposes in this annual report on Form No. 1.

Schedule Page: 103 Line No.: 5 Column: a

Pacific Minerals, Inc. ("PMI") is consolidated for reporting purposes in this annual report on Form No. 1.

Schedule Page: 103 Line No.: 6 Column: a

PMI is a wholly owned subsidiary of PacifiCorp that holds a 66.67% ownership interest in Bridger Coal Company, a coal mining joint

venture with Idaho Energy Resources Company, a subsidiary of Idaho Power Company. 

Schedule Page: 103 Line No.: 8 Column: a

PacifiCorp Investment Management, Inc. previously performed management services for PacifiCorp Environmental Remediation

Company and is no longer active. 

Schedule Page: 103 Line No.: 9 Column: a

PacifiCorp is a minority owner in Trapper Mining Inc., a cooperative. The members are Salt River Project Agricultural Improvement

and Power District (32.10%), Tri-State Generation and Transmission Association, Inc. (26.57%), PacifiCorp (21.40%) and Platte

River Power Authority (19.93%). 

Schedule Page: 103 Line No.: 10 Column: c

The PacifiCorp Foundation is an independent non-profit foundation created by PacifiCorp in 1988. The PacifiCorp Foundation

supports the growth and vitality of the communities where PacifiCorp and its affiliates have operations and employees. The PacifiCorp

Foundation operates as the Rocky Mountain Power Foundation and the Pacific Power Foundation. Two of the PacifiCorp

Foundation's five directors are also directors of PacifiCorp.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

OFFICERS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Title Name of Officer Salary

for Year

(a) (b) (c)

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 Executive Officers as of December 31, 2010:

 2 Chairman of the Board and Chief Executive Officer Gregory E. Abel

 3 Senior Vice President and Chief Financial Officer Douglas K. Stuver 233,525

 4 President, Rocky Mountain Power A. Richard Walje 357,150

 5 President, Pacific Power R. Patrick Reiten 265,740

 6 President, PacifiCorp Energy Micheal G. Dunn 230,114

 7

 8 Other Executive Officers in 2010:

 9 President, PacifiCorp Energy A. Robert Lasich 22,944

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FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: a

PacifiCorp sets forth the salary information for its "named executive officers" for the year ended December 31, 2010, consistent with

Item 402 of Regulation S-K promulgated by the Securities and Exchange Commission in its Annual Report on Form 10-K. Salary

information of other officers will be provided to the Federal Energy Regulatory Commission (the "FERC") upon request, but the

company considers such information personal and confidential to such officers. See 18 CFR 388.107(d), (f).

Schedule Page: 104 Line No.: 2 Column: b

Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimburses MidAmerican Energy Holdings Company

("MEHC") for the cost of Mr. Abel’s time spent on matters supporting PacifiCorp, including compensation paid to him by MEHC,

pursuant to an intercompany administrative services agreement among MEHC and its subsidiaries. Please refer to MEHC’s Annual

Report on Form 10-K for the year ended December 31, 2010 (File No. 001-14881) for executive compensation information for Mr.

Abel.

Schedule Page: 104 Line No.: 6 Column: b

For additional information regarding changes in the status of PacifiCorp's officers refer to Important Changes During the Quarter/Year,

Item 13 of this Form No. 1. On January 13, 2010, Mr. Dunn was elected President of PacifiCorp Energy and director of PacifiCorp,

both effective February 1, 2010.

Schedule Page: 104 Line No.: 9 Column: b

For additional information regarding changes in the status of PacifiCorp's officers refer to Important Changes During the Quarter/Year,

Item 13 of this Form No. 1. On January 13, 2010, Mr. Lasich resigned as President of PacifiCorp Energy and director of PacifiCorp,

both effective February 1, 2010.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

DIRECTORS

PacifiCorp X

04/18/2011

2010/Q4

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

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.

 1 PacifiCorp Board of Directors as of December 31, 2010:

 2 Gregory E. Abel (Chairman of the Board and CEO, PacifiCorp) 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309

 3 R. Patrick Reiten (President, Pacific Power) 825 NE Multnomah, Suite 2000, Portland, Oregon 97232

 4 A. Richard Walje (President, Rocky Mountain Power) 201 South Main, Suite 2300, Salt Lake City, Utah 84111

 5 Douglas L. Anderson 302 South 36th Street, Omaha, Nebraska 68131

 6 Brent E. Gale (Senior Vice President) 825 NE Multnomah, Suite 2000, Portland, Oregon 97232

 7 Patrick J. Goodman 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309

 8 Micheal G. Dunn (President, PacifiCorp Energy) 1407 West North Temple, Suite 320, Salt Lake City, Utah 84116

 9 Mark C. Moench (SVP and General Counsel, PacifiCorp) 201 South Main, Suite 2400, Salt Lake City, Utah 84111

 10 Natalie L. Hocken (VP and General Counsel, Pacific Power) 825 NE Multnomah, Suite 2000, Portland, Oregon 97232

 11

 12 Other PacifiCorp Board of Directors in 2010:

 13 A. Robert Lasich (President, PacifiCorp Energy) 1407 West North Temple, Suite 320, Salt Lake City, Utah 84116

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FERC FORM NO. 1 (ED. 12-95) Page 105
Schedule Page: 105 Line No.: 2 Column: a

Currently there is only one committee, a Compensation Committee, of which the sole member is Mr. Abel.

Schedule Page: 105 Line No.: 8 Column: a

For additional information regarding changes in the status of PacifiCorp's directors refer to Important Changes During the

Quarter/Year, Item 13 of this Form No. 1. On January 13, 2010, Mr. Dunn was elected President of PacifiCorp Energy and director of

PacifiCorp, both effective February 1, 2010.

Schedule Page: 105 Line No.: 13 Column: a

For additional information regarding changes in the status of PacifiCorp's directors refer to Important Changes During the

Quarter/Year, Item 13 of this Form No. 1. On January 13, 2010, Mr. Lasich resigned as President of PacifiCorp Energy and director of

PacifiCorp, both effective February 1, 2010.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

INFORMATION ON FORMULA RATES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. FERC Rate Schedule or Tariff Number FERC Proceeding

Does the respondent have formula rates? Yes

X No

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

accepting the rate(s) or changes in the accepted rate.

FERC Rate Schedule/Tariff Number FERC Proceeding

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FERC FORM NO. 1 (NEW. 12-08) Page 106
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No. Accession No. \ Filed Date

Document Date

Docket No. Description

Formula Rate FERC Rate

Schedule Number or

Tariff Number

INFORMATION ON FORMULA RATES

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

X No

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

FERC Rate Schedule/Tariff Number FERC Proceeding

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

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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

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

INFORMATION ON FORMULA RATES

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

Formula Rate Variances

amounts reported in the Form 1.

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

Form 1.

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

impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.

4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.

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FERC FORM NO. 1 (NEW. 12-08) Page 106b
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report Year/Period of Report

End of

IMPORTANT CHANGES DURING THE QUARTER/YEAR

PacifiCorp X

04/18/2011 2010/Q4

PAGE 108 INTENTIONALLY LEFT BLANK

SEE PAGE 109 FOR REQUIRED INFORMATION.

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.

FERC FORM NO. 1 (ED. 12-96) Page 108
ITEM 1.

Changes in Franchise Rights

The following table includes new or modified franchise agreements. The fee represents either the fee attached to the franchise

agreement, an associated tax or fee.

State Effective Date Expiration Date Fee

California (1)

None

Idaho (2)

None

Oregon (3)

Coquille 01/29/2010 01/29/2020 5.0%

Glendale 02/02/2010 02/02/2020 7.0%

Athena 04/21/2010 04/21/2030 3.5%

Prineville 06/10/2010 06/10/2015 5.0%

Falls City(4) 06/01/2010 06/01/2020 6.0%

Wasco 06/18/2010 06/18/2015 3.5%

Dallas 08/24/2010 08/24/2020 7.0%

Sutherlin 09/01/2010 09/01/2020 3.5%

Junction City 10/01/2010 10/01/2020 5.0%

Coos Bay 09/17/2010 09/17/2015 7.0%

Gates 11/01/2010 11/01/2020 7.0%

Madras 12/14/2010 01/01/2021 7.0%

Utah(2)

Salt Lake County 04/06/2010 04/06/2035 -

Duchesne County 04/19/2010 04/19/2020 -

Layton 06/08/2010 06/08/2015 5.0%

South Jordan 07/22/2010 07/22/2025 6.0%

West Jordan 10/13/2010 10/13/2045 6.0%

Eagle Mountain 11/03/2010 11/03/2015 3.0%

Mayfield 12/08/2010 12/08/2040 -

Washington (2)

Zillah (5) 05/17/2010 05/17/2020 6.0%

Wyoming (6)

Worland (7) 09/01/1999 09/01/2014 5.0%

Bar Nunn 01/15/2010 01/15/2035 4.0%

Riverton 04/22/2010 04/22/2030 6.0%

Glendo 04/28/2010 04/28/2035 2.0%

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.1
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.

(2) In Idaho, Utah and Washington, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.

(3) In Oregon, the first 3.5% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from

customers and remitted directly to the applicable municipalities.

(4) The term of this franchise agreement is for 10 years with a rate review in five years.

(5) The term of this franchise agreement shall be for two successive five-year terms, unless one party gives the other written notice terminating the franchise

agreement at least 90 days before the end of a franchise term.

(6) In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0% is collected

from customers and remitted directly to the applicable municipalities. 

(7) Represents a fee increase only; effective July 1, 2010.

ITEM 2.

Acquisition of Ownership in Other Companies

None.

ITEM 3. 

Purchase or Sale of an Operating Unit

In January 2010, PacifiCorp received approval from the Federal Energy Regulatory Commission (the “FERC”) in Docket

No. EC10-13-000, pursuant to Section 203 of the Federal Power Act, for the acquisition of the Goshen Series Capacitor Bank from

Idaho Power Company (“Idaho Power”). The purchase included a 345 kilovolt (“kV”), 3-phase, 60-Hertz, 2-equal-segment outdoor

series capacitor bank and associated rights and property. In December 2010, the FERC approved the journal entries required by the

Uniform System of Accounts (“USofA”) in Docket No. AC11-5-000. Accordingly, PacifiCorp cleared account 102, Electric plant

purchased or sold, and recorded the purchase to the appropriate plant accounts.

In February 2010, the FERC approved the journal entries required by the USofA as presented in Docket No. AC10-44-000 for the

acquisition of a portion of a 69 kV electric transmission facility from Garkane Energy Cooperative, Inc. 

In July 2010, PacifiCorp received approval from the FERC in Docket No. ER10-1217-000, pursuant to Section 205 of the Federal

Power Act, of the joint ownership and operating agreement with Idaho Power for the 345 kV Populus substation. In addition,

PacifiCorp acquired a portion of the 500 kV Hemingway substation from Idaho Power. The Populus substation was constructed by

PacifiCorp, and the Hemingway substation was constructed by Idaho Power.

In December 2010, PacifiCorp closed the sale of undivided ownership interests in certain of PacifiCorp’s transmission facilities to

Black Hills Power, Inc. (“Black Hills”). The sale consisted of a 22.5% undivided ownership interest in the 230 kV Windstar substation

and a 15% undivided ownership interest in the 230 kV Dave Johnston substation, both located in Converse County, Wyoming, and a

56.25% undivided ownership interest in a 230 kV transmission line between the Windstar substation and the Dave Johnston substation.

The sale provides Black Hills 450 megawatts (“MW”) of transmission rights through the facilities. Pursuant to a joint operating and

maintenance agreement between PacifiCorp and Black Hills, PacifiCorp will operate and maintain the facilities in their entirety. The

assets sold have been included in account 102, Electric plant purchased or sold, and PacifiCorp will file the journal entries required by

the USofA within the required six-month period from the date of the sale. Commission authorizations associated with the sale were as

follows:

• Oregon Public Utility Commission (the "OPUC") - Order No. 10-449, effective November 15, 2010.

• California Public Utilities Commission (the “CPUC”) - Advice Letter 424-E and 425-E, both effective December 9, 2010.

• Wyoming Public Service Commission (the “WPSC”) - Docket No. 20000-382-EA-10, effective February 22, 2011, pursuant

to open meeting action taken on December 28, 2010.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.2
In March 2011, PacifiCorp entered into an agreement for the sale of the Snake Creek hydroelectric generating facility with Heber Light

& Power Company. The sale will close after all regulatory approvals have been obtained. PacifiCorp is in the process of filing

applications for approval of the sale with the OPUC, CPUC and WPSC.

ITEM 4. 

Important Leaseholds

None.

ITEM 5.

Important Extension or Reduction of Transmission System or Distribution Territory

During the year ended December 31, 2010, PacifiCorp did not significantly increase or decrease its distribution territory. Refer to

pages 424-425 of this Form No. 1 for additional information regarding transmission lines added or removed during the year.

ITEM 6. 

Financing Activities

Short-term Debt and Revolving Credit Facilities

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. PacifiCorp had $36 million of short-term debt outstanding as

of December 31, 2010 at a weighted-average interest rate of 0.3% as compared to no short-term debt outstanding as of December 31,

2009. PacifiCorp had no outstanding borrowings under its unsecured revolving credit facilities as of December 31, 2010 or 2009. 

Commission authorizations for up to $1.5 billion outstanding at any one time in commercial paper and other unsecured short-term debt

are as follows:

• OPUC - Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.

• Washington Utilities and Transportation Commission (the "WUTC") - Docket No. UE-980404, dated April 8, 1998.

• Idaho Public Utilities Commission (the "IPUC") - Case No. PAC-E-06-01, Order No. 29999, dated March 14, 2006, effective

through April 30, 2011.

• IPUC – Case No. PAC-E-11-09, Order No. 32221, dated April 8, 2011, effective through April 30, 2016.

• FERC - Docket No. ES09-50-000, dated October 9, 2009, letter order effective January 1, 2010 through December 31, 2011.

For further discussion, refer to Note 8 of Notes to Financial Statements included in this Form No. 1.

Long-term Debt

In addition to the debt issuances discussed herein, PacifiCorp made scheduled repayments on long-term debt totaling $15 million and

$138 million during the years ended December 31, 2010 and 2009, respectively.

In January 2009, PacifiCorp issued $350 million of its 5.50% First Mortgage Bonds due January 15, 2019 and $650 million of its

6.00% First Mortgage Bonds due January 15, 2039. The net proceeds were used to repay short-term debt, to fund capital expenditures

and for general corporate purposes. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.3
In June 2010, PacifiCorp completed a re-offering of a $45 million series of tax-exempt bond obligations. The interest rate for this

obligation was previously fixed for a term which, upon scheduled expiration, was converted to a variable-rate with credit enhancement

and liquidity support provided by a $46 million letter of credit issued under one of PacifiCorp's unsecured revolving credit facilities. In

September 2010, PacifiCorp completed a re-offering of variable-rate tax-exempt bond obligations totaling $38 million. Letters of

credit totaling $39 million were issued under one of PacifiCorp's unsecured revolving credit facilities to provide credit enhancement

and liquidity support for these previously unenhanced obligations.

As of December 31, 2010, PacifiCorp had $601 million of letters of credit available to provide credit enhancement and liquidity

support for variable-rate tax-exempt bond obligations totaling $587 million plus interest. These letters of credit were fully available at

December 31, 2010 and expire periodically through May 2012.

PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2.0 billion of long-term debt. PacifiCorp

must make a notice filing with the WUTC prior to any future issuance. Also, in December 2010, PacifiCorp filed a shelf registration

statement with the United States Securities and Exchange Commission (the “SEC”) covering future first mortgage bond issuances.

State commission authorizations are as follows: 

• OPUC - Docket No. UF-4262, Order No. 10-062, dated February 23, 2010.

• IPUC - Case No. PAC-E-10-02, Order No. 31018, dated March 5, 2010.

PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds

based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of

cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2010,

PacifiCorp estimated it would be able to issue up to $5.9 billion of new first mortgage bonds under the most restrictive issuance test in

the mortgage. Any issuances are subject to market conditions and amounts may be further limited by regulatory authorizations or

commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property

from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash. 

PacifiCorp may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately

negotiated transactions or otherwise. Any debt securities repurchased by PacifiCorp may be reissued or resold by PacifiCorp from time

to time and will depend on prevailing market conditions, PacifiCorp's liquidity requirements, contractual restrictions and other factors.

The amounts involved may be material.

Preferred Stock

In May 2010, PacifiCorp received an unsolicited offer to repurchase certain shares of PacifiCorp's preferred stock. As a result,

PacifiCorp purchased and canceled 4,036 shares of its $100 stated value 4.72% Serial Preferred Stock for $318,844, at an average

price per share of $79, and 3,266 shares of its $100 stated value 4.56% Serial Preferred Stock for $241,684, at an average price per

share of $74. 

Common Shareholder's Equity

In January 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC, a direct subsidiary of

MidAmerican Energy Holdings Company (“MEHC”) on February 28, 2011.

In March 2011, PacifiCorp declared a dividend of $275 million payable to PPW Holdings LLC on April 20, 2011.

Cash capital contributions from MEHC were $100 million and $125 million during the years ended December 31, 2010 and 2009,

respectively. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.4
ITEM 7.

Changes in Articles of Incorporation or Amendments to Charter

None.

ITEM 8. 

Estimated Annual Effect of Wage Scale Changes

PacifiCorp’s bargaining unit wage scale changes were as follows: 

Estimated Annual

Unions Represented % Increase (1) Effective Date(s) Financial Impact (2)

IBEW 57 Power Delivery (UT, ID & WY) 2.1% 1/26/2010 $ 1,727,403

IBEW 57 Power Supply (UT, ID & WY) 2.1% 1/26/2010 803,268

IBEW 57 Combustion Turbine (UT) 1.4% 5/26/2010 31,132

IBEW 57 Laramie (WY) 0.8% 6/26/2010 4,525

IBEW 659 Power Supply (OR & CA) 2.3% 1/26/2010 779,863

IBEW 125 Power Supply (MT, OR & WA) 2.3% 1/26/2010 705,336

UWUA 127 (WY) 1.7% 1/11/2010 & 9/26/2010 682,091

UWUA 197 (OR) 0.9% 5/26/2010 16,356

UMWA 1769 (UT) 2.1% 1/03/2010 263,120

UMWA 2176 (UT) 2.1% 1/03/2010 10,400

 Total $ 5,023,494

(1) This percentage increase represents the increase in wages for all effective dates during the calendar year as compared to the wage scale of the prior effective

period.

(2) The estimated annual impact is based on the time period from the effective date of the increase to the end of the calendar year. Some amounts may be

reimbursed by joint owners.

Labor Agreement

A new four-year contract for Western Energy Workers International Brotherhood of Boilermakers Local S1978 (“union”) went into

effect April 1, 2011. The labor agreement between Pacific Minerals, Inc. (“PMI”) and the union expired November 25, 2010. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.5
ITEM 9.

Legal Proceedings

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or

exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its financial

results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines,

penalties and other costs in substantial amounts and are described below. In addition to the following discussion, refer to Note 13 of

Notes to Financial Statements in this Form No. 1.

In December 2000, Wah Chang, a large industrial customer of PacifiCorp, filed an action before the OPUC asserting that the rates set

by a special tariff with PacifiCorp and approved by the OPUC were not just and reasonable due to alleged market manipulation during

the energy crisis. In October 2001, the OPUC dismissed Wah Chang's petition and found that Wah Chang assumed the risk of price

increases under the special tariff. Wah Chang petitioned the Circuit Court for Marion County, Oregon for review of the OPUC's order.

In June 2002, the Circuit Court for Marion County, Oregon, granted Wah Chang's motion for review, and ordered the OPUC to reopen

the record to allow Wah Chang the opportunity to present new evidence. In September 2009, the OPUC dismissed Wah Chang's

petition and reaffirmed that the rates set by the special tariff were just and reasonable. In October 2009, Wah Chang filed with the

Oregon Court of Appeals a petition for judicial review of the OPUC's September 2009 order denying Wah Chang relief. In July 2010,

the Oregon Court of Appeals accepted judicial review.

In a separate but related proceeding, in December 2000, Wah Chang filed a complaint in the Circuit Court for Linn County, Oregon,

asserting that the OPUC-approved special tariff with PacifiCorp is subject to rescission based on theories of mutual mistake of fact,

frustration of purpose and impracticability. In August 2002, the Circuit Court for Linn County, Oregon, granted PacifiCorp's motion

for summary judgment dismissing Wah Chang's complaint. In February 2004, the Circuit Court for Linn County, Oregon, granted Wah

Chang's motion to reopen the case to present additional evidence of alleged market manipulation. In December 2007, Wah Chang filed

a second amended complaint seeking recovery of a portion of the costs paid under the special tariff based on various theories of legal

relief, including partial rescission, unjust enrichment, and breach of duty of good faith and fair dealing. In August 2009, the Circuit

Court for Linn County, Oregon, granted Wah Chang's request to file a third amended complaint containing a claim for punitive

damages. The trial began in April 2011. Wah Chang is seeking $37 million (less the amount Wah Chang would have paid for

electricity absent the special tariff) in compensatory damages and $200 million in punitive damages. PacifiCorp intends to vigorously

defend these claims and believes that the outcome of these proceedings will not have a material impact on its financial results.

In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in the Third District Court for Salt

Lake County, Utah ("Third District Court") by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring

Canyon Energy, LLC (collectively, "USA Power"), against Utah attorney Jody L. Williams and the law firm Holme,

Roberts & Owen, LLP, who represent PacifiCorp on various matters from time to time. USA Power was the developer of a planned

generation project in Mona, Utah called Spring Canyon, which PacifiCorp, as part of its resource procurement process, at one time

considered as an alternative to the Currant Creek generating facility. USA Power's complaint alleged that PacifiCorp misappropriated

confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and

related claims. USA Power seeks $250 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive

damages, costs and attorneys' fees. The statutory doubling of damages only applies to the plaintiffs' trade secret claim and could

increase the total damages sought to $500 million. After considering various motions for summary judgment, the court ruled in

October 2007 in favor of PacifiCorp on all counts and dismissed the plaintiffs' claims in their entirety. In February 2008, the plaintiffs

filed a petition requesting consideration by the Utah Supreme Court of two of their five claims. The plaintiffs' request was granted and

they filed a brief in November 2008 with the Utah Supreme Court. In January 2009, PacifiCorp filed its reply brief. In May 2010, the

Utah Supreme Court reversed and remanded the case back to the Third District Court for further consideration. The Third District

Court set an eight-week trial for June and July 2011. PacifiCorp cannot predict the outcome of these proceedings, but believes that the

outcome will not have a material impact on its financial results. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.6
ITEM 10.

Officer, Director, Security Holder and Associated Company Transactions

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

PacifiCorp is a consolidated subsidiary of MEHC and its common stock is indirectly owned by MEHC, 666 Grand Avenue,

Des Moines, Iowa 50309. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”) that, as of

January 31, 2011, owns 89.85% of MEHC's common stock. The balance of MEHC's common stock is owned by Walter Scott, Jr.

(along with family members and related entities), a member of MEHC's Board of Directors, and Gregory E. Abel, PacifiCorp's

Chairman and Chief Executive Officer.

None of PacifiCorp’s executive officers and directors owns shares of its preferred stock. The following table sets forth certain

information as of January 31, 2011 regarding the beneficial ownership of MEHC's common stock and the Class A and Class B shares

of Berkshire Hathaway common stock held by each of PacifiCorp’s directors, executive officers and all of PacifiCorp’s directors and

executive officers as a group as of January 31, 2011.

MEHC Berkshire Hathaway

Common Stock Class A Common Stock Class B Common Stock

Number of Number of Number of

Shares Shares Shares

Beneficially Percentage of Beneficially Percentage of Beneficially Percentage of

Beneficial Owner Owned (1) Class (1) Owned (1) Class (1) Owned (1) Class (1)

Gregory E. Abel (2) 595,940 0.8% 1 * 1,930 *

Douglas L. Anderson —— 4 * 300 *

Micheal G. Dunn — — — — — —

Brent E. Gale ——————

Patrick J. Goodman — — 4 * 660 *

Natalie L. Hocken ——————

Mark C. Moench (3) — — 3 * — —

R. Patrick Reiten ——————

Douglas K. Stuver — — — — — —

A. Richard Walje ——————

All executive officers and

directors as a group 

(10 persons) 595,940 0.8% 12 * 2,890 *

* Indicates beneficial ownership of less than one percent of all outstanding shares.

(1) Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities

Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.

(2) In accordance with a shareholders' agreement, as amended on December 7, 2005, based on an assumed value for MEHC's common stock and the closing

price of Berkshire Hathaway common stock on January 31, 2011, Mr. Abel would be entitled to exchange his shares of MEHC common stock for either

1,120 shares of Berkshire Hathaway Class A stock or 1,676,651 shares of Berkshire Hathaway Class B stock. Assuming an exchange of all available

MEHC shares into either Berkshire Hathaway Class A shares or Berkshire Hathaway Class B shares, Mr. Abel would beneficially own less than 1% of the

outstanding shares of either class of stock.

(3) Excludes 12 Class A shares and 15,000 Class B shares of Berkshire Hathaway common stock held by a family corporation and family limited partnership,

as to which Mr. Moench disclaims beneficial ownership.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.7
Other Matters

Pursuant to a shareholders' agreement, as amended on December 7, 2005, Mr. Abel is able to require Berkshire Hathaway to exchange

any or all of his shares of MEHC common stock for shares of Berkshire Hathaway common stock. The number of shares of Berkshire

Hathaway common stock to be exchanged is based on the fair market value of MEHC common stock divided by the closing price of

the Berkshire Hathaway common stock on the day prior to the date of exchange.

Certain Relationships and Related Transactions

The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of Business Conduct, or the Codes, which

apply to all of PacifiCorp’s directors, officers and employees and those of PacifiCorp’s subsidiaries, generally govern the review,

approval or ratification of any related-person transaction. A related-person transaction is one in which PacifiCorp or any of

PacifiCorp’s subsidiaries participate and in which one or more of PacifiCorp’s directors, executive officers, holders of more than five

percent of PacifiCorp’s voting securities or any of such persons' immediate family members have a direct or indirect material interest.

Under the Codes, all of PacifiCorp’s directors and executive officers (including those of PacifiCorp’s subsidiaries) must disclose to

PacifiCorp’s legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with

PacifiCorp’s interests. No action may be taken with respect to such transaction or relationship until approved by the legal department.

For PacifiCorp’s chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be

given by Berkshire Hathaway's audit committee. In addition, prior legal department approval must be obtained before a director or

executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own

business that raises a potential conflict or appearance of conflict with PacifiCorp’s interests.

Under an intercompany administrative services agreement PacifiCorp has entered into with MEHC and its other subsidiaries, the costs

of certain administrative services provided by MEHC to PacifiCorp or by PacifiCorp to MEHC, or shared with MEHC and other

subsidiaries, are directly charged or allocated to the entity receiving such services. This agreement has been filed with the utility

regulatory commissions in the states where PacifiCorp serves retail customers. PacifiCorp also provides an annual report of all

transactions with its affiliates to PacifiCorp’s state regulatory commissions, who have the authority to refuse recovery in rates for

payments PacifiCorp makes to its affiliates deemed to have the effect of subsidizing the separate business activities of MEHC or its

other subsidiaries.

Refer to Note 17 of Notes to Financial Statements and page 429, Transactions with Associated (Affiliated) Companies, in this

Form No.1 for additional information regarding related-party transactions.

ITEM 11.

(Reserved)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.8
ITEM 12.

General Regulation

PacifiCorp is subject to comprehensive governmental regulation, which significantly influences its operating environment, prices

charged to customers, capital structure, costs and ability to recover costs. 

Certain regulatory matters are subject to uncertainties that require the use of estimates on the financial statements, particularly that

related to Oregon Senate Bill 408 (“SB 408”). Refer to Note 5 of Notes to Financial Statements in this Form No. 1 for further

discussion.

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Energy Policy Act of

2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of

electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding

companies; accounting; securities issuances; and other matters, including construction and operation of hydroelectric facilities. The

FERC also has the enforcement authority to assess civil penalties of up to $1 million per day per violation of rules, regulations and

orders issued under the Federal Power Act. PacifiCorp has implemented programs that facilitate compliance with the FERC regulations

described below, including having instituted compliance monitoring procedures. 

Wholesale Electricity and Capacity

The FERC regulates PacifiCorp's rates charged to wholesale customers for electricity and transmission capacity and related services.

Most of PacifiCorp's wholesale electricity sales and purchases take place under market-based pricing allowed by the FERC and are

therefore subject to market volatility. 

The FERC conducts triennial reviews of PacifiCorp's market-based pricing authority. PacifiCorp must demonstrate the lack of market

power in order to charge market-based rates for sales of wholesale electricity and electric generation capacity in its market areas.

PacifiCorp's most recent triennial filing was made in June 2010 and is currently pending before the FERC, while its next triennial filing

is due in June 2013. Under the FERC's market-based rules, PacifiCorp must also file a notice of change in status when there is a

significant change in the conditions that the FERC relied upon in granting market-based pricing authority. PacifiCorp is currently

authorized to sell electricity on the wholesale market at market-based rates.

Transmission

PacifiCorp's wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's Open

Access Transmission Tariff ("OATT"). In accordance with its OATT, PacifiCorp offers several transmission services to wholesale

customers:

• Network transmission service (service that integrates generating resources to serve retail loads); 

• Long- and short-term firm point-to-point transmission service (service with fixed delivery and receipt points); and 

• Non-firm point-to-point service (service with fixed delivery and receipt points on an as available basis).

These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to

access the transmission system. PacifiCorp's transmission business is managed and operated independently from its commercial and

trading business, in accordance with the FERC rules. PacifiCorp has made several required compliance filings in accordance with these

rules. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.9
FERC Reliability Standards

The FERC has approved an extensive number of reliability standards developed by the North American Electric Reliability

Corporation (the "NERC") and the Western Electricity Coordinating Council (the "WECC"), including critical infrastructure

protection standards and regional standard variations. PacifiCorp must comply with all applicable standards. Compliance, enforcement

and monitoring oversight of these standards is carried out by the FERC, the NERC and the WECC. In 2007, the WECC audited

PacifiCorp's compliance with several of the approved reliability standards, and in November 2008, the FERC assumed control of

certain aspects of the WECC's audit. In May 2009, PacifiCorp received a notice of alleged violation and proposed sanctions related to

the portions of the WECC's 2007 audit that remained with the WECC. In July 2009, PacifiCorp reached a settlement with the WECC.

The results of the settlement did not have a material impact on PacifiCorp's financial results. Refer to Note 13 of Notes to Financial

Statements in this Form No. 1 for additional information regarding certain aspects of the WECC's 2007 audit currently under the

FERC's authority and the FERC's reliability standards review. 

Hydroelectric Relicensing

PacifiCorp's Klamath hydroelectric system is the only significant hydroelectric generating facility for which PacifiCorp is engaged in

the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of certain hydroelectric

systems. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power

Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Refer to Note 13 of Notes to Financial Statements

in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's Klamath hydroelectric system.

Hydroelectric Decommissioning

Powerdale Hydroelectric Facility - Hood River, Oregon

In June 2003, PacifiCorp entered into a settlement agreement to decommission the 6-MW Powerdale hydroelectric facility rather than

pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. In 2007, the FERC

authorized PacifiCorp to cease generation at the facility and approved PacifiCorp's proposed accounting entries to defer the remaining

net book value and any additional removal costs of the system as a regulatory asset. PacifiCorp received approval from its state

regulatory commissions to defer and recover these costs. In April 2010, PacifiCorp initiated removal of the Powerdale dam and

associated system features as stipulated in the FERC Surrender Order. As of October 31, 2010, decommissioning activities, including

dam removal and site restoration, were completed. PacifiCorp will monitor restored areas until early 2012 when the project land will

be transferred to the Columbia Land Trust, Oregon Department of Fish and Wildlife and Hood River County. Removal costs for the

Powerdale dam and associated system features were approximately $4 million, and additional monitoring costs are not expected to

exceed $1 million.

Condit Hydroelectric Facility - White Salmon River, Washington

In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectric facility was signed by PacifiCorp, state and

federal agencies and non-governmental organizations. In early February 2005, the parties agreed to modify the settlement agreement,

establishing a total cost to decommission not to exceed $21 million, excluding inflation. In October 2010, the Washington Department

of Ecology issued a Clean Water Act 401 certificate, and in December 2010, the FERC issued a surrender order for project

decommissioning. In January 2011, PacifiCorp filed a request for clarification and rehearing of the surrender order and a motion for

stay with the FERC. In April 2011, a motion for extension of time was filed with the FERC requesting that the FERC allow project

decommissioning to be delayed until 2012 as the FERC has not yet issued an order on PacifiCorp’s request for rehearing on the

surrender order. PacifiCorp will consider a 2011 decommissioning provided: (a) the FERC issues an order on rehearing in April 2011

granting all of PacifiCorp’s rehearing requests; (b) PacifiCorp’s contractor agrees to a later notice to proceed date; (c) other parties to

the rehearing do not appeal the FERC’s order; and (d) PacifiCorp can feasibly manage a 2011 decommissioning. Remaining permitting

includes a Section 404 permit from the United States Army Corps of Engineers. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.10
Northwest Refund Case

For a discussion of the Northwest Refund case, refer to Note 13 of Notes to Financial Statements in this Form No. 1.

United States Mine Safety

PacifiCorp's mining operations are regulated by the federal Mine Safety and Health Administration ("MSHA"), which administers

federal mine safety and health laws and regulations, and state regulatory agencies. MSHA has the statutory authority to institute a civil

action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator

who fails to pay penalties or fines for violations of federal mine safety standards. Federal law requires PacifiCorp to have a written

emergency response plan specific to each underground mine it operates, which is reviewed by MSHA every six months, and to have at

least two rescue teams located within one hour of each mine. Refer to "Coal Mine Safety Disclosures Required by the Dodd-Frank

Wall Street Reform and Consumer Protection Act" below for further information regarding the coal mine and coal processing facilities

that PacifiCorp operates.

State Regulation

PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. Historically,

state regulatory commissions have established rates on a cost-of-service basis, which are designed to allow a utility an opportunity to

recover its costs of providing services and to earn a reasonable return on its investments. A utility's cost of service generally reflects its

allowed operating expenses, including energy costs, operation and maintenance expense, depreciation expense and income and other

tax expense, reduced by wholesale electricity sales and other revenue. The allowed operating expenses are typically based on estimates

of normalized costs, which may differ from realized costs in a given year covered by the established rates. State regulatory

commissions may adjust rates pursuant to a review of (a) the utility's revenue and expenses during a defined test period and (b) the

utility's level of investment. State regulatory commissions typically have the authority to review and change rates on their own

initiative; however, they may also initiate reviews at the request of a utility, utility customer, a governmental agency or a representative

of a group of customers. The utility and such parties, however, may agree with one another not to request a review of or changes to

rates for a specified period of time. 

PacifiCorp's retail rates are generally based on the cost of providing traditional bundled services, including generation, transmission

and distribution services. Historically, the state regulatory framework in PacifiCorp's service areas reflect specified net power costs as

part of bundled retail rates or incorporated net power cost adjustment clauses in PacifiCorp's retail rates and tariffs. In states where net

power cost adjustment clauses exist, permitted periodic adjustments to cost recovery from customers provide protection to PacifiCorp

against exposure to changes in net power costs.

Except for Oregon and Washington, PacifiCorp has an exclusive right to serve customers within its service territories, and in turn, has

the obligation to provide electric service to those customers within its allocated service territory. Under Oregon law, PacifiCorp has the

exclusive right and obligation to provide electric distribution services to all customers within its allocated service territory; however,

nonresidential customers have the right to choose alternative electricity service suppliers. The impact of these programs on

PacifiCorp's financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation.

PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered

into service area agreements under the jurisdiction of the WUTC.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.11
In addition to recovery through rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as

summarized below.

State Regulator Base Rate Test Period Adjustment Mechanism

Utah Public Service Commission

(“UPSC”)

Forecasted or historical with

known and measurable changes (1)

Energy balancing account ("EBA") under which 70% of the difference

between base net power costs established in a general rate case and actual

net power costs, subject to other adjustments, would be subject to the

EBA mechanism between the general rate cases. The EBA will be

effective October 1, 2011.

A recovery mechanism is available for a single capital investment project

that in total exceeds 1% of existing rate base when a general rate case has

occurred within the preceding 18 months.

Oregon Public Utility Commission Forecasted Annual transition adjustment mechanism ("TAM") based on forecasted

net variable power costs; no true-up to actual net variable power costs.

Renewable adjustment clause ("RAC") to recover the revenue

requirement of new renewable resources and associated transmission that

are not reflected in general rates.

Annual true-up of taxes authorized to be collected in rates compared to

taxes paid by PacifiCorp, as defined by Oregon statute and administrative

rules under SB 408.

Wyoming Public Service Commission Forecasted or historical with

known and measurable changes (1)

Energy cost adjustment mechanism ("ECAM") under which 70% of any

difference between actual and forecasted net power costs established in a

general rate case would be subject to the ECAM mechanism between

general rate cases.

Washington Utilities and

Transportation Commission

Historical with known and

measurable changes

Deferral mechanism of costs for up to 24 months of new base load

generation resources and eligible renewable resources and related

transmission that qualify under the state's emissions performance

standard and are not reflected in general rates.

Idaho Public Utilities Commission Historical with known and

measurable changes

ECAM under which 90% of the difference between base net power costs

established in a general rate case and actual net power costs, subject to

other adjustments, would be subject to the ECAM mechanism between

the general rate cases.

California Public Utilities

Commission

Forecasted Post test-year adjustment mechanism for major capital additions ("PTAM

- capital additions") that allows for rate adjustments outside of the context

of a traditional general rate case for the revenue requirement associated

with capital additions exceeding $50 million on a total-company basis.

Filed as eligible capital additions are placed into service.

Energy cost adjustment clause ("ECAC") that allows for an annual update

to actual and forecasted net variable power costs.

Post test-year adjustment mechanism for attrition ("PTAM - attrition"), a

mechanism that allows for an annual adjustment to costs other than net

variable power costs.

(1) PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.12
Generally, PacifiCorp's demand-side management ("DSM") program costs are collected through separately established rates that are

adjusted periodically based on actual and expected costs, as approved by the respective state regulatory commission. As such, recovery

of DSM program costs has no impact on net income.

Rate Proceedings

FERC

As a result of a 2007 multi-party settlement with the FERC regarding long-term shared usage, coordinated operation and maintenance,

and planning of certain 500-kV transmission lines, PacifiCorp agreed to file a Federal Power Act Section 205 general rate change

filing for its system-wide transmission service rates no later than June 1, 2011. PacifiCorp is in the process of preparing for this filing,

which will occur no later than the agreed upon date.

State Commissions

Utah

In March 2009, PacifiCorp filed for an ECAM with the UPSC. The filing recommended that the UPSC adopt the mechanism to

recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. In February

2010, PacifiCorp filed an application with the UPSC seeking approval to defer the difference between the net power costs allowed by

the UPSC's final order in PacifiCorp's 2009 general rate case and the actual net power costs incurred. Also in February 2010, the Utah

Association of Energy Users filed a motion with the UPSC requesting deferral of incremental renewable energy credit revenue in

excess of the renewable energy credit value utilized in Utah rates established by the 2009 general rate case. In July 2010, the UPSC

issued an order approving a stipulation that would establish deferred accounts for both net power costs and renewable energy credit

revenues in excess of the levels currently included in rates, subject to the UPSC's final determination of the ratemaking treatment of the

deferrals. In December 2010, the UPSC approved a separate stipulation that provides a $3 million monthly credit to customers

effective January 1, 2011 that will be applied toward the UPSC's final decision. In March 2011, the UPSC issued its final order

approving the use of an EBA in Utah, which will begin at the conclusion of the pending general rate case. Under the EBA, which will

begin as a four year pilot program, 70% of any difference between actual costs incurred and those established in base rates, subject to

certain other adjustments, will be subject to the EBA mechanism between general rate cases. The UPSC did not provide the final

resolution of the differences in net power costs and renewable energy credit revenues from the 2009 general rate case, but indicated

that it would address the potential deferrals separately from the March 2011 order. In April 2011, PacifiCorp filed a petition with the

UPSC for clarification and reconsideration of the final order.

In February 2010, PacifiCorp filed an application with the UPSC requesting an increase of $34 million associated with two major

construction projects that were completed and in service by June 2010. The application requested recovery in conjunction with a future

rate change. In March 2010, PacifiCorp updated its application to reflect the cost of capital decisions from the February 2010 general

rate case order, reducing the amount requested for recovery to $33 million. In May 2010, a multi-party stipulation was filed with the

UPSC agreeing to recovery of $31 million. In June 2010, the stipulation was approved by the UPSC. 

In August 2010, PacifiCorp filed an application with the UPSC requesting an increase of $39 million associated with two major

construction projects expected to be complete and in service by December 2010. The application requested a 5% increase in rates

effective January 2011 encompassing both the $39 million requested increase and the $31 million increase approved by the UPSC in

June 2010. In December 2010, the UPSC approved a stipulation that provides for a $64 million increase that encompasses both the

February 2010 and the August 2010 applications. The stipulation also provides for collection of a one-time $16 million surcharge for

recovery of amounts related to the February 2010 application that were deferred during the period July 2010 to December 2010. The

new rates were effective January 1, 2011.

In January 2011, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $232 million, or an average price

increase of 14%. If approved by the UPSC, the rates will be effective September 2011.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.13
Oregon

In February 2010, PacifiCorp made its initial filing for the annual TAM with the OPUC for an annual increase of $69 million to

recover the anticipated net power costs forecasted for calendar year 2011. In July 2010, an all-party stipulation was filed with the

OPUC agreeing to an increase of $58 million, or an average price increase of 6%. The OPUC approved the all-party stipulation in

September 2010, subject to updates for anticipated net power costs through November 2010. PacifiCorp filed the scheduled updates to

net power costs in July and November 2010. In December 2010, PacifiCorp filed a final update to net power costs, reflecting an

increase of $60 million, or an average price increase of 6%. The OPUC approved the increase in December 2010 with an effective date

of January 1, 2011. 

In March 2010, PacifiCorp filed a general rate case with the OPUC requesting an increase of $131 million, or an average price

increase of 13%. In July 2010, a multi-party stipulation was filed with the OPUC agreeing to an annual increase of $85 million, or an

average price increase of 8%. The stipulation required PacifiCorp to file updated costs for the Populus to Terminal transmission line

once the asset was placed in service. In December 2010, PacifiCorp filed the updated costs based on the November 2010

placed-in-service date and reduced the annual increase to $80 million, or an average price increase of 8%. In December 2010, the

OPUC approved the stipulation. The new rates were effective January 1, 2011.

In March 2011, PacifiCorp made its initial filing for the annual TAM with the OPUC for an annual increase of $62 million, or an

average price increase of 5%, to recover the anticipated net power costs forecasted for calendar year 2012. The new rates will be

effective January 1, 2012 and are subject to updates throughout the proceeding.

Wyoming

In October 2009, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $71 million with an effective date of

August 1, 2010. Net power costs included in the general rate case filing reflected an increase in coal costs and the expiration of low

cost long-term power purchase contracts. The application was based on a test period ending December 31, 2010. In March 2010, a

multi-party stipulation was filed with the WPSC agreeing to an overall rate increase of $36 million, or an average price increase of 7%,

to be implemented in two phases. In May 2010, the WPSC approved the settlement agreement. The first phase of the rate increase,

consisting of a $26 million increase, became effective July 1, 2010 and the second phase, consisting of the remaining $10 million

increase, was effective February 1, 2011.

In January 2010, PacifiCorp filed its annual power cost adjustment mechanism (“PCAM”) application with the WPSC requesting

recovery of $8 million in deferred net power costs. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to

reduce the requested recovery to $4 million. In May 2010, the WPSC approved the settlement agreement allowing for the change in the

PCAM surcharge rate effective April 1, 2010.

In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The

PCAM concluded with the final deferral of net power costs in November 2010 and collection through March 2012. In November 2010,

the WPSC approved effective December 1, 2010, the deferral of net power costs incurred above or below base net power costs

currently provided for in rates until the WPSC issues an order on PacifiCorp's application for the ECAM. In November 2010, the

WPSC held hearings for the establishment and design of an ECAM. In February 2011, the WPSC issued an order approving an ECAM

under which the base net power costs will be established in general rate cases based on forecasted net power costs and 70% of any

difference between actual and forecasted net power costs, subject to certain other adjustments, will be subject to the ECAM mechanism

between general rate cases. 

In February 2011, PacifiCorp filed its final PCAM application with the WPSC requesting recovery of $16 million in deferred net

power costs. If approved by the WPSC, the application would result in an $11 million rate increase over the $5 million currently

reflected in the tariff. PacifiCorp requested and received approval from the WPSC to implement an interim rate change effective

April 1, 2011, which will be in effect until the WPSC issues a final order.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.14
In November 2010, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $98 million, or an average price

increase of 17%. If approved by the WPSC, the rates will be effective September 2011.

Washington

In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price

increase of 21%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. In

March 2011, the WUTC issued a final order and a clarification letter approving an annual increase of $33 million, or an average price

increase of 12%, offset in the first year by a customer bill credit of $5 million, or 2% related to the sale of renewable energy credits

expected during the rate year. The new rates were effective in April 2011. In April 2011, PacifiCorp filed a petition for reconsideration

requesting the WUTC to reconsider various items on the final order including income tax and net power cost issues and the WUTC’s

conclusions with respect to rate of return. The petition will be deemed denied if, within 20 days from the April 4, 2011 filing date, the

WUTC does not either rule on the petition or issue a notice specifying the date it will act on the petition.

Idaho

In February 2010, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $2 million in deferred net power costs.

In March 2010, the IPUC issued an order approving PacifiCorp's ECAM application effective April 1, 2010.

In May 2010, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $28 million, or an average price

increase of 14%. In November 2010, the requested annual increase was reduced to $25 million, or an average price increase of 12%. In

December 2010, the IPUC issued an interim order approving an annual increase of $14 million, or an average price increase of 7%

with an effective date of December 28, 2010. In February 2011, the IPUC issued its final order with no revisions to the December

2010 increase. In March 2011, PacifiCorp petitioned the IPUC seeking reconsideration or rehearing on certain aspects of the order. In

March 2011, the IPUC staff filed reply comments to PacifiCorp’s motion for reconsideration accepting corrections identified by

PacifiCorp and providing for a slight increase in the recovery. In April 2011, the IPUC issued an order accepting in part and rejecting

in part PacifiCorp’s petition for reconsideration resulting in no material effect on the IPUC’s initial order.

In June 2010, the IPUC approved an increase to PacifiCorp's energy efficiency rider to fund DSM programs of $1 million, or an

average price increase of 1%, with an effective date of July 1, 2010. As a result of the 1% increase, the energy efficiency rider

increased to 5%. In December 2010, the IPUC reduced the energy efficiency rider to 3%.

In February 2011, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $13 million in deferred net power

costs. In March 2011, the IPUC issued an order approving recovery of $10 million beginning in 2011 and the remaining $3 million

beginning in 2012. The rate change was effective April 1, 2011.

California 

In November 2009, PacifiCorp filed a general rate case with the CPUC requesting an annual increase of $8 million, or an average price

increase of 10%. In June 2010, PacifiCorp filed an all-party settlement agreement with the CPUC that reflects an annual increase of

$4 million, or an average price increase of 5%, and includes the establishment of revised depreciation rates on California distribution

assets. In September 2010, the CPUC approved the settlement agreement with an effective date of January 1, 2011.

In August 2010, PacifiCorp filed an application with the CPUC to increase rates pursuant to the ECAC. In the application, PacifiCorp

requested a rate increase of $9 million, or an average price increase of 11%. In November 2010, the CPUC approved the ECAC with

an effective date of January 1, 2011.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.15
Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,

emissions performance standards, climate change, coal combustion byproducts, hazardous and solid waste disposal, protected species

and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing

continuing compliance obligations, these laws and regulations provide authority to levy substantial penalties for noncompliance

including fines, injunctive relief and other sanctions. These laws and regulations are administered by the United States Environmental

Protection Agency (the "EPA") and various other state and local agencies. All such laws and regulations are subject to a range of

interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp

is unable to predict the impact of the changing laws and regulations on its operations and financial results. PacifiCorp believes it is in

material compliance with all applicable laws and regulations. In addition to the following discussion, refer to Note 13 of Notes to

Financial Statements in this Form No. 1.

Clean Air Standards

The Clean Air Act is a federal law, administered by the EPA that provides a framework for protecting and improving the nation's air

quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation

Plans ("SIPs"). SIPs, which are a collection of regulations, programs and policies to be followed, vary by state and are subject to

public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the

EPA. The major Clean Air Act programs, which most directly affect PacifiCorp's operations, are described below.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal pollutants,

consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfur dioxide, considered harmful to public health

and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in

attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a

nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards

require measurement over a defined period of time to determine the average concentration of the pollutant present.

In December 2009, the EPA designated the Utah counties of Davis and Salt Lake, as well as portions of Box Elder, Cache, Tooele,

Utah and Weber counties, to be in nonattainment of the fine particulate matter standard. This designation has the potential to impact

PacifiCorp's Little Mountain, Lake Side and Gadsby facilities, depending on the requirements to be established in the Utah SIP. The

impact on the PacifiCorp facilities is not anticipated to be significant.

In January 2010, the EPA proposed a rule to strengthen the national ambient air quality standard for ground level ozone. The proposed

rule arises out of legal challenges claiming that the March 2008 rule that reduced the standard from 80 parts per billion to 75 parts per

billion was not strict enough. The new rule proposes a standard between 60 and 70 parts per billion. The EPA has delayed issuance of

the final ozone standards until July 2011.

In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 0.10 part per million. State attainment

designations were required to be submitted to the EPA by January 1, 2011, and the EPA must finalize the designations by January 1,

2012.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.16
In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the new rule, the existing

24-hour and annual standards for sulfur dioxide, which were 140 parts per billion measured over 24 hours and 30 parts per billion

measured over an entire year, were replaced with a new one-hour standard of 75 parts per billion. The new rule will utilize a three-year

average to determine attainment. The rule will utilize source modeling, in addition to the installation of ambient monitors where sulfur

dioxide emissions impact populated areas, with new monitors required to be in-service no later than January 2013. Attainment

designations are due by June 2012, with SIPs due by 2014 and final attainment demonstrations by August 2017. 

As new, more stringent standards are adopted, the number of counties designated as nonattainment areas is likely to increase.

Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce

emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve

certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of

facilities that are sources of emissions could become more difficult in nonattainment areas. Until additional monitoring and modeling is

conducted, the impacts on PacifiCorp cannot be determined.

Hazardous Air Pollutant Maximum Achievable Control Technology

The EPA issued the proposed Hazardous Air Pollutant Maximum Achievable Control Technology rule for coal- and oil-fueled electric

generating units in March 2011. The proposed rule sets standards for 10 non-mercury hazardous air pollutant (“HAP”) metals, mercury

and acid gases and establishes work practices to minimize emissions of organic HAPs. The proposed rule establishes numeric emission

limits for mercury, total metals, particulate matter and hydrogen chloride, which will be effective three years after the final rule is

issued. The EPA indicated the public comment period would be open for 60 days after the proposed rule is published in the Federal

Register and the final rule would be issued in November 2011. PacifiCorp is reviewing the proposed rule; the impacts on PacifiCorp

have not yet been determined.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas").

Some of PacifiCorp's generating facilities meet the threshold applicability criteria to be eligible units under the Clean Air Visibility

Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable

progress towards achieving natural visibility conditions in Class I areas by requiring emissions controls, known as best available

retrofit technology, on sources constructed between 1962 and 1977 with emissions that are anticipated to cause or contribute to

impairment of visibility. Wyoming issued best available retrofit technology permits to PacifiCorp on December 31, 2009, requiring

PacifiCorp to implement emissions control projects that are consistent with the planned emissions reduction projects at PacifiCorp's

Wyoming generating facilities. PacifiCorp appealed certain provisions of the Naughton and Jim Bridger generating facilities' permits,

but the appeals were settled. Utah submitted its SIP and suggested that the emissions reduction projects planned by PacifiCorp are

sufficient to meet its initial emissions reduction requirements. Utah amended its regional haze SIP in April 2011 and submitted the

revisions to the EPA for consideration. In January 2009, the EPA found that 37 states, including Wyoming, had failed to file a SIP that

met some or all of the basic regional haze program requirements. Wyoming submitted its regional haze SIP to the EPA in

January 2011. PacifiCorp believes that its planned emissions reduction projects will satisfy the regional haze requirements in Utah and

Wyoming. It is possible that additional controls may be required after the respective SIPs have been considered by the EPA or that the

timing of installation of planned controls could change. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.17
New Source Review

Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facility that emits regulated pollutants is required to

obtain a permit from the EPA or a state regulatory agency prior to (a) beginning construction of a new major stationary source of a

regulated pollutant or (b) making a physical or operational change to an existing stationary source of such pollutants that increases

certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement

of equipment). In general, projects subject to NSR regulations require pre-construction review and permitting under the Prevention of

Significant Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of

regulated pollutants must undergo an analysis to determine the best available control technology and evaluate the most effective

emissions controls after consideration of a number of factors. Violations of NSR regulations, which may be alleged by the EPA, states,

environmental groups and others, potentially subject a company to material fines and other sanctions and remedies, including

installation of enhanced pollution controls and funding of supplemental environmental projects.

As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested information

and supporting documentation from numerous utilities regarding their capital projects for various generating facilities. A NSR

enforcement case against an unrelated utility has been decided by the United States Supreme Court, holding that an increase in the

annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR

permitting. Between 2001 and 2003, PacifiCorp responded to requests for information relating to its capital projects at its generating

facilities. PacifiCorp has been engaged in periodic discussions with the EPA over several years regarding PacifiCorp's historical

projects and their compliance with NSR and PSD provisions. Final resolution has not been achieved. PacifiCorp cannot predict the

outcome of its discussions with the EPA at this time; however, PacifiCorp could be required to install additional emissions controls

and incur additional costs and penalties in the event it is determined that PacifiCorp's historical projects did not meet all regulatory

requirements. 

Numerous changes have been proposed to the NSR rules and regulations over the last several years. In addition to the proposed

changes, differing interpretations by the EPA and the courts create risk and uncertainty for entities when seeking permits for new

projects and installing emissions controls at existing facilities under NSR requirements. PacifiCorp monitors these changes and

interpretations to ensure permitting activities are conducted in accordance with the applicable requirements. 

Climate Change 

The increased global attention to climate change has resulted in significant measures being proposed at the federal level to regulate

greenhouse gas ("GHG") emissions. The United States Congress has considered, but has not adopted comprehensive climate change

legislation, which included a market-based cap-and-trade program that was intended to reduce GHG emissions 83% below 2005 levels

by 2050. 

In December 2009, the EPA published its findings that GHG threaten the public health and welfare and is pursuing regulation of GHG

emissions under the Clean Air Act. Additionally, in May 2010, the EPA issued the greenhouse gas "tailoring rule" to address

permitting requirements for GHG after determining that GHG are subject to regulation and would trigger Clean Air Act permitting

requirements for stationary sources beginning in January 2011. Numerous lawsuits have been filed on both the EPA's endangerment

finding and the tailoring rule and are pending in the D.C. Circuit.

PacifiCorp supports the implementation of reasonable emissions caps, but opposes trading mechanisms that impose additional costs

and do not result in decreased emissions. PacifiCorp also believes that any law or regulation should provide a reasonable transition

period to allow the phase in of low-carbon generating technologies that will achieve sustainable and cost-effective GHG emissions

reduction benefits.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.18
While the debate continues at the federal and international level over the direction of climate change policy, several states have

developed or are developing state-specific laws or regional initiatives to report or mitigate GHG emissions. In addition, governmental,

non-governmental and environmental organizations have become more active in pursuing climate change related litigation under

existing laws.

PacifiCorp voluntarily reports its GHG emissions to the California Climate Action Registry and The Climate Registry. In September

2009, the EPA issued its final rule regarding mandatory reporting of GHG ("GHG Reporting") beginning January 1, 2010. Under

GHG Reporting, suppliers of fossil fuels, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per

year of GHG are required to submit annual reports to the EPA. PacifiCorp is subject to this requirement. The EPA deferred the filing

of the first report from March 31, 2011 to September 30, 2011 to incorporate changes to its electronic reporting system.

PacifiCorp is committed to operating in an environmentally responsible manner. Examples of PacifiCorp's significant investments in

programs and facilities that will mitigate its GHG emissions include:

• PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated

utilities. As of December 31, 2010, PacifiCorp owned 1,032 MW of wind-powered generating capacity and has purchase

power agreements with 705 MW of wind-powered generating capacity. PacifiCorp has invested $2.1 billion in wind-powered

generating facilities.

• PacifiCorp owns 1,157 MW of hydroelectric generating capacity.

• PacifiCorp's Energy Gateway Transmission Expansion Program represents a plan to build approximately 2,000 miles of new

high-voltage transmission lines with an estimated cost exceeding $6 billion. The plan includes several transmission line

segments that will: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system

constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of

electricity throughout PacifiCorp's six-state service area.

• PacifiCorp has offered customers a comprehensive set of DSM programs for more than 20 years. The programs assist

customers to manage the timing of their usage, as well as to reduce overall energy consumption, resulting in lower utility bills.

• PacifiCorp has installed and upgraded emissions control equipment at certain of its coal-fired generating facilities to reduce

emissions of sulfur dioxide and nitrogen oxides.

The impact of pending federal, regional, state and international accords, legislation, regulation, or judicial proceedings related to

climate change cannot be quantified in any meaningful range at this time. New requirements limiting GHG emissions could have a

material adverse impact on PacifiCorp, the United States and the global economy. Companies and industries with higher GHG

emissions, such as utilities with significant coal-fired generating facilities, will be subject to more direct impacts and greater financial

and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These

factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the

requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of

offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost

recovery mechanisms. Examples of how new requirements may impact PacifiCorp include:

• Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in

excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be

developed and deployed to reduce emissions or lower carbon generation is available;

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.19
• Acquiring and renewing construction and operating permits for new and existing facilities may be costly and difficult;

• Additional costs may be incurred to purchase and deploy new generating technologies;

• Costs may be incurred to retire existing coal facilities before the end of their otherwise useful lives or to convert them to burn

fuels, such as natural gas or biomass, that result in lower emissions;

• Operating costs may be higher and unit outputs may be lower;

• Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view

climate change and GHG emissions as a financial risk; and

• PacifiCorp's electric transmission and retail sales may be impacted in response to changes in customer demand and

requirements to reduce GHG emissions.

PacifiCorp expects it will be allowed to recover the prudently incurred costs to comply with climate change requirements.

The impact of events or conditions caused by climate change, whether from natural processes or human activities, could vary widely,

from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may

cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events.

Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy

consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity,

such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence

PacifiCorp's existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity

production and increase the price customers pay or their demand for electricity.

International Accords

Under the United Nations Framework Convention on Climate Change, adopted in 1992, members of the convention meet periodically

to discuss international responses to climate change. To date, the United States has not made a binding reduction commitment as a

result of these international discussions.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.20
Federal Legislation

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009

("Waxman-Markey bill"). In addition to a federal renewable portfolio standard ("RPS"), which would have required utilities to obtain a

portion of their energy from certain qualifying renewable sources and energy efficiency measures, the bill required a reduction in GHG

emissions beginning in 2012, with emissions reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020;

42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a cap-and-trade program. Similar legislation was

introduced in the Senate, but it did not pass.

Greenhouse Gas Tailoring Rule

The EPA finalized the GHG "tailoring rule" in May 2010 requiring new or modified sources of GHG emissions with increases of

75,000 or more tons per year of total GHG to determine the best available control technology for their GHG emissions beginning in

January 2011. New or existing major sources will also be subject to Title V operating permit requirements for GHG. Beginning July 1,

2011 through June 30, 2013, new construction projects that emit GHG emissions of at least 100,000 tons per year and modifications of

existing facilities that increase GHG emissions by at least 75,000 tons per year will be subject to permitting requirements and facilities

that were previously not subject to Title V permitting requirements will be required to obtain Title V permits if they emit at least

100,000 tons per year of carbon dioxide equivalents. Several legal challenges have been filed to the EPA's final GHG tailoring rule in

the D.C. Circuit. The EPA issued a GHG best available control technology guidance document in November 2010 in an effort to

provide permitting authorities guidance on how to conduct a best available control technology review for GHG. Until the permitting

authorities begin to implement the tailoring rule and determine what constitutes best available control technology for GHG, the impacts

of the tailoring rule on PacifiCorp cannot be fully determined.

Regional and State Activities

Several states have developed state-specific laws or regional legislative initiatives to report or mitigate GHG emissions that are

expected to impact PacifiCorp, including:

• The Western Climate Initiative, a comprehensive regional effort to reduce GHG emissions by 15% below 2005 levels by 2020

through a cap-and-trade program that includes the electricity sector. The Western Climate Initiative includes the states of

California, Montana, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia,

Manitoba, Ontario and Quebec. The state and provincial partners have agreed to begin reporting GHG emissions in 2011 for

emissions that occurred in 2010. The first phase of the cap-and-trade program is scheduled to begin on January 1, 2012.

• An executive order signed by California's governor in June 2005 would reduce GHG emissions in that state to 2000 levels by

2010, to 1990 levels by 2020 and 80% below 1990 levels by 2050. The California Air Resources Board proposed regulations

to adopt a GHG cap-and-trade program in October 2010; however, those regulations have not yet been finalized. In addition,

California has adopted legislation that imposes a GHG emissions performance standard to all electricity generated within the

state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-art combined-cycle

natural gas-fired generating facility, as well as legislation that adopts an economy-wide cap on GHG emissions to 1990 levels

by 2020.

• Over the past several years, the states of California, Washington and Oregon have adopted GHG emissions performance

standards for base load electrical generating resources. Under the laws in all three states, the emissions performance standards

provide that emissions must not exceed 1,100 lbs of carbon dioxide per megawatt hour ("MWh"). These GHG emissions

performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new

ownership investments, upgrades, or new or renewed contracts with a term of 5 or more years) unless any base load

generation supplied under long-term financial commitments comply with the GHG emissions performance standards.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.21
• The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing goals for

the reduction of GHG emissions in their respective states. Washington's goals seek to (a) reduce emissions to 1990 levels by

2020; (b) reduce emissions to 25% below 1990 levels by 2035; and (c) reduce emissions to 50% below 1990 levels by 2050,

or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek to (a) cease the growth of Oregon GHG

emissions by 2010; (b) reduce GHG levels to 10% below 1990 levels by 2020; and (c) reduce GHG levels to at least 75%

below 1990 levels by 2050. Each state's legislation also calls for state government to develop policy recommendations in the

future to assist in the monitoring and achievement of these goals.

Renewable Portfolio Standards

The RPS described below could significantly impact PacifiCorp's financial results. Resources that meet the qualifying electricity

requirements under the RPS vary from state to state. Each state's RPS requires some form of compliance reporting and PacifiCorp can

be subject to penalties in the event of noncompliance.

In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities,

including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016

through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative. 

In June 2007, the Oregon Renewable Energy Act ("OREA") was adopted, providing a comprehensive renewable energy policy for

Oregon. Subject to certain exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electric utilities

must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014,

15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC

has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its

investments in renewable energy generating facilities and associated transmission costs. 

In 2011, the California Legislature passed, and the governor signed, legislation to expand the state’s RPS to require 20% of retail load

to be procured from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020 and

each year thereafter. The new law will likely supersede the California Air Resources Board 33% renewable electricity standard

adopted pursuant to Executive Order S-21-09 in September 2009. The 2011 legislation expands the RPS to all California retail sellers,

provides additional flexible compliance mechanisms for retail sellers and modifies the types of renewable electricity products that may

be used to comply with the law. 

In March 2008, Utah's governor signed Utah Senate Bill 202. Among other things, this law provides that, beginning in the year 2025,

20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will

be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided

as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere in the WECC areas,

and renewable energy credits can be used. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.22
Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality

in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean

Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental

impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing

electric generating facilities that take in more than 50 million gallons of water per day. These rules are aimed at minimizing the adverse

environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water

withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit remanded almost all aspects of the rule to

the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements.

On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a

cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse

environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the

§316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to

conduct further proceedings consistent with its opinion. Compliance and the potential costs of compliance, therefore, cannot be

ascertained until such time as the Second Circuit takes action or further action is taken by the EPA. Currently, PacifiCorp's Dave

Johnston generating facility, which has water cooling towers, exceeds the 50 million gallons of water per day intake threshold. In the

event that PacifiCorp's existing intake structures require modification or alternative technology required by new rules, expenditures to

comply with these requirements could be significant. PacifiCorp believes that it currently has, or has initiated the process to receive, all

required water quality permits.

Coal Combustion Byproduct Disposal

In December 2008, an ash impoundment dike at the Tennessee Valley Authority's Kingston power plant collapsed after heavy rain,

releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surrounding area. In light of this

incident, federal and state officials have called for greater regulation of the storage and disposal of coal combustion byproducts. In

May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two

alternatives to regulation under the Resource Conservation and Recovery Act ("RCRA"). Under the first option, coal combustion

byproducts would be regulated as special waste under RCRA Subtitle C and the EPA would establish requirements for coal

combustion byproducts from the point of generation to disposition, including the closure of disposal units. Alternatively, the EPA is

considering regulation under RCRA Subtitle D under which it would establish minimum nationwide standards for the disposal of coal

combustion byproducts. Under both options, surface impoundments utilized for coal combustion byproducts would have to be cleaned

and closed unless they could meet more stringent regulatory requirements; in addition, more stringent requirements would be

implemented for new ash landfills and expansions of existing ash landfills. PacifiCorp operates 16 surface impoundments and six

landfills that contain coal combustion byproducts. These ash impoundments and landfills may be impacted by the newly proposed

regulation, particularly if the materials are regulated as hazardous or special waste under RCRA Subtitle C, and could pose significant

additional costs associated with ash management and disposal activities at PacifiCorp's coal-fired generating facilities. The public

comment period closed in November 2010; however, the timing of the final rule is not known. The impact of the proposed regulations

on coal combustion byproducts cannot be determined at this time.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.23
Other

Other laws, regulations and agencies to which PacifiCorp is subject to include, but are not limited to:

• The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any

current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to

such disposal site, to share in environmental remediation costs.

• The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation

and closure standards that must be met during and upon completion of mining activities.

• The FERC oversees the relicensing of existing hydroelectric systems and is also responsible for the oversight and issuance of

licenses for new construction of hydroelectric systems, dam safety inspections and environmental monitoring. Refer to

Note 13 of Notes to Financial Statements in this Form No. 1 for additional information regarding the relicensing of certain of

PacifiCorp's existing hydroelectric facilities.

Future Generation and Conservation

Integrated Resource Plan 

As required by certain state regulations, PacifiCorp uses an Integrated Resource Plan ("IRP") to develop a long-term view of prudent

future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers.

The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs and an associated optimal future

resource mix that accounts for planning uncertainty, risks, reliability impacts, state energy policies and other factors. The IRP is a

coordinated effort with stakeholders in each of the six states where PacifiCorp operates. PacifiCorp files its IRP on a biennial basis and

receives a formal notification in five states as to whether the IRP meets the commission's IRP standards and guidelines, referred to as

acknowledgment. PacifiCorp has received acknowledgment of its 2008 IRP from the state commissions in Oregon, Utah, Washington,

Idaho and Wyoming. In March 2011, PacifiCorp filed its 2011 IRP with the state commissions.

Requests for Proposals

PacifiCorp has issued a series of individual Requests for Proposals ("RFPs"), each of which focuses on a specific category of electric

generation resources consistent with the IRP. The IRP and the RFPs provide for the identification and staged procurement of resources

in future years to achieve a balance of load requirements and resources. As required by applicable laws and regulations, PacifiCorp

files draft RFPs with the UPSC, the OPUC and the WUTC prior to issuance to the market. Approval by the UPSC, the OPUC or the

WUTC may be required depending on the nature of the RFPs. 

In August 2009, under PacifiCorp's 2008R-1 renewable resources RFP (approved by the OPUC in September 2008), PacifiCorp

executed a power purchase agreement to purchase the entire output of the 200-MW Top of the World wind-powered generating facility

located in Wyoming and the associated renewable energy credits. The generating facility reached commercial operation in

October 2010, and the power purchase agreement will continue for a period of 20 years. PacifiCorp's 2009R renewable resources RFP

(approved by the OPUC with modification in July 2009) seeks additional cost-effective renewable generation projects with no single

resource greater than 300 MW, combined total resources of no more than 400 MW and on-line dates no later than December 31, 2012.

As a result of the 2009R renewable resources RFP, PacifiCorp's 111-MW Dunlap Ranch I wind-powered generating facility located in

Wyoming was constructed and placed in service in October 2010.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.24
In October 2009, PacifiCorp filed a request for approval with the UPSC to re-issue the All Source RFP, which was previously

suspended in April 2009. In October 2009 and November 2009, respectively, the UPSC and the OPUC approved resumption of the All

Source RFP. The All Source RFP seeks up to 1,500 MW on a system wide basis from projects with in-service dates from 2014 through

2016. In December 2009, the All Source RFP was issued to the market. As a result, PacifiCorp signed an engineer, procure and

construct contract, subject to regulatory approval, for the approximately 637-MW Lake Side 2 natural gas-fired combined-cycle

generating facility, which is expected to be placed in service by June 2014. The Lake Side 2 generating facility will be constructed

adjacent to PacifiCorp's Lake Side generating facility, which is located in Vineyard, Utah, about 40 miles south of Salt Lake City.

PacifiCorp expects that the UPSC will issue an order approving the construction of Lake Side 2 in the spring of 2011. 

Demand-side Management 

PacifiCorp has provided a comprehensive set of DSM programs to its customers since the 1970s. The programs are designed to reduce

energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current

programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their

homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the

purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors,

process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to solicit participation in load

management programs by residential, business and agricultural customers through programs, such as PacifiCorp's residential and small

commercial air conditioner load control program and irrigation equipment load control programs. Although subject to prudence

reviews, state regulations allow for contemporaneous recovery of costs incurred for the DSM programs through state-specific energy

efficiency surcharges to retail customers or for recovery of costs through rates. In addition to these DSM programs, PacifiCorp has

load curtailment contracts with a number of large industrial customers that deliver up to 305 MW of load reduction when needed.

Recovery for the costs associated with the large industrial load management program is determined through PacifiCorp's general rate

case process. During 2010, $113 million was expended on PacifiCorp's DSM programs, resulting in an estimated 499,054 MWh of

first-year energy savings and an estimated 481 MW of peak load management. Total demand-side load available for control during

2010, including both load management from the large industrial curtailment contracts and DSM programs, was 718 MW.

Collateral and Contingent Features

PacifiCorp's senior secured and senior unsecured debt credit ratings are as follows:

Fitch Moody's Standard & Poor's

Senior secured debt A- A2 A

Senior unsecured debt BBB+ Baa1 AOutlook Stable Stable Stable

Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating

agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit

ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue

for any given period of time. 

PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings

is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the

maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates

under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also

increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or

exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings

on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.25
In accordance with industry practice, certain wholesale energy agreements, including derivative contracts, contain provisions that

require PacifiCorp to maintain specific credit ratings on its unsecured debt from one or more of the three recognized credit rating

agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other

security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features")

or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's

creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2010, PacifiCorp's credit ratings from the

three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance

provisions for these agreements, including derivative contracts, had been triggered as of December 31, 2010, PacifiCorp would have

been required to post $225 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to

market price volatility, changes in credit ratings, changes in legislation or regulation or other factors. Refer to Note 7 of Notes to

Financial Statements in this Form No. 1 for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative

contracts.

In July 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Reform Act"). The

Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms and

providing new enforcement powers to regulators. Virtually all major areas of the Reform Act, including collateral requirements on

derivative contracts, will be the subject of regulatory interpretation and implementation rules requiring rulemaking proceedings that

may take several years to complete. 

PacifiCorp is a party to derivative contracts, including over-the-counter derivative contracts. The Reform Act provides for extensive

new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing,

exchange trading, capital and margin requirements for "swap dealers" and "major swap participants." The Reform Act provides certain

exemptions from these regulations for commercial end-users that use derivatives to hedge and manage the commercial risk of their

businesses. Although PacifiCorp generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging

of commercial risk and does not believe it will be considered a swap dealer or major swap participant, the outcome of the rulemaking

proceedings cannot be predicted and, therefore, the impact of the Reform Act on PacifiCorp's financial results cannot be determined at

this time.

Coal Mines

PacifiCorp has interests in coal mines that support its coal-fired generating facilities. These mines supplied 29% and 31% of

PacifiCorp's total coal requirements during the years ended December 31, 2010 and 2009, respectively. The remaining coal

requirements are acquired through long- and short-term third-party contracts. PacifiCorp's mines are located adjacent to certain of its

coal-fired generating facilities, which significantly reduces overall transportation costs included in fuel expense. Most of PacifiCorp's

coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states

and private parties. The leases generally have multi-year terms that may be renewed or extended only with the consent of the lessor and

require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection

and reclamation standards be met during the course of mining operations and upon completion of mining activities.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.26
Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new

mining technology and changes in regulation and economic factors affecting the utilization of such reserves. Recoverable coal reserves

as of December 31, 2010, based on PacifiCorp's most recent engineering studies, were as follows (in millions):

Coal Mine Location Generating Facility Served Mining Method Recoverable Tons

Bridger Rock Springs, WY Jim Bridger Surface 51 (1)

Bridger Rock Springs, WY Jim Bridger Underground 43 (1)

Deer Creek Huntington, UT Huntington, Hunter and Carbon Underground 35 (2)

Trapper Craig, CO Craig Surface 46 (3)

175

(1) These coal reserves are leased and mined by Bridger Coal Company, ("Bridger Coal") a joint venture between PMI and a subsidiary of Idaho Power. PMI, a

wholly owned subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The amounts included above represent only PacifiCorp's two-thirds

interest in the coal reserves.

(2) These coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.

(3) These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp

has an ownership interest of 21%. The amount included above represents only PacifiCorp's 21% interest in the coal reserves. PacifiCorp does not operate

the Trapper Mine.

For surface mine operations, PacifiCorp removes the overburden with heavy earth-moving equipment, such as draglines and power

shovels. Once exposed, PacifiCorp drills, fractures and systematically removes the coal using haul trucks or conveyors to transport the

coal to the associated generating facility. PacifiCorp reclaims disturbed areas as part of its normal mining activities. After final coal

removal, draglines, power shovels, excavators or loaders are used to backfill the remaining pits with the overburden removed at the

beginning of the process. Once the overburden and topsoil have been replaced, vegetation and plant life are re-established, and other

improvements are made that have local community and environmental benefits. Draglines are used at the Bridger surface mine and

draglines with shovels and trucks are used at the Trapper surface mine. 

For underground mine operations, a longwall is used as a mechanical shearer to extract coal from long rectangular blocks of medium to

thick seams. In longwall mining, PacifiCorp also uses continuous miners to develop access to these long rectangular coal blocks.

Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face

of the coal seam, cutting the coal from the face. Chain conveyors then move the loosened coal to an underground mine conveyor

system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion.

PacifiCorp operates the Deer Creek, Bridger surface and Bridger underground coal mines, as well as the Cottonwood Preparatory Plant

and Wyodak Coal Crushing Facility. Refer below for further information about the coal mines and coal processing facilities that

PacifiCorp operates.

Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques

ranges from 50% to 70%. To meet applicable standards, PacifiCorp blends coal mined at its owned mines with contracted coal and

utilizes emissions reduction technologies for controlling sulfur dioxide and other emissions. For fuel needs at PacifiCorp's coal-fired

generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and

short-term contracts to supply its generating facilities with coal over their currently expected remaining useful lives. 

During the year ended December 31, 2010, PacifiCorp-owned coal-fired generating facilities held sufficient sulfur dioxide emission

allowances to comply with the EPA Title IV requirements.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.27
Coal Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

The operation of PacifiCorp's coal mines and coal processing facilities is regulated by MSHA under the Federal Mine Safety and

Health Act of 1977 ("Mine Safety Act"). MSHA inspects PacifiCorp's coal mines and coal processing facilities on a regular basis and

may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act.

For citations, monetary penalties are assessed by MSHA. Citations, notices and orders can be contested and appealed and the severity

and assessment of penalties may be reduced or, in some cases, dismissed through the appeal process. 

The table below summarizes the total number of citations, notices and orders issued and penalties assessed by MSHA for each coal

mine or coal processing facility operated by PacifiCorp under the indicated provisions of the Mine Safety Act during the three- and

six-month periods ended December 31, 2010. Legal actions pending before the Federal Mine Safety and Health Review Commission,

which are not exclusive to citations, notices, orders and penalties assessed by MSHA, are as of December 31, 2010. Closed or idled

mines have been excluded from the table below as no citations, orders or notices were issued for such mines during the three- and

six-month periods ended December 31, 2010. In addition, there were no fatalities at PacifiCorp's coal mines or coal processing

facilities during the three- and six-month periods ended December 31, 2010. 

Mine Safety Act

Total

Section Value of

Section 104(a) Section 107(a) Proposed

Significant & Section 104(d) Section Imminent Section MSHA Legal

Coal Mine or Substantial 104(b) Citations & 110(b)(2) Danger 104(e) Assessments Actions

Coal Processing Facility Citations(1) Orders(2) Orders(3) Citations(4) Orders(5) Notice(6) (in thousands) Pending

Three-month period ended 

December 31, 2010

Deer Creek 3 — — — — — $ 44 17

Bridger (surface) 2— — — — — 3 6

Bridger (underground) 7 — — — — — 48 17

Cottonwood Preparatory Plant —— — — — — ——

Wyodak Coal Crushing Facility 1 — — — — — — —

Six-month period ended 

December 31, 2010

Deer Creek 13 — 1 — — — $ 84 17

Bridger (surface) 4— — — — — 7 6

Bridger (underground) 16 — — — 1 — 90 17

Cottonwood Preparatory Plant —— — — — — ——

Wyodak Coal Crushing Facility 1 — — — — — — —

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.28
(1) For alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an

injury or illness of a reasonably serious nature.

(2) For alleged failure to totally abate the subject matter of a Mine Safety Act section 104(a) citation within the period specified in the citation.

(3) For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or

regulation.

(4) For alleged flagrant violations (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation of a mandatory health or safety

standard that substantially and proximately caused, or reasonably caused, or reasonably could have been expected to cause, death or serious bodily injury).

(5) The total number of imminent danger orders (i.e., the existence of any condition or practice in a coal or other mine which could reasonably be expected to

cause death or serious physical harm before such condition or practice can be abated).

(6) For a pattern, or the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature as could have significantly and

substantially contributed to the cause and effect of coal or other mine health or safety hazards.

ITEM 13. 

Officer & Director Changes

PacifiCorp discloses information for its "named executive officers" ("NEOs") consistent with Item 402 of Regulation S-K promulgated

by the SEC in its Annual Report on Form 10-K.

On January 13, 2010, A. Robert Lasich accepted the position of Vice President and General Counsel, Procurement for MEHC, and

accordingly resigned as President of PacifiCorp Energy, a business unit of PacifiCorp, and as director of PacifiCorp, both effective

February 1, 2010.

On January 13, 2010, Micheal G. Dunn was elected President of PacifiCorp Energy and director of PacifiCorp, both effective

February 1, 2010. Mr. Dunn previously served as President of Kern River Gas Transmission Company (“Kern River”) since

June 2007. Prior to that, Mr. Dunn served as Vice President of Operations, Information Technology and Engineering at Kern River.

Kern River is an indirect subsidiary of MEHC. 

ITEM 14.

Not applicable.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

FERC FORM NO. 1 (ED. 12-96) Page 109.29
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

X

Date of Report

(Mo, Da, Yr)

Year/Period of Report

End of

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line

No. Title of Account

(a)

Ref.

Page No.

(b)

Current Year

End of Quarter/Year

Balance

(c)

Prior Year

End Balance

12/31

(d)

PacifiCorp 04/18/2011 2010/Q4

 1 UTILITY PLANT

 2 Utility Plant (101-106, 114) 200-201 22,017,833,818 19,881,830,192

 3 Construction Work in Progress (107) 200-201 1,000,790,049 1,799,367,394

 4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 23,018,623,867 21,681,197,586

 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 200-201 7,467,085,584 7,199,824,404

 6 Net Utility Plant (Enter Total of line 4 less 5) 15,551,538,283 14,481,373,182

 7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0

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

 9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0

 10 Spent Nuclear Fuel (120.4) 0 0

 11 Nuclear Fuel Under Capital Leases (120.6) 0 0

 12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 202-203 0 0

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

 14 Net Utility Plant (Enter Total of lines 6 and 13) 15,551,538,283 14,481,373,182

 15 Utility Plant Adjustments (116) 0 0

 16 Gas Stored Underground - Noncurrent (117) 0 0

 17 OTHER PROPERTY AND INVESTMENTS

 18 Nonutility Property (121) 16,174,139 11,538,314

 19 (Less) Accum. Prov. for Depr. and Amort. (122) 1,214,176 1,421,418

 20 Investments in Associated Companies (123) 69,928 11,220,813

 21 Investment in Subsidiary Companies (123.1) 224-225 213,443,234 184,718,167

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

 23 Noncurrent Portion of Allowances 228-229 0 0

 24 Other Investments (124) 84,517,252 84,336,862

 25 Sinking Funds (125) 0 0

 26 Depreciation Fund (126) 0 0

 27 Amortization Fund - Federal (127) 0 0

 28 Other Special Funds (128) 4,236,855 6,945,599

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

 30 Long-Term Portion of Derivative Assets (175) 9,400,334 42,909,107

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

 32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 326,627,566 340,247,444

 33 CURRENT AND ACCRUED ASSETS

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

 35 Cash (131) 4,143,415 4,238,848

 36 Special Deposits (132-134) 603,868 610,443

 37 Working Fund (135) 1,720 1,920

 38 Temporary Cash Investments (136) 463,002 81,769,678

 39 Notes Receivable (141) 351,089 208,656

 40 Customer Accounts Receivable (142) 352,691,649 361,520,728

 41 Other Accounts Receivable (143) 62,682,797 32,319,952

 42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 7,517,126 7,052,112

 43 Notes Receivable from Associated Companies (145) 0 4,748,292

 44 Accounts Receivable from Assoc. Companies (146) 16,630,240 14,254,320

 45 Fuel Stock (151) 227 188,493,087 170,930,143

 46 Fuel Stock Expenses Undistributed (152) 227 0 0

 47 Residuals (Elec) and Extracted Products (153) 227 0 0

 48 Plant Materials and Operating Supplies (154) 227 186,406,158 178,147,022

 49 Merchandise (155) 227 0 0

 50 Other Materials and Supplies (156) 227 0 0

 51 Nuclear Materials Held for Sale (157) 202-203/227 0 0

 52 Allowances (158.1 and 158.2) 228-229 0 0

FERC FORM NO. 1 (REV. 12-03) Page 110
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

X

Date of Report

(Mo, Da, Yr)

Year/Period of Report

End of

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line

No. Title of Account

(a)

Ref.

Page No.

(b)

Current Year

End of Quarter/Year

Balance

(c)

Prior Year

End Balance

12/31

(d)

PacifiCorp 04/18/2011 2010/Q4

(Continued)

 53 (Less) Noncurrent Portion of Allowances 0 0

 54 Stores Expense Undistributed (163) 227 0 0

 55 Gas Stored Underground - Current (164.1) 0 0

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

 57 Prepayments (165) 392,988,760 298,656,263

 58 Advances for Gas (166-167) 0 0

 59 Interest and Dividends Receivable (171) 6,674 8,788

 60 Rents Receivable (172) 1,535,228 2,772,053

 61 Accrued Utility Revenues (173) 205,559,000 213,989,000

 62 Miscellaneous Current and Accrued Assets (174) 0 0

 63 Derivative Instrument Assets (175) 123,801,642 151,143,601

 64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 9,400,334 42,909,107

 65 Derivative Instrument Assets - Hedges (176) 0 0

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

 67 Total Current and Accrued Assets (Lines 34 through 66) 1,519,440,869 1,465,358,488

 68 DEFERRED DEBITS

 69 Unamortized Debt Expenses (181) 33,300,472 35,978,910

 70 Extraordinary Property Losses (182.1) 230a 0 0

 71 Unrecovered Plant and Regulatory Study Costs (182.2) 230b 135,566 5,289,133

 72 Other Regulatory Assets (182.3) 232 1,737,446,767 1,550,913,652

 73 Prelim. Survey and Investigation Charges (Electric) (183) 2,895,724 3,116,069

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

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

 76 Clearing Accounts (184) 0 0

 77 Temporary Facilities (185) 90,676 89,891

 78 Miscellaneous Deferred Debits (186) 233 86,483,361 67,302,539

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

 80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0

 81 Unamortized Loss on Reaquired Debt (189) 11,446,745 13,778,067

 82 Accumulated Deferred Income Taxes (190) 234 588,589,916 587,517,758

 83 Unrecovered Purchased Gas Costs (191) 0 0

 84 Total Deferred Debits (lines 69 through 83) 2,460,389,227 2,263,986,019

 85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 19,857,995,945 18,550,965,133

FERC FORM NO. 1 (REV. 12-03) Page 111
Schedule Page: 110 Line No.: 21 Column: c

Refer to Note 2 of Notes to Financial Statements in this Form No. 1 for discussion of the consolidation of Pacific Minerals, Inc.

("PMI") beginning January 1, 2010.

Schedule Page: 110 Line No.: 43 Column: c

Refer to Note 2 of Notes to Financial Statements in this Form No. 1 for discussion of the consolidation of PMI beginning January 1,

2010.

Schedule Page: 110 Line No.: 57 Column: c

As of December 31, 2010, account 165 Prepayments included $344,671,476 in income taxes receivable from MidAmerican Energy

Holdings Company, PacifiCorp's indirect parent company. Refer to Note 12 of Notes to Financial Statements in this Form No. 1 for

discussion of bonus depreciation guidance issued by the Internal Revenue Service in March 2011.

Schedule Page: 110 Line No.: 57 Column: d

As of December 31, 2009, account 165 Prepayments included $249,055,093 in income taxes receivable from MidAmerican Energy

Holdings Company, PacifiCorp's indirect parent company.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report is: Year/Period of Report

(1) An Original

(2) A Resubmission

x

Date of Report

(mo, da, yr)

end of

Line

No. Title of Account

(a)

Ref.

Page No.

(b)

Current Year

End of Quarter/Year

Balance

(c)

Prior Year

End Balance

12/31

(d)

PacifiCorp 04/18/2011 2010/Q4

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

 1 PROPRIETARY CAPITAL

 2 Common Stock Issued (201) 250-251 3,417,945,896 3,417,945,896

 3 Preferred Stock Issued (204) 250-251 40,733,100 41,463,300

 4 Capital Stock Subscribed (202, 205) 0 0

 5 Stock Liability for Conversion (203, 206) 0 0

 6 Premium on Capital Stock (207) 0 0

 7 Other Paid-In Capital (208-211) 253 1,102,229,981 1,002,063,956

 8 Installments Received on Capital Stock (212) 252 0 0

 9 (Less) Discount on Capital Stock (213) 254 0 0

 10 (Less) Capital Stock Expense (214) 254b 41,284,560 41,288,207

 11 Retained Earnings (215, 215.1, 216) 118-119 2,792,155,606 2,225,701,346

 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 6,232,713 8,330,470

 13 (Less) Reaquired Capital Stock (217) 250-251 0 0

 14 Noncorporate Proprietorship (Non-major only) (218) 0 0

 15 Accumulated Other Comprehensive Income (219) 122(a)(b) -6,961,899 -5,819,577

 16 Total Proprietary Capital (lines 2 through 15) 7,311,050,837 6,648,397,184

 17 LONG-TERM DEBT

 18 Bonds (221) 256-257 6,357,741,000 6,372,343,000

 19 (Less) Reaquired Bonds (222) 256-257 0 0

 20 Advances from Associated Companies (223) 256-257 0 0

 21 Other Long-Term Debt (224) 256-257 0 0

 22 Unamortized Premium on Long-Term Debt (225) 32,845 35,563

 23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 14,381,234 15,413,483

 24 Total Long-Term Debt (lines 18 through 23) 6,343,392,611 6,356,965,080

 25 OTHER NONCURRENT LIABILITIES

 26 Obligations Under Capital Leases - Noncurrent (227) 55,883,528 57,295,450

 27 Accumulated Provision for Property Insurance (228.1) 0 0

 28 Accumulated Provision for Injuries and Damages (228.2) 8,499,000 7,487,871

 29 Accumulated Provision for Pensions and Benefits (228.3) 502,064,476 592,543,110

 30 Accumulated Miscellaneous Operating Provisions (228.4) 39,343,745 41,878,303

 31 Accumulated Provision for Rate Refunds (229) 0 0

 32 Long-Term Portion of Derivative Instrument Liabilities 399,481,536 409,727,110

 33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 0

 34 Asset Retirement Obligations (230) 105,328,750 102,516,932

 35 Total Other Noncurrent Liabilities (lines 26 through 34) 1,110,601,035 1,211,448,776

 36 CURRENT AND ACCRUED LIABILITIES

 37 Notes Payable (231) 36,000,000 0

 38 Accounts Payable (232) 472,504,319 539,268,266

 39 Notes Payable to Associated Companies (233) 0 0

 40 Accounts Payable to Associated Companies (234) 19,893,492 13,729,206

 41 Customer Deposits (235) 39,611,243 31,895,824

 42 Taxes Accrued (236) 262-263 48,804,714 46,747,021

 43 Interest Accrued (237) 115,234,368 111,568,228

 44 Dividends Declared (238) 512,462 520,947

 45 Matured Long-Term Debt (239) 0 0

FERC FORM NO. 1 (rev. 12-03) Page 112
Name of Respondent This Report is: Year/Period of Report

(1) An Original

(2) A Resubmission

x

Date of Report

(mo, da, yr)

end of

Line

No. Title of Account

(a)

Ref.

Page No.

(b)

Current Year

End of Quarter/Year

Balance

(c)

Prior Year

End Balance

12/31

(d)

PacifiCorp 04/18/2011 2010/Q4

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

 46 Matured Interest (240) 0 0

 47 Tax Collections Payable (241) 16,587,742 15,796,380

 48 Miscellaneous Current and Accrued Liabilities (242) 64,738,616 63,197,166

 49 Obligations Under Capital Leases-Current (243) 1,369,860 1,725,318

 50 Derivative Instrument Liabilities (244) 483,234,721 494,721,339

 51 (Less) Long-Term Portion of Derivative Instrument Liabilities 399,481,536 409,727,110

 52 Derivative Instrument Liabilities - Hedges (245) 0 0

 53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0

 54 Total Current and Accrued Liabilities (lines 37 through 53) 899,010,001 909,442,585

 55 DEFERRED CREDITS

 56 Customer Advances for Construction (252) 18,492,298 20,946,236

 57 Accumulated Deferred Investment Tax Credits (255) 266-267 41,949,428 45,888,892

 58 Deferred Gains from Disposition of Utility Plant (256) 0 0

 59 Other Deferred Credits (253) 269 51,492,025 40,157,480

 60 Other Regulatory Liabilities (254) 278 59,611,213 64,164,255

 61 Unamortized Gain on Reaquired Debt (257) 0 0

 62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 11,642,708 0

 63 Accum. Deferred Income Taxes-Other Property (282) 3,330,234,891 2,802,655,179

 64 Accum. Deferred Income Taxes-Other (283) 680,518,898 450,899,466

 65 Total Deferred Credits (lines 56 through 64) 4,193,941,461 3,424,711,508

 66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 19,857,995,945 18,550,965,133

FERC FORM NO. 1 (rev. 12-03) Page 113
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF INCOME

PacifiCorp X

04/18/2011

2010/Q4

Line

(a) (b) (c)

Title of Account

No.

Total

Current Year to

Date Balance for

Quarter/Year

(d)

(Ref.)

Page No.

Quarterly

1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the

data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.

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

3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)

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

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

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

5. If additional columns are needed, place them in a footnote.

Annual or Quarterly if 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.

Current 3 Months

Ended

Quarterly Only

No 4th Quarter

(e)

Prior 3 Months

Ended

Quarterly Only

No 4th Quarter

(f)

Total

Prior Year to

Date Balance for

Quarter/Year

 1 UTILITY OPERATING INCOME

 2 Operating Revenues (400) 300-301 4,402,215,385 4,353,766,380

 3 Operating Expenses

 4 Operation Expenses (401) 320-323 2,277,135,354 2,279,099,664

 5 Maintenance Expenses (402) 320-323 414,960,789 394,816,343

 6 Depreciation Expense (403) 336-337 501,224,256 473,163,461

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

 8 Amort. & Depl. of Utility Plant (404-405) 336-337 34,838,293 32,391,772

 9 Amort. of Utility Plant Acq. Adj. (406) 336-337 5,518,393 5,479,353

 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 4,523,779 5,149,968

 11 Amort. of Conversion Expenses (407)

 12 Regulatory Debits (407.3) -2,004,224 1,549,004

 13 (Less) Regulatory Credits (407.4)

 14 Taxes Other Than Income Taxes (408.1) 262-263 136,550,272 123,877,487

 15 Income Taxes - Federal (409.1) 262-263 -517,806,480 -472,156,577

 16 - Other (409.1) 262-263 -4,449,586 -2,026,201

 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 1,254,766,756 1,368,522,890

 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 551,088,560 688,511,583

 19 Investment Tax Credit Adj. - Net (411.4) 266 -1,874,204 -1,874,204

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

 21 Losses from Disp. of Utility Plant (411.7)

 22 (Less) Gains from Disposition of Allowances (411.8) 2,817,551 3,790,891

 23 Losses from Disposition of Allowances (411.9)

 24 Accretion Expense (411.10) 96,470

 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 3,549,573,757 3,515,690,486

 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 852,641,628 838,075,894

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF INCOME FOR THE YEAR (Continued)

PacifiCorp X

04/18/2011

2010/Q4

 Previous Year to Date Line

(in dollars)

(g) (j) (k)

ELECTRIC UTILITY

No.

Current Year to Date

(in dollars)

OTHER UTILITY

(l)

GAS UTILITY

Previous Year to Date

(in dollars)

Current Year to Date

(in dollars)

Previous Year to Date

(in dollars)

Current Year to Date

(in dollars)

(h) (i)

9. Use page 122 for important notes regarding the statement of income for any account thereof.

10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to 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.

 1

 4,402,215,385 4,353,766,380 2

 3

 2,277,135,354 2,279,099,664 4

 414,960,789 394,816,343 5

 501,224,256 473,163,461 6

 7

 34,838,293 32,391,772 8

 5,518,393 5,479,353 9

 4,523,779 5,149,968 10

 11

 -2,004,224 1,549,004 12

 13

 136,550,272 123,877,487 14

 -517,806,480 -472,156,577 15

 -4,449,586 -2,026,201 16

 1,254,766,756 1,368,522,890 17

 551,088,560 688,511,583 18

 -1,874,204 -1,874,204 19

 20

 21

 2,817,551 3,790,891 22

 23

 96,470 24

 3,549,573,757 3,515,690,486 25

 852,641,628 838,075,894 26

FERC FORM NO. 1 (ED. 12-96) Page 115
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF INCOME FOR THE YEAR (continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 Previous Year

(a) (b) (c)

Title of Account

No.

Current Year

TOTAL

(d)

(Ref.)

Page No.

Current 3 Months

Ended

Quarterly Only

No 4th Quarter

(e)

Prior 3 Months

Ended

Quarterly Only

No 4th Quarter

(f)

 27 Net Utility Operating Income (Carried forward from page 114) 852,641,628 838,075,894

 28 Other Income and Deductions

 29 Other Income

 30 Nonutilty Operating Income

 31 Revenues From Merchandising, Jobbing and Contract Work (415) 1,416,581 1,526,343

 32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 1,362,155 1,518,065

 33 Revenues From Nonutility Operations (417) 247,917 241,243

 34 (Less) Expenses of Nonutility Operations (417.1) 81,037 28,326

 35 Nonoperating Rental Income (418) 91,251 74,959

 36 Equity in Earnings of Subsidiary Companies (418.1) 119 -2,097,757 1,811,740

 37 Interest and Dividend Income (419) 5,077,391 20,556,977

 38 Allowance for Other Funds Used During Construction (419.1) 79,298,238 63,955,322

 39 Miscellaneous Nonoperating Income (421) 27,081,235 32,225,273

 40 Gain on Disposition of Property (421.1) 2,617,525 2,267,272

 41 TOTAL Other Income (Enter Total of lines 31 thru 40) 112,289,189 121,112,738

 42 Other Income Deductions

 43 Loss on Disposition of Property (421.2) 46,470 82,456

 44 Miscellaneous Amortization (425) 1,285,816 1,263,905

 45 Donations (426.1) 2,676,885 2,997,500

 46 Life Insurance (426.2) -4,971,828 -5,605,297

 47 Penalties (426.3) -418,323 400,132

 48 Exp. for Certain Civic, Political & Related Activities (426.4) 2,284,308 1,519,511

 49 Other Deductions (426.5) 29,828,972 34,666,110

 50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 30,732,300 35,324,317

 51 Taxes Applic. to Other Income and Deductions

 52 Taxes Other Than Income Taxes (408.2) 262-263 367,905 576,313

 53 Income Taxes-Federal (409.2) 262-263 28,723,272 29,005,691

 54 Income Taxes-Other (409.2) 262-263 3,903,016 3,941,391

 55 Provision for Deferred Inc. Taxes (410.2) 234, 272-277 85,258,308 99,093,919

 56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234, 272-277 85,411,869 99,416,511

 57 Investment Tax Credit Adj.-Net (411.5)

 58 (Less) Investment Tax Credits (420) 2,065,260 2,065,260

 59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 30,775,372 31,135,543

 60 Net Other Income and Deductions (Total of lines 41, 50, 59) 50,781,517 54,652,878

 61 Interest Charges

 62 Interest on Long-Term Debt (427) 363,203,396 369,236,117

 63 Amort. of Debt Disc. and Expense (428) 3,727,614 3,786,241

 64 Amortization of Loss on Reaquired Debt (428.1) 2,331,323 2,785,112

 65 (Less) Amort. of Premium on Debt-Credit (429) 2,718 2,718

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

 67 Interest on Debt to Assoc. Companies (430)

 68 Other Interest Expense (431) 12,367,152 10,264,106

 69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 44,618,458 35,186,532

 70 Net Interest Charges (Total of lines 62 thru 69) 337,008,309 350,882,326

 71 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 566,414,836 541,846,446

 72 Extraordinary Items

 73 Extraordinary Income (434)

 74 (Less) Extraordinary Deductions (435)

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

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

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

 78 Net Income (Total of line 71 and 77) 566,414,836 541,846,446

FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
Schedule Page: 114 Line No.: 6 Column: c

Depreciation expense associated with transportation equipment is generally charged to operations and maintenance expense and

construction work in progress. During the years ended December 31, 2010 and 2009, depreciation expense associated with

transportation equipment was $14,065,119 and $13,886,246, respectively.

Schedule Page: 114 Line No.: 7 Column: c

Generally, PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.

Schedule Page: 114 Line No.: 12 Column: c

For a additional information regarding the Powerdale hydroelectric generating facility, refer to Important Changes During the

Quarter/Year, Item 12 of this Form No. 1. The net credit position reflected in account 407.3, Regulatory Debits, primarily represents a

true-up to regulatory assets based on currently approved state commission orders for the decommissioning and removal of the

Powerdale hydroelectric generating facility. 

Schedule Page: 114 Line No.: 14 Column: c

Payroll taxes are generally charged to operations and maintenance expense and construction work in progress. During the years ended

December 31, 2010 and 2009, payroll taxes were $39,760,547 and $38,397,330, respectively.

Schedule Page: 114 Line No.: 15 Column: c

The following presents PacifiCorp's total income tax expense for the years ended December 31, 2010 and 2009. Individual expenses

are referenced back to the respective line number on pages 114 - 117. Refer to Note 12 of Notes to Financial Statements in this Form

No. 1 for discussion of bonus depreciation guidance issued by the Internal Revenue Service in March 2011.

 Years Ended December 31, 

Line No. 2010 2009 

15 Income Taxes - Federal (409.1) $ (517,806,480) (a) $ (472,156,577) (b) 

16 - Other (409.1) (4,449,586) (a) (2,026,201) (b) 

17 Provision for Deferred Income Taxes (410.1) 1,254,766,756 1,368,522,890 

18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 551,088,560 688,511,583 

19 Investment Tax Credit Adj. - Net (411.4) (1,874,204) (1,874,204)

53 Income Taxes-Federal (409.2) 28,723,272 29,005,691 

54 Income Taxes-Other (409.2) 3,903,016 3,941,391 

55 Provision for Deferred Income Taxes (410.2) 85,258,308 99,093,919 

56 (Less) Provision for Deferred Income Taxes-Cr (411.2) 85,411,869 99,416,511 

58 (Less) Investment Tax Credits (420) 2,065,260 2,065,260

Total Income Tax Expense $ 209,955,393 $ 234,513,555 

 (a) The net credit position reflected in account 409.1, Income taxes is primarily due to bonus depreciation. 

 (b) The net credit position reflected in account 409.1, Income taxes is primarily due to bonus depreciation and repairs deduction. 

Schedule Page: 114 Line No.: 24 Column: c

Generally, Pacificorp records the accretion expense of asset retirement obligations as either a regulatory asset or liability.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF RETAINED EARNINGS

PacifiCorp X

04/18/2011

2010/Q4

Line

Current

Quarter/Year

Year to Date

Balance

(a) (b) (c)

Item

Contra Primary

No.

Account Affected

1. Do not report Lines 49-53 on the quarterly version.

2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and 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.

Previous

Quarter/Year

Year to Date

Balance

(d)

UNAPPROPRIATED RETAINED EARNINGS (Account 216)

 1 Balance-Beginning of Period 2,222,125,535 1,684,184,571

 2 Changes

 3 Adjustments to Retained Earnings (Account 439)

 4

 5

 6

 7

 8

 9 TOTAL Credits to Retained Earnings (Acct. 439)

 10

 11

 12

 13

 14

 15 TOTAL Debits to Retained Earnings (Acct. 439)

 16 Balance Transferred from Income (Account 433 less Account 418.1) 568,512,593 540,034,706

 17 Appropriations of Retained Earnings (Acct. 436)

 18

 19

 20

 21

 22 TOTAL Appropriations of Retained Earnings (Acct. 436)

 23 Dividends Declared-Preferred Stock (Account 437)

 24 Preferred Stock, various series and rates 238 -2,058,333 ( 2,083,790)

 25

 26

 27

 28

 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437) -2,058,333 ( 2,083,790)

 30 Dividends Declared-Common Stock (Account 438)

 31

 32

 33

 34

 35

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

 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings ( 9,952)

 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 2,788,579,795 2,222,125,535

APPROPRIATED RETAINED EARNINGS (Account 215)

 39

 40

FERC FORM NO. 1/3-Q (REV. 02-04) Page 118
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF RETAINED EARNINGS

PacifiCorp X

04/18/2011

2010/Q4

Line

Current

Quarter/Year

Year to Date

Balance

(a) (b) (c)

Item

Contra Primary

No.

Account Affected

1. Do not report Lines 49-53 on the quarterly version.

2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and 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.

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) 3,575,811 3,575,811

 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 3,575,811 3,575,811

 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) 2,792,155,606 2,225,701,346

UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account

Report only on an Annual Basis, no Quarterly

 49 Balance-Beginning of Year (Debit or Credit) 8,330,470 6,508,778

 50 Equity in Earnings for Year (Credit) (Account 418.1) -2,097,757 1,811,740

 51 (Less) Dividends Received (Debit)

 52 Transfers to Unappropriated Retained Earnings (Account 216) 9,952

 53 Balance-End of Year (Total lines 49 thru 52) 6,232,713 8,330,470

FERC FORM NO. 1/3-Q (REV. 02-04) Page 119
Schedule Page: 118 Line No.: 24 Column: c

Dividends on preferred stock during the year ended December 31, 2010 were as follows:

Shares Dividend

4.52% Serial Preferred 2,065 $ 9,334 

4.56% Serial Preferred 81,326 374,570 

4.72% Serial Preferred 65,854 315,593 

5.00% Serial Preferred 41,908 209,540 

5.40% Serial Preferred 65,959 356,179 

6.00% Serial Preferred 5,930 35,580 

7.00% Serial Preferred 18,046 126,322 

5.00% Preferred 126,243 631,215 

 407,331 $ 2,058,333 

Schedule Page: 118 Line No.: 24 Column: d

Dividends on preferred stock during the year ended December 31, 2009 were as follows:

Shares Dividend

4.52% Serial Preferred 2,065 $ 9,334 

4.56% Serial Preferred 84,592 385,739 

4.72% Serial Preferred 69,890 329,881 

5.00% Serial Preferred 41,908 209,540 

5.40% Serial Preferred 65,959 356,179 

6.00% Serial Preferred 5,930 35,580 

7.00% Serial Preferred 18,046 126,322 

5.00% Preferred 126,243 631,215 

 414,633 $ 2,083,790 

Schedule Page: 118 Line No.: 31 Column: a

For information regarding common stock dividends declared, refer to Important Changes During the Quarter/Year, Item 6 and Note 15

of Notes to Financial Statements in this Form No. 1.

Schedule Page: 118 Line No.: 47 Column: c

The balance in account 215.1 Appropriated retained earnings - amortization reserve, federal is due to requirements of certain

hydroelectric relicensing projects.

Schedule Page: 118 Line No.: 47 Column: d

See footnote for column (c) line 47.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

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

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF CASH FLOWS

PacifiCorp X

04/18/2011

2010/Q4

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

Quarter/Year

(b) (a)

No.

Previous Year to Date

Quarter/Year

(c)

 1 Net Cash Flow from Operating Activities:

 2 Net Income (Line 78(c) on page 117) 566,414,836 541,846,446

 3 Noncash Charges (Credits) to Income:

 4 Depreciation and Depletion 517,014,250 492,861,350

 5 Amortization: 44,162,057 45,834,002

 6

 7 Unrealized (Gains)/Losses on Derivative Contracts -1,892,323 726,000

 8 Deferred Income Taxes (Net) 703,524,635 679,678,715

 9 Investment Tax Credit Adjustment (Net) -3,939,464 -3,939,464

 10 Net (Increase) Decrease in Receivables -13,328,543 -7,140,528

 11 Net (Increase) Decrease in Inventory -25,822,080 -41,858,225

 12 Net (Increase) Decrease in Allowances Inventory

 13 Net Increase (Decrease) in Payables and Accrued Expenses -130,489,533 -33,318,429

 14 Net (Increase) Decrease in Other Regulatory Assets 8,890,615 12,441,383

 15 Net Increase (Decrease) in Other Regulatory Liabilities -4,813,321 -6,970,542

 16 (Less) Allowance for Other Funds Used During Construction 79,298,238 63,955,322

 17 (Less) Undistributed Earnings from Subsidiary Companies -2,097,757 1,811,740

 18 Amounts Due To/From Affiliates (Net) -90,231,534 -216,306,739

 19 Derivative Collateral (Net) -102,246,009 57,400,001

 20 Other Operating Activities: 22,143,762 16,989,197

 21

 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 1,412,186,867 1,472,476,105

 23

 24 Cash Flows from Investment Activities:

 25 Construction and Acquisition of Plant (including land):

 26 Gross Additions to Utility Plant (less nuclear fuel) -1,686,214,575 -2,356,195,937

 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 -79,298,238 -63,955,322

 31 Other (provide details in footnote):

 32

 33

 34 Cash Outflows for Plant (Total of lines 26 thru 33) -1,606,916,337 -2,292,240,615

 35

 36 Acquisition of Other Noncurrent Assets (d)

 37 Proceeds from Disposal of Noncurrent Assets (d) 7,282,766 1,274,203

 38

 39 Investments in and Advances to Assoc. and Subsidiary Companies -13,402,178

 40 Contributions and Advances from Assoc. and Subsidiary Companies 4,643,134

 41 Disposition of Investments in (and Advances to)

 42 Associated and Subsidiary Companies

 43

 44 Purchase of Investment Securities (a) -269,354

 45 Proceeds from Sales of Investment Securities (a) 458,430

FERC FORM NO. 1 (ED. 12-96) Page 120
(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.

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STATEMENT OF CASH FLOWS

PacifiCorp X

04/18/2011

2010/Q4

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

Quarter/Year

(b) (a)

No.

Previous Year to Date

Quarter/Year

(c)

 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 Investing Activities: 2,401,475 3,540,757

 54

 55

 56 Net Cash Provided by (Used in) Investing Activities

 57 Total of lines 34 thru 55) -1,610,634,274 -2,282,593,445

 58

 59 Cash Flows from Financing Activities:

 60 Proceeds from Issuance of:

 61 Long-Term Debt (b) 982,802,997

 62 Preferred Stock

 63 Common Stock

 64 Equity Contribution 100,000,000 125,000,000

 65

 66 Net Increase in Short-Term Debt (c) 35,999,320

 67 Other (provide details in footnote):

 68

 69

 70 Cash Provided by Outside Sources (Total 61 thru 69) 135,999,320 1,107,802,997

 71

 72 Payments for Retirement of:

 73 Long-term Debt (b) -14,602,000 -138,454,000

 74 Preferred Stock -560,528

 75 Common Stock

 76 Other (provide details in footnote):

 77 Repayment of Capital Lease Obligations -1,724,876 -5,811,642

 78 Net Decrease in Short-Term Debt (c) -84,991,027

 79

 80 Dividends on Preferred Stock -2,066,818 -2,083,790

 81 Dividends on Common Stock

 82 Net Cash Provided by (Used in) Financing Activities

 83 (Total of lines 70 thru 81) 117,045,098 876,462,538

 84

 85 Net Increase (Decrease) in Cash and Cash Equivalents

 86 (Total of lines 22,57 and 83) -81,402,309 66,345,198

 87

 88 Cash and Cash Equivalents at Beginning of Period 86,010,446 19,665,248

 89

 90 Cash and Cash Equivalents at End of period 4,608,137 86,010,446

FERC FORM NO. 1 (ED. 12-96) Page 121
Schedule Page: 120 Line No.: 4 Column: b

Includes depreciation expense associated with transportation equipment and capital lease assets of $15,789,994 and $19,697,889

during the years ended December 31, 2010 and 2009, respectively.

Schedule Page: 120 Line No.: 5 Column: a

 Years Ended December 31, 

 2010 2009 

Amortization of software development & other intangibles $ 34,838,293 $ 32,391,772

Amortization of hydroelectric relicensing costs 1,285,816 1,263,905

Amortization of electric plant acquisition adjustments 5,518,393 5,479,353

Amortization of regulatory assets 2,519,555 6,698,972

 $ 44,162,057 $ 45,834,002 

Schedule Page: 120 Line No.: 20 Column: a

 Years Ended December 31, 

 2010 2009 

Coal & steam depreciation & depletion included in cost of fuel $ 12,685,957 $ 13,212,110

(Gain)/loss on sale of property (2,992,914) (2,357,000)

Write-off of assets under construction 8,670,990 4,489,364

Other 3,779,729 1,644,723

 $ 22,143,762 $ 16,989,197

Schedule Page: 120 Line No.: 22 Column: c

Certain amounts in the prior year financial statements have been reclassified to conform to the current year presentation.

Schedule Page: 120 Line No.: 37 Column: b

Represents proceeds from disposal of fixed assets.

Schedule Page: 120 Line No.: 37 Column: c

Represents proceeds from disposal of fixed assets.

Schedule Page: 120 Line No.: 53 Column: a

 Years Ended December 31, 

 2010 2009 

Other investments/special funds $ (371,886) $ 1,020,004

Temporary facilities (785) (1,062)

Restricted cash 2,730,061 2,521,815

Net cash as a result of consolidation of PMI (1) 44,085 -

 $ 2,401,475 $ 3,540,757

(1) As discussed in Note 2 of Notes to Financial Statements in this Form No. 1, Pacific Minerals, Inc. ("PMI"), a wholly owned

subsidiary of PacifiCorp, was consolidated for FERC reporting purposes on a prospective basis beginning January 1, 2010.

Schedule Page: 120 Line No.: 57 Column: c

Certain amounts in the prior year financial statements have been reclassified to conform to the current year presentation. 

Schedule Page: 120 Line No.: 74 Column: b

For a discussion of PacifiCorp's preferred stock purchase, refer to Important Changes During the Quarter/Year, Item 6 and Note 14 of

Notes to Financial Statements in this Form No. 1.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report Year/Period of Report

End of

NOTES TO FINANCIAL STATEMENTS

PacifiCorp X

04/18/2011 2010/Q4

PAGE 122 INTENTIONALLY LEFT BLANK

SEE PAGE 123 FOR REQUIRED INFORMATION.

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

FERC FORM NO. 1 (ED. 12-96) Page 122
PACIFICORP AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS

(1) Organization and Operations

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric company serving 1.7 million retail

customers, including residential, commercial, industrial and other customers in portions of the states of Utah, Oregon, Wyoming,

Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and

geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the

wholesale market with public and private utilities, energy marketing companies and incorporated municipalities. PacifiCorp is subject

to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining

and environmental remediation services. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company ("MEHC"),

a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. MEHC is a

consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

(2) Summary of Significant Accounting Policies

Basis of Presentation

These financial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commission (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 accounting principles generally accepted in the United States of America ("GAAP"). These notes include

disclosures required by GAAP adjusted to the FERC basis of presentation and include specific information requested by the FERC. 

The following are the significant differences between the FERC accounting and reporting standards and GAAP.

Investments in Subsidiaries

PacifiCorp accounts for its investment in PacifiCorp Environmental Remediation Company ("PERCo") using the equity

method rather than consolidating the assets, liabilities, revenues and expenses of PERCo as required by GAAP. GAAP

requires that entities in which a company holds a controlling financial interest be consolidated. The accounting for the

investment in PERCo using the equity method rather than the consolidation method in accordance with GAAP has no effect

on net income or retained earnings.

Costs of Removal

Estimated removal costs that are recovered through approved depreciation rates, but that do not meet the requirements of a

legal asset retirement obligation ("ARO"), are reflected in the cost of removal regulatory liability under GAAP and as

accumulated depreciation under the FERC accounting and reporting standards.

Income Taxes

Accumulated deferred income taxes are classified as current and non-current on the balance sheet for GAAP. Under the

FERC accounting and reporting standards, accumulated deferred income taxes are classified as gross non-current assets and

gross non-current liabilities. Additionally, there are certain presentational differences between FERC and GAAP for amounts

related to unrecognized tax benefits associated with temporary differences in accordance with FERC Docket No. AI07-2-000,

"Accounting and Financial Reporting for Uncertainty in Income Taxes."

Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as

interest income, interest expense and penalties under the FERC accounting and reporting standards.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.1
Unrealized Gains and Losses on Derivative Instruments

Under the FERC accounting and reporting standards, unrealized gains and losses on derivative instruments that are not

recorded as a net regulatory asset or accumulated other comprehensive income ("AOCI") are presented on a gross basis on the

Statement of Income as miscellaneous nonoperating income for unrealized gains and as other deductions for unrealized losses

in accordance with FERC Order 627, "Accounting and Reporting of Financial Instruments, Comprehensive Income,

Derivatives and Hedging Activities." For GAAP, unrealized gains and losses on energy derivative contracts not held for

trading purposes and that are not recorded as a net regulatory asset or AOCI are presented on the Statement of Income as

revenues for sales contracts and as energy costs and operating expense for purchase and financial swap energy contracts.

Reclassifications

Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to conform

to the FERC basis of presentation. These reclassifications had no effect on net income.

Use of Estimates in Preparation of Financial Statements

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that

affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and

expenses during the period. These estimates include, but are not limited to, unbilled revenue; valuation of certain financial assets and

liabilities, including derivative contracts; effects of regulation; accounting for contingencies, including environmental and regulatory

matters; income taxes; AROs; and certain assumptions made in accounting for pension and other postretirement benefits. Actual results

may differ from the estimates used in preparing the financial statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the

economic effects of regulation. Accordingly, PacifiCorp is required to defer the recognition of certain costs or income if it is probable

that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. 

PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and

liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates

from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limit

PacifiCorp's ability to recover its costs. Based upon this continuous evaluation, PacifiCorp believes the application of the guidance for

regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The

evaluation reflects the current political and regulatory climate at both the federal and state levels and is subject to change in the future.

If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and

liabilities will be written off to net income, returned to customers or re-established as AOCI.

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market

participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction

prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation

techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer

a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an

exchange and not under duress. Nonperformance or credit risk is considered when determining the fair value of assets and liabilities.

Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates

of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market

exchange.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.2
Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in United States Treasury Bills, money market funds and other investments with a maturity

of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal

requirements, loan agreements or other contractual provisions. Restricted amounts are included in other special funds and special

deposits on the Comparative Balance Sheet. Total cash and cash equivalents were as follows as of December 31 (in millions):

2010 2009

Cash (131) $ 4 $ 4

Working funds (135) - -

Temporary cash investments (136) 1 82

Total cash and cash equivalents $ 5 $ 86

Allowance for Doubtful Accounts

Accounts receivable are stated at the outstanding principal amount, net of estimated allowances for doubtful accounts. The allowance

for doubtful accounts is based on PacifiCorp's assessment of the collectibility of amounts owed to PacifiCorp by its customers. This

assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. The change in the

balance of the allowance for doubtful accounts, which is included in accumulated provision for uncollectible accounts on the

Comparative Balance Sheet is summarized as follows for the years ended December 31 (in millions):

2010 2009

Beginning balance $ 7 $ 9

Charged to operation expenses, net 12 12

Write-offs, net (11) (14)

Ending balance $ 8 $ 7

Derivatives

PacifiCorp employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to

manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the

Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value unless they are designated as normal

purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under

master netting arrangements with counterparties and cash collateral paid or received under such agreements. 

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for

and may be designated as normal purchases and normal sales. Normal purchases or normal sales contracts are not marked-to-market

and settled amounts are recognized as operating revenues or operation expenses on the Statement of Income. 

For PacifiCorp's derivatives designated as hedging contracts, PacifiCorp formally assesses, at inception and thereafter, whether the

hedging contract is highly effective in offsetting changes in the hedged item. PacifiCorp formally documents hedging activity by

transaction type and risk management strategy.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.3
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are

included on the Statements of Accumulated Comprehensive Income, Comprehensive Income, and Hedging Activities as AOCI, net of

tax, until the contract settles and the hedged item is recognized in earnings. PacifiCorp discontinues hedge accounting prospectively

when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the

hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as

an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses

related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged

item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time

associated deferred amounts in AOCI will be immediately recognized in earnings.

For PacifiCorp's derivatives not designated as hedging contracts, the settled amount is generally included in rates. Accordingly,

changes in the fair value of a derivative contract that are probable of inclusion in rates are recorded as net regulatory assets. For a

derivative contract not probable of inclusion in rates and not designated as a hedging contract, changes in the fair value are recognized

in earnings.

Inventories

Inventories consist of materials and supplies, coal stocks, natural gas and fuel oil, which are stated at the lower of average cost or

market. 

Net Utility Plant

 General

Additions to utility plant are recorded at cost. PacifiCorp capitalizes all construction related material, direct labor and contract

services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction

("AFUDC"). The cost of major additions and betterments are capitalized, while costs incurred that do not improve or extend the useful

lives of the related assets are generally expensed.

Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated

useful lives or mandated recovery periods as prescribed by PacifiCorp's various regulatory authorities. Depreciation studies are

completed to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are

ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and

any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either

accumulated provision for depreciation or as an ARO liability on the Comparative Balance Sheet, depending on whether the obligation

meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced. 

Generally when PacifiCorp retires or sells a component of depreciable utility plant, it charges the original cost and any net proceeds

from the disposition to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded through

earnings.

PacifiCorp records debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance

additions to utility plant. AFUDC is capitalized as a component of utility plant, with offsetting credits to the Statement of Income.

After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as

recover these costs through depreciation expense over the useful lives of the related assets.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.4
 Asset Retirement Obligations

PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon

retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is

recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount

of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the

ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to

utility plant) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the

corresponding ARO asset included in utility plant and amounts recovered in depreciation rates to satisfy such liabilities is recorded as a

regulatory asset or liability.

Revenue Recognition

Revenue is recognized as electricity is delivered or services are provided. Revenue recognized includes unbilled, as well as billed,

amounts. As of December 31, 2010 and 2009, unbilled revenue was $206 million and $214 million, respectively, and is included in

accrued utility revenues, net on the Comparative Balance Sheet. Rates charged are established by regulators or contractual

arrangements. 

The determination of sales to individual customers is based on the reading of the customer's meter, which is performed on a systematic

basis throughout the month. At the end of each month, amounts of energy provided to customers since the date of the last meter reading

are estimated, and the corresponding unbilled revenue is recorded. The estimate is reversed in the following month and actual revenue

is recorded based on subsequent meter readings. 

The monthly unbilled revenues of PacifiCorp are determined by the estimation of unbilled energy provided during the period, the

assignment of unbilled energy provided to customer classes and the average rate per customer class. Factors that can impact the

estimate of unbilled energy provided include, but are not limited to, seasonal weather patterns, customer usage patterns, historical

trends, volumes, line losses, retail rate changes and composition of customer classes. 

PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on

a net basis on the Statement of Income.

Income Taxes

Berkshire Hathaway includes PacifiCorp in its United States federal income tax return. Consistent with established regulatory practice,

PacifiCorp's provision for income taxes has been computed on a stand-alone basis.

Deferred tax assets and liabilities are based on differences between the financial statement and tax basis of assets and liabilities using

estimated tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income

tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly

to OCI. Changes in deferred income tax assets and liabilities that are associated with income tax benefits related to certain

property-related basis differences and other various differences that PacifiCorp is required to pass on to its customers in most state

jurisdictions are charged or credited directly to a regulatory asset or liability. These amounts were recognized as a net regulatory asset

totaling $426 million and $401 million as of December 31, 2010 and 2009, respectively, and will be included in rates when the

temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax

expense. 

Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by

various regulatory jurisdictions. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.5
In determining PacifiCorp's income taxes, management is required to interpret complex tax laws and regulations, which includes

consideration of regulatory implications imposed by PacifiCorp's various regulatory jurisdictions. PacifiCorp's tax returns are subject

to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex

laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed

and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more likely than not

that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax

benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than

50% likelihood of being realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local tax

examinations is uncertain, PacifiCorp believes it has made adequate provisions for these tax positions. The aggregate amount of any

additional tax liabilities that may result from these examinations, if any, is not expected to have a material adverse effect on

PacifiCorp's financial results. PacifiCorp's unrecognized tax benefits are primarily included in Taxes accrued on the Comparative

Balance Sheet. Estimated interest and penalties, if any, related to uncertain tax positions are included in interest income, interest

expense and penalties on the Statement of Income.

Segment Information

PacifiCorp currently has one segment, which includes its regulated electric utility operations.

New Accounting Pronouncements 

In January 2010, the Financial Accounting Standards Board (the "FASB") issued Accounting Standards Update ("ASU") No. 2010-06

("ASU No. 2010-06"), which amends FASB Accounting Standards Codification ("ASC") Topic 820, "Fair Value Measurements and

Disclosures." ASU No. 2010-06 requires disclosure of (a) the amount of significant transfers into and out of Levels 1 and 2 of the fair

value hierarchy and the reasons for those transfers and (b) gross presentation of purchases, sales, issuances and settlements in the

Level 3 fair value measurement rollforward. This guidance clarifies that existing fair value measurement disclosures should be

presented for each class of assets and liabilities. The existing disclosures about the valuation techniques and inputs used to measure fair

value for both recurring and nonrecurring fair value measurements have also been clarified to ensure such disclosures are presented for

the Levels 2 and 3 fair value measurements. PacifiCorp adopted this guidance as of January 1, 2010, with the exception of the

disclosure requirement to present purchases, sales, issuances and settlements gross in the Level 3 fair value measurement rollforward,

which is effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption

did not have a material impact on PacifiCorp's disclosures included within Notes to Financial Statements.

In June 2009, the FASB issued authoritative guidance (which was codified into ASC Topic 810, "Consolidation" with the issuance of

ASU No. 2009-17) that requires a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable

interest entity. This analysis is based on whether the enterprise has (a) the power to direct the activities of the variable interest entity

that most significantly impact the entity's economic performance and (b) the obligation to absorb losses of the entity or the right to

receive benefits from the entity that could potentially be significant to the variable interest entity. In addition, enterprises are required

to more frequently reassess whether an entity is a variable interest entity and whether the enterprise is the primary beneficiary of the

variable interest entity. Finally, the guidance for consolidation or deconsolidation of a variable interest entity is amended and

disclosure requirements about an enterprise's involvement with a variable interest entity are enhanced. PacifiCorp adopted this

guidance as of January 1, 2010 on a prospective basis. As a result, PacifiCorp's coal mining joint venture, Bridger Coal Company

("Bridger Coal"), was deconsolidated and is being accounted for under the equity method of accounting as the power to direct the

activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. Bridger Coal

was previously and continues to be accounted for under the equity method for FERC accounting and reporting purposes. Pacific

Minerals, Inc. (“PMI”), a wholly owned subsidiary of PacifiCorp that owns 66.67% of Bridger Coal, was consolidated for FERC

reporting purposes on a prospective basis beginning January 1, 2010. The consolidation of PMI did not have a significant impact on

PacifiCorp’s financial results.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.6
(3) Net Utility Plant 

Utility plant, net consists of the following as of December 31 (in millions):

Utility Plant: Depreciable Life 2010 2009

Generation 15 – 80 years $ 9,901 $ 9,022

Transmission 25 – 75 years 4,335 3,346

Distribution 44 – 52 years 5,491 5,332

Intangible plant(1) 5 – 53 years 848 752

Other 5 – 43 years 1,443 1,430

Utility plant in service 22,018 19,882

Accumulated provision for depreciation,

amortization and depletion (7,467) (7,200)

Net utility plant in service 14,551 12,682

Construction work in progress 1,001 1,799

Total utility plant, net $ 15,552 $ 14,481

(1) Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.

Unallocated Acquisition Adjustments

PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in utility plant purchased

from the entity that first devoted the assets to utility service over their net book value in those assets. These unallocated acquisition

adjustments included in utility plant had an original cost of $159 million and $157 million as of December 31, 2010 and 2009,

respectively, and accumulated provision for depreciation, amortization and depletion of $102 million and $96 million as of

December 31, 2010 and 2009, respectively.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.7
(4) Jointly Owned Utility Facilities 

Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly

owned generation, transmission and distribution facilities and transmission lines. PacifiCorp accounts for its proportionate share of

each facility, and each joint owner has provided financing for its share of each generating facility or transmission line. Operating costs

of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of

the cost. Operating costs and expenses on the Statement of Income include PacifiCorp's share of the expenses of these facilities.

The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility as of December 31, 2010

(dollars in millions):

Accumulated

Facility Depreciation Construction

PacifiCorp in and Work-inShare Service Amortization Progress

Jim Bridger Nos. 1 – 4(1) 67% $ 1,077 $ 510 $ 29

Hunter No. 1 94 348 151 21

Wyodak (1) 80 341 187 85

Colstrip Nos. 3 and 4(1) 10 247 132 2

Hunter No. 2 60 193 94 77

Hermiston(2) 50 175 51 1

Craig Nos. 1 and 2 19 170 89 4

Hayden No. 1 25 46 26 5

Foote Creek 79 37 18 -

Hayden No. 2 13 28 17 3

Other transmission and distribution facilities Various 181 26 11

Total $ 2,843 $ 1,301 $ 238

(1) Includes transmission lines and substations.

(2) PacifiCorp has contracted to purchase the remaining 50% of the output of the Hermiston generating facility.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.8
(5) Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the

Comparative Balance Sheet consist of the following as of December 31 (in millions):

Weighted

Average

Remaining

Life 2010 2009

Employee benefit plans(1) 9 years $ 595 $ 576

Unrealized loss on regulated derivative contracts 4 years 487 367

Deferred income taxes(2) 33 years 448 422

Other Various 207 186

Total $ 1,737 $ 1,551

(1) Substantially represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.

Amounts are partially offset by $12 million and $19 million of the unamortized portion of net regulatory deferrals related to curtailment gains and the

measurement date change transitional adjustment as of December 31, 2010 and 2009, respectively.

(2) Represents deferred income tax assets and liabilities that are associated with income tax benefits related to certain property-related basis differences and

other various differences that PacifiCorp is required to pass on to its customers in most state jurisdictions.

PacifiCorp had regulatory assets not earning a return on investment of $1.575 billion and $1.385 billion as of December 31, 2010 and

2009, respectively.

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's

regulatory liabilities reflected on the Comparative Balance Sheet consist of the following as of December 31 (in millions):

Weighted

Average

Remaining

Life 2010 2009

Deferred income taxes Various $ 22 $ 21

Other Various 38 43

Total $ 60 $ 64

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.9
Rate Matters

Oregon Senate Bill 408 

Oregon Senate Bill 408 ("SB 408") requires PacifiCorp and other large regulated, investor-owned utilities that provide electric or

natural gas service to Oregon customers to file an annual report each October with the Oregon Public Utility Commission (the

"OPUC") comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. If after its

review, the OPUC determines the amount of income taxes collected differs from the amount of income taxes paid by more than

$100,000, the OPUC must require the public utility to establish an automatic adjustment clause to account for the difference.

The OPUC issued an order in April 2008 approving the recovery of $35 million, plus interest, related to PacifiCorp's 2006 tax report.

This order was challenged by the Industrial Customers of Northwest Utilities ("ICNU"), which petitioned the Oregon Court of Appeals

for judicial review of, among other things, the application of certain administrative rules considered in the April 2008 order. In

December 2010, the Oregon Court of Appeals affirmed the OPUC's April 2008 order. The ICNU did not seek further judicial review

of the order, and the order is now final. The $35 million, plus interest, was previously recorded and collected from customers.

In October 2009, PacifiCorp filed for a surcharge of $38 million in its 2008 tax report under SB 408. In January 2010, PacifiCorp

entered into a stipulation with OPUC staff and the Citizens' Utility Board of Oregon ("CUB"), agreeing to a lower surcharge totaling

$2 million, including interest. In April 2010, the OPUC issued an order adopting the stipulation in its entirety, at which time

PacifiCorp recorded the $2 million in operating revenue.

In October 2010, PacifiCorp filed its 2009 tax report under SB 408. In January 2011, PacifiCorp entered into a stipulation with the

OPUC staff and the CUB, whereby PacifiCorp, the OPUC staff and the CUB agreed to a surcharge of $13 million, plus interest. In

April 2011, the OPUC issued an order adopting the stipulation without significant modification. The $13 million, plus interest, will be

recorded in operating revenue in April 2011 and collected over a one-year period beginning in June 2011. The stipulation also

contained an agreement that the OPUC staff will support PacifiCorp’s request to defer resolution of certain aspects of the 2009 tax

report in a separate proceeding, the outcome of which is not expected to have a material impact on PacifiCorp’s financial results. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.10
(6) Fair Value Measurements 

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, special funds, other investments, payables, accrued

liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has

various financial assets and liabilities that are measured at fair value on the financial statements using inputs from the three levels of

the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input

that is significant to the fair value measurement. The three levels are as follows:

• Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the

ability to access at the measurement date.

• Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or

similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset

or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other

means (market corroborated inputs).

• Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in

pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best

information available, including its own data.

 The following table presents PacifiCorp's assets and liabilities recognized on the Comparative Balance Sheet and measured at fair

value on a recurring basis (in millions):

Input Levels for Fair Value

Measurements

Level 1 Level 2 Level 3 Other (1) Total

As of December 31, 2010

Assets:

Commodity derivatives $ - $ 263 $ 5 $ (145) $ 123

Investments in available-for-sale securities:

Money market funds(2) 2 - - - 2

$ 2 $ 263 $ 5 $ (145) $ 125

Liabilities:

Commodity derivatives $ - $ (405) $ (350) $ 272 $ (483)

As of December 31, 2009

Assets:

Commodity derivatives $ - $ 285 $ 6 $ (140) $ 151

Investments in available-for-sale securities:

Money market funds (2) 94 - - - 94

$ 94 $ 285 $ 6 $ (140) $ 245

Liabilities:

Commodity derivatives $ - $ (274) $ (386) $ 165 $ (495)

(1) Represents netting under master netting arrangements and a net cash collateral receivable of $127 million and $25 million as of December 31, 2010 and

2009, respectively.

(2) Amounts are included in other investments, other special funds and temporary cash investments on the Comparative Balance Sheet. The fair value of these

money market mutual funds approximates cost.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.11
Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value

unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the

fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp

transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves

represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates.

PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial

models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers,

exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for

certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years; therefore, PacifiCorp's

forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and

natural gas trading hubs are not as readily obtainable for the first six years. Given that limited market data exists for these contracts, as

well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on

perceived pricing relationships to major trading hubs that are based on significant unobservable inputs. The estimated fair value of

these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility,

counterparty creditworthiness and duration of contracts. Refer to Note 7 for further discussion regarding PacifiCorp's risk management

and hedging activities.

Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap

and option components. Forward and swap components are valued against the appropriate forward price curve. Option components are

valued using Black-Scholes-type models, such as European option, Asian option, spread option and best-of option, with the

appropriate forward price curve and other inputs.

PacifiCorp's investments in money market mutual funds and debt and equity securities are accounted for as available-for-sale securities

and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an

active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair

value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities

with similar characteristics.

The following table reconciles the beginning and ending balances of PacifiCorp's commodity derivative assets and liabilities measured

at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):

2010 2009

Beginning balance $ (380) $ (408)

Changes in fair value recognized in regulatory assets (38) (5)

Purchases, sales, issuances and settlements 73 56

Net transfers (to) from Level 2 - (23)

Ending balance $ (345) $ (380)

PacifiCorp's long-term debt is carried at cost on the financial statements. The fair value of PacifiCorp's long-term debt has been

estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent

with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair

value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and

estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):

2010 2009

Carrying Fair Carrying Fair

Value Value Value Value

Long-term debt $ 6,344 $ 7,086 $ 6,357 $ 6,843

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.12
(7) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to

electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated

service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to

commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is

purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other

unpredictable items, weather; market liquidity; generating facility availability; customer usage; storage; and transmission and

transportation constraints. Interest rate risk exists on variable-rate short- and long-term debt and future debt issuances. PacifiCorp does

not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of

the various types of risk involved in its business. To mitigate a portion of its commodity risk, PacifiCorp uses commodity derivative

contracts, including forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production

generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through

the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. PacifiCorp may from time to time enter

into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No

interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest

rate risks, thereby exposing the unhedged portion to changes in market prices. 

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 6 for additional

information on derivative contracts.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.13
The following table, which excludes contracts that qualify for the normal purchases or normal sales exception afforded by GAAP,

summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented

on a net basis on the Comparative Balance Sheet (in millions):

Derivative Assets Derivative Liabilities

Current Noncurrent Current Noncurrent Total

As of December 31, 2010

Not designated as hedging contracts (1)(2):

Commodity assets $ 185 $ 13 $ 34 $ 36 $ 268

Commodity liabilities (62) (4) (213) (476) (755)

Total 123 9 (179) (440) (487)

Designated as cash flow hedging contracts(1):

Commodity assets - - - - -

Commodity liabilities - - - - -

Total - - - - -

Total derivatives 123 9 (179) (440) (487)

Cash collateral (payable) receivable (9) - 95 41 127

Total derivatives – net basis $ 114 $ 9 $ (84) $ (399) $ (360)

As of December 31, 2009

Not designated as hedging contracts (1)(2):

Commodity assets $ 191 $ 61 $ 8 $ 31 $ 291

Commodity liabilities (29) (17) (142) (472) (660)

Total 162 44 (134) (441) (369)

Designated as cash flow hedging contracts(1):

Commodity assets - - - - -

Commodity liabilities - - - - -

Total - - - - -

Total derivatives 162 44 (134) (441) (369)

Cash collateral (payable) receivable (54) (1) 49 31 25

Total derivatives – net basis $ 108 $ 43 $ (85) $ (410) $ (344)

(1) Derivative contracts within these categories subject to master netting arrangements are presented on a net basis on the Comparative Balance Sheet.

(2) PacifiCorp's commodity derivatives not designated as hedging contracts are generally included in rates and as of December 31, 2010 and 2009, a net

regulatory asset of $487 million and $367 million, respectively, was recorded related to the net derivative liability of $487 million and $369 million,

respectively.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.14
Not Designated as Hedging Contracts

For PacifiCorp's commodity derivatives not designated as hedging contracts, the settled amount is generally included in rates.

Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as

derivatives and probable of inclusion in rates are recorded as net regulatory assets. The following table reconciles the beginning and

ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts

recognized in net regulatory assets, as well as amounts reclassified to earnings for the years ended December 31 (in millions):

2010 2009

Beginning balance $ 367 $ 442

Changes in fair value recognized in net regulatory assets 90 (74)

Net gains reclassified to earnings – operating revenues 64 222

Net losses reclassified to earnings – operation expenses (34) (223)

Ending balance $ 487 $ 367

For PacifiCorp's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as a net

regulatory asset or liability, unrealized gains and losses are recognized on the Statement of Income as miscellaneous nonoperating

income for unrealized gains and as other deductions for unrealized losses. The following table summarizes the pre-tax gains (losses)

included on the Statement of Income associated with PacifiCorp's derivative contracts not designated as hedging contracts and not

recorded as a net regulatory asset for the years ended December 31 (in millions): 

2010 2009

Commodity derivatives:

Miscellaneous non-operating income $ 16 $ 23

Other deductions (16) (17)

Total $ - $ 6

Designated as Hedging Contracts

PacifiCorp uses derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices. The

following table reconciles the beginning and ending balances of PacifiCorp's AOCI (pre-tax) and summarizes pre-tax gains and losses

on commodity derivative contracts designated and qualifying as cash flow hedges recognized in OCI, as well as amounts reclassified to

earnings for the years ended December 31 (in millions):

2010 2009

Beginning balance $ - $ -

Net (gains) losses recognized in OCI (12) 2

Net losses reclassified to earnings – operating revenues (1) (2)

Net losses reclassified to earnings – operation expenses 13 -

Ending balance $ - $ -

Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as miscellaneous nonoperating income and

other deductions, depending upon the nature of the item being hedged. For the years ended December 31, 2010 and 2009, hedge

ineffectiveness was insignificant. As of December 31, 2010 and 2009, PacifiCorp had no cash flow hedges outstanding.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.15
Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the

mark-to-market values as of December 31 (in millions):

Unit of

Measure 2010 2009

Commodity contracts:

Electricity sales Megawatt hours (13) (22)

Natural gas purchases Decatherms 159 201

Fuel oil purchases Gallons 16 14

Credit Risk

PacifiCorp extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants

in conjunction with wholesale sales and purchases activities. Credit risk relates to the risk of loss that might occur as a result of

nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other

commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more

groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual

obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a

counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to

circumstances involving other market participants that have a direct or indirect relationship with the counterparty.

PacifiCorp analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes

limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit

limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp enters into netting and

collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of

credit and cash deposits. Counterparties may be assessed interest fees for delayed payments. If required, PacifiCorp exercises rights

under these arrangements, including calling on the counterparty's credit support arrangement. 

Collateral and Contingent Features

In accordance with industry practice, certain derivative contracts contain provisions that require PacifiCorp to maintain specific credit

ratings from one or more of the major credit rating agencies on its unsecured debt. These derivative contracts may either specifically

provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold

levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of

a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31,

2010, PacifiCorp's credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features

totaled $448 million and $353 million as of December 31, 2010 and 2009, respectively, for which PacifiCorp had posted collateral of

$136 million and $80 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions

had been triggered as of December 31, 2010 and 2009, PacifiCorp would have been required to post $129 million and $159 million,

respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility,

changes in credit ratings, changes in legislation or regulation or other factors.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.16
(8) Short-term Debt and Other Financing Agreements

PacifiCorp has two unsecured credit facilities totaling $1.395 billion, which includes a $635 million unsecured credit facility that

expires in October 2012 and a $760 million unsecured credit facility that is fully available until July 2011. After July 2011, $720

million is available until July 2012 and $630 million is available until July 2013. The credit facilities include a fixed or variable

borrowing option for which rates vary based on the borrowing option and PacifiCorp's credit ratings for its senior unsecured long-term

debt securities. These facilities support PacifiCorp's commercial paper program and certain variable-rate tax-exempt bond obligations.

As of December 31, 2010, PacifiCorp had $36 million of commercial paper borrowings outstanding at a weighted-average interest rate

of 0.3% and no borrowings outstanding under its credit facilities. As of December 31, 2009, PacifiCorp had no short-term debt

outstanding. 

As of December 31, 2010, PacifiCorp had $601 million of letters of credit issued under committed arrangements, of which $304

million were issued under the revolving credit agreements. As of December 31, 2009, PacifiCorp had $517 million of letters of credit

issued under committed arrangements, of which $220 million were issued under the revolving credit agreements. These letters of credit

support PacifiCorp's variable-rate tax-exempt bond obligations, are fully available as of December 31, 2010 and 2009, respectively,

and expire periodically through May 2012. In addition, PacifiCorp's credit facilities supported $38 million of unenhanced variable-rate

tax-exempt bond obligations as of December 31, 2009.

Each revolving credit agreement and letter of credit arrangement requires that PacifiCorp's ratio of debt, including current maturities,

to total capitalization at no time exceed 0.65 to 1.0. As of December 31, 2010, PacifiCorp was in compliance with the covenants of its

revolving credit agreements and letter of credit arrangements.

The following table summarizes PacifiCorp's availability under its two unsecured revolving credit facilities as of December 31 (in

millions):

2010:

Available revolving credit facilities $ 1,395

Less:

Short-term debt (36)

Letters of credit and tax-exempt bond support (304)

Net revolving credit facilities available $ 1,055

2009:

Available revolving credit facilities $ 1,395

Less:

Letters of credit and tax-exempt bond support (258)

Net revolving credit facilities available $ 1,137 

As of December 31, 2010, PacifiCorp had approximately $15 million of additional letters of credit issued on its behalf to provide

credit support for certain transactions as required by third parties. These letters of credit were all fully available as of December 31,

2010 and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not

to renew a letter of credit prior to the expiration date.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.17
(9) Long-Term Debt and Capital Lease Obligations

PacifiCorp's long-term debt and capital lease obligations were as follows as of December 31 (in millions):

2010 2009

Average Average

Interest Interest

Par Value Amount Rate Amount Rate

First mortgage bonds:

5.0% to 9.2%, due through 2015 $ 1,040 $ 1,040 6.5% $ 1,054 6.5%

5.5% to 8.6%, due 2016 to 2019 855 852 5.6 852 5.6

6.7% to 8.5%, due 2021 to 2023 324 324 7.7 324 7.7

6.7% due 2026 100 100 6.7 100 6.7

5.3% to 7.7% due 2031 to 2035 800 798 6.3 798 6.3

5.8% to 6.4%, due 2036 to 2039 2,500 2,491 6.1 2,490 6.1

Tax-exempt bond obligations:

Variable rates, due 2013 (1) 41 41 0.4 41 0.3

Variable rates, due 2014 to 2025 325 325 0.3 325 0.5

Variable rates, due 2016 to 2024 (1) (2) 221 221 0.3 176 0.2

Variable rates, due 2014 to 2025 (1) (2) 68 68 4.0 113 3.8

5.6% to 5.7%, due 2021 to 2023 (1) 71 71 5.6 71 5.6

6.2% due 2030 13 13 6.2 13 6.2

Total long-term debt 6,358 6,344 6,357

Capital lease obligations:

8.8% to 14.8%, due through 2036 57 57 11.4 59 11.7

Total long-term debt and capital lease 

obligations $ 6,415 $ 6,401 $ 6,416

Reflected as:

2010 2009

Bonds $ 6,358 $ 6,372

Unamortized discount on long-term debt (14) (15)

Obligations under capital leases - noncurrent 56 57

Obligations under capital leases - current 1 2

Total long-term debt and capital lease obligations $ 6,401 $ 6,416

(1) Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and

redemption provisions as the tax-exempt bond obligations.

(2) Interest rates fixed for a term at 3.4% to 4.1%, with $68 million scheduled to reset in 2013. In 2010, $45 million reset at a variable rate.

PacifiCorp's long-term debt may include provisions that allow PacifiCorp to redeem the long-term debt in whole or in part at any time.

These provisions generally include make-whole premiums. 

In September 2010, PacifiCorp completed a re-offering of variable-rate tax-exempt bond obligations totaling $38 million. Letters of

credit totaling $39 million were issued under one of PacifiCorp's unsecured revolving credit facilities to provide credit enhancement

and liquidity support for these previously unenhanced obligations.

In June 2010, PacifiCorp completed a re-offering of a $45 million series of tax-exempt bond obligations. The interest rate for this

obligation was previously fixed for a term which, upon scheduled expiration, was converted to a variable rate with credit enhancement

and liquidity support provided by a $46 million letter of credit issued under one of PacifiCorp's unsecured revolving credit facilities. 

In January 2009, PacifiCorp issued $350 million of its 5.50% First Mortgage Bonds due January 15, 2019 and $650 million of its

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.18
6.00% First Mortgage Bonds due January 15, 2039. The net proceeds were used to repay short-term debt, to fund capital expenditures

and for general corporate purposes.

The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's

mortgage. Approximately $21 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage

as of December 31, 2010.

PacifiCorp has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $2.0 billion of

long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future

issuance. Also, in December 2010, PacifiCorp filed a shelf registration statement with the United States Securities and Exchange

Commission (the "SEC") covering future first mortgage bond issuances.

As of December 31, 2010, PacifiCorp had variable-rate tax-exempt bond obligations totaling $587 million that are supported by $601

million of letters of credit issued under committed bank arrangements. These letters of credit were fully available as of December 31,

2010 and expire periodically through May 2012.

PacifiCorp's letters of credit agreements generally contain similar covenants and default provisions as those contained in PacifiCorp's

revolving credit facilities, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1.0. PacifiCorp

monitors these covenants on a regular basis in order to ensure that events of default do not occur. As of December 31, 2010,

PacifiCorp was in compliance with these covenants.

PacifiCorp has entered into long-term agreements that qualify as capital leases and expire at various dates through October 2036 for

transportation services, power purchase agreements, real estate and for the use of certain equipment. The transportation services

agreements included as capital leases are for the right to use pipeline facilities to provide natural gas to three of PacifiCorp's generating

facilities. Net capital lease assets of $57 million and $59 million as of December 31, 2010 and 2009, respectively, were included in net

utility plant in the Comparative Balance Sheet.

As of December 31, 2010, the annual maturities of long-term debt and capital lease obligations, excluding unamortized discounts and

including interest on capital lease obligations, for 2011 and thereafter are as follows (in millions):

Long-Term Capital Lease

Debt Obligations Total

2011 $ 587 $ 8 $ 595

2012 17 7 24

2013 261 12 273

2014 253 8 261

2015 122 7 129

Thereafter 5,118 87 5,205

Total 6,358 129 6,487

Unamortized discount (14) - (14)

Amounts representing interest (1) - (72) (72)

Total $ 6,344 $ 57 $ 6,401

(1) Interest expense on capital lease obligations is recorded as rent expense.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.19
(10) Asset Retirement Obligations

PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash

spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a

credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including plan revisions, inflation and

changes in the amount and timing of the expected work.

PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate

removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be

estimated and no amounts are recognized on the financial statements other than those included in the accumulated provision for

depreciation established via approved depreciation rates and in accordance with accepted regulatory practices. These accruals totaled

$782 million and $755 million as of December 31, 2010 and 2009, respectively.

The following table reconciles the beginning and ending balances of PacifiCorp's ARO liability for the years ended December 31

(in millions):

2010 2009

Beginning balance $ 103 $ 81

Change in estimated costs (1) 2 19

Additions 1 3

Retirements (6) (5)

Accretion (2) 5 5

Ending balance $ 105 $ 103

(1) Results from changes in the timing and amounts of estimated cash flows for certain plant and mine reclamation.

(2) PacifiCorp records the accretion expense of asset retirement obligations as either a regulatory asset or liability.

Certain of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is

committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint

participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the

defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily recorded as

ARO liabilities.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.20
(11) Employee Benefit Plans

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides certain postretirement

healthcare and life insurance benefits through various plans for eligible retirees. In addition, PacifiCorp sponsors a defined

contribution 401(k) employee savings plan ("401(k) Plan"). Non-union employees hired on or after January 1, 2008 and certain union

employees are not eligible to participate in the PacifiCorp Retirement Plan ("Retirement Plan"). These employees are eligible to

receive enhanced benefits under the 401(k) Plan. 

Pension and Other Postretirement Benefit Plans

PacifiCorp's pension plans include a non-contributory defined benefit pension plan, the Retirement Plan; the Supplemental Executive

Retirement Plan ("SERP"); and certain joint trust union plans to which PacifiCorp contributes on behalf of certain bargaining units. All

non-union Retirement Plan participants that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective

January 1, 2009, earn benefits based on a cash balance formula. For most union employees, benefits under the Retirement Plan were

frozen at various dates from December 31, 2007 through March 31, 2010 as they are now being provided with enhanced 401(k) Plan

benefits. Certain union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years

of service and a final average pay formula. 

The cost of other postretirement benefits, including healthcare and life insurance benefits for eligible retirees, is accrued over the active

service period of employees. PacifiCorp funds these other postretirement benefits through a combination of funding vehicles.

PacifiCorp also contributes to joint trust union plans for postretirement benefits offered to certain bargaining units.

Healthcare Reform Legislation

In March 2010, the President signed into law healthcare reform legislation that included provisions to eliminate the tax deductibility of

other postretirement costs to the extent of retiree drug subsidies received from the federal government beginning after December 31,

2012. Accordingly, PacifiCorp increased deferred income tax liabilities and regulatory assets by $39 million. PacifiCorp has received

authorization from various state regulatory commissions for deferral of the $16 million of the adjustment that related to income tax

benefits associated with amounts previously recognized as net periodic benefit costs. The remaining $23 million of the adjustment

relates to income tax benefits that will no longer be realized in the future when the net periodic benefit cost is recognized and for which

recovery of the resulting higher future income tax expense will be addressed through on-going ratemaking proceedings.

The new law also contains a provision that requires a 40% excise tax for group health benefits that are provided to employees above

certain premium thresholds beginning in 2018. The tax would apply to the amount of premiums in excess of the thresholds. Virtually

all major areas of the healthcare reform legislation, including the 40% excise tax, are subject to interpretation and implementation rules

that may take several years to complete. As of December 31, 2010, PacifiCorp's other postretirement benefit obligation increased by

$12 million as a result of the projected impact of the excise tax on benefits provided to a certain bargaining unit.

Curtailments

In August 2008, non-union employee participants in the Retirement Plan were offered the option to continue to receive pay credits in

their current cash balance pension plan or receive equivalent fixed contributions to the 401(k) Plan. The election was effective

January 1, 2009 and resulted in the recognition of a $38 million curtailment gain. PacifiCorp recorded $36 million of the curtailment

gain representing the amount to be returned to customers in rates as a regulatory deferral, resulting in a reduction to regulatory assets as

of December 31, 2008. The regulatory deferral is being amortized over a period of three to 10 years based on agreements with various

state regulatory commissions.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.21
Effective March 31, 2010, the Utility Workers Union of America Local Union No. 127 ("Local 127") elected to cease participation in

the Retirement Plan and participate only in the 401(k) Plan with enhanced benefits. As a result of this election, the Local 127

participants' Retirement Plan benefits were frozen on March 31, 2010. This change resulted in a $2 million curtailment gain that was

recorded as a regulatory deferral and is being amortized over periods similar to those required for other recent curtailments. Also as a

result of this change, PacifiCorp's pension benefit obligation and regulatory assets each decreased by $14 million.

Net Periodic Benefit Cost

For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is

calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first

year in which they occur. 

Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):

Pension Other Postretirement

2010 2009 2010 2009 

Service cost (1) $ 12 $ 16 $ 6 $ 5

Interest cost 66 71 31 33

Expected return on plan assets (74) (70) (30) (29)

Net amortization 23 10 14 12

Net amortization of regulatory deferrals (10) (8) 1 1

Curtailment gain - - - -

Net periodic benefit cost $ 17 $ 19 $ 22 $ 22

(1) Service cost excludes $13 million and $11 million of contributions to the joint trust union plans during each of the years ended December 31, 2010 and

2009, respectively.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.22
Funded Status

The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):

Pension Other Postretirement 

2010 2009 2010 2009

Plan assets at fair value, beginning of year $ 825 $ 692 $ 350 $ 284

Employer contributions 117 54 24 24

Participant contributions - - 9 9

Actual return on plan assets 102 160 44 70

Benefits paid (84) (81) (38) (37)

Plan assets at fair value, end of year $ 960 $ 825 $ 389 $ 350

The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):

Pension Other Postretirement 

2010 2009 2010 2009

Benefit obligation, beginning of year $ 1,199 $ 1,070 $ 545 $ 489

Service cost 12 16 6 5

Interest cost 66 71 31 33

Participant contributions - - 9 9

Plan amendments - (1) - (4)

Curtailment (14) - - -

Actuarial loss 57 124 25 47

Benefits paid, net of Medicare subsidy (84) (81) (35) (34)

Benefit obligation, end of year $ 1,236 $ 1,199 $ 581 $ 545

Accumulated benefit obligation, end of year $ 1,230 $ 1,178

The funded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 31 are as follows

(in millions):

Pension Other Postretirement 

2010 2009 2010 2009

Plan assets at fair value, end of year $ 960 $ 825 $ 389 $ 350

Less – Benefit obligation, end of year 1,236 1,199 581 545

Funded status $ (276) $ (374) $ (192) $ (195)

Amounts recognized on the Comparative Balance Sheet:

Other current liabilities $ (4) $ (4) $ - $ -

Other long-term liabilities (272) (370) (192) (195)

Amounts recognized $ (276) $ (374) $ (192) $ (195)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.23
The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments

to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi

trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was

$40 million and $39 million as of December 31, 2010 and 2009, respectively. These assets are not included in the plan assets in the

above table, but are reflected on the Comparative Balance Sheet. The portion of the pension plans' projected benefit obligation related

to the SERP was $56 million and $55 million as of December 31, 2010 and 2009, respectively.

Unrecognized Amounts

The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in

millions):

Pension Other Postretirement 

2010 2009 2010 2009

Net loss $ 507 $ 523 $ 142 $ 135

Prior service credit (50) (60) - -

Net transition obligation - - 19 29

Regulatory deferrals (16) (24) 4 5

Total $ 441 $ 439 $ 165 $ 169

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.24
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2010

and 2009 is as follows (in millions):

Accumulated

Other

Regulatory Comprehensive

Asset Loss, Net Total

Pension

Balance, January 1, 2009 $ 404 $ 4 $ 408

Net loss arising during the year 29 5 34

Prior service credit arising during the year (1) - (1)

Net amortization (2) - (2)

Total 26 5 31

Balance, December 31, 2009 430 9 439

Net loss arising during the year 27 2 29

Curtailment (14) - (14)

Net amortization (13) - (13)

Total - 2 2

Balance, December 31, 2010 $ 430 $ 11 $ 441

Deferred

Regulatory Income

Asset Taxes Total

Other Postretirement

Balance, January 1, 2009 $ 160 $ 20 $ 180

Net loss arising during the year 4 3 7

Prior service credit arising during the year (1) - (1)

Transition obligation credit arising during the year (3) - (3)

Net amortization (14) - (14)

Total (14) 3 (11)

Balance, December 31, 2009 146 23 169

Net loss arising during the year 11 - 11

Income tax benefits no longer realizable(1) 23 (23) -

Net amortization (15) - (15)

Total 19 (23) (4)

Balance, December 31, 2010 $ 165 $ - $ 165

(1) Represents adjustments to regulatory assets associated with income tax benefits that will no longer be realized when the net periodic benefit cost is

recognized as a result of the healthcare reform legislation.

The net loss, prior service credit, net transition obligation and regulatory deferrals that will be amortized in 2011 into net periodic

benefit cost are estimated to be as follows (in millions):

Net Prior Service Net Transition Regulatory

Loss Credit Obligation Deferrals Total

Pension $ 37 $ (8) $ - $ (9) $ 20

Other postretirement 6 - 11 1 18

Total $ 43 $ (8) $ 11 $ (8) $ 38

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.25
Plan Assumptions

Assumptions used to determine benefit obligations and net periodic benefit cost for the years ended December 31 were as follows:

Pension Other Postretirement

2010 2009 2010 2009

Benefit obligations as of December 31:

Discount rate 5.35% 5.80% 5.45% 5.85%

Rate of compensation increase 3.50 3.00 N/A N/A

Net benefit cost for the years ended:

Discount rate 5.80% 6.90% 5.85% 6.90%

Expected return on plan assets 7.75 7.75 7.75 7.75

Rate of compensation increase 3.00 3.50 N/A N/A

In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the expected asset allocation and return

assumptions for each asset class based on historical performance and forward-looking views of the financial markets.

2010 2009

Assumed healthcare cost trend rates as of December 31: 

Healthcare cost trend rate assumed for next year 8% 8%

Rate that the cost trend rate gradually declines to 5% 5%

Year that the rate reaches the rate it is assumed to remain at 2016 2016

A one percentage-point change in assumed healthcare cost trend rates would have the following effects (in millions):

Increase (Decrease)

One Percentage-Point One Percentage-Point

Increase Decrease

Effect on total service and interest cost $ 2 $ (2)

Effect on other postretirement benefit obligation 41 (33)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.26
Contributions and Benefit Payments

Employer contributions to the pension and other postretirement benefit plans are expected to be $71 million and $28 million,

respectively, during 2011. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and

the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act

of 2006, as amended. PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels

specified under the Pension Protection Act of 2006, as amended. PacifiCorp's funding policy for its other postretirement benefit plans

is to contribute an amount equal to the sum of the net periodic benefit cost and the amount of Medicare subsidies expected to be earned

during the period. 

The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2011 through 2015

and for the five years thereafter are summarized below (in millions):

Projected Benefit Payments

Other Postretirement

Pension Gross Medicare Subsidy Net of Subsidy

2011 $ 97 $ 34 $ (3) $ 31

2012 99 36 (3) 33

2013 105 39 (3) 36

2014 112 42 (4) 38

2015 107 43 (4) 39

2016 – 2020 513 242 (30) 212

Plan Assets

Investment Policy and Asset Allocations

PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified

portfolio of fixed income securities, equity securities and other alternative investments. Maturities for fixed income securities are

managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments

within the parameters outlined by the PacifiCorp Pension Committee. The investment portfolio is managed in line with the investment

policy with sufficient liquidity to meet near-term benefit payments. The return on assets assumption for each plan is based on a

weighted-average of the expected historical performance for the types of assets in which the plans invest.

The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as

of December 31, 2010:

Pension(1) Other Postretirement(1)

% %

Fixed-income securities(2) 33 – 37 33 – 37

Equity securities(2) 53 – 57 61 – 65

Limited partnership interests 8 – 12 1 – 3

Cash and cash equivalents 0 – 1 0 – 1

(1) PacifiCorp's Retirement Plan trust includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this

separate account, the assets for the other postretirement benefit plans are held in two Voluntary Employees' Beneficiaries Association ("VEBA") trusts, each

of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plans include the separate account of the

Retirement Plan trust and the two VEBA trusts.

(2) For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying

investments in fixed-income and equity securities.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.27
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plans (in

millions):

Input Levels for Fair Value Measurements

Level 1(1) Level 2(1) Level 3(1) Total

As of December 31, 2010

Cash and cash equivalents $ - $ 8 $ - $ 8

Fixed-income securities:

United States government obligations 20 - - 20

Corporate obligations - 52 - 52

International government obligations - 81 - 81

Municipal obligations - 4 - 4

Agency, asset and mortgage-backed obligations - 49 - 49

Equity securities:

United States equity securities 366 - - 366

International equity securities 7 - - 7

Investment funds (2) 109 180 - 289

Limited partnership interests(3) - - 84 84

Total $ 502 $ 374 $ 84 $ 960

As of December 31, 2009

Cash and cash equivalents $ - $ 8 $ - $ 8

Fixed-income securities:

United States government obligations 20 - - 20

Corporate obligations - 44 - 44

International government obligations - 65 - 65

Municipal obligations - 2 - 2

Agency, asset and mortgage-backed obligations - 43 - 43

Equity securities:

United States equity securities 296 - - 296

International equity securities 4 - - 4

Investment funds(2) 95 168 - 263

Limited partnership interests(3) - - 80 80

Total $ 415 $ 330 $ 80 $ 825

(1) Refer to Note 6 for additional discussion regarding the three levels of the fair value hierarchy.

(2) Investment funds are comprised of mutual funds and collective trust funds. These investment funds represent equity and fixed-income securities as of

December 31, 2010 and 2009, of approximately 60% and 40% and 61% and 39%, respectively.

(3) Limited partnership interests include several private equity funds that invest primarily in buyout, growth equity and venture capital.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.28
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan

(in millions):

Input Levels for Fair Value Measurements

Level 1(1) Level 2(1) Level 3(1) Total

December 31, 2010

Cash and cash equivalents $ 2 $ 1 $ - $ 3

Fixed-income securities:

United States government obligations 2 - - 2

Corporate obligations - 4 - 4

International government obligations - 7 - 7

Agency, asset and mortgage-backed obligations - 4 - 4

Equity securities:

United States equity securities 134 - - 134

International equity securities 3 - - 3

Investment funds (2) 118 107 - 225

Limited partnership interests(3) - - 7 7

Total $ 259 $ 123 $ 7 $ 389

December 31, 2009

Cash and cash equivalents $ 4 $ - $ - $ 4

Fixed-income securities:

United States government obligations 2 - - 2

Corporate obligations - 4 - 4

International government obligations - 6 - 6

Agency, asset and mortgage-backed obligations - 4 - 4

Equity securities:

United States equity securities 115 - - 115

International equity securities 2 - - 2

Investment funds(2) 101 104 - 205

Limited partnership interests(3) - - 8 8

Total $ 224 $ 118 $ 8 $ 350

(1) Refer to Note 6 for additional discussion regarding the three levels of the fair value hierarchy.

(2) Investment funds are comprised of mutual funds and collective trust funds. These investment funds represent equity and fixed-income securities as of

December 31, 2010 and 2009, of approximately 47% and 53% and 50% and 50%, respectively.

(3) Limited partnership interests include several private equity funds that invest primarily in buyout, growth equity and venture capital.

When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to

record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined

using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar

characteristics. When observable market data is not available, the fair value is determined using unobservable inputs, such as estimated

future cash flows, purchase multiples paid in other comparable third-party transactions or other information. Investments in limited

partnerships are valued at estimated fair value based on the Plan's proportionate share of the partnerships' fair value as recorded in the

partnerships' most recently available financial statements adjusted for recent activity and forecasted returns. The fair values recorded in

the partnerships' financial statements are generally determined based on closing public market prices for publicly traded securities and

as determined by the general partners for other investments based on factors including estimated future cash flows, purchase multiples

paid in other comparable third-party transactions, comparable public company trading multiples and other information. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.29
The following table reconciles the beginning and ending balances of PacifiCorp's plan assets measured at fair value using significant

Level 3 inputs for the years ended December 31 (in millions):

Limited Partnership Interests

Pension Other Postretirement

Balance, January 1, 2009 $ 78 $ 7

Actual return on plan assets still held at December 31, 2009 5 1

Purchases, sales, distributions and settlements (3) -

Balance, December 31, 2009 80 8

Actual return on plan assets still held at December 31, 2010 10 -

Purchases, sales, distributions and settlements (6) (1)

Balance, December 31, 2010 $ 84 $ 7

Defined Contribution Plan

PacifiCorp sponsors a defined contribution plan covering substantially all employees. PacifiCorp's contributions are based primarily on

each participant's level of contribution and cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the

401(k) Plan were $39 million and $34 million for the years ended December 31, 2010 and 2009, respectively. As previously described,

certain participants now receive enhanced benefits in the 401(k) Plan and no longer accrue benefits in the Retirement Plan.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.30
(12) Income Taxes

Income tax expense consists of the following for the years ended December 31 (in millions):

2010 2009

Current:

Federal $ (489) $ (443)

State (1) 2

Total (490) (441)

Deferred:

Federal 675 646

State 29 34

Total 704 680

Investment tax credits (4) (4)

Total income tax expense $ 210 $ 235

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax

expense is as follows for the years ended December 31:

2010 2009

Federal statutory tax rate 35% 35%

State taxes, net of federal benefit 3 3

Tax credits (1) (8) (6)

Effects of ratemaking (2) -

Other (1) (2)

Effective income tax rate 27% 30%

(1) Primarily attributable to the impact of federal renewable electricity production tax credits related to qualifying wind-powered generating facilities that

extend 10 years from the date the facilities were placed in service.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.31
The net deferred income tax liability consists of the following as of December 31 (in millions):

2010 2009

Deferred tax assets:

Employee benefits $ 187 $ 244

Derivative contracts 185 140

Regulatory liabilities 26 40

Other 191 164

 589 588

Deferred tax liabilities:

Property, plant and equipment (3,342) (2,643)

Regulatory assets (650) (576)

Other (30) (35)

 (4,022) (3,254)

Net deferred tax liability $ (3,433) $ (2,666)

The sale of PacifiCorp to MEHC on March 21, 2006 triggered certain tax related events that remain unsettled. PacifiCorp does not

believe that the tax, if any, arising from the ultimate settlement of these events will have a material impact on its financial results.

The United States Internal Revenue Service has closed its examination of PacifiCorp's income tax returns through the 2003 tax year. In

most cases, state jurisdictions have closed their examinations of PacifiCorp's income tax returns through 1993.

As of December 31, 2010 and 2009, net unrecognized tax benefits totaled $70 million and $75 million, respectively, which included

$9 million and $6 million, respectively, of tax positions that, if recognized, would have an impact on the effective tax rate. The

remaining unrecognized tax benefits relate to positions for which ultimate deductibility is highly certain but for which there is

uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would

not affect PacifiCorp's effective tax rate. 

In March 2011, the United States Internal Revenue Service released Revenue Procedure 2011-26, which provides guidance regarding

the application of the 100% bonus depreciation provisions that were provided for in the Tax Relief, Unemployment Insurance

Reauthorization, and Job Creation Act of 2010. PacifiCorp is currently evaluating the impacts of this guidance on its December 31,

2010 income tax provision and expects that income taxes receivable from MEHC, which is included Account 165 Prepayments, will

decrease significantly with a concurrent decrease in Account 282 Accumulated deferred income taxes – other property.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.32
(13) Commitments and Contingencies 

Legal Matters

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or

exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its financial

results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines,

penalties and other costs in substantial amounts and are described below.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,

emissions performance standards, climate change, coal combustion byproducts, hazardous and solid waste disposal, protected species

and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in

material compliance with all applicable laws and regulations.

New Source Review

As part of an industry-wide investigation to assess compliance with the New Source Review ("NSR") and Prevention of Significant

Deterioration ("PSD") provisions, the Environmental Protection Agency ("EPA") has requested from numerous utilities information

and supporting documentation regarding their capital projects for various generating facilities. Between 2001 and 2003, PacifiCorp

responded to requests for information relating to its capital projects at its generating facilities, and has been engaged in periodic

discussions with the EPA over several years regarding its historical projects and their compliance with NSR and PSD provisions. A

NSR enforcement case against another utility has been decided by the United States Supreme Court, holding that an increase in annual

emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR

permitting. PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event it

is determined that PacifiCorp's historical projects did not meet all regulatory requirements. The impact of these additional emissions

controls, costs and penalties, if any, on PacifiCorp's financial results cannot be determined at this time.

Hydroelectric Relicensing

PacifiCorp's hydroelectric portfolio consists of 46 generating facilities with an aggregate facility net owned capacity of

1,157 megawatts ("MW"). FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses, which typically

have terms of 30 to 50 years. PacifiCorp expects to incur ongoing operating and maintenance expense and capital expenditures

associated with the terms of its renewed hydroelectric licenses and settlement agreements, including natural resource enhancements.

PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses. Substantially all of PacifiCorp's remaining

hydroelectric generating facilities are operating under licenses that expire between 2030 and 2058. 

Klamath Hydroelectric System - Klamath River, Oregon and California

PacifiCorp is currently operating under an annual license for the Klamath hydroelectric system as part of a relicensing settlement

process that includes possible removal of the system's four mainstem dams. 

In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the State of

California, the State of Oregon and various other governmental and non-governmental settlement parties signed the Klamath

Hydroelectric Settlement Agreement ("KHSA"). Among other things, the KHSA provides that the United States Department of the

Interior conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's four mainstem

dams is in the public interest and will advance the Klamath Basin's salmonid fisheries. If it is determined that dam removal should

proceed, dam removal is expected to commence no earlier than 2020. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.33
Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. For dam removal to

occur, federal legislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from all

liabilities associated with dam removal activities. If Congress does not enact legislation, then PacifiCorp will resume relicensing at the

FERC. In addition, the KHSA limits PacifiCorp's contribution to dam removal costs to no more than $200 million, of which up to

$184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California

customers. An additional $250 million for dam removal costs is expected to be raised through a California bond measure or other

appropriate State of California financing mechanism. If dam removal costs exceed $200 million and if the State of California is unable

to raise the additional funds necessary for dam removal costs, sufficient funds would need to be provided by an entity other than

PacifiCorp in order for the KHSA and dam removal to proceed.

PacifiCorp has begun collection of surcharges from Oregon customers for their share of dam removal costs, as approved by the OPUC,

and is depositing the proceeds in a trust account maintained by the OPUC. The California Public Utilities Commission issued a

proposed decision in February 2011 with similar provisions for California customers and a final order is pending. 

As of December 31, 2010, the net book value of PacifiCorp's Klamath hydroelectric system generating facilities was $59 million with

an average remaining depreciable life of 36 years. As of December 31, 2010, relicensing and settlement costs associated with the

Klamath hydroelectric system totaled $74 million. PacifiCorp received approval from the OPUC to depreciate its hydroelectric system

generating facilities and relicensing and settlement costs through the expected dam removal date, and is at various stages of seeking

similar approval in its remaining jurisdictions. 

Hydroelectric Commitments

As described above, certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and

operating expenditures related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of

approximately $321 million over the next 10 years related to these licenses.

FERC Issues

FERC Investigation

During 2007, the Western Electricity Coordinating Council ("WECC") audited PacifiCorp's compliance with several of the reliability

standards developed by the North American Electric Reliability Corporation ("NERC"). In April 2008, PacifiCorp received notice of a

preliminary non-public investigation from the FERC and the NERC to determine whether an outage that occurred in PacifiCorp's

transmission system in February 2008 involved any violations of reliability standards. In November 2008, PacifiCorp received

preliminary findings from the FERC staff regarding its non-public investigation into the February 2008 outage. Also in

November 2008, in conjunction with the reliability standards review, the FERC assumed control of certain aspects of the WECC's

2007 audit. PacifiCorp has engaged in discussions with FERC staff regarding findings related to the non-public investigation, which

includes the WECC's findings that are now being processed by the FERC. PacifiCorp does not believe that the outcome of the

non-public investigation will have a material impact on its financial results. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.34
Northwest Refund Case

In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral

sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an

appropriate resolution of the matter. In November 2003, the FERC issued its final order denying rehearing. Several market

participants, excluding PacifiCorp, filed petitions in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") for

review of the FERC's final order. In August 2007, the Ninth Circuit concluded that the FERC failed to adequately explain how it

considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific

Northwest, and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy in the

Pacific Northwest spot market made by the California Energy Resources Scheduling ("CERS") division of the California Department

of Water Resources. Without issuing the mandate order, the Ninth Circuit remanded the case to the FERC to (a) address the new

market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the

proceedings; (b) include sales to CERS in its analysis; and (c) further consider its refund decision in light of related, intervening

opinions of the court. The Ninth Circuit offered no opinion on the FERC's findings based on the record established by the

administrative law judge and did not rule on the merits of the FERC's November 2003 decision to deny refunds. In April 2009, the

Ninth Circuit issued a formal mandate order, completing the remand of the case to the FERC, which has not yet undertaken further

action. PacifiCorp cannot predict the future course of this proceeding and its impact on its financial results, if any, at this time. 

Purchase Obligations 

PacifiCorp has the following purchase obligations that are not reflected on the Comparative Balance Sheet. Minimum payments as of

December 31, 2010 are as follows (in millions):

2011 2012 2013 2014 2015 Thereafter Total

Purchased electricity $ 170 $ 136 $ 135 $ 100 $ 96 $ 543 $ 1,180

Fuel 764 604 595 573 472 2,591 5,599

Construction 393 97 20 9 9 37 565

Transmission 115 108 97 83 62 745 1,210

Operating leases 6 5 4 4 3 39 61

Maintenance, service

and other commitments 44 19 16 12 6 53 150

Total commitments $ 1,492 $ 969 $ 867 $ 781 $ 648 $ 4,008 $ 8,765

Purchased Electricity

As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange

agreements. PacifiCorp has several power purchase agreements with wind-powered and other generating facilities that are not included

in the table above as the payments are based on the amount of energy generated and there are no minimum payments. Included in the

purchased electricity payments are any power agreements that meet the definition of an operating lease. 

Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several

hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis

for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are

included in operation expenses on the Statement of Income. PacifiCorp is required to pay its portion of operating costs and its portion

of the debt service, whether or not any electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2010

and 2009 energy sources.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.35
Fuel

PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.

Construction

PacifiCorp has purchase obligations for its ongoing construction programs to meet increased electricity usage, customer growth,

system reliability objectives, develop incremental generating capacity, foster the use of renewable resources, enhance transmission

capabilities and mitigate environmental impacts through the installation of emission reduction technology. The amounts included in the

table above relate to firm commitments. The following discussion describes PacifiCorp's overall commitments and includes amounts

that PacifiCorp is not yet firmly committed through a purchase order or other agreement.

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may

change significantly as a result of such reviews. Estimates may change significantly at any time as a result of, among other factors,

changes in rules and regulations, including environmental; changes in income tax laws; general business conditions; load projections;

system reliability standards; the cost and efficiency of construction labor, equipment, and materials; and the cost and availability of

capital.

As part of the March 2006 acquisition of PacifiCorp, MEHC and PacifiCorp made a number of commitments to the state regulatory

commissions in all six states in which PacifiCorp has retail customers. These commitments are generally being implemented over

several years following the acquisition and are subject to subsequent regulatory review and approval. As of December 31, 2010, the

status of the key financial commitments was as follows:

• Invest approximately $812 million in emissions reduction technology for PacifiCorp's existing coal-fired generating

facilities. Through December 31, 2010, PacifiCorp had spent a total of $1.2 billion, including non-cash equity AFUDC,

on these emissions reduction projects. In June 2010, PacifiCorp filed notification of its completion of this commitment

with the applicable state regulatory commissions.

• Invest in certain transmission and distribution system projects that would enhance reliability, facilitate the receipt of

renewable resources and enable further system optimization in an amount that was originally estimated to be

approximately $520 million at the date of the acquisition. Through December 31, 2010, PacifiCorp had spent a total of

$958 million in capital expenditures, including non-cash equity AFUDC, which was in excess of the original estimate due

to the evolving nature of the projects agreed to in the commitment. This amount includes costs for certain segments of the

transmission expansion program discussed below.

PacifiCorp's Energy Gateway Transmission Expansion Program, which began in 2007, represents a plan to build approximately

2,000 miles of new high-voltage transmission lines, with an estimated cost exceeding $6 billion, primarily in Wyoming, Utah, Idaho

and Oregon. The plan includes several transmission line segments that will: (a) address customer load growth; (b) improve system

reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable

resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area. 

Transmission

PacifiCorp has agreements for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's

customers.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.36
Operating Leases and Easements 

PacifiCorp has non-cancelable operating leases primarily for office equipment, office space, certain operating facilities, land and

equipment under operating leases that expire at various dates through the year ending December 31, 2092. These leases generally

require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal

options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp also has

non-cancelable easements for land on which its wind-powered generating facilities are located. Rent expense on non-cancelable

operating leases totaled $15 million for 2010 and $13 million for 2009.

Maintenance, Service and Other Commitments

PacifiCorp has various non-cancelable maintenance, service and other commitments primarily related to turbine and equipment

maintenance and various other service agreements.

 (14) Preferred Stock

PacifiCorp's preferred stock was as follows as of December 31 (shares in thousands, dollars in millions, except per share amounts): 

Redemption 2010 2009

Price Per Share Shares Amount Shares Amount

Series:

Serial Preferred, $100 stated value,

3,500 shares authorized

 4.52% to 4.72% $102.3 to $103.5 149 $ 15 157 $ 15

 5.00% to 5.40% $100.0 to $101.0 108 10 108 10

 6.00% Non-redeemable 6 1 6 1

 7.00% Non-redeemable 18 2 18 2

5% Preferred, $100 stated value,

127 shares authorized $110.0 126 13 126 13

 407 $ 41 415 $ 41

Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. In the event of

voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends.

Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are

cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in

default in an amount equal to four full quarterly payments.

In May 2010, PacifiCorp received an unsolicited offer to repurchase certain shares of PacifiCorp's preferred stock. As a result,

PacifiCorp purchased and canceled 4,036 shares of its $100 stated value 4.72% Serial Preferred Stock for $318,844, at an average

price per share of $79, and 3,266 shares of its $100 stated value 4.56% Serial Preferred Stock for $241,684, at an average price per

share of $74.

Dividends declared but not yet due for payment on preferred stock were $1 million as of December 31, 2010 and 2009. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.37
 (15) Common Shareholder's Equity

In January 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC, a direct subsidiary of MEHC

on February 28, 2011.

In March 2011, PacifiCorp declared a dividend of $275 million payable to PPW Holdings LLC on April 20, 2011.

Through PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that

authorized MEHC's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would

reduce PacifiCorp's common stock equity below specified percentages of defined capitalization.

As of December 31, 2010, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to

PPW Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp's common stock

equity below 46.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. This minimum level

of common equity declines to 45.25% for the year ending December 31, 2011 and 44% thereafter. The terms of this commitment treat

50% of PacifiCorp's remaining balance of preferred stock in existence prior to the acquisition of PacifiCorp by MEHC as common

equity. As of December 31, 2010, PacifiCorp's actual common stock equity percentage, as calculated under this measure, was 55.8%,

and PacifiCorp would have been permitted to dividend $2.320 billion under this commitment.

These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings LLC or MEHC if PacifiCorp's

unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings or Baa3 or lower by Moody's Investor

Service, as indicated by two of the three rating services. As of December 31, 2010, PacifiCorp's unsecured debt rating was A- by

Standard & Poor's Rating Services, BBB+ by Fitch Ratings and Baa1 by Moody's Investor Service.

PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further

discussed in Notes 8 and 9.

Appropriated Retained Earnings

In accordance with the requirements of certain hydroelectric relicensing projects, as of December 31, 2010 and 2009, PacifiCorp had

$4 million in appropriated retained earnings – amortization reserve, federal.

(16) Variable-Interest Entities

PacifiCorp holds an undivided interest in 50% of the 474-MW Hermiston generating facility (refer to Note 4), dictates when the

generating facility operates, procures 100% of the natural gas for the generating facility and subsequently receives 100% of the

generated electricity, 50% of which is acquired through a long-term power purchase agreement. As a result, PacifiCorp holds a

variable interest in the joint owner of the remaining 50% of the facility and is the primary beneficiary. PacifiCorp has been unable to

obtain the information necessary to consolidate the entity because the entity has not agreed to supply the information due to the lack of

a contractual obligation to do so. PacifiCorp continues to request from the entity the information necessary to perform the

consolidation; however, no information has yet been provided by the entity. Cost of the electricity purchased from the joint owner was

$37 million and $36 million during the years ended December 31, 2010 and 2009, respectively. The entity is operated by the equity

owners and PacifiCorp has no risk of loss in relation to the entity in the event of a disaster.

PacifiCorp holds a two-thirds interest in Bridger Coal, which supplies coal to the Jim Bridger generating facility that is owned

proportionately by PacifiCorp and PacifiCorp's joint venture partner in Bridger Coal. PacifiCorp purchases two-thirds of the coal

produced by Bridger Coal, while the remaining coal is purchased by the joint venture partner. The power to direct the activities that

most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. Refer to Note 17 for

information regarding related party transactions with Bridger Coal.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.38
 (17) Related-Party Transactions

PacifiCorp has an intercompany administrative services agreement with its indirect parent company, MEHC and its subsidiaries.

Expenses charged to PacifiCorp under this agreement totaled $9 million during each of the years ended December 31, 2010 and 2009.

MEHC also pays certain third-party expenses on behalf of PacifiCorp that are reimbursed by PacifiCorp. These reimbursements were

$2 million and $1 million during the years ended December 31, 2010 and 2009, respectively. Payables associated with these

administrative and third-party expenses were $1 million and $2 million as of December 31, 2010 and 2009, respectively. PacifiCorp

also receives payments for services performed by PacifiCorp for MEHC and its affiliates, as well as for reimbursement of certain

expenses. Services performed by PacifiCorp for MEHC and its affiliates primarily relate to administrative and technology services and

direct-assigned employees. During the years ended December 31, 2010 and 2009, these services and expense reimbursements were

$3 million and $1 million, respectively. Receivables associated with these activities were $1 million and $- million as of December 31,

2010 and 2009, respectively.

PacifiCorp also engages in various transactions with several subsidiaries of MEHC in the ordinary course of business. Services

provided by these affiliates in the ordinary course of business and charged to PacifiCorp relate to the transportation of natural gas and

relocation services. These expenses totaled $5 million and $3 million during the years ended December 31, 2010 and 2009,

respectively. Payables associated with these expenses were $- million and $1 million as of December 31, 2010 and 2009, respectively.

PacifiCorp has long-term transportation contracts with BNSF Railway Company ("BNSF"), which became an indirect wholly owned

subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company, in February 2010. Transportation costs under these contracts

were $30 million and $29 million during the years ended December 31, 2010 and 2009, respectively. As of December 31, 2010 and

2009, PacifiCorp had $2 million and $1 million of accounts payable to BNSF outstanding under these contracts, including indirect

payables related to a jointly owned facility. 

PacifiCorp participated in a captive insurance program provided by MEHC Insurance Services Ltd. ("MISL"), a wholly owned

subsidiary of MEHC. MISL covered significant portions of the property damage and liability insurance deductibles in many of

PacifiCorp's current policies, as well as overhead distribution and transmission line property damage. PacifiCorp has no equity interest

in MISL and has no obligation to contribute equity or loan funds to MISL. Premium amounts were established in March 2006 based on

a combination of actuarial assessments and market rates to cover loss claims, administrative expenses and appropriate reserves, but as

a result of regulatory commitments were capped through December 31, 2010. Certain costs associated with the program were prepaid

and amortized over the policy coverage period which expired in March 2011. Premium expenses were $7 million during each of the

years ended December 31, 2010 and 2009. Prepayments to MISL were $2 million as of December 31, 2010 and 2009. Receivables for

claims were $12 million and $10 million as of December 31, 2010 and 2009, respectively. Proceeds from claims were $14 million and

$17 million during the years ended December 31, 2010 and 2009, respectively.

PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. As of

December 31, 2010 and 2009, income taxes receivable from MEHC were $345 million and $249 million, respectively.

PacifiCorp transacts with its equity investees, Bridger Coal, Trapper Mining Inc. and PERCo. Services provided by PacifiCorp and

charged to its equity investees relate primarily to management services, income taxes and labor. Receivables for these services were

$3 million and $4 million as of December 31, 2010 and 2009, respectively. Services provided by equity investees and charged to

PacifiCorp primarily relate to coal purchases. These payables were $17 million and $10 million as of December 31, 2010 and 2009,

respectively. During the year ended December 31, 2010 and 2009, coal purchases from PacifiCorp’s equity investees totaled

$141 million and $126 million, respectively. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.39
 (18) Supplemental Cash Flows Information

The summary of supplemental cash flows information for the years ended December 31 is as follows (in millions):

2010 2009

Interest paid, net of amounts capitalized $ 331 $ 322

Income taxes received, net $ 393 $ 248

Supplemental disclosure of non-cash investing and financing activities:

Utility plant additions in accounts payable $ 216 $ 240

Utility plant additions acquired under capital lease obligations $ - $ -

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

NOTES TO FINANCIAL STATEMENTS (Continued)

FERC FORM NO. 1 (ED. 12-88) Page 123.40
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 

2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 

3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.

4. Report data on a year-to-date basis.

Other

Adjustments

(e)

Foreign Currency

Hedges

(d)

Minimum Pension

Liability adjustment

(net amount)

(c)

Unrealized Gains and

Losses on Availablefor-Sale Securities

(b)

Item

(a)

( 130,769) ( 2,419,911)

Balance of Account 219 at Beginning of

Preceding Year

 1

 191,182

Preceding Qtr/Yr to Date Reclassifications

from Acct 219 to Net Income

 2

( 60,413) ( 3,399,666)

Preceding Quarter/Year to Date Changes in

Fair Value

 3

 4 Total (lines 2 and 3) 130,769 ( 3,399,666)

( 5,819,577)

Balance of Account 219 at End of

Preceding Quarter/Year

 5

( 5,819,577)

Balance of Account 219 at Beginning of

Current Year

 6

Current Qtr/Yr to Date Reclassifications

from Acct 219 to Net Income

 7

( 1,142,322)

Current Quarter/Year to Date Changes in

Fair Value

 8

 9 Total (lines 7 and 8) ( 1,142,322)

( 6,961,899)

Balance of Account 219 at End of Current

Quarter/Year

 10

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

Hedges

[Specify]

(g)

Other Cash Flow

Hedges

Interest Rate Swaps

(f)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Total

Comprehensive

Income

(j)

Net Income (Carried

Forward from

Page 117, Line 78)

(i)

Totals for each

category of items

recorded in 

Account 219

(h)

 1 ( 2,550,680)

 2 191,182

 3 ( 3,460,079)

 4 ( 3,268,897) 541,846,446 538,577,549

 5 ( 5,819,577)

 6 ( 5,819,577)

 7 7,825,262 7,825,262

 8 ( 7,825,262) ( 8,967,584)

 9 ( 1,142,322) 566,414,836 565,272,514

 10 ( 6,961,899)

FERC FORM NO. 1 (NEW 06-02) Page 122b
Schedule Page: 122(a)(b) Line No.: 5 Column: e

Unrecognized amounts on retirement benefits of ($9,379,000) less tax of $3,559,423 netting to ($5,819,577).

Schedule Page: 122(a)(b) Line No.: 10 Column: e

Unrecognized amounts on retirement benefits of ($11,220,000) less tax of $4,258,101 netting to ($6,961,899).

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

Year/Period of Report

End of

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. (a) (b)

Classification Electric

(c)

FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Total Company for the 

Current Year/Quarter Ended

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

column (h) common function.

 1 Utility Plant

 2 In Service

 3 Plant in Service (Classified) 21,284,241,062 21,284,241,062

 4 Property Under Capital Leases 65,393,121 65,393,121

 5 Plant Purchased or Sold -4,484,801 -4,484,801

 6 Completed Construction not Classified 495,830,779 495,830,779

 7 Experimental Plant Unclassified

 8 Total (3 thru 7) 21,840,980,161 21,840,980,161

 9 Leased to Others

 10 Held for Future Use 17,678,149 17,678,149

 11 Construction Work in Progress 1,000,790,049 1,000,790,049

 12 Acquisition Adjustments 159,175,508 159,175,508

 13 Total Utility Plant (8 thru 12) 23,018,623,867 23,018,623,867

 14 Accum Prov for Depr, Amort, & Depl 7,467,085,584 7,467,085,584

 15 Net Utility Plant (13 less 14) 15,551,538,283 15,551,538,283

 16 Detail of Accum Prov for Depr, Amort & Depl

 17 In Service:

 18 Depreciation 6,893,664,705 6,893,664,705

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

 20 Amort of Underground Storage Land/Land Rights

 21 Amort of Other Utility Plant 471,575,613 471,575,613

 22 Total In Service (18 thru 21) 7,365,240,318 7,365,240,318

 23 Leased to Others

 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 101,845,266 101,845,266

 33 Total Accum Prov (equals 14) (22,26,30,31,32) 7,467,085,584 7,467,085,584

FERC FORM NO. 1 (ED. 12-89) Page 200
(g)

Common

(h)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Gas Other (Specify)

(d) (e) (f)

Other (Specify) Other (Specify)

 1

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

FERC FORM NO. 1 (ED. 12-89) Page 201
Schedule Page: 200 Line No.: 18 Column: c

Depreciation is comprised of:

 Depreciation $6,855,190,564

 Depletion 38,474,141

 Total $6,893,664,705

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description of item Balance

(a) (b) (c)

Changes during Year Beginning of Year Additions

1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by 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.

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

 2 Fabrication

 3 Nuclear Materials

 4 Allowance for Funds Used during Construction

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

 6 SUBTOTAL (Total 2 thru 5)

 7 Nuclear Fuel Materials and Assemblies

 8 In Stock (120.2)

 9 In Reactor (120.3)

 10 SUBTOTAL (Total 8 & 9)

 11 Spent Nuclear Fuel (120.4)

 12 Nuclear Fuel Under Capital Leases (120.6)

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

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

 15 Estimated net Salvage Value of Nuclear Materials in line 9

 16 Estimated net Salvage Value of Nuclear Materials in line 11

 17 Est Net Salvage Value of Nuclear Materials in Chemical Processing

 18 Nuclear Materials held for Sale (157)

 19 Uranium

 20 Plutonium

 21 Other (provide details in footnote):

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

FERC FORM NO. 1 (ED. 12-89) Page 202
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Balance

(d) (e) (f)

Changes during Year

Amortization Other Reductions (Explain in a footnote) 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

FERC FORM NO. 1 (ED. 12-89) Page 203
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Account Balance Additions

(a) (b) (c)

Beginning of Year

1. Report below the original cost of electric plant in service according to the prescribed accounts.

2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;

Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.

3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.

4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions 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)

 1 1. INTANGIBLE PLANT

 2 (301) Organization

 3 (302) Franchises and Consents 162,527,923 77,267,612

 4 (303) Miscellaneous Intangible Plant 589,907,847 23,939,123

 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 752,435,770 101,206,735

 6 2. PRODUCTION PLANT

 7 A. Steam Production Plant

 8 (310) Land and Land Rights 95,879,653 20,488

 9 (311) Structures and Improvements 838,579,575 4,433,606

 10 (312) Boiler Plant Equipment 3,124,068,006 576,748,680

 11 (313) Engines and Engine-Driven Generators

 12 (314) Turbogenerator Units 832,870,176 80,225,196

 13 (315) Accessory Electric Equipment 366,892,467 18,979,727

 14 (316) Misc. Power Plant Equipment 29,208,805 863,529

 15 (317) Asset Retirement Costs for Steam Production 37,319,815 5,965,060

 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 5,324,818,497 687,236,286

 17 B. Nuclear Production Plant

 18 (320) Land and Land Rights

 19 (321) Structures and Improvements

 20 (322) Reactor Plant Equipment

 21 (323) Turbogenerator Units

 22 (324) Accessory Electric Equipment

 23 (325) Misc. Power Plant Equipment

 24 (326) Asset Retirement Costs for Nuclear Production

 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)

 26 C. Hydraulic Production Plant

 27 (330) Land and Land Rights 20,209,614 5,914,565

 28 (331) Structures and Improvements 104,317,417 8,572,335

 29 (332) Reservoirs, Dams, and Waterways 314,817,920 14,385,298

 30 (333) Water Wheels, Turbines, and Generators 111,436,535 2,106,752

 31 (334) Accessory Electric Equipment 59,040,854 759,180

 32 (335) Misc. Power PLant Equipment 2,391,127

 33 (336) Roads, Railroads, and Bridges 15,942,236 138,551

 34 (337) Asset Retirement Costs for Hydraulic Production

 35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 628,155,703 31,876,681

 36 D. Other Production Plant

 37 (340) Land and Land Rights 23,516,708 5,394,604

 38 (341) Structures and Improvements 155,449,405 439,916

 39 (342) Fuel Holders, Products, and Accessories 10,811,674

 40 (343) Prime Movers 2,276,086,094 240,919,747

 41 (344) Generators 347,539,112 27,923

 42 (345) Accessory Electric Equipment 230,222,062 4,326,760

 43 (346) Misc. Power Plant Equipment 12,179,685

 44 (347) Asset Retirement Costs for Other Production 4,031,634 1,078,163

 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,059,836,374 252,187,113

 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 9,012,810,574 971,300,080

FERC FORM NO. 1 (REV. 12-05) Page 204
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Account Balance Additions

(a) (b) (c)

Beginning of Year

 47 3. TRANSMISSION PLANT

 48 (350) Land and Land Rights 101,061,038 78,701,268

 49 (352) Structures and Improvements 86,366,332 18,215,228

 50 (353) Station Equipment 1,306,947,373 290,415,773

 51 (354) Towers and Fixtures 480,248,436 375,535,768

 52 (355) Poles and Fixtures 583,430,919 102,011,621

 53 (356) Overhead Conductors and Devices 762,583,203 164,583,952

 54 (357) Underground Conduit 3,211,828 47,624

 55 (358) Underground Conductors and Devices 7,529,724 -54,629

 56 (359) Roads and Trails 11,535,068 63,635

 57 (359.1) Asset Retirement Costs for Transmission Plant

 58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 3,342,913,921 1,029,520,240

 59 4. DISTRIBUTION PLANT

 60 (360) Land and Land Rights 52,407,949 1,229,245

 61 (361) Structures and Improvements 66,526,605 42,850

 62 (362) Station Equipment 788,914,257 48,583,269

 63 (363) Storage Battery Equipment 1,457,804

 64 (364) Poles, Towers, and Fixtures 909,346,119 39,382,964

 65 (365) Overhead Conductors and Devices 633,551,900 18,432,598

 66 (366) Underground Conduit 292,200,023 10,912,103

 67 (367) Underground Conductors and Devices 701,110,916 19,423,783

 68 (368) Line Transformers 1,062,949,128 42,087,257

 69 (369) Services 559,763,102 22,803,407

 70 (370) Meters 187,209,616 17,562,522

 71 (371) Installations on Customer Premises 8,809,120 108,262

 72 (372) Leased Property on Customer Premises

 73 (373) Street Lighting and Signal Systems 62,391,252 1,852,948

 74 (374) Asset Retirement Costs for Distribution Plant 1,937,045

 75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5,328,574,836 222,421,208

 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

 86 (389) Land and Land Rights 16,200,395

 87 (390) Structures and Improvements 231,527,327 4,173,919

 88 (391) Office Furniture and Equipment 81,338,734 10,030,590

 89 (392) Transportation Equipment 100,146,208 1,690,843

 90 (393) Stores Equipment 13,899,989 372,170

 91 (394) Tools, Shop and Garage Equipment 62,717,636 997,536

 92 (395) Laboratory Equipment 37,088,803 898,197

 93 (396) Power Operated Equipment 131,425,381 8,328,313

 94 (397) Communication Equipment 246,182,036 39,209,034

 95 (398) Miscellaneous Equipment 6,816,010 276,095

 96 SUBTOTAL (Enter Total of lines 86 thru 95) 927,342,519 65,976,697

 97 (399) Other Tangible Property 278,447,958 23,409,773

 98 (399.1) Asset Retirement Costs for General Plant 39,748

 99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,205,830,225 89,386,470

 100 TOTAL (Accounts 101 and 106) 19,642,565,326 2,413,834,733

 101 (102) Electric Plant Purchased (See Instr. 8) 3,003,416 6,533,307

 102 (Less) (102) Electric Plant Sold (See Instr. 8) 4,484,801

 103 (103) Experimental Plant Unclassified

 104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 19,645,568,742 2,415,883,239

FERC FORM NO. 1 (REV. 12-05) Page 206
(f)

Transfers Balance at

End of Year

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No. (g)

Adjustments

(e)

Retirements

(d)

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

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

 1

 2

 239,795,535 3

 7,008,585 1,017,776 607,856,161 4

 7,008,585 1,017,776 847,651,696 5

 6

 7

 1,289 95,898,852 8

 889,911 79,423,572 921,546,842 9

 64,329,284 -115,588,486 3,520,898,916 10

 11

 17,358,033 1,248,076 896,985,415 12

 1,493,361 31,588,682 415,967,515 13

 238,492 3,400,178 33,234,020 14

 -938,718 42,346,157 15

 84,310,370 -938,718 72,022 5,926,877,717 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 592 26,123,587 27

 661,187 797,518 113,026,083 28

 799,257 -1,820,024 326,583,937 29

 775,985 -334,380 112,432,922 30

 470,930 871,703 60,200,807 31

 27,742 -2,652 2,360,733 32

 42,813 285,341 16,323,315 33

 34

 2,778,506 -202,494 657,051,384 35

 36

 28,911,312 37

 84,472 155,973,793 38

 10,811,674 39

 2,854,966 -413,169 2,513,737,706 40

 692,131 79,619 346,954,523 41

 15,301 215,899 234,749,420 42

 732 2,729 12,181,682 43

 5,109,797 44

 3,563,130 -30,450 3,308,429,907 45

 90,652,006 -938,718 -160,922 9,892,359,008 46

FERC FORM NO. 1 (REV. 12-05) Page 205
(f)

Transfers Balance at

End of Year

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No. (g)

Adjustments

(e)

Retirements

(d)

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

 47

 44,483 1,799,642 181,517,465 48

 111,471 18,478,503 122,948,592 49

 33,474,957 -14,044,880 1,549,843,309 50

 460,185 8,112,938 863,436,957 51

 2,706,624 3,829,570 686,565,486 52

 4,842,433 -9,855,548 912,469,174 53

 3,259,452 54

 7,475,095 55

 11,598,703 56

 57

 41,640,153 8,320,225 4,339,114,233 58

 59

 1,273 -798,528 52,837,393 60

 580,354 8,686,881 74,675,982 61

 12,063,046 -8,013,059 817,421,421 62

 1,393,065 -64,739 63

 6,639,749 -512 942,088,822 64

 3,134,824 648,849,674 65

 1,137,011 241,775 302,216,890 66

 1,648,360 -241,263 718,645,076 67

 7,378,770 141,227 1,097,798,842 68

 788,760 581,777,749 69

 25,318,933 179,453,205 70

 116,306 8,801,076 71

 72

 3,307,134 -141,227 60,795,839 73

 1,937,045 74

 63,507,585 -189,445 5,487,299,014 75

 76

 77

 78

 79

 80

 81

 82

 83

 84

 85

 16,200,395 86

 1,399,136 1,238,043 235,540,153 87

 13,176,849 -972,877 77,219,598 88

 3,068,409 98,768,642 89

 321,589 -184,387 13,766,183 90

 1,890,225 -2,605 61,822,342 91

 1,385,370 -7,331 36,594,299 92

 7,227,118 132,526,576 93

 27,006,003 1,456,743 259,841,810 94

 197,284 11,230 6,906,051 95

 55,671,983 1,538,816 939,186,049 96

 27,280,184 -155,454 274,422,093 97

 39,748 98

 82,952,167 -155,454 1,538,816 1,213,647,890 99

 285,760,496 -1,094,172 10,526,450 21,780,071,841 100

 -9,536,723 101

 4,484,801 102

 103

 285,760,496 -1,094,172 989,727 21,775,587,040 104

FERC FORM NO. 1 (REV. 12-05) Page 207
Schedule Page: 204 Line No.: 97 Column: b

Account Description Balance Beginning of

Year 

 Additions Retirements Adjustments Balance at End of

Year 

(a) (b) (c) (d) (e) (g) 

39921 Land Owned in Fee $ 2,634,916 $ - $ - $ - $ 2,634,916 

39922 Land Rights 52,550,647 - - - 52,550,647 

39930 Structures 40,641,166 - - - 40,641,166 

39941 Surface - Plant Equipment 12,156,504 43,312 68,500 - 12,131,316 

39944 Surface - Electric Power Facilities 3,424,575 - - - 3,424,575 

39945 Underground - Coal Mine Equipment 69,683,627 4,141,344 1,372,883 - 72,452,088 

39946 Longwall Shields 17,699,562 15,414,285 17,602,272 - 15,511,575 

39947 Longwall Equipment 10,652,772 1,423,486 7,614,631 - 4,461,627 

39948 Mainline Extension 17,975,045 1,064,141 398,884 - 18,640,302 

39949 Section Extension 3,896,914 306,616 - - 4,203,530 

39951 Vehicles 1,264,591 - 26,609 - 1,237,982 

39952 Heavy Construction Equipment 5,159,693 299,000 152,962 - 5,305,731 

39960 Miscellaneous General Equipment 2,165,001 114,458 43,443 - 2,236,016 

39961 Computers - Mainframe 568,271 - - - 568,271 

39970 Mine Development and Road Extension 37,548,438 603,131 - - 38,151,569 

399915 Coal Mine Asset Retirement Obligations 426,236 - - (155,454) 270,782 

Total Plant Used in Mining Activities $ 278,447,958 $ 23,409,773 $ 27,280,184 $ (155,454) $ 274,422,093 

Schedule Page: 204 Line No.: 97 Column: c

See footnote line 97, column b.

Schedule Page: 204 Line No.: 97 Column: d

See footnote line 97, column b.

Schedule Page: 204 Line No.: 97 Column: e

See footnote line 97, column b.

Schedule Page: 204 Line No.: 97 Column: g

See footnote line 97, column b.

Schedule Page: 204 Line No.: 101 Column: c

Refer to page 108, Important Changes During the Quarter/Year, Item 3, of this Form No. 1.

Schedule Page: 204 Line No.: 101 Column: f

Refer to page 108, Important Changes During the Quarter/Year, Item 3, of this Form No. 1.

Schedule Page: 204 Line No.: 102 Column: c

Refer to page 108, Important Changes During the Quarter/Year, Item 3, of this Form No. 1.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ELECTRIC PLANT LEASED TO OTHERS (Account 104)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Lessee

Description of

(a) (b)

(Designate associated companies with a double asterisk) Property LeasedCommission

Authorization

(c)

Expiration

Date of

Lease

(d)

Balance at

End of Year

(e)

 1

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

 46

FERC FORM NO. 1 (ED. 12-95) Page 213

47 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)

PacifiCorp X

04/18/2011 2010/Q4

Line Description and Location Date Originally Included Balance at

End of Year

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

Date Expected to be used in Utility Service (d) No.

1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property 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.

 1 Land and Rights:

 2

 3 North Horn Mountain Coal Properties 1977 2018-2025 953,014

 4 Barnes Butte Substation 2007 2015 746,268

 5 Wild Horse Wind Plant 2007 2020 6,763,094

 6 Twelve Mile Wind Plant 2007 2021 2,160,207

 7 Jumbers Point Substation 2008 2015 1,173,276

 8 Mountain Green Substation 2009 2025 284,996

 9 Hoggard Substation 2009 2025 254,397

 10 Oquirrh-Terminal 345 kV Transmission Line 2009 2014 396,020

 11 Bend Service Center 2010 2020 3,507,838

 12 Legacy Substation 2010 2020 722,119

 13

 14 Miscellaneous, each under $250,000: 716,920

 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

FERC FORM NO. 1 (ED. 12-96) Page 214

47 Total 17,678,149
Schedule Page: 214 Line No.: 3 Column: c

The North Horn Mountain Coal Properties are needed to access future coal portals and federal coal reserves when existing East

Mountain coal mines are mined out.

Schedule Page: 214 Line No.: 5 Column: c

Land purchased for wind farms with an estimated construction date of 2020 before subject to the timing of completion of the Energy

Gateway Transmission Expansion Project.

Schedule Page: 214 Line No.: 6 Column: c

Land purchased for wind farms with an estimated construction date of 2021 before subject to the timing of completion of the Energy

Gateway Transmission Expansion Project.

Schedule Page: 214 Line No.: 10 Column: a

Land previously included in Hoggard Substation.

Schedule Page: 214 Line No.: 14 Column: c

Various dates and plans.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description of Project Construction work in progress - 

(a) (b)

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 $1,000,000, whichever is less) may be grouped.

 1 Intangible:

 2 Harry Allen Sub Install Transformer 14,508,952

 3 Energy Trading Systems 11,654,227

 4 Mobile Radio Purch-Implement VHF Spectrum 2,922,082

 5 SAP license and maintenance enhancements 2,590,806

 6

 7 Production:

 8 Naughton U2 Flue Gas Desulfurization System 97,852,693

 9 Dave Johnston U4 SO2 & PM Emission Control Upgrades 83,434,697

 10 Naughton U1 Flue Gas Desulfurization System 71,803,962

 11 Wyodak U1 SO2 & PM Emission Control Upgrades 69,766,970

 12 North Umpqua River System Relicensing Implementation 35,753,200

 13 Hunter U2 Clean Air - PM 32,332,081

 14 Huntington U1 SO2 & PM Emission Control Upgrades 22,684,809

 15 Lewis River System Relicensing Implementation 21,663,099

 16 Hunter U1 SO2 & PM Emission Control Upgrades 20,535,338

 17 Hunter U2 SO2 & PM Emission Control Upgrades 19,658,370

 18 Blundell Proofing Well Integration 15,662,505

 19 Hunter U2 Turbine Upgrade HP/IP/LP 13,138,382

 20 Ashton Dam Seepage Control 11,818,025

 21 Wyodak U1 Air Cooled Condenser Replacement 9,861,092

 22 Jim Bridger U3 SO2 & PM Emission Control Upgrades 8,717,197

 23 Hayden Coal Unloading Facility 7,510,593

 24 Jim Bridger U1 Turbine Upgrade HP/IP/LP 7,404,728

 25 Hunter U2 Main Controls Replacement 4,055,129

 26 Generation Compliance Initiative Hardware 4,051,513

 27 Hunter U3 Turbine Upgrade HP/IP/LP 3,917,040

 28 Lake Side 2 Development 3,797,498

 29 Jim Bridger U3 Turbine Upgrade HP/IP/LP 3,475,741

 30 Huntington U2 Turbine Upgrade HP/IP/LP 2,953,717

 31 Wyodak U1 OH Clean Air - NOX 2,551,903

 32 Hunter U2 Economizer Replacement 2,422,289

 33 Wyodak U1 Replacement of Secondary Superheater 2,306,337

 34 Rogue River System Relicensing Implementation 2,594,462

 35 Slide Creek Overhaul 2,116,993

 36 Hunter U2 Low Temp SH Replacement 1,853,869

 37 Craig U1 HP-IP Turbine Rotor Replacement 1,688,900

 38 Hunter U2 RH Pendant Replacement 1,627,669

 39 Klamath River System Interim Implementation Measures 1,545,438

 40 Soda Unit 1 Generator Rewind 1,526,445

 41 Huntington U2 Boiler Finishing SH Pendants Replacement 1,467,568

 42 Craig U2 HP-IP Turbine Rotor Upgrade 1,414,798

FERC FORM NO. 1 (ED. 12-87) Page 216

43 TOTAL 1,000,790,049
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description of Project Construction work in progress - 

(a) (b)

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 $1,000,000, whichever is less) may be grouped.

 1 Huntington U1 Steam Inerting for Coal Mills 1,404,294

 2 Currant Creek Block 2 Development 1,379,807

 3 Jim Bridger U3 Reheater Outlet Terminal Tubes 11 1,286,788

 4 Jim Bridger U4 Turbine Upgrade HP/IP/LP 1,135,970

 5 Goodnoe Wind Blade Replacements 1,000,671

 6

 7 Transmission:

 8 Gateway West 500kV Line 45,692,963

 9 Mona-Oquirrh 345kV/500kV Line 26,927,521

 10 Red Butte Sub SVC and Property Acquisition 21,446,742

 11 Bridger Mona 500kV Line 17,019,304

 12 Sigurd-Red Butte-Crystal 345kV Line 16,355,518

 13 Malin Sub Series Capacitor Replacement 16,178,910

 14 Populus-Terminal: Double Circuit 345 kV Line 10,806,981

 15 Oquirrh New 345-138kV Substation 6,265,829

 16 Dave Johnston to Casper 230kV No 1&2 Line Rebuild 5,883,823

 17 California-Oregon Intertie Transfer Capability Increase 5,366,035

 18 Oquirrh-Terminal 345kV Line 4,535,245

 19 Chappel Creek 230kV Cimarex Energy 3,664,891

 20 Vickers Sub Add 46kV Circuit Breakers 3,145,454

 21 Tom McCall Industrial Park 115kV Project 3,027,576

 22 Wyoming Transmission Clearance Project 3,017,130

 23 Southwest WY Silver Creek Build 138kV Line 2,977,830

 24 Wallula-McNary 230kV Line 2,795,752

 25 St George-Red Butte 138kV Line 2,637,961

 26 TOT 4A-4B Transmission Path Transfer Capacity 2,596,618

 27 Line 3 Convert to 115kV 2,510,101

 28 Line 37 Convert to 115kV Build Nickel Mt Sub 2,046,439

 29 Idaho Transmission Clearance Project 1,716,683

 30 West Point-New 138 kV Line & 40 MVA Sub 1,650,483

 31 Vantage-Pomona Heights 230kV Line 1,449,273

 32 Eastside Transmission Line Ratings Wave Traps 1,394,346

 33 Two Elks Intercon at Tri County Switchyard 1,347,235

 34 Cameron-Milford 138kV Transmission 1,279,887

 35 Dave Johnston U3 GSU Replacement 1,118,268

 36 Utah Transmission Clearance Project 1,087,466

 37 Hemingway-Captain Jack 500kV Line 1,071,035

 38

 39 Distribution:

 40 Skypark Build New 138-12.5kV Substation 5,471,601

 41 Copper Hills New 138-12.5kV Sub 2,937,847

 42 Nibley 138-12.5kV Sub 2,622,983

FERC FORM NO. 1 (ED. 12-87) Page 216.1

43 TOTAL 1,000,790,049
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description of Project Construction work in progress - 

(a) (b)

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 $1,000,000, whichever is less) may be grouped.

 1 Saratoga Sub Add 2nd Trnsf Rebld Tran Jumper 2,593,830

 2 City Creek Center (SLC) New 40 MW Dev for PRI 2,430,483

 3 Bend Plant Sub Increase Capacity 2,102,256

 4 Farmington Sub Add 2nd 138-12.5 kV Transfmr 1,043,448

 5

 6 General:

 7 Mobile Radio Replacement Project 25,383,718

 8 Deer Creek Mine-Reconstruct Longwall System 14,093,017

 9 PCC/SCC Router Replacement TOM 1,823,963

 10

 11 Miscellaneous Projects each under $1,000,000 90,424,957

 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

FERC FORM NO. 1 (ED. 12-87) Page 216.2

43 TOTAL 1,000,790,049
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Item Total

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

Section A. Balances and Changes During Year

(c+d+e) Electric Plant in Service Electric Plant Held 

for Future Use

Electric Plant Leased to Others

(e)

1. Explain in a footnote any important adjustments during year.

2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported 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.

 1 Balance Beginning of Year 6,663,897,531 6,663,897,531

 2 Depreciation Provisions for Year, Charged to

 3 (403) Depreciation Expense 501,224,256 501,224,256

(403.1) Depreciation Expense for Asset

Retirement Costs

 4

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

 6 Transportation Expenses-Clearing

 7 Other Clearing Accounts

 8 Other Accounts (Specify, details in footnote): 27,690,769 27,690,769

 9

TOTAL Deprec. Prov for Year (Enter Total of

lines 3 thru 9)

 10 528,915,025 528,915,025

 11 Net Charges for Plant Retired:

 12 Book Cost of Plant Retired 278,227,865 278,227,865

 13 Cost of Removal 43,273,030 43,273,030

 14 Salvage (Credit) 10,644,919 10,644,919

TOTAL Net Chrgs. for Plant Ret. (Enter Total

of lines 12 thru 14)

 15 310,855,976 310,855,976

Other Debit or Cr. Items (Describe, details in

footnote):

 16 11,708,125 11,708,125

 17

 18 Book Cost or Asset Retirement Costs Retired

Balance End of Year (Enter Totals of lines 1,

10, 15, 16, and 18)

 19 6,893,664,705 6,893,664,705

 20 Steam Production

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

 2,549,642,134 2,549,642,134

 21 Nuclear Production

 22 Hydraulic Production-Conventional 262,715,132 262,715,132

 23 Hydraulic Production-Pumped Storage

 24 Other Production 388,889,683 388,889,683

 25 Transmission 1,172,814,664 1,172,814,664

 26 Distribution 2,072,617,011 2,072,617,011

 27 Regional Transmission and Market Operation

 28 General 446,986,081 446,986,081

 29 TOTAL (Enter Total of lines 20 thru 28) 6,893,664,705 6,893,664,705

FERC FORM NO. 1 (REV. 12-05) Page 219
Schedule Page: 219 Line No.: 4 Column: b

Generally, PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.

Schedule Page: 219 Line No.: 8 Column: b

Depreciation of mining assets included in account 151 Fuel Stock - until consumed $ 9,747,627

Account 143 Joint Owner Receivable - depreciation expense billed to joint owners 168,562

ARO asset amortization recorded as a regulatory asset or liability 2,424,556

Transportation depreciation allocated to O&M based on usage activity 14,065,119

Account 503 Blundell depletion 185,368

Account 503 Blundell depreciation and amortization 1,099,537

Total other accounts $ 27,690,769

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

Other items including: $ 11,708,125

 - Recovery from third parties for asset relocations and damaged property

 - Insurance recoveries

 - Adjustments of reserve related to electric plant sold

 - Reclassifications from electric plant

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Description of Investment Date Acquired

(a) (b) (c)

Amount of Investment at

Beginning of Year

Date Of 

Maturity (d)

1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.

2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL 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 BRIDGER COAL COMPANY 2/1/1974

 2 Partner Capital 161,668,072

 3 SUBTOTAL 161,668,072

 4

 5 PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 8/19/1994

 6 Capital Contributions 14,719,625

 7 Undistributed Subsidiary Earnings 8,330,470

 8 SUBTOTAL 23,050,095

 9

 10 TRAPPER MINING INC. 4/15/1992

 11 Members' Equity

 12 SUBTOTAL

 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

FERC FORM NO. 1 (ED. 12-89) Page 224

42 Total Cost of Account 123.1 $ 207,210,521 TOTAL 184,718,167
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Equity in Subsidiary 

Earnings of Year

Revenues for Year Amount of Investment at

End of Year

Gain or Loss from Investment

Disposed of (e) (f) (g) (h)

4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of 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

 1

 180,989,538 2

 180,989,538 3

 4

 5

 14,719,625 6

 -2,097,757 6,232,713 7

 -2,097,757 20,952,338 8

 9

 10

 11,501,358 11

 11,501,358 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

FERC FORM NO. 1 (ED. 12-89) Page 225

42 -2,097,757 213,443,234
Schedule Page: 224 Line No.: 1 Column: a

Refer to Note 2 of Notes to Financial Statements in this Form No. 1 for discussion of the consolidation of Pacific Minerals, Inc.

("PMI") beginning January 1, 2010.

Schedule Page: 224 Line No.: 10 Column: a

In the prior year, Trapper Mining Inc. was included in Account 123, Investment in Associated Companies.

Schedule Page: 224 Line No.: 14 Column: a

PacifiCorp consolidates certain wholly owned subsidiaries and as a result those investments are not reflected in Account 123.1,

Investments in Subsidiary Companies. Refer to page 103, Corporations Controlled by Respondent in this Form No. 1 for more

information regarding the wholly owned subsidiaries that PacifiCorp consolidates.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MATERIALS AND SUPPLIES

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Account Balance Balance

(a) (b) (c)

Department or

Departments which 

(d)

Beginning of Year End of Year

Use Material

1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);

estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.

2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and 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) 170,930,143 188,493,087 Electric

 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) 69,236,794 71,053,270 Electric

 6 Assigned to - Operations and Maintenance

 7 Production Plant (Estimated) 87,614,292 93,357,638 Electric

 8 Transmission Plant (Estimated) 838,582 718,031 Electric

 9 Distribution Plant (Estimated) 16,134,398 16,656,313 Electric

 10 Regional Transmission and Market Operation Plant

(Estimated)

 11 Assigned to - Other (provide details in footnote) 4,322,956 4,620,906 Electric

 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 178,147,022 186,406,158

 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) 349,077,165 374,899,245

FERC FORM NO. 1 (REV. 12-05) Page 227
Schedule Page: 227 Line No.: 11 Column: b

Mining M&S $ 4,170,119

General Plant M&S 152,837

 $ 4,322,956

Schedule Page: 227 Line No.: 11 Column: c

Mining M&S $ 4,477,840

General Plant M&S 143,066

 $ 4,620,906

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Allowances (Accounts 158.1 and 158.2)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

SO2 Allowances Inventory Current Year

(a) (b)

(Account 158.1) No. Amt.

(c)

No.

(d)

Amt.

(e)

1. Report below the particulars (details) called for concerning allowances.

2. Report all acquisitions of allowances at cost.

3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by 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.

2011

 1 Balance-Beginning of Year 170,953.00 156,646.00

 2

 3 Acquired During Year:

 4 Issued (Less Withheld Allow)

 5 Returned by EPA 4,562.00

 6

 7

 8 Purchases/Transfers:

 9 Adjustment 2.00

 10

 11

 12

 13

 14

 15 Total 2.00

 16

 17 Relinquished During Year:

 18 Charges to Account 509 65,838.00

 19 Other:

 20

 21 Cost of Sales/Transfers:

 22 See footnote for details 80,000.00

 23

 24

 25

 26

 27

 28 Total 80,000.00

 29 Balance-End of Year 29,679.00 156,646.00

 30

 31 Sales:

 32 Net Sales Proceeds(Assoc. Co.)

 33 Net Sales Proceeds (Other)

 34 Gains

 35 Losses

Allowances Withheld (Acct 158.2)

 36 Balance-Beginning of Year 2,259.00 2,259.00

 37 Add: Withheld by EPA

 38 Deduct: Returned by EPA

 39 Cost of Sales 2,259.00

 40 Balance-End of Year 2,259.00

 41

 42 Sales:

 43 Net Sales Proceeds (Assoc. Co.)

 44 Net Sales Proceeds (Other)

 45 Gains

 46 Losses

FERC FORM NO. 1 (ED. 12-95) Page 228a
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Allowances (Accounts 158.1 and 158.2)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(f) (j)

No. Amt.

(g)

No.

(h)

Amt.

(i)

No. Amt. No. Amt.

(k) (l) (m)

Future Years Totals

(Continued)

6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on 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.

2012 2013

 156,647.00 156,646.00 4,035,430.00 4,676,322.00 1

 2

 3

 156,645.00 156,645.00 4

 4,562.00 5

 6

 7

 8

 2.00 9

 10

 11

 12

 13

 14

 2.00 15

 16

 17

 65,838.00 18

 19

 20

 21

 80,000.00 22

 23

 24

 25

 26

 27

 80,000.00 28

 156,647.00 156,646.00 4,192,075.00 4,691,693.00 29

 30

 31

 32

 33

 34

 35

 2,259.00 2,259.00 110,921.00 119,957.00 36

 4,528.00 4,528.00 37

 38

 2,269.00 4,528.00 39

 2,259.00 2,259.00 113,180.00 119,957.00 40

 41

 42

 43

 44

 45

 46

FERC FORM NO. 1 (ED. 12-95) Page 229a
Schedule Page: 228 Line No.: 22 Column: b

The names of purchasers/transferees and the number of allowances disposed of during the year ended December 31, 2010 are as

follows:

NRG Power Marketing LLC 25,000

Constellation Energy Commodities Group, Inc. 15,000

Luminant Energy Company LLC 15,000

Sunbury Generation LP 12,000

Macquarie Bank Limited 8,000

Barclays Bank PLC 5,000

 80,000

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Allowances (Accounts 158.1 and 158.2)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

NOx Allowances Inventory Current Year

(a) (b)

(Account 158.1) No. Amt.

(c)

No.

(d)

Amt.

(e)

1. Report below the particulars (details) called for concerning allowances.

2. Report all acquisitions of allowances at cost.

3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by 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.

2011

 1 Balance-Beginning of Year

 2

 3 Acquired During Year:

 4 Issued (Less Withheld Allow)

 5 Returned by EPA

 6

 7

 8 Purchases/Transfers:

 9

 10

 11

 12

 13

 14

 15 Total

 16

 17 Relinquished During Year:

 18 Charges to Account 509

 19 Other:

 20

 21 Cost of Sales/Transfers:

 22

 23

 24

 25

 26

 27

 28 Total

 29 Balance-End of Year

 30

 31 Sales:

 32 Net Sales Proceeds(Assoc. Co.)

 33 Net Sales Proceeds (Other)

 34 Gains

 35 Losses

Allowances Withheld (Acct 158.2)

 36 Balance-Beginning of Year

 37 Add: Withheld by EPA

 38 Deduct: Returned by EPA

 39 Cost of Sales

 40 Balance-End of Year

 41

 42 Sales:

 43 Net Sales Proceeds (Assoc. Co.)

 44 Net Sales Proceeds (Other)

 45 Gains

 46 Losses

FERC FORM NO. 1 (ED. 12-95) Page 228b
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Allowances (Accounts 158.1 and 158.2)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(f) (j)

No. Amt.

(g)

No.

(h)

Amt.

(i)

No. Amt. No. Amt.

(k) (l) (m)

Future Years Totals

(Continued)

6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on 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.

2012 2013

 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

FERC FORM NO. 1 (ED. 12-95) Page 229b
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

Description of Extraordinary Loss

[Include in the description the date of Commission Authorization to use Acc 182.1

and period of amortization (mo, yr to mo, yr).]

Total 

Amount 

of Loss

Losses

Recognised

During Year

WRITTEN OFF DURING YEAR

Account

Charged Amount

Balance at

End of Year

(e) (f)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

FERC FORM NO. 1 (ED. 12-88) Page 230a

20 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

Description of Unrecovered Plant Total 

Amount 

of Charges

Costs

Recognised

During Year

WRITTEN OFF DURING YEAR

Account

Charged Amount

Balance at

End of Year

(e) (f)

and Regulatory Study Costs [Include

in the description of costs, the date of Commission Authorization to use Acc 182.2

and period of amortization (mo, yr to mo, yr)]

21 Unrecovered Plant: Trojan Nuclear 1,809,172 407, 131 1,673,606 135,566

22 Plant located near Portland, OR

23 Date of Retirement: 12/31/1992

24 Date of Commission Authorization:

25 04/20/1993

26 Amortization Period: 01/1993

27 through 01/2011

28

29 Unrecovered Plant: Powerdale 3,479,961 3,479,961

30 Hydro Electric Plant

31 Date of Retirement: 02/08/2007

32 Date of Commission Authorization:

33 05/14/2007

34 Amortization Period: 05/2007

35 through 12/2010

36

37

38

39

40

41

42

43

44

45

46

47

48

FERC FORM NO. 1 (ED. 12-88) Page 230b

49 TOTAL 5,289,133 5,153,567 135,566
Schedule Page: 230 Line No.: 29 Column: d

Account 407, Amortization of property losses, unrecovered plant and regulatory study costs

Account 182.3, Other regulatory assets

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

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.

7. In column (e) report the account credited with the reimbursement received for performing the study.

the Period

 1 Transmission Studies

 2 Aref 591168 14,314 5616000 14,314 4562000

 3 Aref 592473 12,687 5616000 12,687 4562000

 4 Aref 594665 9,062 5616000 9,062 4562000

 5 Aref 599599 12,325 5616000 12,325 4562000

 6 Aref 610299 5,869 5616000 5,869 4562000

 7 Aref 618363 8,833 5616000 8,833 4562000

 8 Aref 645170 3,644 5616000 3,644 4562000

 9 Aref 654674 1,618 5616000 1,618 4562000

 10 Aref 581025 21,160 5616000

 11 Accruals - Customer Studies ( 6,036) 5616000

 12 Aref 575662 203 1070000

 13 Aref 575869 203 1070000

 14 Aref 583608 2,561 1070000

 15 Aref 583614 2,529 1070000

 16 Aref 604216 4,856 1070000

 17 Aref 604662 3,171 1070000

 18 Aref 617716 2,477 1070000

 19 Aref 618940 8,402 1070000

 20 Aref 620282 3,575 1070000

 21 Generation Studies

 22 GIQ0093 319 5617000 319 4562000

 23 GIQ0128 136 5617000 136 4562000

 24 GIQ0169 90 5617000 90 4562000

 25 GIQ0170 90 5617000 90 4562000

 26 GIQ0187 1,234 5617000 1,234 4562000

 27 GIQ0187, 188, 189 16,126 5617000 16,126 4562000

 28 GIQ0188 582 5617000 582 4562000

 29 GIQ0189 76 5617000 76 4562000

 30 GIQ0193 821 5617000 821 4562000

 31 GIQ0234 303 5617000 303 4562000

 32 GIQ0243 372 5617000 372 4562000

 33 GIQ0247 1,571 5617000 1,571 4562000

 34 GIQ0248 60 5617000 60 4562000

 35 GIQ0254 2,924 5617000 2,924 4562000

 36 GIQ0255 13,191 5617000 13,191 4562000

 37 GIQ0258 467 5617000 467 4562000

 38 GIQ0260, 261, 262, 263 40,691 5617000 40,691 4562000

 39 GIQ0268 8,443 5617000 8,443 4562000

 40 GIQ0269 10,739 5617000 10,739 4562000

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2 Aref 621679 3,916 1070000

 3 Aref 624709 9,244 1070000

 4 Aref 626275 4,514 1070000

 5 Aref 630525 2,293 1070000

 6 Aref 635532 5,789 1070000

 7 Aref 637972 1,651 1070000

 8 Aref 637974 5,462 1070000

 9 Aref 637977 4,233 1070000

 10 Aref 637979 4,696 1070000

 11 Aref 648008 28,760 1070000

 12 Aref 648013 5,004 1070000

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 GIQ0274 120 5617000 120 4562000

 23 GIQ0276 36,841 5617000 36,841 4562000

 24 GIQ0277 13,116 5617000 13,116 4562000

 25 GIQ0278 1,052 5617000 1,052 4562000

 26 GIQ0279 1,872 5617000 1,872 4562000

 27 GIQ0283 1,069 5617000 1,069 4562000

 28 GIQ0287 10,565 5617000 10,565 4562000

 29 GIQ0288 435 5617000 435 4562000

 30 GIQ0289 41,082 5617000 41,082 4562000

 31 GIQ0290 40,083 5617000 40,083 4562000

 32 GIQ0291 24,928 5617000 24,928 4562000

 33 GIQ0292 16,089 5617000 16,089 4562000

 34 GIQ0293 13,299 5617000 13,299 4562000

 35 GIQ0294 18,348 5617000 18,348 4562000

 36 GIQ0295 30,806 5617000 30,806 4562000

 37 GIQ0296 3,163 5617000 3,163 4562000

 38 GIQ0297 2,679 5617000 2,679 4562000

 39 GIQ0298 6,959 5617000 6,959 4562000

 40 GIQ0299 5,554 5617000 5,554 4562000

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 GIQ0300 7,402 5617000 7,402 4562000

 23 GIQ0302 4,699 5617000 4,699 4562000

 24 GIQ0303 7,140 5617000 7,140 4562000

 25 GIQ0304 6,078 5617000 6,078 4562000

 26 GIQ0305 7,719 5617000 7,719 4562000

 27 GIQ0306 30,724 5617000 30,724 4562000

 28 GIQ0307 21,285 5617000 21,285 4562000

 29 GIQ0308 634 5617000 634 4562000

 30 GIQ0309 5,360 5617000 5,360 4562000

 31 GIQ0310 13,263 5617000 13,263 4562000

 32 GIQ0311 17,533 5617000 17,533 4562000

 33 GIQ0312 2,816 5617000 2,816 4562000

 34 GIQ0313 43,204 5617000 43,204 4562000

 35 GIQ0314 11,734 5617000 11,734 4562000

 36 GIQ0315 22,995 5617000 22,995 4562000

 37 GIQ0316 23,177 5617000 23,177 4562000

 38 GIQ0317 1,475 5617000 1,475 4562000

 39 GIQ0318 2,041 5617000 2,041 4562000

 40 GIQ0319 20,394 5617000 20,394 4562000

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 GIQ0320 1,841 5617000 1,841 4562000

 23 GIQ0321 4,206 5617000 4,206 4562000

 24 GIQ0322 15,850 5617000 15,850 4562000

 25 GIQ0323 53,682 5617000 53,682 4562000

 26 GIQ0324 41,214 5617000 41,214 4562000

 27 GIQ0325 1,977 5617000 1,977 4562000

 28 GIQ0326 34,067 5617000 34,067 4562000

 29 GIQ0327 3,078 5617000 3,078 4562000

 30 GIQ0328 1,569 5617000 1,569 4562000

 31 GIQ0329 2,910 5617000 2,910 4562000

 32 GIQ0330 5,612 5617000 5,612 4562000

 33 GIQ0331 1,143 5617000 1,143 4562000

 34 GIQ0332 9,958 5617000 9,958 4562000

 35 GIQ0333 6,844 5617000 6,844 4562000

 36 GIQ0334 2,652 5617000 2,652 4562000

 37 GIQ0335 8,666 5617000 8,666 4562000

 38 GIQ0337 5,829 5617000 5,829 4562000

 39 GIQ0338 622 5617000 622 4562000

 40 GIQ0339 3,552 5617000 3,552 4562000

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 GIQ0340 613 5617000 613 4562000

 23 GIQ0341 18,959 5617000 18,959 4562000

 24 GIQ0342 5,547 5617000 5,547 4562000

 25 GIQ0343 9,380 5617000 9,380 4562000

 26 GIQ0344 1,858 5617000 1,858 4562000

 27 GIQ0345 2,506 5617000 2,506 4562000

 28 GIQ0346 6,682 5617000 6,682 4562000

 29 GIQ0347 4,852 5617000 4,852 4562000

 30 GIQ0348 2,709 5617000 2,709 4562000

 31 GIQ0349 10,870 5617000 10,870 4562000

 32 GIQ0350 10,857 5617000 10,857 4562000

 33 GIQ0351 12,468 5617000 12,468 4562000

 34 GIQ0352 2,266 5617000 2,266 4562000

 35 GIQ0353 182 5617000 182 4562000

 36 GIQ0354 2,468 5617000 2,468 4562000

 37 GIQ0355 846 5617000 846 4562000

 38 GIQ0356 1,126 5617000 1,126 4562000

 39 GIQ0357 1,100 5617000 1,100 4562000

 40 GIQ0358 657 5617000 657 4562000

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.4
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

Transmission Service and Generation Interconnection Study Costs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

Period Account Charged

(c)

Reimbursements

Received During

(d)

Account Credited

With Reimbursement

(e)

the Period

(continued)

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 22 GIQ0359 2,104 5617000 2,104 4562000

 23 GIQ0360 2,831 5617000 2,831 4562000

 24 GIQ0361 549 5617000 549 4562000

 25 GIQ0362 489 5617000 489 4562000

 26 GIQ0363 65 5617000 65 4562000

 27 GIQ0364 124 5617000 124 4562000

 28 GIQ0365 46 5617000 46 4562000

 29 Accruals - Customer Studies ( 15,847) 5617000

 30 GIQ0284 9,875 5617000

 31 GIQ0270 12,985 5617000

 32 GIQ0271 8,497 5617000

 33 GIQ0267 18,577 1070000

 34 GIQ0301 41,071 1070000

 35

 36

 37

 38

 39

 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

OTHER REGULATORY ASSETS (Account 182.3)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description and Purpose of Debits CREDITS

Written off During

the Quarter/Year

Account Charged

(a) (c) (d)

Balance at end of

Current Quarter/Year

(e)

Other Regulatory Assets Written off During

the Period

Amount

(f)

1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.

2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be

grouped by classes.

3. For Regulatory Assets being amortized, show period of amortization.

Balance at

Beginning of

Current

Quarter/Year

(b)

 1 DSM Regulatory Asset - CA ( 2,099,141) 865,247 908 1,959,697 -3,193,591

 2 DSM Regulatory Asset - ID 4,072,036 7,547,413 908 6,280,307 5,339,142

 3 DSM Regulatory Asset - UT 28,520,678 47,799,611 908 74,035,776 2,284,513

 4 DSM Regulatory Asset -WA 1,727,139 7,723,507 908, 431 8,855,255 595,391

 5 DSM Regulatory Asset - WY ( 2,468,965) 2,809,153 908, 431 4,341,024 -4,000,836

 6 DSM Regulatory Assets- Accruals 4,977,717 408,419 5,386,136

 7 Alternative Rate For Energy (CARE) - CA 1,396,569 71,694 142 1,214,280 253,983

 8 Transition Plan - OR 2,269,573 19,792 930.2 2,289,365

 9 2006 Transition Plan - OR (3) 4,683,761 920 1,714,502 2,969,259

 10 2006 Transition Plan - WA (3) 318,524 920 318,524

 11 2006 Transition Plan - ID (3) 610,195 920 610,195

 12 2006 Transition Plan - CA 222,772 222,772

 13 2006 Transition Plan - WY (3) 1,062,222 920 1,062,222

 14 Deferred Income Taxes Electric 422,169,290 26,311,488 448,480,778

 15 Deferral of Interest on Uncertain Tax Positions-UT 1,444,909 1,444,909

 16 Deferral of Interest on Uncertain Tax Positions-WY 372,132 372,132

 17 Tax Revenue Requirement Adjustment - WY 99,955 99,955

 18 Sch 781 Direct Access Shopping Incentive ( 68,360) 110,673 407.3, 431 42,313

 19 Glenrock Mine Excluding Reclamation - UT (9) 112,218 930.2 112,218

 20 Deferred Excess Net Power Costs - OR UE116 175,363 1,215 254 176,578

 21 Deferred Excess Net Power Costs - OR 3,526,084 3,526,084

 22 Deferred Excess Net Power Costs/ECAC - CA ( 2,604,371) 4,514,015 1,909,644

 23 Deferred Excess Net Power Costs - WY 2008 9,970,836 59,340 555 10,030,176

 24 Deferred Excess Net Power Costs - WY 2009 1,539,406 3,131,266 555 3,073,730 1,596,942

 25 Deferred Excess Net Power Costs - WY 2010 14,492,513 14,492,513

 26 Deferred Excess Net Power Costs - WA Hydro (3) 4,364,406 282,664 555 1,977,054 2,670,016

 27 Deferred Excess Net Power Costs - ID 2009 2,615,813 232,967 555 2,361,551 487,229

 28 Deferred Excess Net Power Costs - ID 2010 11,434,111 11,434,111

 29 Deferred Excess Net Power Costs - ID 2011 1,035,589 1,035,589

 30 Environmental Costs (10) 7,516,382 2,281,510 925 1,501,251 8,296,641

 31 Environmental Costs - WA (10) ( 591,843) 105,082 925 163,356 -650,117

 32 Reg Asset - Environmental Costs 3,441,141 5,929,721 9,370,862

 33 Cholla Plant Transaction Costs (26) 7,117,962 183,792 557 1,122,425 6,179,329

 34 Washington Colstrip #3 (22) 578,447 456 52,188 526,259

 35 Derivative Net Regulatory Asset 367,301,591 119,993,673 487,295,264

 36 Asset Retirement Obligations Regulatory Difference 64,991,572 17,072,813 230 13,813,374 68,251,011

 37 Pension/Other Postretirement 575,745,416 70,908,399 50,014,094 596,639,721

 38 RTO Grid West N/R - OR (3) 1,034,108 25,468 904 321,528 738,048

 39 RTO Grid West N/R - WY (3) 92,022 904 92,022

 40 RTO Grid West N/R - ID (5) 54,324 904 27,162 27,162

 41 Deferred Independent Evaluator Fee - UT ( 12,573) 557 3,928 -16,501

 42 Deferred Independent Evaluator Fee - OR (1) 1,042,120 409,751 557 912,358 539,513

 43 Deferred Intervenor Funding Grants - ID 61,378 928 17,581 43,797

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232

44 TOTAL 1,550,913,652 398,649,476 212,116,361 1,737,446,767
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

OTHER REGULATORY ASSETS (Account 182.3)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description and Purpose of Debits CREDITS

Written off During

the Quarter/Year

Account Charged

(a) (c) (d)

Balance at end of

Current Quarter/Year

(e)

Other Regulatory Assets Written off During

the Period

Amount

(f)

1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.

2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be

grouped by classes.

3. For Regulatory Assets being amortized, show period of amortization.

Balance at

Beginning of

Current

Quarter/Year

(b)

 1 Deferred Intervenor Funding Grants - OR ( 175,032) 213,506 431 1,392 37,082

 2 BPA Idaho Balancing Account 2,081,580 603,662 2,685,242

 3 Renewable Adjustment Clause (1) - OR 5,196,941 1,918,389 6,485,375 629,955

 4 Goodnoe Hills Settlement - WY (24) 510,000 930.2 21,250 488,750

 5 Lake Side Settlement - WY (38) 1,032,722 930.2 27,627 1,005,095

 6 SB 408 Regulatory Asset - OR (1) 9,770,616 2,160,057 10,835,128 1,095,545

 7 SB 408 Regulatory Asset - MCBIT ( 22,043) 415,568 582,540 -189,015

 8 Chehalis Generating Facility Deferral - WA (6) 18,000,000 3,000,000 15,000,000

 9 Powerdale Decommissioning - ID (10) 313,766 407.3 9,000 304,766

 10 Powerdale Decommissioning - OR (1.5) 917,937 407.3 424,921 493,016

 11 Powerdale Decommissioning - WA 851,788 851,788

 12 Powerdale Decommissioning - WY (1) 188,117 407.3 153,725 34,392

 13 Deferred Advertising Costs - WY 52,198 52,198

 14 Major Plant Additions - UT 15,724,521 15,724,521

 15 Solar Feed-In Tariff Deferral - OR 226,622 226,622

 16 Tax Adj on Postretirement Benefits - CA 383,431 383,431

 17 Tax Adj on Postretirement Benefits - ID 819,988 819,988

 18 Tax Adj on Postretirement Benefits - OR 4,471,643 4,471,643

 19 Tax Adj on Postretirement Benefits - UT 6,284,000 410.1, 283 392,750 5,891,250

 20 Tax Adj on Postretirement Benefits - WA 1,126,592 1,126,592

 21 Tax Adj on Postretirement Benefits - WY 2,121,315 2,121,315

 22 Storm Damage Deferral - CA 1,230,000 1,230,000

 23 Deferred Overburden Cost - ID 684,923 501 435,826 249,097

 24 Deferred Overburden Cost - WY 1,830,954 501 1,165,063 665,891

 25 Regulatory Assets - Reclassifications 7,485,673 254 85,730 7,399,943

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.1

44 TOTAL 1,550,913,652 398,649,476 212,116,361 1,737,446,767
Schedule Page: 232 Line No.: 14 Column: a

Weighted average remaining life is 33 years. Represents deferred income tax assets and liabilities that are associated with income tax

benefits related to certain property-related basis differences and other various differences that PacifiCorp is required to pass on to its

customers in most state jurisdictions.

Schedule Page: 232 Line No.: 20 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 21 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 22 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 23 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 24 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 25 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 27 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 28 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 29 Column: a

Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.

Schedule Page: 232 Line No.: 35 Column: a

Weighted average remaining life is 4 years.

Schedule Page: 232 Line No.: 37 Column: a

Weighted average remaining life is 9 years. Substantially represents amounts not yet recognized as a component of net periodic benefit

cost that are expected to be included in rates when recognized.

Schedule Page: 232 Line No.: 37 Column: d

Pensions and benefits are associated with labor and generally charged to operations and maintenance expense, construction work in

progress and account 228.3, accumulated provision for pensions and benefits.

Schedule Page: 232.1 Line No.: 3 Column: d

Account 440, Residential Sales

Account 442, Commercial and industrial sales

Account 444, Public street and highway lighting

Schedule Page: 232.1 Line No.: 6 Column: d

Account 440, Residential sales

Account 442, Commercial and industrial sales

Account 444, Public street and highway lighting

Schedule Page: 232.1 Line No.: 7 Column: d

Account 440, Residential sales

Account 442, Commercial and industrial sales

Account 444, Public street and highway lighting

Account 426.5, Other deductions

Schedule Page: 232.1 Line No.: 8 Column: d

Account 440, Residential sales

Account 442, Commercial and industrial sales

Account 444, Public street and highway lighting

Schedule Page: 232.1 Line No.: 25 Column: f

The following schedule summarizes regulatory assets reclassifications: 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
 December 31, 2010 

Reclassified from Regulatory Assets to Regulatory Liabilities:

 DSM Regulatory Asset - CA $ 3,193,591 

 DSM Regulatory Asset - WY 4,000,836 

 Deferred Independent Evaluator Fee - UT 16,501 

 SB 408 Regulatory Asset - MCBIT 189,015

 $ 7,399,943 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MISCELLANEOUS DEFFERED DEBITS (Account 186)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description of Miscellaneous Debits CREDITS

Account

(a) (b) (c)

Balance at

End of Year

(d)

Deferred Debits Amount

(e)

Balance at 

Beginning of Year

(f) Charged

1. Report below the particulars (details) called for concerning miscellaneous deferred debits.

2. For any deferred debit being amortized, show period of amortization in column (a)

3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by

classes.

 1 Joseph Settlement (20) 1,110,495 557 137,381 973,114

 2

 3 Lacomb Irrigation (24) 552,450 557 45,720 506,730

 4

 5 Bogus Creek (42) 1,241,840 557 41,280 1,200,560

 6

 7 Mead Phoenix Availability

 8 & Trans Charge (50) 14,134,520 565 377,760 13,756,760

 9

 10 TGS Buyout (23) 156,025 557 15,474 140,551

 11

 12 Hermiston Swap (40) 4,564,178 557 171,694 4,392,484

 13

 14 Deferred Longwall Costs 994,128 2,211,852 151 2,100,584 1,105,396

 15

 16 Point to Point Transmission 2,573,900 2,496,680 142, 557 593,680 4,476,900

 17

 18 Deferred Coal Costs - Wyodak

 19 Settlement (22) 4,357,363 151 335,181 4,022,182

 20

 21 Deferred Coal Costs - Arch

 22 Settlement (3) 1,713,105 151 1,650,075 63,030

 23

 24 Deferred Coal Costs - Naughton

 25 Settlement (7) 8,945,000 151 688,077 8,256,923

 26

 27 Deferred Colstrip Plant Costs 1,085,161 416,000 232 1,161 1,500,000

 28

 29 Jim Boyd Hydro Buyout (11) 338,345 557 82,860 255,485

 30

 31 Credit Agreement Costs (5) 1,507,772 427, 431 456,629 1,051,143

 32

 33 PCRB LOC/SBBPA Costs (5) 473,238 152,493 427 212,602 413,129

 34

 35 PCRB Mode Conversion Costs (10) 261,965 270,482 427 118,961 413,486

 36

 37 '94 Series Restruct. Costs (16) 1,105,412 427 116,981 988,431

 38

 39 Emission Reduction Credits 2,956,980 2,956,980

 40

 41 LGIA LT Transmission Prepaid 3,228,303 1,218,644 1,360,230 3,086,717

 42

 43 Lease Incentives (11) 1,270,348 454 155,119 1,115,229

 44

 45 LT Lease Commissions

 46 Prepaids (10) 739,981 931 90,322 649,659

FERC FORM NO. 1 (ED. 12-94) Page 233

49 TOTAL

47 Misc. Work in Progress

48 Deferred Regulatory Comm.

Expenses (See pages 350 - 351)

 67,302,539 86,483,361
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MISCELLANEOUS DEFFERED DEBITS (Account 186)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description of Miscellaneous Debits CREDITS

Account

(a) (b) (c)

Balance at

End of Year

(d)

Deferred Debits Amount

(e)

Balance at 

Beginning of Year

(f) Charged

1. Report below the particulars (details) called for concerning miscellaneous deferred debits.

2. For any deferred debit being amortized, show period of amortization in column (a)

3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by

classes.

 1 BPA LT Transmission Prepaid 9,593,309 332,014 232 791,362 9,133,961

 2

 3 Lake Side Maint. Prepayment 9,477,588 5,243,161 14,720,749

 4

 5 Chehalis Maint. Prepayment 2,587,071 3,190,535 5,777,606

 6

 7 Currant Creek Maint. Prepayment 1,167,388 5,645,065 107 1,346,843 5,465,610

 8

 9 Other Deferred Debits with

 10 balances less than $100,000 111,674 various 51,128 60,546

 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

FERC FORM NO. 1 (ED. 12-94) Page 233.1

49 TOTAL

47 Misc. Work in Progress

48 Deferred Regulatory Comm.

Expenses (See pages 350 - 351)

 67,302,539 86,483,361
Schedule Page: 233 Line No.: 41 Column: d

Account 232 - Accounts payable

Account 419 - Interest and dividend income

Account 549 - Miscellaneous other power generation expenses

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ACCUMULATED DEFERRED INCOME TAXES (Account 190)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description and Location Balance of Begining

(a) (b) (c)

Balance at End

of Year of Year

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.

2. At Other (Specify), include deferrals relating to other income and deductions.

 1 Electric

 2 Employee Benefits 243,734,412 187,114,591

 3 Derivative Contracts 139,689,181 184,509,824

 4 Regulatory Liabilities 40,091,582 25,903,274

 5

 6

 7 Other 164,002,583 191,062,227

 8 TOTAL Electric (Enter Total of lines 2 thru 7) 587,517,758 588,589,916

 9 Gas

 10

 11

 12

 13

 14

 15 Other

 16 TOTAL Gas (Enter Total of lines 10 thru 15

 17 Other (Specify)

 18 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 587,517,758 588,589,916

Notes

FERC FORM NO. 1 (ED. 12-88) Page 234
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CAPITAL STOCKS (Account 201 and 204)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Stock and Number of shares

(a) (b) (c)

Call Price at 

End of Year

Par or Stated

Value per share

(d)

Name of Stock Series Authorized by Charter

1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing 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.

 1 Common Stock (Account 201) 750,000,000

 2 MidAmerican Energy Holdings Company

 3 indirectly owns all of the shares of

 4 PacifiCorp's outstanding common stock.

 5 Therefore, there is no public market for

 6 PacifiCorp's common stock.

 7

 8 TOTAL COMMON STOCK 750,000,000

 9

 10

 11 Preferred Stock (Account 204):

 12 5% Cumulative Preferred 126,533 100.00 110.00

 13

 14

 15 Serial Preferred, Cumulative: 3,500,000

 16 4.52% Series 100.00 103.50

 17 7.00% Series 100.00

 18 6.00% Series 100.00

 19 5.00% Series 100.00 100.00

 20 5.40% Series 100.00 101.00

 21 4.72% Series 100.00 103.50

 22 4.56% Series 100.00 102.34

 23 No Par Serial Preferred 16,000,000

 24

 25 TOTAL PREFERRED STOCK 19,626,533

 26

 27

 28

 29

 30

 31

 32

 33

 34 Authorized and unissued Capital Stock

 35

 36

 37

 38

 39

 40

 41

 42

FERC FORM NO. 1 (ED. 12-91) Page 250
AS REACQUIRED STOCK (Account 217)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CAPITAL STOCKS (Account 201 and 204) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT

IN SINKING AND OTHER FUNDS

Shares

(g)

Cost

(h)

Shares Amount Shares

(Total amount outstanding without reduction

for amounts held by respondent)

Amount

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

3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory 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.

 357,060,915 3,417,945,896 1

 2

 3

 4

 5

 6

 7

 357,060,915 3,417,945,896 8

 9

 10

 11

 126,243 12,624,300 12

 13

 14

 15

 2,065 206,500 16

 18,046 1,804,600 17

 5,930 593,000 18

 41,908 4,190,800 19

 65,959 6,595,900 20

 65,854 6,585,400 21

 81,326 8,132,600 22

 23

 24

 407,331 40,733,100 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

FERC FORM NO. 1 (ED. 12-88) Page 251
Schedule Page: 250 Line No.: 1 Column: d

This class of stock is not redeemable.

Schedule Page: 250 Line No.: 17 Column: d

This series of preferred stock is not redeemable.

Schedule Page: 250 Line No.: 18 Column: d

This series of preferred stock is not redeemable.

Schedule Page: 250 Line No.: 21 Column: e

Refer to page 108. Important Changes During the Quarter/Year, Item 6. Financing Activities in this Form No. 1 for a discussion of

PacifiCorp's repurchase of certain shares of its preferred stock.

Schedule Page: 250 Line No.: 21 Column: f

See footnote for column (e) line 19.

Schedule Page: 250 Line No.: 22 Column: e

See footnote for column (e) line 19.

Schedule Page: 250 Line No.: 22 Column: f

See footnote for column (e) line 19.

Schedule Page: 250 Line No.: 34 Column: a

Authorizations for the issuance of common stock by PacifiCorp to its immediate corporate parent, PPW Holdings LLC are as follows:

Oregon Public Utility Commission, Docket No. UF-4228, Order No. 06-417, dated July 17, 2006. 

Washington Utilities and Transportation Commission, Docket No. UE-060974, Order No. 1, dated June 28, 2006.

Idaho Public Utilities Commission, Case No. PAC-E-06-7, Order No. 30099, dated July 7, 2006.

As of December 31, 2010, 30,000,000 shares authorized; 30,000,000 available.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line Item Amount (a) (b)

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

No.

Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide 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.

 1 Account 211 Miscellaneous Paid-in Capital

 2 Additional Paid-in Capital

 3 Share based payments 1,973,218

 4 Tax benefit from stock option exercises 14,422,979

 5 Benefit plan separation -3,575,760

 6 Capital contributions 1,089,950,000

 7 Gain on sale of ScottishPower stock 136,208

 8 Qualified production activity tax deduction -1,275,241

 9 Contribution of Intermountain Geothermal 432,552

 10 Gain on repurchase of preferred stock 166,025

 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

FERC FORM NO. 1 (ED. 12-87) Page 253

40 TOTAL 1,102,229,981
Schedule Page: 253 Line No.: 3 Column: b

Represents the fair value of stock options granted by Scottish Power plc for which certain performance measures were met in March

2005. These options became fully vested in May 2005.

Schedule Page: 253 Line No.: 4 Column: b

Represents the income tax deduction attributable to the exercise of stock options granted by Scottish Power plc.

Schedule Page: 253 Line No.: 5 Column: b

Represents the effect of transferring benefit plans to PPM Energy, Inc. as a result of the sale of PacifiCorp by Scottish Power plc.

Schedule Page: 253 Line No.: 6 Column: b

Represents capital contributions to PacifiCorp (with no shares of stock issued) from its indirect parent MidAmerican Energy Holdings

Company ("MEHC"), of which $100,000,000 were made during the year ended December 31, 2010.

Schedule Page: 253 Line No.: 7 Column: b

Represents a realized gain on stock related to separation of PPM Energy, Inc. participants from the deferred compensation plan.

Schedule Page: 253 Line No.: 8 Column: b

Represents amounts associated with IRC Section 199 qualified production activities.

Schedule Page: 253 Line No.: 9 Column: b

Represents contribution of Intermountain Geothermal Company to PacifiCorp from MEHC in March 2006, subsequent to the sale of

PacifiCorp to MEHC. Intermountain Geothermal Company was merged with and into its direct parent, PacifiCorp, on August 31,

2007, with PacifiCorp surviving.

Schedule Page: 253 Line No.: 10 Column: b

Refer to page 108, Important Changes During the Quarter/Year, Item 6. Financing Activities in this Form No. 1 for a discussion of

PacifiCorp's repurchase of certain shares of its preferred stock.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

CAPITAL STOCK EXPENSE (Account 214)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Stock Balance at End of Year

(a) (b)

1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.

2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars

(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.

 1 Common Stock 41,101,062

 2

 3 Preferred Stock:

 4 5.00% 98,049

 5 4.52% Serial 9,676

 6 4.72% Serial 28,596

 7 4.56% Serial 47,177

 8

 9

 10

 11 Refer to page 108, Important Changes During the Quarter/Year, Item 6. Financing Activities

 12 and to page 123, Notes to Financial Statements, Note 14. Preferred Stock in this Form No. 1

 13 for a discussion of PacifiCorp's repurchase of certain shares of its preferred stock.

 14

 15

 16

 17

 18

 19

 20

 21

FERC FORM NO. 1 (ED. 12-87) Page 254b

22 TOTAL 41,284,560
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Obligation, Coupon Rate 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

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

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.

 1 Bonds: (Account 221)

 2 First Mortgage Bonds:

 3

 4 8.271% Series due October 1, 2010 48,972,000

 5 7.978% Series due October 1, 2011 4,422,000

 6 6.900% Series due November 15, 2011 500,000,000 3,567,009

 7 1,735,000 D

 8 8.493% Series due October 1, 2012 19,772,000

 9 8.797% Series due October 1, 2013 16,203,000

 10 5.450% Series due September 15, 2013 200,000,000 1,422,659

 11 232,000 D

 12 4.950% Series due August 15, 2014 200,000,000 1,442,365

 13 728,000 D

 14 8.734% Series due October 1, 2014 28,218,000

 15 8.294% Series due October 1, 2015 46,946,000

 16 8.635% Series due October 1, 2016 18,750,000

 17 8.470% Series due October 1, 2017 19,609,000

 18 5.650% Series due July 15, 2018 500,000,000 3,067,221

 19 905,000 D

 20 5.500% Series due January 15, 2019 350,000,000 2,515,793

 21 2,292,500 D

 22 7.700% Series due November 15, 2031 300,000,000 2,874,150

 23 864,000 D

 24 5.900% Series due August 15, 2034 200,000,000 1,892,365

 25 722,000 D

 26 5.25% Series due June 15, 2035 300,000,000 2,912,055

 27 1,080,000 D

 28 6.10% Series due August 1, 2036 350,000,000 2,908,542

 29 1,141,000 D

 30 5.75% Series due April 1, 2037 600,000,000 589,216

 31 24,000 D

 32

FERC FORM NO. 1 (ED. 12-96) Page 256

33 TOTAL 6,507,262,000 74,175,437
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Obligation, Coupon Rate 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

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

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.

 1 6.25% Series due October 15, 2037 600,000,000 5,127,281

 2 750,000 D

 3 6.35% Series due July 15, 2038 300,000,000 2,290,333

 4 1,671,000 D

 5 6.00% Series due January 15, 2039 650,000,000 6,134,687

 6 6,175,000 D

 7 9.15% Series C Medium-Term Notes due Aug. 9, 2011 8,000,000 75,327

 8 8.95% Series C Medium-Term Notes due Sept. 1, 2011 25,000,000 175,398

 9 8.95% Series C Medium-Term Notes due Sept. 1, 2011 20,000,000 132,118

 10 8.92% Series C Medium-Term Notes due Sept. 1, 2011 20,000,000 188,318

 11 8.29% Series C Medium-Term Notes due Dec. 30, 2011 3,000,000 23,040

 12 8.26% Series C Medium-Term Notes due Jan. 10, 2012 1,000,000 7,649

 13 8.28% Series C Medium-Term Notes due Jan. 10, 2012 2,000,000 13,297

 14 8.25% Series C Medium-Term Notes due Feb. 1, 2012 3,000,000 22,946

 15 8.13% Series E Medium-Term Notes due Jan. 22, 2013 10,000,000 75,827

 16 8.53% Series C Medium-Term Notes due Dec. 16, 2021 15,000,000 115,202

 17 8.375% Series C Medium-Term Notes due Dec. 31, 2021 5,000,000 38,400

 18 8.26% Series C Medium-Term Notes due Jan. 7, 2022 5,000,000 33,243

 19 8.27% Series C Medium-Term Notes due Jan. 10, 2022 4,000,000 30,594

 20 8.05% Series E Medium-Term Notes due Sept. 1, 2022 15,000,000 131,471

 21 8.07% Series E Medium-Term Notes due Sept. 9, 2022 8,000,000 70,118

 22 8.12% Series E Medium-Term Notes due Sept. 9, 2022 50,000,000 438,238

 23 8.11% Series E Medium-Term Notes due Sept. 9, 2022 12,000,000 105,177

 24 8.05% Series E Medium-Term Notes due Sept. 14, 2022 10,000,000 87,648

 25 8.08% Series E Medium-Term Notes due Oct. 14, 2022 26,000,000 208,198

 26 8.08% Series E Medium-Term Notes due Oct. 14, 2022 25,000,000 200,190

 27 8.23% Series E Medium-Term Notes due Jan. 20, 2023 5,000,000 37,914

 28 8.23% Series E Medium-Term Notes due Jan. 20, 2023 4,000,000 30,331

 29 -81,560 P

 30 7.26% Series F Medium-Term Notes due July 21, 2023 27,000,000 246,981

 31 7.26% Series F Medium-Term Notes due July 21, 2023 11,000,000 100,622

 32 7.23% Series F Medium-Term Notes due Aug. 16, 2023 15,000,000 137,211

FERC FORM NO. 1 (ED. 12-96) Page 256.1

33 TOTAL 6,507,262,000 74,175,437
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Obligation, Coupon Rate 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

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

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.

 1 7.24% Series F Medium-Term Notes due Aug. 16, 2023 30,000,000 274,423

 2 6.75% Series F Medium-Term Notes due Sept. 14, 2023 5,000,000 38,250

 3 6.75% Series F Medium-Term Notes due Sept. 14, 2023 2,000,000 15,300

 4 6.72% Series F Medium-Term Notes due Sept. 14, 2023 2,000,000 15,300

 5 6.75% Series F Medium-Term Notes due Oct. 26, 2023 20,000,000 152,326

 6 6.75% Series F Medium-Term Notes due Oct. 26, 2023 16,000,000 121,861

 7 6.75% Series F Medium-Term Notes due Oct. 26, 2023 12,000,000 91,396

 8 6.71% Series G Medium-Term Notes due Jan. 15, 2026 100,000,000 904,467

 9 Subtotal - First Mortgage Bonds 5,768,892,000 59,320,397

 10

 11 Pollution Control Obligations - Secured by Pledged First Mortgage Bonds:

 12

 13 Poll Ctrl Rev Refunding Bonds, Moffat County, CO, Series 1994 40,655,000 874,159

 14 5-5/8% Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1993 8,300,000 228,980

 15 197,125 D

 16 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993A 46,500,000 1,624,793

 17 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993B 16,400,000 625,551

 18 389,500 D

 19 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 21,260,000 510,479

 20 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 8,190,000 209,777

 21 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 121,940,000 3,274,246

 22 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 9,365,000 206,519

 23 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 15,060,000 422,858

 24 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 17,000,000 155,970

 25 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 15,000,000 122,887

 26 105,000 D

 27 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 45,000,000 771,836

 28 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 8,500,000 304,824

 29 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 5,300,000 132,043

 30 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 22,000,000 404,262

 31 Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 400,470,000 10,560,809

 32

FERC FORM NO. 1 (ED. 12-96) Page 256.2

33 TOTAL 6,507,262,000 74,175,437
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Obligation, Coupon Rate 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

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

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.

 1

 2 Pollution Control Obligations - Unsecured

 3

 4 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 9,335,000 167,524

 5 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 6,305,000 151,908

 6 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 22,485,000 242,163

 7 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 11,500,000 84,822

 8 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 70,000,000 660,750

 9 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 45,000,000 872,505

 10 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 50,000,000 422,443

 11 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 45,000,000 380,198

 12 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 41,200,000 351,905

 13 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400,000 225,000

 14 6.150% Environ. Imprvmnt Rev Bonds, Emery County, UT, Series 1996 12,675,000 556,549

 15 178,464 D

 16

 17 Subtotal - Pollution Control Obligations - Unsecured 337,900,000 4,294,231

 18

 19

 20

 21 TOTAL ACCOUNT 221 6,507,262,000 74,175,437

 22

 23

 24 Reacquired Bonds: (Account 222)

 25

 26

 27 Advances from Associated Companies: (Account 223)

 28

 29

 30

 31 Other Long-Term Debt: (Account 224)

 32

FERC FORM NO. 1 (ED. 12-96) Page 256.3

33 TOTAL 6,507,262,000 74,175,437
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Class and Series of Obligation, Coupon Rate 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

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

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.

 1 TOTAL ACCOUNT 224

 2

 3

 4 Long-Term Debt Authorized but Unissued

 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

FERC FORM NO. 1 (ED. 12-96) Page 256.4

33 TOTAL 6,507,262,000 74,175,437
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Nominal Date

of Issue

Date of

Maturity

AMORTIZATION PERIOD

Date From Date To

Outstanding (Total amount outstanding without

reduction for amounts held by respondent)

Interest for Year

Amount

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

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.

11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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

and purpose of the pledge.

14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end 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.

 1

 2

 3

04/15/1992 10/01/2010 04/15/1992 10/01/2010 294,903 4

04/15/1992 10/01/2011 04/15/1992 10/01/2011 412,000 55,667 5

11/15/2001 11/15/2011 11/15/2001 11/15/2011 500,000,000 34,500,000 6

 7

04/15/1992 10/01/2012 04/15/1992 10/01/2012 3,590,000 406,050 8

04/15/1992 10/01/2013 04/15/1992 10/01/2013 4,247,000 452,320 9

09/15/2003 09/15/2013 11/15/2001 09/15/2013 200,000,000 10,900,000 10

 11

08/24/2004 08/15/2014 08/24/2004 08/15/2014 200,000,000 9,900,000 12

 13

04/15/1992 10/01/2014 04/15/1992 10/01/2014 9,301,000 935,367 14

04/15/1992 10/01/2015 04/15/1992 10/01/2015 17,918,000 1,660,480 15

04/15/1992 10/01/2016 04/15/1992 10/01/2016 8,318,000 784,835 16

04/15/1992 10/01/2017 04/15/1992 10/01/2017 9,585,000 873,913 17

07/17/2008 07/15/2018 07/17/2008 07/15/2018 500,000,000 28,250,000 18

 19

01/08/2009 01/15/2019 01/08/2009 01/15/2019 350,000,000 19,250,000 20

 21

11/15/2001 11/15/2031 11/15/2001 11/15/2031 300,000,000 23,100,000 22

 23

08/24/2004 08/15/2034 08/24/2004 08/15/2034 200,000,000 11,800,000 24

 25

06/13/2005 06/15/2035 06/13/2005 06/15/2035 300,000,000 15,750,000 26

 27

08/10/2006 08/01/2036 08/10/2006 08/01/2036 350,000,000 21,350,000 28

 29

03/14/2007 04/01/2037 03/14/2007 04/01/2037 600,000,000 34,500,000 30

 31

 32

FERC FORM NO. 1 (ED. 12-96) Page 257

 6,357,741,000 363,203,396 33
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Nominal Date

of Issue

Date of

Maturity

AMORTIZATION PERIOD

Date From Date To

Outstanding (Total amount outstanding without

reduction for amounts held by respondent)

Interest for Year

Amount

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

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.

11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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

and purpose of the pledge.

14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end 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.

10/03/2007 10/15/2037 10/03/2007 10/15/2037 600,000,000 37,500,000 1

 2

07/17/2008 07/15/2038 07/17/2008 07/15/2038 300,000,000 19,050,000 3

 4

01/08/2009 01/15/2039 01/08/2009 01/15/2039 650,000,000 39,000,000 5

 6

08/09/1991 08/09/2011 08/09/1991 08/09/2011 8,000,000 732,000 7

08/16/1991 09/01/2011 08/16/1991 09/01/2011 25,000,000 2,237,500 8

08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 1,790,000 9

08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 1,784,000 10

12/31/1991 12/30/2011 12/31/1991 12/30/2011 3,000,000 248,700 11

01/09/1992 01/10/2012 01/09/1992 01/10/2012 1,000,000 82,600 12

01/10/1992 01/10/2012 01/10/1992 01/10/2012 2,000,000 165,600 13

01/15/1992 02/01/2012 01/15/1992 02/01/2012 3,000,000 247,500 14

01/20/1993 01/22/2013 01/20/1993 01/22/2013 10,000,000 813,000 15

12/16/1991 12/16/2021 12/16/1991 12/16/2021 15,000,000 1,279,500 16

12/31/1991 12/31/2021 12/31/1991 12/31/2021 5,000,000 418,750 17

01/08/1992 01/07/2022 01/08/1992 01/07/2022 5,000,000 413,000 18

01/09/1992 01/10/2022 01/09/1992 01/10/2022 4,000,000 330,800 19

09/18/1992 09/01/2022 09/18/1992 09/01/2022 15,000,000 1,207,500 20

09/09/1992 09/09/2022 09/09/1992 09/09/2022 8,000,000 645,600 21

09/11/1992 09/09/2022 09/11/1992 09/09/2022 50,000,000 4,060,000 22

09/11/1992 09/09/2022 09/11/1992 09/09/2022 12,000,000 973,200 23

09/14/1992 09/14/2022 09/14/1992 09/14/2022 10,000,000 805,000 24

10/15/1992 10/14/2022 10/15/1992 10/14/2022 26,000,000 2,100,800 25

10/15/1992 10/14/2022 10/15/1992 10/14/2022 25,000,000 2,020,000 26

01/20/1993 01/20/2023 01/20/1993 01/20/2023 5,000,000 411,500 27

01/29/1993 01/20/2023 01/29/1993 01/20/2023 4,000,000 329,200 28

 29

07/22/1993 07/21/2023 07/22/1993 07/21/2023 27,000,000 1,960,200 30

07/22/1993 07/21/2023 07/22/1993 07/21/2023 11,000,000 798,600 31

08/16/1993 08/16/2023 08/16/1993 08/16/2023 15,000,000 1,084,500 32

FERC FORM NO. 1 (ED. 12-96) Page 257.1

 6,357,741,000 363,203,396 33
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Nominal Date

of Issue

Date of

Maturity

AMORTIZATION PERIOD

Date From Date To

Outstanding (Total amount outstanding without

reduction for amounts held by respondent)

Interest for Year

Amount

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

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.

11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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

and purpose of the pledge.

14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end 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.

08/16/1993 08/16/2023 08/16/1993 08/16/2023 30,000,000 2,172,000 1

09/14/1993 09/14/2023 09/14/1993 09/14/2023 5,000,000 337,500 2

09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,000,000 135,000 3

09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,000,000 134,400 4

10/26/1993 10/26/2023 10/26/1993 10/26/2023 20,000,000 1,350,000 5

10/26/1993 10/26/2023 10/26/1993 10/26/2023 16,000,000 1,080,000 6

10/26/1993 10/26/2023 10/26/1993 10/26/2023 12,000,000 810,000 7

01/23/1996 01/15/2026 01/23/1996 01/15/2026 100,000,000 6,710,000 8

 5,619,371,000 349,981,485 9

 10

 11

 12

11/17/1994 05/01/2013 11/17/1994 05/01/2013 40,655,000 353,792 13

11/15/1993 11/01/2021 11/15/1993 11/01/2021 8,300,000 476,835 14

 15

11/15/1993 11/01/2023 11/15/1993 11/01/2023 46,500,000 2,683,050 16

11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,400,000 942,180 17

 18

11/17/1994 11/01/2024 11/17/1994 11/01/2024 21,260,000 168,760 19

11/17/1994 11/01/2024 11/17/1994 11/01/2024 8,190,000 73,010 20

11/17/1994 11/01/2024 11/17/1994 11/01/2024 121,940,000 1,005,483 21

11/17/1994 11/01/2024 11/17/1994 11/01/2024 9,365,000 74,924 22

11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,000 137,933 23

01/01/1988 01/01/2014 01/01/1988 01/01/2014 17,000,000 680,352 24

12/01/1984 12/01/2014 12/01/1984 12/01/2014 15,000,000 600,357 25

 26

01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,000,000 953,494 27

12/01/1986 12/01/2016 12/01/1986 12/01/2016 8,500,000 359,450 28

11/17/1995 11/01/2025 11/17/1995 11/01/2025 5,300,000 224,251 29

11/17/1995 11/01/2025 11/17/1995 11/01/2025 22,000,000 953,747 30

 400,470,000 9,687,618 31

 32

FERC FORM NO. 1 (ED. 12-96) Page 257.2

 6,357,741,000 363,203,396 33
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Nominal Date

of Issue

Date of

Maturity

AMORTIZATION PERIOD

Date From Date To

Outstanding (Total amount outstanding without

reduction for amounts held by respondent)

Interest for Year

Amount

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

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.

11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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

and purpose of the pledge.

14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end 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.

 1

 2

 3

09/29/1992 12/01/2020 09/29/1992 12/01/2020 9,335,000 109,784 4

09/29/1992 12/01/2020 09/29/1992 12/01/2020 6,305,000 74,393 5

09/29/1992 12/01/2020 09/29/1992 12/01/2020 22,485,000 263,488 6

01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,500,000 89,883 7

07/25/1990 07/01/2015 07/25/1990 07/01/2015 70,000,000 535,882 8

05/23/1991 07/01/2015 05/23/1991 07/01/2015 45,000,000 365,100 9

01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,000,000 437,603 10

01/01/1988 01/01/2018 01/01/1988 01/01/2018 45,000,000 356,956 11

01/01/1988 01/01/2018 01/01/1988 01/01/2018 41,200,000 323,737 12

12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400,000 197,954 13

09/24/1996 09/01/2030 09/24/1996 09/01/2030 12,675,000 779,513 14

 15

 16

 337,900,000 3,534,293 17

 18

 19

 20

 6,357,741,000 363,203,396 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

FERC FORM NO. 1 (ED. 12-96) Page 257.3

 6,357,741,000 363,203,396 33
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Nominal Date

of Issue

Date of

Maturity

AMORTIZATION PERIOD

Date From Date To

Outstanding (Total amount outstanding without

reduction for amounts held by respondent)

Interest for Year

Amount

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

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.

11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, 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

and purpose of the pledge.

14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end 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.

 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

FERC FORM NO. 1 (ED. 12-96) Page 257.4

 6,357,741,000 363,203,396 33
Schedule Page: 256.3 Line No.: 21 Column: h

Refer to page 108, Important Changes During the Quarter/Year, Item 6, and Notes to Financial Statements of this Form No. 1 for a 

discussion of PacifiCorp's long-term debt.

Schedule Page: 256.4 Line No.: 4 Column: a

In December 2010, PacifiCorp filed a shelf registration statement with the United States Securities and Exchange Commission on

Form S-3 covering future first mortgage bond issuances through December 2013.

For authorization for the issuance of long-term debt ($2.0 billion authorized; $2.0 billion available as of December 31, 2010), refer to

page 108, Important Changes During the Quarter/Year, Item 6, of this Form No. 1. 

Authorization to borrow the proceeds of pollution control revenue refunding bonds issued (total of $300,345,000 authorized and

available as of December 31, 2010) by the counties of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming; 

Sweetwater, Wyoming; and Moffat, Colorado.

Authorization to borrow the proceeds of new pollution control revenue bonds issued (total of $150,000,000 authorized and available as

of December 31, 2010) by one or more of the following counties or municipalities: Emery, Utah; Converse, Wyoming; Lincoln,

Wyoming; Sweetwater, Wyoming; City of Gillette, Wyoming; Navajo County, Arizona; and Routt County, Colorado is as follows:

 Oregon Public Utility Commission, Docket No. UF-4250, Order No. 08-382, dated July 29, 2008.

 Idaho Public Utilities Commission, Case No. PAC-E-08-05, Order No. 30606, dated August 4, 2008.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Particulars (Details)

(a) (b)

Line Amount 

No.

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.

 1 Net Income for the Year (Page 117) 566,414,836

 2

 3

 4 Taxable Income Not Reported on Books

 5

 6

 7

 8 Other 186,118,747

 9 Deductions Recorded on Books Not Deducted for Return

 10

 11

 12

 13 Other 1,106,402,210

 14 Income Recorded on Books Not Included in Return

 15

 16

 17

 18 Other 154,071,658

 19 Deductions on Return Not Charged Against Book Income

 20

 21

 22

 23

 24

 25 Other 3,018,805,017

 26 State Tax Deductions 6,881,135

 27 Federal Tax Net Income -1,307,059,747

 28 Show Computation of Tax:

 29

 30 Federal Income Tax at 35.00% -457,470,911

 31 Provision to Return Adjustment 25,508,786

 32 Tax Reserve Changes -1,467,224

 33 Renewable Electricity Production Tax Credits -55,464,174

 34 Mining Rescue Training Credits -72,211

 35 Research & Experimentation Credits -71,195

 36 Foreign Tax Credit -29,612

 37 Fuel Tax Credit -16,667

 38

 39

 40

 41 Federal Income Tax Accrual -489,083,208

 42

 43

 44

FERC FORM NO. 1 (ED. 12-96) Page 261
Schedule Page: 261 Line No.: 8 Column: a

Particulars (Details) Amounts

PacifiCorp Minerals, Inc. (PMI) Dividend Gross Up for Foreign Tax Credit 29,612 

Sec. 481a Adjustment - Repair Deduction 16,316,468 

CIAC 46,836,991 

Reimbursements 6,694,692 

Avoided Costs 73,561,100 

Deferred Excess Net Power Costs - WY 08 9,970,836 

Deferred Excess Net Power Costs - WA Hydro 1,694,391 

OR _RCAC Sep-Dec 07 Deferred 4,566,986 

OR SB 408 Recovery 8,675,071 

NW Power Act-WA 579,420 

Regulatory Liability - Tax Revenue Adjustment - UT 49,234 

Regulatory Liability - WA Low Energy Program 241,237 

Regulatory Liability - OR Balance Consol 2,626,320 

Reg Liability - Sale of Renewable Energy Credit - OR 3,922,178 

Regulatory Liability - OR Energy Conservation Charge 1,516,395 

Regulatory Liability - Blue Sky Program OR 248,691 

Regulatory Liability - Blue Sky Program WA 8,148 

Regulatory Liability - Blue Sky Program UT 185,811 

Regulatory Liability - Sale of Renewable Energy Credits - WY 3,594,057 

Def Regulatory Asset-Transmission Service Deposit 419,175 

Bear River Settlement Agreement 369,257 

Unearned Joint Use Pole Contact Revenue 20,353 

MCI FOG Wire Lease 668 

Bridger Coal Company Gain/Loss on Assets Disposed 166,776 

Bridger Coal Company Reclamation Trust Earnings - PMI 1,727,115 

BCC Money Market Interest Income - PMI 8 

Equity Earnings in Subsidiaries 2,097,757

 Total $ 186,118,747 

Schedule Page: 261 Line No.: 13 Column: a

Particulars (Details) Amounts

Fed/State Tax Expense 209,955,393 

Fed/State Tax Expense-Interest 2,035,366 

Capitalized labor and benefits costs for Power tax input - Permanent 805,108 

Meals & Entertainment 1,050,493 

Penalties- PMI 203,437 

Lobbying expenses 2,493,024 

Meals & Entertainment - Bridger Coal 9,585 

MEHC Insurance Services - Premium 6,969,001 

Mining Rescue Training Credit Addback - PacifiCorp 44,658 

PMI Fuel Tax Cr 16,667 

Non-deductible post-retirement costs 5,520,000 

Mine Rescue Training Credit Addback - PMI 27,553 

Capitalized labor and benefits costs for Power tax input - Temporary 13,493,191 

Book Depreciation 566,450,834 

Book Depreciation - PMI 17,814,653 

Capitalization of Test Energy 555,842 

Book Cost Depletion - Addback 2,152,540

May 2000 Transition Plan Costs-OR 2,269,573 

Glenrock Excluding Reclamation-UT 112,218 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Regulatory Asset - Pension Liab Adj. 20,280,280 

Regulatory Asset - Post Ret. Liab. 14,315,000 

Environmental Costs - WA 58,274 

Cholla Plant Transaction Costs-APS Amortization 1,122,425 

WA Disallowed Colstrip #3-Write-off 52,188 

Def Regulatory Asset-OR Def Net Power Costs 175,363 

Regulatory Asset - Lake Side Liquidation 27,627 

Goodnoe Hills Liquidation Damages - WY 21,250 

RTO Grid West Notes Receivable - OR 296,060 

RTO Grid West Notes Receivable - WY 92,022 

RTO Grid West Notes Receivable - ID 27,162 

Regulatory Asset - Pension MMT -UT 283,176 

Regulatory Asset - Post -Ret MMT -OR 249,393 

Regulatory Asset - Post -Ret MMT -WY 308,642 

Regulatory Asset - Post - Ret MMT -UT 278,648 

Regulatory Asset - Post - Ret MMT -CA 17,235 

Regulatory Asset-Deferred OR Independent Evaluator Fees 502,606 

Unrecovered Plant - Powerdale 103,976 

Deferred UT Independent Evaluation Fee 3,927 

ID MEHC 2006 Transition Costs 610,194 

WY - 2006 Transition Severance Costs 1,062,222 

WA - Chehalis Plant Revenue Requirement 3,000,000 

Deferred Regulatory Expense 17,580 

Weatherization 28,318,709 

Reg Asset - SB 1149 Balance Reclass 68,360 

Reg Asset - Other - Balance Reclass 39,320 

Reg Asset - Def NPC Balance Reclass 2,604,370 

Trojan Decommissioning Costs - Regulatory 1,901,813 

Coal Pile Inventory Adjustment 3,741,527 

Prepaid Taxes - OR PUC 354,528 

Prepaid Taxes - UT PUC 288,268 

Other Prepaid 1,096,630 

RTO Grid West Note Receivable - w/o - WA 46,941 

TGS Buyout 15,474 

Joseph Settlement 137,381 

Hermiston Swap 171,693 

Western Coal Carrier Postretirement Benefit Accrual 1,702,000 

Derivatives - Current 94,838,151 

Post Merger Loss-Reacquisition Debt - Addback 2,331,323 

ARO Regulatory Liabilities 248,448 

Non-ARO Liability - Regulatory Liability 26,654,196 

Regulatory liability BPA balancing accounts 756,054 

OR Regulatory Asset/Liability Consolidation 61,152 

CA-California Alternative Rate for Energy Program (CARE) 1,142,586 

March 2006 Transition Plan Costs - WA 318,524 

Vacation Accrual - Cash Basis (2.5 months) 815,994 

Deferred Compensation Accrual - Cash Basis 14,958 

Derivatives - noncurrent 23,263,199 

ARO Liability 7,523,374 

Distribution O&M Amortization of Write-off 2,872,313 

PMI-Fuel Cost Adjustment 3,007,257 

Bad Debts Allowance - Cash Basis 1,314,913 

Deferred Coal Cost - Arch 1,650,075 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Rogue River - Habitat Enhancement Liability 15,350 

Lewis River Settlement Agreement 168,368 

Other Environmental Liabilities 2,460,845 

N. Umpqua Settlement Agreement 1,285,817 

Umpqua Settlement Agreement 381,866 

Accrued Insurance Premium Tax 176,436 

Reverse Accrued Final Reclamation 214,463 

Injuries and Damages Accrual - Cash Basis 1,011,129 

Post Employment Benefits Book Reserve 1,581,001 

Sec. 263A Inventory Change - PMI 121,584 

Vacation Accrual - PMI 17,490 

PMI Pre-Stripping Costs 906,977 

Pension Liability - Boilermaker Trust - PMI 8,605,606 

Reserve on Pension Boilermaker Trust - PMI 4,302,803 

Bridger Coal Company Section 471 Adjustment - PMI 1,071,313 

Bridger Coal Company Extraction Taxes Payable - PMI 1,897,245

 Total $ 1,106,402,210 

Schedule Page: 261 Line No.: 18 Column: a

Particulars (Details) Amounts

Medicare Subsidy (8,123,000)

Bridger Coal Tax Exempt Interest Income (25,929)

AFUDC (118,429,747)

Basis Intangible Difference (5,489,877)

Book Gain/Loss on Land Sales (3,034,342)

Regulatory Asset balance reclass (2,626,320)

Trojan Decommissioning Costs - WA (275,765)

Trojan Decommissioning Costs - OR (67,953)

781 Shopping Incentive (68,360)

Trapper Mining Stock Basis (350,474)

Regulatory Liability -Blue Sky Program CA (48,900)

Regulatory Liability - Blue Sky Program ID (26,201)

Regulatory Liability - Blue Sky Program WY (21,143)

Regulatory Liability - CA Gain on Sale of Asset (41,280)

SMUD Revenue Imputation - UT regulatory liability (10,988,748)

UT DSM - SMUD Offset (2,850,000)

Willow Wind Account Receivable (7,547)

Def Regulatory Asset-Foote Creek Contract (137,640)

Tenant Lease Allow - PSU Call Center (48,156)

Duke/Hermiston Contract Renegotiation (754,839)

Deferred Revenue - Citibank (500)

Redding Contract - Prepaid (549,996)

Unrealized Gain/Loss from Trading Securities (104,941)

 Total $ (154,071,658)

Schedule Page: 261 Line No.: 25 Column: a

Particulars (Details) Amounts

Book Depreciation Allocated to Medicare and M&E (234,743)

Tax Percentage Depletion - Blundell Steam Field (Prior IGC) (446,104)

PPL Pre - 1943 Preferred Stock Div - Deduction (381,063)

Penalties (418,323)

Utah Deferred Comp / COLI (4,170,868)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
MEHC Insurance Services - Receivable (16,311,944)

Dividend Received Deduction - PMI (190,159)

PMI Overriding Coal Royalty % Depletion - PacifiCorp (13,882)

Repair Deduction (110,465,957)

Tax Depreciation (2,462,905,267)

Depreciation (Tax Depreciation M-1) - PMI (27,643,239)

Capitalized Depreciation (5,038,044)

§1031 Like Kind Exchange (15,303)

Mine Safety Sec 179E Election ~PPW (1,042,374)

Mine Safety Sec 179E Election ~PMI (8,039)

Gain / (Loss) on Prop. Disposition (13,920,178)

Coal Mine Development (421,752)

Coal Mine Extension (651,766)

Removal Costs (43,232,515)

Cholla SHL-NOPA (Lease Amortization) (82,539)

ARO - reclass to ARO liabilities (6,609,132)

ARO - reclass to regulatory assets/liability & ARO liability (26,654,196)

Tax Percentage Depletion - Deduction (512,714)

Tax Depletion (169,961)

ARO Regulatory Assets (1,162,691)

Environmental Clean-up Accrual (6,709,980)

Cholla Plant Transaction Costs - APS Amortization - ID (32,973)

Cholla Plant Transaction Costs - APS Amortization - OR (53,813)

Cholla Plant Transaction Costs - APS Amortization - WA (97,006)

Deferred Intervener Funding Grants (212,113)

Contra Pension Regulatory Asset MMT & CTG - OR (699,514)

Contra Pension Regulatory Asset MMT & CTG - WY (1,370,277)

Contra Pension Regulatory Asset CTG - UT (5,067,634)

Contra Pension Regulatory Asset MMT & CTG - CA (37,036)

Contra Pension Regulatory Asset CTG - WA (865,074)

Powerdale Decommissioning Reg Asset - ID (304,766)

Powerdale Decommissioning Reg Asset - OR (493,016)

Powerdale Decommissioning Reg Asset - WA (851,788)

CA - January 2010 Storm Costs (1,230,000)

Powerdale Decommissioning Reg Asset - WY (34,392)

ID - Deferred Overburden Costs (249,096)

WY - Deferred Overburden Costs (665,891)

WY - Deferred Advertising Costs (52,198)

Reg Asset - Utah MPA (15,724,521)

Reg Asset - OR Solar Feed-In Tariff (226,622)

Deferred Excess Net Power Costs-CA (4,514,014)

Deferred Excess Net Power Costs - WY 09 and After (14,550,049)

Deferred Excess Net Power Costs - OR (3,526,084)

Deferred Excess Net Power Costs - ID 09 (10,341,116)

OR - MEHC Transition Service Costs (2,969,259)

Reg Asset MEHC Transition Service Costs - CA (222,772)

Deferred Coal Costs - Naughton Contract Settlement (8,256,923)

Idaho Customer Balancing Account (603,662)

Regulatory asset - Net Derivatives (119,993,673)

Prepaid Taxes - ID PUC (25,946)

Prepaid Taxes - Property Taxes (4,907,666)

WY Joint Water Board Reserve - Deduction (75,000)

Wasach workers comp reserve (96,960)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.4
Reg Liability - Tax Revenue Adjustment - WY (99,955)

OR Rate Refunds (79,965)

WA Rate Refunds (228,659)

Regulatory Liability - UT Home Energy Lifeline (210,493)

Reg Liability - Other - Balance Reclass (39,320)

Reg Liability - Def NPC Balance Reclass (2,604,370)

Reg Liability - SB 1149 Balance Reclass (68,360)

Oregon Gain on Sale (385,621)

Property Insurance (same as Injuries & Damages) (109,564)

Regulatory Liability - Deferred Benefit Arch Settlement (1,173,017)

Bonus Liability - Electric - Cash Basis (2.5 months) (37,586)

Pension / Retirement Accrual - Cash Basis (120,181)

Severance Accrual - Cash Basis (24,245)

Pension Liability (58,346,300)

Post-Retirement Liability (14,431,488)

SERP Liability (697,207)

Malin SHL (Tax Int. - Tax Rent + Book Depreciation) (3,115)

M&S Inventory Write-Off (168,634)

R & E - Sec.174 Deduction (2,950,928)

Accrued Royalties (1,014,993)

Misc. Current and Accrued Liability (67,024)

Amortization NOPAs 99-00 RAR (58,446)

Coal Mine Extension Costs-PP&E - PMI (3,951,514)

Coal Mine Development-PMI (55,120)

PMI Development Cost Amortization (3,012,969)

Bridger Coal Company Underground Mine Cost Depletion (164,607)

Bridger Coal Company Mine Reclamation Costs - PMI (937,749)

 Total $ (3,018,805,017)

Schedule Page: 261 Line No.: 41 Column: b

Berkshire Hathaway Inc. includes PacifiCorp in its United States federal income tax return. PacifiCorp's provision for income taxes has

been computed on a stand-alone basis.

Names of group members who will file a consolidated Federal Tax Return:

Under MEHC:

PPW Holdings LLC Sub-Group:

PacifiCorp

PPW Holdings LLC

PacifiCorp Sub-Group:

Centralia Mining Company

Energy West Mining Company

Glenrock Coal Company

Interwest Mining Company

Pacific Minerals, Inc.

PacifiCorp Environmental Remediation Company

PacifiCorp Investment Management, Inc.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.5
MEHC Sub-Group:

Alaska Gas Transmission Company, LLC FFR, Inc

Allerton Capital, Ltd First Realty, Ltd

American Pacific Finance Company First Reserve Insurance, Inc

American Pacific Finance Company II For Rent, Inc

Arizona Home Services, L.L.C. HMSV Financial Services, Inc

BG Energy Holding LLC HN Heritage Title Holdings, LLC

BG Energy LLC HN Insurance Holdings, LLC

CalEnergy Generation Operating Company HN Mortgage, LLC

CalEnergy Holdings, Inc HN Real Estate Group N.C., Inc.

CalEnergy Imperial Valley Company, Inc. HN Real Estate Group, LLC

CalEnergy International Services, Inc HN Referral Corporation

CalEnergy International, Inc HomeServices Financial Holdings, Inc

CalEnergy Minerals Development LLC HomeServices Financial, LLC

CalEnergy Minerals LLC HomeServices Financial-Iowa, LLC

CalEnergy Pacific Holdings Corp HomeServices Insurance, Inc

CalEnergy UK Inc HomeServices of Alabama, Inc.

Capitol Intermediary Company HomeServices of America, Inc

Capitol Land Exchange, Inc HomeServices of California, Inc

Capitol Title Company HomeServices of Florida, Inc

CBEC Railway, Inc HomeServices of Illinois d/b/a Koenig & Strey GM

CBSHome Real Estate Company HomeServices of Iowa, Inc

CBSHome Real Estate of Iowa, Inc HomeServices of Kentucky Real Estate Academy, LLC

CBSHome Relocation Services, Inc HomeServices of Kentucky, Inc

CE Administrative Services, Inc HomeServices of Nebraska, Inc

CE Electric (NY), Inc HomeServices of Nevada, Inc

CE Electric, Inc HomeServices of the Carolinas, Inc

CE Exploration Company HomeServices Referral Network, LLC

CE Geothermal, Inc. HomeServices Relocation, LLC

CE Geothermal, LLC HSR Equity Funding, Inc

CE Indonesia Geothermal, Inc Huff Commercial Group, LLC

CE International Investments, Inc Huff Realty Insurance, LLC

CE Obsidian Energy LLC Huff-Drees Realty, Inc.

CE Obsidian Holding LLC IMO Company, Inc

CE Power, Inc InsuranceSouth, LLC

CE/TA LLC InterCoast Capital Company

Champion Realty, Inc InterCoast Energy Company

Chancellor Title Services, Inc Iowa Realty Company, Inc

Cimmred Leasing Company Iowa Realty Insurance Agency, Inc

Columbia Title of Florida, Inc Iowa Title Company

Constellation Energy Holdings LLC J.S. White Associates, Inc

Cordova Energy Company LLC JBRC, Inc.

Cordova Funding Corporation Jenny Pruitt & Associates

Dakota Dunes Development Company Jim Huff Realty, Inc.

DCCO, Inc JP & A, Inc

Edina Financial Services, Inc JRHBW Realty, Inc d/b/a RealtySouth

Edina Realty Insurance, LLC Kansas City Title, Inc

Edina Realty Referral Network, Inc Kentucky Residential Referral Service, LLC

Edina Realty Relocation, Inc Kern River Funding Corporation

Edina Realty Title, Inc Kern River Gas Transmission Company

Edina Realty, Inc KR Acquisition 1, LLC

Esslinger-Wooten-Maxwell, Inc KR Acquisition 2, LLC

E-W-M Referral Services, Inc. KR Holding, LLC

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.6
MEHC Sub-Group (continued):

Larabee School of Real Estate & Insurance Pickford Holdings LLC

M & M Ranch Acquisition Company, LLC Pickford Real Estate, Inc

M & M Ranch Holding Company, LLC Pickford Services Company, Inc

MEC Construction Services Company Plaza Financial Services, L.L.C.

MEHC America Transco, LLC Plaza Mortgage Services, L.L.C.

MEHC Insurance Services Ltd. Preferred Carolinas Realty, Inc

MEHC Investment, Inc Preferred Carolinas Title Agency, L.L.C.

MEHC Merger Sub Inc Professional Referral Organization, Inc

MEHC Texas Transco, LLC Quad Cities Energy Company

MHC Investment Company Real Estate Links, LLC

MHC, Inc Real Estate Referral Network, inc

Mid-America Referral Network, Inc. Reece & Nichols Alliance, Inc

MidAmerican Comercial R.E. Services, Inc Reece & Nichols Realtors, Inc

MidAmerican Energy Company Referral Company of North Carolina, Inc

MidAmerican Energy Holdings Company RHL Referral Company, L.L.C.

MidAmerican Energy Machining Services LLC Roberts Brothers, Inc

MidAmerican Funding, LLC Roy H. Long Realty Company, Inc

MidAmerican Nuclear Energy Company, LLC Safe Harbor Holding Company, LLC

MidAmerican Nuclear Energy Holdings Co., LLC Salton Sea Minerals Corporation

MidAmerican Transmission, LLC San Diego PCRE, Inc

Midland Escrow Services, Inc Semonin Realtors, Inc

Midwest Capital Group, Inc Southwest Relocation, LLC

Midwest Gas Company The Escrow Firm

MWR Capital, Inc The Referral Company

Nebraska Land Title & Abstract Company TitleSouth, LLC

NNGC Acquisition, LLC Trinity Mortgage Partners, Inc

Northern Aurora Inc Two Rivers, Inc

Northern Natural Gas Company United Settlement Services, L.C.

Pickford Escrow Company, Inc West Valley Holdings, LLC

Pickford Golden State Member LLC

With respect to members of the MEHC Sub-Group, MEHC requires all subsidiaries to pay or receive from MEHC an amount of tax

based primarily on the stand-alone method of allocation. The computation includes all tax benefits from tax deductions from costs borne

by utility customers.

Berkshire Hathaway Inc. Sub-Group:

21 SPC, Inc. Agile Manufacturing, Inc.

21st Communities, Inc. AJF Warehouse Distributors, Inc.

21st Mortgage Corporation AL/TEX Homes, Inc.

AAS-Lunken, Inc. Albecca, Inc.

Acme Brick Company All Bilt Uniforms

Acme Brick DFW, Inc. Alpha Cargo Motor Express, Inc.

Acme Brick Sales Company Ambucor Health Solutions, Inc.

Acme Building Brands, Inc. American All Risk Insurance Services Inc.

Acme Investment Company American Centennial Insurance Company

Acme Management Company American Commercial Claims Administrators Inc.

Acme Ochs Brick and Stone American Dairy Queen Corporation

Acme Services Company, L.P. American Employers Group, Inc.

Adalet/Scott Fetzer Company American Tile Supply, Inc

AEG Processing Center No. 35, Inc. Apeks Apparel, Inc.

AEG Processing Center No. 58, Inc. Applied Group Insurance Holdings, Inc.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.7
Berkshire Hathaway Inc. Sub-Group (continued):

Applied Investigations Inc. California Insurance Company

Applied Logistics, Inc. Camp Manufacturing Company

Applied Premium Finance, Inc. Campbell Hausfeld/Scott Fetzer Company

Applied Risk Services of New York, Inc. Carefree/Scott Fetzer Company

Applied Risk Services, Inc. Cavalier Homes, Inc.

Applied Underwriters, Inc. Central States Indemnity Co. of Omaha

Atlanta International Insurance Company Central States of Omaha Companies, Inc.

AU Captive Risk Assurance Co. CG Service, Inc.

AU Captive Risk Assurance Co., Inc. Chatwell, Inc.

AU Holding Company, Inc. Chippewa Shoe Company

B. Lippman Citadel Insurance Company

Bayport Systems, Inc. CJE II, Inc.

Ben Bridge Jeweler, Inc. Claims Services, Inc.

Benjamin Moore & Co. Clayton Commercial Buildings, Inc.

Berkshire Hathaway Assurance Corporation Clayton Homes, Inc.

Berkshire Hathaway Credit Corporation CMH Capital, Inc.

Berkshire Hathaway Finance Corporation CMH Hodgenville, Inc.

Berkshire Hathaway Inc. (Common Parent) CMH Homes, Inc.

Berkshire Hathaway Life Insurance Company of Nebr. CMH Manufacturing West, Inc.

BH Columbia Inc. CMH Manufacturing, Inc.

BH Finance, Inc. CMH of KY, Inc.

BH Shoe Holdings, Inc. CMH Parks, Inc.

BHG Structured Settlements, Inc. CMH Services, Inc.

BHR Inc. CMH Set and Finish, Inc.

BHSF, Inc. Cologne Reinsurance Company Of America

Blue Chip Stamps Cologne Services Corporation

BN Leasing Corporation Columbia Insurance Company

BNJ NetJets, Inc. Combined Claims Services, Inc.

BNSF Communications, Inc. Command Uniforms

BNSF Logistics International, Inc. Commercial Casualty Insurance Company

BNSF Railway Company Commercial General Indemnity, Inc.

BNSF Railway International Services, Inc. Commonwealth Uniforms Inc.

BNSF Spectrum, Inc. Complementary Coatings Corporation

Boat America Corporation Continental Divide Insurance Company

Boat U.S, Inc. Continental Indemnity Company

Boat U.S. Travel International, Ltd. Corbond Corporation

Boot Royalty Company Cornhusker Casualty Company

Borsheim Jewelry Company, Inc. Cort Business Services

BR Agency, Inc. Coverage Dynamics Group, Inc.

Bricker-Mincolla Uniforms Criterion Insurance Agency

Brilliant National Services, Inc. Crowley Garment Mfg Co Inc.

Brooks Sports, Inc. Crowley Shirt Mfg Co Inc.

Brookwood Insurance Company CSI Life Insurance Company

Buffalo News CTB Credit Corp

Burlington Northern Railroad Holdings, Inc. CTB Inc.

Burlington Northern Santa Fe British Columbia, Ltd. CTB International Corp

Burlington Northern Santa Fe Ins. Company, Ltd. CTB IW INC

Burlington Northern Santa Fe Manitoba, Inc. CTB MN Investments

Burlington Northern Santa Fe, LLC Cumberland Asset Management, Inc.

Business Wire, Inc. Cypress Insurance Company

C & R Insurance Services, Inc. Dairy Queen Corporate Stores, Inc.

California Employer Group No. 27, Inc. Dairy Queen Of Georgia, Inc.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.8
Berkshire Hathaway Inc. Sub-Group (continued):

Denver Brick Company Gateway Underwriters Agency, Inc.

Dexter Shoe Company GEICO Casualty Co.

DQ Funding Corporation GEICO Corporation

DQ Joint Venture Stores, Inc. GEICO General Insurance Co.

DQ Managed Stores, Inc. GEICO Indemnity Co.

DQ Wholly-Owned Stores, Inc. GEICO Insurance Agency

DQF, Inc. GEICO Products, Inc.

DQGC, Inc. Gen Re Intermediaries Corporation

Eastern States Life Insurance Co., Ltd. General Re Corporation

Eco Color Company General Re Financial Products Corporation

Edmonds Material and Equipment Co. General Re New England Asset Management

Elm Street Corporation General Reinsurance Corporation

Empire Distributors of North Carolina, Inc. General Star Indemnity Company

Empire Distributors, Inc. General Star Management Company

Executive Jet Europe, Inc. General Star National Insurance Company

Executive Jet Management, Inc. Genesis Indemnity Insurance Company

Expertos en Administracion, S.A. de C.V. Genesis Insurance Company

Fairfield Insurance Company Genesis Underwriting Management Company

Faraday Capital Limited Giles Industries, Inc.

Farriors, Inc. Glass Mountain Optics, Inc.

FFG Insurance Company Golden Skillet International, Inc.

Finial Holdings, Inc. Government Employees Financial Corp.

Finial Reinsurance Company Government Employees Insurance Co.

First Berkshire Hathaway Life Insurance Company GRD Holdings Corporation

FlightSafety Capital Corp. Great Plains Uniforms

FlightSafety Development Corp. Griffey Uniforms

FlightSafety International Inc. H. H. Brown Shoe Company, Inc.

FlightSafety New York, Inc. H. H. Brown Shoe Technologies, Inc.

FlightSafety Properties, Inc. H.J. Justin & Sons, Inc.

FlightSafety Services Corporation Halex/Scott Fetzer Company

Floors, Inc. Hardy Frames, Inc.

Footwear Investment Company Harris Uniforms

Forest River Financial Services, Inc. Harrison Uniforms

Forest River Housing, Inc. HDS Redevelopment Corporation

Forest River Warranty Company HeatPipe Technologies

Forest River, Inc. Helzberg's Diamond Shops, Inc.

France/Scott Fetzer Company Hohmann & Barnard, Inc.

Freedom Warehouse Corp. Homefirst Agency, Inc.

FreightWise, Inc. Homemakers Plaza, Inc.

Fruit of the Loom Caribbean, Inc. Horizon Wine & Spirits-Chatanooga, Inc.

Fruit of the Loom Direct, Inc. Horizon Wine & Spirits-Nashville, Inc.

Fruit of the Loom Trading Company Innovative Building Products, Inc.

Fruit of the Loom, Inc. International America Group Inc.

Fruit of the Loom, Inc. (Sub) International American Management Company

FSI Delaware Holding Corp. International Dairy Queen, Inc.

FTL Regional Sales Co., Inc. International Insurance Underwriters, Inc.

FTL Sales Company, Inc. Ironwood Plastics Inc

Fulton Manufacturing Company Isabella Shoe Corporation

Garan Central America Corp. J.S Justin, Inc.

Garan Incorporated JM E3 CO

Garan Manufacturing Corp. Johns Manville China, Ltd.

Garan Services Corp Johns Manville Corporation

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.9
Berkshire Hathaway Inc. Sub-Group (continued):

Johns Manville, Inc. Mossy Oak Apparel Company

Jordan's Furniture, Inc. Mount Vernon Fire Insurance Company

Justin Belt Company, Inc. Mouser Electronics, Inc.

Justin Boot Company MS Property Company 

Justin Brands, Inc. National Fire & Marine Insurance Company

Justin Industries, Inc. National Indemnity Company

Kahn Ventures, Inc. National Indemnity Company of Mid-America

Kale Uniforms National Indemnity Company of the South

Kansas Bankers Surety Company National Liability & Fire Insurance Company

Karmelkorn Shoppes, Inc. National Reinsurance Corporation

Kay Uniforms Nationwide Uniforms

L.A. Terminals, Inc. Nebraska Furniture Mart, Inc.

Laurier Indemnity Company NetJets Aviation, Inc.

Leesburg Yarn Mills, Inc. NetJets Europe Holdings, LLC

Los Angeles Junction Railway Company NetJets Inc.

M & C Products, Inc. NetJets International, Inc.

Macro Retailing, Inc. NetJets Large Aircraft, Inc.

Mapletree Transportation, Inc. NetJets Leasing, Inc.

Marquis Jet Holdings, Inc. NetJets M.E., Inc.

Marquis Jet Partners, Inc. NetJets Sales, Inc.

Martin Manufacturing Company NetJets Services, Inc.

Martin Mills, Inc. NetJets U.S., Inc.

Maryland Ventures, Inc. NFM of Kansas, Inc.

McCain Uniform Company, Inc. Nick Bloom Uniforms

McCarty-Hull Cigar Company, Inc. NJ Executive Services, Inc.

McLane Company, Inc. NJA Jets Inc.

McLane Eastern, Inc. NJE Holdings, LLC

McLane Express, Inc. NJI Sales, Inc.

McLane Foodservice, Inc. NJI, Inc.

McLane Mid-Atlantic, Inc. Nocona Boot Company

McLane Midwest, Inc. North American Casualty Co.

McLane Minnesota, Inc. North Star Reinsurance Corporation

McLane New Jersey, Inc. Northern States Agency, Inc.

McLane Southern, Inc. Northland/Scott Fetzer Company

McLane Suneast, Inc. Oak River Insurance Company

McLane Western, Inc. Orange Julius Of America

Medical Protective Corporation Pan-Am Shoe Co., Inc.

Medical Protective Finance Corporation Pima Uniforms

Medical Protective Insurance Services, Inc. Pine Canyon Lane Company

MedPro Risk Retention Services, Inc. PJR Management, Inc.

Meteor Communications Corporation Plaza Financial Services Co.

Metro Uniforms Plaza Resources Co.

MH Transport, Inc. Ponce Fashions, Inc.

Midland State Life Insurance Co., Ltd. Powerex-Iwata Air Technology, Inc.

Midwest Northwest Properties, Inc. Precision Brand Products, Inc.

Miller-Sage, Inc. Precision Steel Warehouse - Charlotte S/C

MiTek Framings, Inc. Precision Steel Warehouse - Franklin Park

MiTek Holdings, Inc. Priority One Financial Services, Inc.

MiTek Industries, Inc. Pro Installations, Inc.

MiTek, Inc. Professional Datasolutions, Inc.

MMX Corporation Promesa Health, Inc.

Mobile Disaster Structures, Inc. Queen Carpet Corporation

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.10
Berkshire Hathaway Inc. Sub-Group (continued):

R.C. Willey Home Furnishings The Ben Bridge Corporation

Rabun Apparel, Inc. The BN and SF Railway de Mexico, S.A. de C.V.

Railsplitter Holdings Corporation The BVD Licensing Corporation

Redwood Fire and Casualty Company The Eagle Company

RENTCO Trailer Corporation The Fechheimer Brothers Co.

Resolute Management Inc. The Indecor Group, Inc.

Richline Group, Inc The Medical Protective Company

Ringwalt & Liesche Co. The Pampered Chef, Ltd.

Roberts Men's Shop The Scott Fetzer Company

Running with Heels The Zia Company

Rush Air Inc. TMI Custom Air Systems, Inc.

Rush Air Services Tony Lama Company

Russell Athletic Corporation Top Five Club, Inc.

Salado Sales, Inc. Total Quality Apparel Resources

Santa Fe Pacific Insurance Company TPC European Holdings, LTD.

Santa Fe Pacific Pipeline Holdings, Inc. TPC North America, Ltd.

Santa Fe Pacific Pipelines, Inc. Transco, Inc.

Santa Fe Pacific Railroad Company TTI, Inc.

Santa Fe Receivables Corporation U.S. Investment Corporation

Scott Fetzer Financial Group Inc. U.S. Underwriters Insurance Co.

ScottCare Corporation Undergarment Fashions, Inc.

Seaworthy Insurance Company Unified Supply Chain, Inc.

See's Candies, Inc Uniforms of Texas

Sees Candy Shops, Incorporated Union Sales, Inc.

Seventeenth Street Realty, Inc. Union Underwear Co., Inc

Shaw Contract Flooring Installation Services, Inc. Unione Italiana Reinsurance Company of America, Inc.

Shaw Contract Flooring Services, Inc. United Consumer Financial Services Company

Shaw Diversified Services, Inc. United Direct Finance, Inc.

Shaw Floors, Inc. United States Aviation Underwriters, Inc.

Shaw Funding Company United States Liability Insurance Company

Shaw Industries Group, Inc. Universal Uniforms

Shaw Industries, Inc. Vanderbilt ABS Corp.

Shaw International Services, Inc. Vanderbilt Mortgage and Finance, Inc.

Shaw Retail Properties, Inc. Vanderbilt Property & Casualty Insurance Co., Ltd.

Shaw Transport, Inc. Vanderbilt SPC, Inc.

SHX Flooring, Inc. Vanity Fair, Inc.

SHX Leasing, Inc. Vertis Insurance Group, Inc.

SidePlate Systems, Inc. Vessel Assist Association of America, Inc.

Silver State Uniforms Vessel Assist Insurance Services, Inc.

Simon's Incorporated VFI-Mexico, Inc.

Simpad, Inc. Vision Retailing, Inc.

Soco West, Inc. Wayne/Scott Fetzer Company

Sofft Shoe Company Waynesburg Shirt Company Inc.

Sol Frank Uniforms Inc. Wesco Financial Corporation

Somerset Services, Inc Wesco Holdings Midwest, Inc.

Southern Energy Homes, Inc. Wesco-Financial Insurance Company

Stahl/Scott Fetzer Company West Virginia Uniforms

Star Furniture Company Western Fruit Express Company

Star Lake Railroad Company Western/Scott Fetzer Company

Stonewall Insurance Company Whittaker, Clark & Daniels, Inc.

Strategic Staff Management, Inc. Winona Bridge Railroad Company

Technical Coatings Co. WMC Corp.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.11
Berkshire Hathaway Inc. Sub-Group (continued):

World Book Encyclopedia XTRA Companies, Inc.

World Book Inc. XTRA Corporation

World Book/Scott Fetzer Company, Inc. XTRA Finance Corporation

Worldbook.com, Inc. XTRA Intermodal, Inc.

X-L-Co., Inc. XTRA International Pacific, Ltd.

XLI, Inc. XTRA International, Ltd.

XTR, Inc. XTRA Mexicana, S.A. de C.V.

XTRA Chassis, Inc. Zuckerbergs Uniforms

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.12
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Kind of Tax

(See instruction 5)

BALANCE AT BEGINNING OF YEAR

Taxes Accrued

(Account 236) Prepaid Taxes (Include in Account 165)

Taxes

Charged

During

Year

Taxes

Paid 

During

Adjustments Year

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

1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts 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.

 1 Federal:

 2 Income 15,057,106 243,804,243 -489,083,208 -378,627,466

 3 FICA 654,362 40,451,265 40,582,820 -208,383

 4 Unemployment 52,902 383,109 391,381 -353

 5 Excise Tax - Coal 167,805 3,121,283 3,126,302

 6 Subtotal 15,932,175 243,804,243 -445,127,551 -334,526,963 -208,736

 7

 8 State:

 9

 10 Arizona:

 11 Property 960,566 2,363,138 2,142,135

 12 Income 44,924 26,354

 13 Subtotal 960,566 44,924 2,389,492 2,142,135

 14

 15 California:

 16 Property 2,259,708 2,259,708

 17 Unemployment 31,522 30,753

 18 Franchise-Income 364,355 148,513 -105,096

 19 Use 5,581 179,485 181,784

 20 Local Franchise 936,366 1,150,173 1,112,815

 21 Subtotal 941,947 364,355 3,769,401 3,479,964

 22

 23 Colorado:

 24 Property 1,901,000 1,719,136 1,820,136

 25 Income 44,000 70 -43,930

 26 Subtotal 1,901,000 44,000 1,719,206 1,776,206

 27

 28 Idaho:

 29 Property 2,056,753 4,738,233 4,155,558

 30 Income 343,439 438,250 -1,228,209

 31 KWh 15,012 26,822 28,158

 32 Unemployment 733 95,862 94,680

 33 Use 837 160,036 146,895

 34 Subtotal 2,073,335 343,439 5,459,203 3,197,082

 35

 36 Montana:

 37 Property 1,399,991 3,275,197 3,042,627

 38 Corporate License-Income -153,660 50 67,710

 39 Unemployment 1,030 1,030

 40 Energy License 33,362 269,226 238,722

 258,675,803

FERC FORM NO. 1 (ED. 12-96) Page 262

41 TOTAL 46,747,021 -286,256,396 -191,003,416 -209,999
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Kind of Tax

(See instruction 5)

BALANCE AT BEGINNING OF YEAR

Taxes Accrued

(Account 236) Prepaid Taxes (Include in Account 165)

Taxes

Charged

During

Year

Taxes

Paid 

During

Adjustments Year

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

1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts 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.

 1 Wholesale Energy 23,788 191,815 170,097

 2 Subtotal 1,457,141 -153,660 3,737,318 3,520,186

 3

 4 New Mexico:

 5 Property 8,398 8,398

 6 Income 50 50

 7 Subtotal 8,448 8,448

 8

 9 Oregon:

 10 Property 9,620,711 20,348,226 21,470,885

 11 Unemployment 38,519 1,841,356 1,829,441

 12 Wilsonville Payroll 288 799 827

 13 Excise-Income 922,587 -1,761,300 -2,006,049

 14 City of Portland-Income 1,000 -1,679 -3,149

 15 Department of Energy 357,444 722,590 1,445,179

 16 Tri-Met 351,459 863,452 870,961

 17 Lane County 1,872 1,872

 18 Franchise 4,195,671 22,210,008 22,246,753

 19 Subtotal 4,943,381 10,544,298 44,225,324 45,856,720

 20

 21 Utah:

 22 Property 398,350 52,353,573 52,281,027

 23 Income 3,684,204 -300,165 -11,503,320

 24 Unemployment 52,150 203,542 252,986

 25 Navajo Nation 804 804

 26 Salt Lake Valley Law Enforc 648 648

 27 Use 314,915 4,958,116 4,731,443

 28 Subtotal 765,415 3,684,204 57,216,518 45,763,588

 29

 30 Washington:

 31 Property 6,787,000 9,165,928 7,252,928

 32 Unemployment 2,611 128,956 125,303

 33 Business & Occupation 4,998 33,252 34,870

 34 Public Utility 1,675,000 9,832,285 10,447,279

 35 Natural Gas Use Tax 449,559 1,990,456 2,324,198

 36 Use 38,923 394,687 385,391

 37 Franchise 91,260 91,260

 38 Land Tax 63 63

 39 Subtotal 8,958,091 21,636,887 20,661,292

 40

 258,675,803

FERC FORM NO. 1 (ED. 12-96) Page 262.1

41 TOTAL 46,747,021 -286,256,396 -191,003,416 -209,999
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Kind of Tax

(See instruction 5)

BALANCE AT BEGINNING OF YEAR

Taxes Accrued

(Account 236) Prepaid Taxes (Include in Account 165)

Taxes

Charged

During

Year

Taxes

Paid 

During

Adjustments Year

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

1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts 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.

 1 Wyoming:

 2 Property 6,544,398 13,744,851 13,099,632

 3 Unemployment 2,001 551,149 544,675 -1,263

 4 Franchise 239,100 1,567,954 1,560,054

 5 Use 111,294 1,490,853 1,462,238

 6 Annual Report 93,853 93,853

 7 Subtotal 6,896,793 17,448,660 16,760,452 -1,263

 8

 9 State Other 1,899,175 903,287

 10

 11 Miscellaneous:

 12 Goshute Possessory 15,079 15,079

 13 Sho-Ban Possessory 151,097 151,097

 14 Navajo Possessory 18,002 35,877 35,940

 15 Ute Possessory 27,349 27,349

 16 Crow Possessory 63,720 63,720

 17 Umatilla Possessory 64,289 64,289

 18 Subtotal 1,917,177 1,260,698 357,474

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 258,675,803

FERC FORM NO. 1 (ED. 12-96) Page 262.2

41 TOTAL 46,747,021 -286,256,396 -191,003,416 -209,999
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. (Taxes accrued

BALANCE AT END OF YEAR

Prepaid Taxes Electric

(Account 408.1, 409.1) Extraordinary Items

(Account 409.3)

Adjustments to Ret. Other Earnings (Account 439)

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

DISTRIBUTION OF TAXES CHARGED

5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,

identifying the year in column (a).

6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. 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.

 1

 13,589,884 352,792,763 -517,806,480 28,723,272 2

 727,676 -3,514 40,451,265 3

 44,983 383,109 4

 162,786 3,121,283 5

 14,525,329 352,789,249 -517,806,480 72,678,929 6

 7

 8

 9

 10

 1,181,569 2,363,138 11

 18,570 -14,946 41,300 12

 1,181,569 18,570 2,348,192 41,300 13

 14

 15

 2,103,347 156,361 16

 769 31,522 17

 110,746 39,367 109,146 18

 3,282 179,485 19

 973,724 1,150,173 20

 977,775 110,746 3,292,887 476,514 21

 22

 23

 1,800,000 1,678,036 41,100 24

 -648 718 25

 1,800,000 1,677,388 41,818 26

 27

 28

 2,639,428 3,139,896 1,598,337 29

 -1,323,020 197,088 241,162 30

 13,676 26,822 31

 1,915 95,862 32

 13,978 160,036 33

 2,668,997 -1,323,020 3,363,806 2,095,397 34

 35

 36

 1,632,561 3,275,197 37

 -86,000 -26,987 27,037 38

 1,030 39

 63,866 269,226 40

FERC FORM NO. 1 (ED. 12-96) Page 263

 48,804,714 355,776,477 -385,705,794 99,449,398 41
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. (Taxes accrued

BALANCE AT END OF YEAR

Prepaid Taxes Electric

(Account 408.1, 409.1) Extraordinary Items

(Account 409.3)

Adjustments to Ret. Other Earnings (Account 439)

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

DISTRIBUTION OF TAXES CHARGED

5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,

identifying the year in column (a).

6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. 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.

 45,506 191,815 1

 1,741,933 -86,000 3,709,251 28,067 2

 3

 4

 8,398 5

 -195 245 6

 8,203 245 7

 8

 9

 10,743,370 19,830,171 518,055 10

 50,434 1,841,356 11

 260 799 12

 677,838 -3,555,890 1,794,590 13

 -470 -2,433 754 14

 365,145 722,590 15

 343,950 863,452 16

 1,872 17

 4,158,926 22,210,008 18

 4,553,570 11,785,883 39,204,446 5,020,878 19

 20

 21

 470,896 45,297,821 7,055,752 22

 -7,518,951 -1,988,229 1,688,064 23

 2,706 203,542 24

 804 25

 648 26

 541,588 4,958,116 27

 1,015,190 -7,518,951 43,311,044 13,905,474 28

 29

 30

 8,700,000 8,922,538 243,390 31

 6,264 128,956 32

 3,380 31,331 1,921 33

 1,060,006 9,832,285 34

 115,817 1,990,456 35

 48,219 394,687 36

 91,260 37

 63 38

 9,933,686 18,877,477 2,759,410 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 263.1

 48,804,714 355,776,477 -385,705,794 99,449,398 41
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. (Taxes accrued

BALANCE AT END OF YEAR

Prepaid Taxes Electric

(Account 408.1, 409.1) Extraordinary Items

(Account 409.3)

Adjustments to Ret. Other Earnings (Account 439)

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

DISTRIBUTION OF TAXES CHARGED

5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,

identifying the year in column (a).

6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. 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.

 1

 7,189,617 13,385,487 359,364 2

 9,738 551,149 3

 247,000 1,567,954 4

 139,909 1,490,853 5

 93,853 6

 7,586,264 15,047,294 2,401,366 7

 8

 2,802,462 903,287 9

 10

 11

 15,079 12

 151,097 13

 17,939 35,877 14

 27,349 15

 63,720 16

 64,289 17

 2,820,401 1,260,698 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 263.2

 48,804,714 355,776,477 -385,705,794 99,449,398 41
Schedule Page: 262 Line No.: 2 Column: l

Federal income tax appliable to other income and deductions - 409.2

Schedule Page: 262 Line No.: 3 Column: f

Recognition of January 1, 2010 balance for Pacific Minerals, Inc., which was consolidated for FERC reporting purposes on a

prospective basis beginning January 1, 2010. Refer to Note 2 of Notes to Financial Statements within this FERC Form No. 1 for

further discussion.

Schedule Page: 262 Line No.: 3 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262 Line No.: 4 Column: f

Recognition of January 1, 2010 balance for Pacific Minerals, Inc., which was consolidated for FERC reporting purposes on a

prospective basis beginning January 1, 2010. Refer to Note 2 of Notes to Financial Statements within this FERC Form No. 1 for

further discussion.

Schedule Page: 262 Line No.: 4 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262 Line No.: 5 Column: l

Fuel inventory - 151

Schedule Page: 262 Line No.: 12 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262 Line No.: 16 Column: l

 Amount Account

Taxes other than income taxes $ 142,765 408.2

Construction 12,084 107

Distribution expenses - rents 1,512 589

Total $ 156,361

Schedule Page: 262 Line No.: 17 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262 Line No.: 18 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262 Line No.: 19 Column: l

Charged to same account as related goods.

Schedule Page: 262 Line No.: 24 Column: l

 Amount Account

Taxes other than income taxes $ 698 408.2

Construction 40,402 107

Total $ 41,100

Schedule Page: 262 Line No.: 25 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262 Line No.: 29 Column: l

 Amount Account

Taxes other than income taxes $ 1,343 408.2

Construction 1,596,994 107

Total $ 1,598,337

Schedule Page: 262 Line No.: 30 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262 Line No.: 32 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262 Line No.: 33 Column: l

Charged to same account as related goods.

Schedule Page: 262 Line No.: 38 Column: l

State income tax applicable to other income and deductions - 409.2

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Schedule Page: 262 Line No.: 39 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 6 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262.1 Line No.: 10 Column: l

 Amount Account

Taxes other than income taxes $ 19,038 408.2

Construction 449,521 107

Distribution expenses - rents 49,496 589

Total $ 518,055

Schedule Page: 262.1 Line No.: 11 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 12 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 13 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262.1 Line No.: 14 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262.1 Line No.: 16 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 17 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 22 Column: l

 Amount Account

Taxes other than income taxes $ 62,016 408.2

Fuel stock 1,785,193 151

Construction 5,208,543 107

Total $ 7,055,752

Schedule Page: 262.1 Line No.: 23 Column: l

State income tax applicable to other income and deductions - 409.2

Schedule Page: 262.1 Line No.: 24 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 27 Column: l

Charged to same account as related goods.

Schedule Page: 262.1 Line No.: 31 Column: l

 Amount Account

Taxes other than income taxes $ 119,471 408.2

Construction 120,496 107

Distribution expenses - rents 3,423 589

Total $ 243,390

Schedule Page: 262.1 Line No.: 32 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.1 Line No.: 33 Column: l

Fuel stock - 151

Schedule Page: 262.1 Line No.: 35 Column: l

Fuel stock - 151

Schedule Page: 262.1 Line No.: 36 Column: l

Charged to same account as related goods.

Schedule Page: 262.2 Line No.: 2 Column: l

 Amount Account

Taxes other than income taxes $ 927 408.2

Construction 346,998 107

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Distribution expenses - rents 11,439 589

Total $ 359,364

Schedule Page: 262.2 Line No.: 3 Column: f

Recognition of January 1, 2010 balance for Pacific Minerals, Inc., which was consolidated for FERC reporting purposes on a

prospective basis beginning January 1, 2010. Refer to Note 2 of Notes to Financial Statements within this FERC Form No. 1 for

further discussion.

Schedule Page: 262.2 Line No.: 3 Column: l

Payroll taxes are generally charged to operations and maintenance expense, construction work in progress and fuel.

Schedule Page: 262.2 Line No.: 5 Column: l

Charged to same account as related goods.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Account Balance at Beginning

(c) (a) (b)

of Year Subdivisions Adjustments Deferred for Year Allocations to

Current Year's Income

Account No. Amount Account No. Amount

(d) (e) (f) (g)

Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and

nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)

the average period over which the tax credits are amortized.

 1 Electric Utility

 2 3%

 3 4%

 4 7%

 5 10% 37,000,901 411.4 1,808,768

 6 10% 7,294,222 420 1,624,452

 7 Idaho 712,457 411.4 65,436

 8 TOTAL 45,007,580 3,498,656

Other (List separately

and show 3%, 4%, 7%,

10% and TOTAL)

 9

 10

 11

 12

 13 10% 881,312 420 440,808

 14

 15 Total Nonutility 881,312 440,808

 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

FERC FORM NO. 1 (ED. 12-89) Page 266
Balance at End

(h) (i)

of Year

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

ADJUSTMENT EXPLANATION Average Period

of Allocation

to Income

 1

 2

 3

 4

 35,192,133 48.37 5

 5,669,770 30 6

 647,021 30 7

 41,508,924 8

 9

 10

 11

 12

 440,504 30 13

 14

 440,504 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

FERC FORM NO. 1 (ED. 12-89) Page 267
Schedule Page: 266 Line No.: 5 Column: e

Internal Revenue Code 46(f)2

Schedule Page: 266 Line No.: 6 Column: e

Internal Revenue Code 46(f)1

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

OTHER DEFFERED CREDITS (Account 253)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description and Other DEBITS

 Credits

Account

(a) (b) (c)

Balance at

End of Year

(d)

Deferred Credits Amount

(e)

Balance at 

Beginning of Year Contra

(f)

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

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

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

 1

 2 Working Capital Deposits 3,410,544 974,570 4,385,114

 3

 4 Reclamation Costs - Trapper Mine 4,499,352 237,270 4,736,622

 5

 6 Reclamation Costs - Deseret Mine 534,826 131 7,300 527,526

 7

 8 Reclamation Costs - Trail

 9 Mountain Mine 1,090,948 131 3,450 1,087,498

 10

 11 Deferred Compensation Plan 9,791,441 232, 241,920 2,177,184 2,192,142 9,806,399

 12

 13 Western Coal Carriers Benefits

 14 Obligation 232 279,264 9,403,264 9,124,000

 15

 16 Transmission Service Deposits 1,893,375 232, 235,456 3,937,100 4,356,275 2,312,550

 17

 18 MCI F.O.G. wire lease 557,783 454 3,350,037 3,350,705 558,451

 19

 20 Redding Contract (20) 3,300,076 456 549,996 2,750,080

 21

 22 Foote Creek Contract (15) 705,302 142 137,640 567,662

 23

 24 Environmental Liabilities 6,928,295 4,379,701 6,840,546 9,389,140

 25

 26 Unearned Joint Use Pole Contact 3,342,497 454 8,295,047 8,315,400 3,362,850

 27

 28 Deferred Revenue -

 29 Hermiston Gas Settlement (5) 1,163,710 547, 555 754,839 408,871

 30

 31 Transmission Security Deposits 1,550,000 107, 142,232 1,308,253 1,208,253 1,450,000

 32

 33 Other deferred credits with

 34 balances less than $500,000 1,389,331 various 364,069 1,025,262

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

 46

FERC FORM NO. 1 (ED. 12-94) Page 269

47 TOTAL 40,157,480 25,543,880 36,878,425 51,492,025
Schedule Page: 269 Line No.: 13 Column: a

This account was reclassified from FERC account 232 during the fourth quarter of 2010. The amount in column (d) represents activity

since the transfer date. 

Schedule Page: 269 Line No.: 24 Column: c

Account 182.3 - Other regulatory assets

Account 232 - Accounts payable

Account 557 - Other expenses

Account 923 - Outside services employed

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Account

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

Balance at

Beginning of Year

CHANGES DURING YEAR

Amounts Debited Amounts Credited 

to Account 410.1 to Account 411.1

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable

property.

2. For other (Specify),include deferrals relating to other income and deductions.

 1 Accelerated Amortization (Account 281)

 2 Electric

 3 Defense Facilities

 4 Pollution Control Facilities 13,316,552 1,673,844

 5 Other (provide details in footnote):

 6

 7

 8 TOTAL Electric (Enter Total of lines 3 thru 7) 13,316,552 1,673,844

 9 Gas

 10 Defense Facilities

 11 Pollution Control Facilities

 12 Other (provide details in footnote):

 13

 14

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

 16

 17 TOTAL (Acct 281) (Total of 8, 15 and 16) 13,316,552 1,673,844

 18 Classification of TOTAL

 19 Federal Income Tax

 20 State Income Tax

 21 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 272

NOTES
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

CHANGES DURING YEAR ADJUSTMENTS

Balance at

End of Year

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

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

3. Use footnotes as required.

 1

 2

 3

 11,642,708 4

 5

 6

 7

 11,642,708 8

 9

 10

 11

 12

 13

 14

 15

 16

 11,642,708 17

 18

 19

 20

 21

FERC FORM NO. 1 (ED. 12-96) Page 273

NOTES (Continued)
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Account

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

Balance at

Beginning of Year

CHANGES DURING YEAR

Amounts Debited Amounts Credited 

to Account 410.1 to Account 411.1

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not

subject to accelerated amortization

2. For other (Specify),include deferrals relating to other income and deductions.

 1 Account 282

 2 Electric 2,801,783,463 1,074,973,139 400,329,543

 3 Gas

 4

 5 TOTAL (Enter Total of lines 2 thru 4) 2,801,783,463 1,074,973,139 400,329,543

 6 Nonutility 871,716

 7

 8

 9 TOTAL Account 282 (Enter Total of lines 5 thru 2,802,655,179 1,074,973,139 400,329,543

 10 Classification of TOTAL

 11 Federal Income Tax 2,467,379,311 946,376,315 352,438,944

 12 State Income Tax 335,275,868 128,596,824 47,890,599

 13 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 274

NOTES
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

CHANGES DURING YEAR ADJUSTMENTS

Balance at

End of Year

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

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

3. Use footnotes as required.

 1

190, 283 173,479,616190, 182.3 27,287,448 3,330,234,891 2

 3

 4

 173,479,616 27,287,448 3,330,234,891 5

 10,848 882,564 6

 7

 8

 10,848 882,564 173,479,616 27,287,448 3,330,234,891 9

 10

 9,550 776,985 152,726,607 24,023,107 2,931,845,747 11

 1,298 105,579 20,753,009 3,264,341 398,389,144 12

 13

FERC FORM NO. 1 (ED. 12-96) Page 275

NOTES (Continued)
Schedule Page: 274 Line No.: 2 Column: g

As of December 31, 2010, $170 million was reclassified from account 282 Accumulated deferred income taxes - other property to

account 283 Accumulated deferred income taxes - other in order to conform to the current year presentation. As a result of the

reclassification, accumulated deferred income tax liabilities generated by the gross up for revenue requirement on property-related

timing differences for which the benefits were previously flowed through to customers and that will be included in rates when the

timing differences reverse are included in account 283, such that account 282 includes only accumulated deferred income tax liabilities

that result directly from property-related timing differences.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Account

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

Balance at

Beginning of Year

CHANGES DURING YEAR

Amounts Debited Amounts Credited 

to Account 410.1 to Account 411.1

1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts

recorded in Account 283.

2. For other (Specify),include deferrals relating to other income and deductions.

 1 Account 283

 2 Electric

 3 Regulatory Assets 416,262,076 51,931,202 65,065,028

 4

 5

 6 Other Deferred Liabilities 34,637,390 2,227,685 6,070,503

 7

 8

 9 TOTAL Electric (Total of lines 3 thru 8) 450,899,466 54,158,887 71,135,531

 10 Gas

 11

 12

 13

 14

 15

 16

TOTAL Gas (Total of lines 11 thru 16) 17

 18

 19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 450,899,466 54,158,887 71,135,531

 20 Classification of TOTAL

 21 Federal Income Tax 396,958,249 47,679,971 62,625,734

 22 State Income Tax 53,941,217 6,478,916 8,509,797

 23 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 276

NOTES
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

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

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

CHANGES DURING YEAR ADJUSTMENTS

Balance at

End of Year

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

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

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

4. Use footnotes as required.

 1

 2

 56,437,118 10,898,320 16,149,192 217,159,853 649,677,709 3

 4

 5

190 325,743 190 372,360 30,841,189 6

 7

 8

 56,437,118 10,898,320 16,474,935 217,532,213 680,518,898 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 56,437,118 10,898,320 16,474,935 217,532,213 680,518,898 19

 20

 49,685,662 9,594,577 14,504,072 191,509,282 599,108,781 21

 6,751,456 1,303,743 1,970,863 26,022,931 81,410,117 22

 23

FERC FORM NO. 1 (ED. 12-96) Page 277

NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: g

Account 182.3 - Other regulatory assets

Account 283 - Accumulated deferred income taxes - Other

Account 254 - Other regulatory liabilities

Schedule Page: 276 Line No.: 3 Column: i

Account 182.3 - Other regulatory assets

Account 190 - Accumulated deferred income taxes

Account 282 - Accumulated deferred income taxes - Other property

Account 283 - Accumulated deferred income taxes - Other

As of December 31, 2010, $170 million was reclassified from account 282 Accumulated deferred income taxes - other property to

account 283 Accumulated deferred income taxes - other in order to conform to the current year presentation. As a result of the

reclassification, accumulated deferred income tax liabilities generated by the gross up for revenue requirement on property-related

timing differences for which the benefits were previously flowed through to customers and that will be included in rates when the

timing differences reverse are included in account 283, such that account 282 includes only accumulated deferred income tax liabilities

that result directly from property-related timing differences.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

OTHER REGULATORY LIABILITIES (Account 254)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description and Purpose of DEBITS

Account Credits

(a) (c) (d)

Balance at End

of Current

Quarter/Year

(e)

Other Regulatory Liabilities Amount

(f)

Credited

1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if

applicable.

2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped

by classes.

3. For Regulatory Liabilities being amortized, show period of amortization.

Balance at Begining

of Current

Quarter/Year

(b)

 1 Income Tax Regulatory Liability 20,359,322 190 1,013,976 19,345,346

 2 Income Tax Reg. Liab. - WA Flow Through 876,629 1,549,811 2,426,440

 3 Gain on Sale of Assets - OR 459,170 851,328 465,707 73,549

 4 Gain on Sale of Assets - CA 45,034 421.1 41,279 3,755

 5 Property Insurance Reserve 109,564 228.1,924 109,564

 6 SMUD Revenue Imputation (11) 22,913,046 400,442 13,956,848 118,100 9,074,298

 7 WA Rate Refund 228,659 142 228,728 69

 8 Utah Home Energy Lifeline 413,856 142 4,165,060 3,954,566 203,362

 9 BPA Washington Balancing Account 903,021 579,420 1,482,441

 10 BPA Oregon Balancing Account 2,419,092 756,054 3,175,146

 11 Asset Retirement Obligations Reg. Difference 4,409,486 230 259,882 257,947 4,407,551

 12 Washington Low Income Program ( 35,188) 142 967,554 1,208,791 206,049

 13 Misc. Regulatory Liabilities - OR 211,435 182.3 176,623 157,812 192,624

 14 Blue Sky - OR 378,243 456 1,077,654 1,326,346 626,935

 15 Blue Sky - WA 40,285 456 159,322 167,471 48,434

 16 Blue Sky - CA 67,399 456 119,651 70,750 18,498

 17 Blue Sky - UT 734,895 456 2,475,501 2,661,312 920,706

 18 Blue Sky - ID 28,623 456 83,459 57,258 2,422

 19 Blue Sky - WY 76,129 456 220,683 199,539 54,985

 20 OR Energy Conservation Charge 822,596 456 19,538,442 21,054,837 2,338,991

 21 Deferred Arch Coal Settlement (3) 1,217,286 557 1,173,017 44,269

 22 Renewable Energy Credit Sales Deferral - OR 3,922,178 3,922,178

 23 Renewable Energy Credit Sales Deferral - WY 3,594,057 3,594,057

 24 Tax Revenue Requirement Adj. - UT 49,234 49,234

 25 Regulatory Liability - Reclassifications 7,485,673 182.3 85,730 7,399,943

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

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

41 TOTAL 64,164,255 46,704,301 42,151,259 59,611,213
Schedule Page: 278 Line No.: 3 Column: c

Account 440, Residential sales

Account 442, Commercial and industrial sales

Account 444, Public street and highway lighting

Account 431, Other interest expense

Schedule Page: 278 Line No.: 25 Column: f

The following schedule summarizes regulatory liabilities reclassifications: 

 Year Ended

 December 31, 2010 

Reclassified from Regulatory Assets to Regulatory Liabilities:

 DSM Regulatory Asset - CA $ 3,193,591 

 DSM Regulatory Asset - WY 4,000,836 

 Deferred Independent Evaluator Fee - UT 16,501 

 SB 408 Regulatory Asset - MCBIT 189,015

 $ 7,399,943 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ELECTRIC OPERATING REVENUES (Account 400)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Title of Account

(a) (b) (c)

Operating Revenues Year

to Date Quarterly/Annual

1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and 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.

5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.

Operating Revenues

Previous year (no Quarterly)

 1 Sales of Electricity

 2 (440) Residential Sales 1,357,826,906 1,346,519,773

 3 (442) Commercial and Industrial Sales

 4 Small (or Comm.) (See Instr. 4) 1,146,322,741 1,120,956,943

 5 Large (or Ind.) (See Instr. 4) 1,030,052,681 976,991,304

 6 (444) Public Street and Highway Lighting 20,610,361 20,913,398

 7 (445) Other Sales to Public Authorities 19,770,416 19,032,148

 8 (446) Sales to Railroads and Railways

 9 (448) Interdepartmental Sales

 10 TOTAL Sales to Ultimate Consumers 3,574,583,105 3,484,413,566

 11 (447) Sales for Resale 501,563,210 643,321,157

 12 TOTAL Sales of Electricity 4,076,146,315 4,127,734,723

 13 (Less) (449.1) Provision for Rate Refunds

 14 TOTAL Revenues Net of Prov. for Refunds 4,076,146,315 4,127,734,723

 15 Other Operating Revenues

 16 (450) Forfeited Discounts 7,411,888 7,318,368

 17 (451) Miscellaneous Service Revenues 5,919,271 6,908,893

 18 (453) Sales of Water and Water Power 2,609 12,154

 19 (454) Rent from Electric Property 19,559,096 19,158,931

 20 (455) Interdepartmental Rents

 21 (456) Other Electric Revenues 225,364,091 128,935,328

 22 (456.1) Revenues from Transmission of Electricity of Others 67,812,115 63,697,983

 23 (457.1) Regional Control Service Revenues

 24 (457.2) Miscellaneous Revenues

 25

 26 TOTAL Other Operating Revenues 326,069,070 226,031,657

 27 TOTAL Electric Operating Revenues 4,402,215,385 4,353,766,380

FERC FORM NO. 1/3-Q (REV. 12-05) Page 300
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ELECTRIC OPERATING REVENUES (Account 400)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MEGAWATT HOURS SOLD

Current Year (no Quarterly) Previous Year (no Quarterly)

AVG.NO. CUSTOMERS PER MONTH

Year to Date Quarterly/Annual Amount Previous year (no Quarterly)

(d) (e) (f) (g)

6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by 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.)

7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.

8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.

9. Include unmetered sales. Provide details of such Sales in a footnote.

 1

 15,794,444 15,998,640 1,474,909 1,466,724 2

 3

 15,969,253 16,194,257 220,171 213,730 4

 20,679,453 19,934,268 33,854 34,070 5

 145,032 144,765 3,868 3,948 6

 427,352 437,595 13 13 7

 8

 9

 53,015,534 52,709,525 1,732,815 1,718,485 10

 11,414,592 12,349,061 11

 64,430,126 65,058,586 1,732,815 1,718,485 12

 13

 64,430,126 65,058,586 1,732,815 1,718,485 14

Page 301

Line 12, column (b) includes $ of unbilled revenues.

Line 12, column (d) includes MWH relating to unbilled revenues

 205,559,000

 3,209,886

FERC FORM NO. 1/3-Q (REV. 12-05)
Schedule Page: 300 Line No.: 11 Column: f

For a complete list of the number of customers see pages 310-311 Sales for Resale of this Form No. 1.

Schedule Page: 300 Line No.: 11 Column: g

For a complete list of the number of customers see pages 310-311 Sales for Resale of this Form No. 1.

Schedule Page: 300 Line No.: 17 Column: b

(451) Miscellaneous Service Revenues include the following items that were $250,000 or greater for the years ended December 31:

 2010 2009 

Account service charge - disconnects/reconnects/returned check charges $ 4,070,201 $ 4,609,636 

Customer contract flat rate billings 1,756,340 2,188,111 

Schedule Page: 300 Line No.: 21 Column: b

(456) Other Electric Revenues include the following items that were $250,000 or greater for the years ended December 31:

 2010 2009 

 Demand-side management revenue $ 100,095,141 $ 50,259,795 

 Renewable energy credit sales, net of deferrals 93,760,900 50,793,765 

 Energy exchange credits 7,822,254 8,415,849 

 Wind-based ancillary services 7,281,432 7,216,814 

 Steam sales 5,719,969 4,857,715 

 Blue Sky revenue 4,167,040 - 

 Flyash/by-product sales 2,658,821 3,238,868 

 Power sale and exchange agreements 1,091,292 1,091,292 

 Revenue from generation interconnection and transmission service request studies 991,746 840,474 

 Phase shifting equipment fee from Western Electricity Coordinating Counsel 455,941 1,271,449 

 Maintenance charges for work on transmission facilities 494,787 423,133 

 Net profit on sales of materials and supplies inventory - (a) 361,448 

(a) The current year amount is less than $250,000. 

Schedule Page: 300 Line No.: 27 Column: b

A reconciliation of operating electric revenues for the year ended December 31, 2010 is as follows:

Page 300 Page 304 Variance

Sales of Electricity

Residential Sales - Account (440) $ 1,357,826,906 $ 1,357,826,906 $ - 

Commercial and Industrial Sales - Account (442)

Small (Commercial) 1,146,322,741 1,146,322,741 - 

Large (Industrial) 1,030,052,681 1,030,052,681 - (a)

Public Street and Highway Lighting - Account (444) 20,610,361 20,610,361 - 

Other Sales to Public Authorities - Account (445) 19,770,416 19,770,416 - 

Sales to Railroads and Railways - Account (446) - - - 

Interdepartmental Sales - Account (448) - - - 

Total Sales to Ultimate Consumers 3,574,583,105 3,574,583,105 - 

Sales for Resale - Account (447) 501,563,210 - 501,563,210 (b)

Total Sales of Electricity 4,076,146,315 3,574,583,105 501,563,210

(Less) Provision for Rate Refunds - Account (449.1) - - - 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Total Revenues Net of Provisions for Refunds 4,076,146,315 3,574,583,105 501,563,210

Other Operating Revenues

Forfeited Discounts - Account (450) 7,411,888 7,411,888 - 

Miscellaneous Service Revenues - Account (451) 5,919,271 5,919,271 - 

Sales of Water and Water Power - Account (453) 2,609 2,609 - 

Rent from Electric Property - Account (454) 19,559,096 19,559,096 - 

Interdepartmental Rents - Account (455) - - - 

Other Electric Revenues - Account (456) 225,364,091 220,074,820 5,289,271 (c)

Revenues from Transmission of Electricity of Others (456.1) 67,812,115 - 67,812,115 (b)

Total Operating Revenues $ 4,402,215,385 $ 3,827,550,789 $ 574,664,596

(a) The large industrial line on page 300 includes industrial sales of $943,745,752 and irrigation sales of $86,306,929.

(b) Sales for Resale and Revenues from Transmission of Electricity of Others are not included on page 304 Sales of Electricity by

Rate Schedules as the revenues are included in pages 310-311 Sales for Resale and pages 328-330 Transmission of Electricity for

Others, respectively, in this Form No. 1.

(c) The variance in Other Electric Revenues-Account (456) for the year ended December 31, 2010 is as follows:

Page 300 Page 304 Variance

Steam Sales $ 5,719,969 $ - $ 5,719,969

Materials and Supplies Inventory Cost of Sales (430,698) - (430,698)

Other Electric Revenues - Account (456) 220,074,820 220,074,820 - 

Total Other Electric Revenues - Account (456) $ 225,364,091 $ 220,074,820 $ 5,289,271

Schedule Page: 300 Line No.: 1 Column: $

The following is a reconciliation of the unbilled revenue accrual at December 31, 2010 and the reversal of the December 31, 2009

unbilled revenue accrual.

December 31, 2010 unbilled revenue accrual $ 205,559,000 

December 31, 2009 unbilled revenue accrual reversal (213,989,000)

Change in unbilled revenue accrual $ (8,430,000)

Schedule Page: 300 Line No.: 1 Column: MWH

The following is a reconciliation of the unbilled MWh accrual at December 31, 2010 and the reversal of the December 31, 2009

unbilled MWh accrual. 

December 31, 2010 unbilled MWh accrual 3,209,886 

December 31, 2009 unbilled MWh accrual reversal (3,380,278)

Change in unbilled MWh accrual (170,392)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No. Description of Service

(a)

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)

1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration,

etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.

Balance at End of

(b) (c)

Balance at End of

Quarter 1 Quarter 2

Balance at End of

Quarter 3

(d) (e)

Balance 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

 43

 44

 45

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302

46 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 RESIDENTIAL SALES

 2 CALIFORNIA

 3 06CHCK000R-CA RES CHECK M 1

 4 06LNX00109-REF/NREF ADV+ -40

 5 06NETMT135-CA RES NET 266 30,174 29 9,172 0.1134

 6 06OALT015R-OUTD AR LGT SR 339 72,752 368 921 0.2146

 7 06RESD000D-RES SRVC 196,737 21,997,535 18,812 10,458 0.1118

 8 06RESDDL06-CA LOW INCOME 109,576 12,158,912 9,459 11,584 0.1110

 9 06RESDDM9M-MULTI FAMILY 60 6,498 6 10,000 0.1083

 10 06RESD0DM9-MULTI FAMILY 178 19,082 8 22,250 0.1072

 11 06RESDDS8M-MULT FAM SBMET 866 77,940 15 57,733 0.0900

 12 06RESDDS8M-MULT FAM SBMET 626 60,969 15 41,733 0.0974

 13 REVENUE ADJ. - DEFERRED NPC 1,259,052

 14 REV. ACCOUNTING ADJ. -1,024,881

 15 SMUD REVENUE IMPUTATIONS 44,729

 16 06RESD00DN - CA RES SRVC - 96,864 10,717,286 7,463 12,979 0.1106

 17 UNBILLED REVENUE -2,551 -399,000 0.1564

 18 IDAHO

 19 07LNX00010-MNTHLY 80%GUAR 1,192

 20 07LNX00035-ADV 80%MO GUAR 1,520

 21 07NETMT135 - ID RESIDENTIAL 1,054 84,442 59 17,864 0.0801

 22 07OALCO007-CUST OWN LIGHT 10 3,704 1 10,000 0.3704

 23 07OALT07AR-SECURITY AR LG 106 42,548 136 779 0.4014

 24 07RESD0001-RES SRVC 423,071 38,736,381 42,306 10,000 0.0916

 25 07RESD0001-RES SRVC 6

 26 07RESD0036-RES SRVC-OPTIO 284,972 21,122,790 14,789 19,269 0.0741

 27 07RESD0036-RES SRVC-OPTIO -2

 28 BPA BALANCING ACCOUNT 1,640,993

 29 07ZZMERGCR-MERGER CREDITS 1

 30 UNBILLED REV - UNCOLLECTIBLE 3,000

 31 SMUD REVENUE IMPUTATIONS 74,932

 32 UNBILLED REVENUE -4,086 -200,000 0.0489

 33 OREGON

 34 01CHCK000R-RES CHECK MTR 1

 35 01COST0004 - 01RESD0004 5,240,762 239,182,779 0.0456

 36 01FXRENEWR - Fx Rnw Blue Sky -1

 37 01HABIT004 - 01RESD0004 43,891 1,951,428 0.0445

 38 01LNX00102-LINE EXT 80% G 17,436

 39 01LNX00105-CNTRCT $ MIN G 42

 40 01LNX00109-REF/NREF ADV + 3,016

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01NETMT135-NET METERING 404,935 938

 2 01NETMT135-NET METERING -40,917

 3 01NMTOU135-TOU NET METR 1,707 7

 4 01NMTOU135-TOU NET BPA -172

 5 01OALT014R-OUTD AR LGT RE 2,480 392,792 2,873 863 0.1584

 6 01OALT014R-OUTD AR LGT RE -12,192

 7 01PTOU0004 - 01RESD0004 20,792 965,659 0.0464

 8 01RENEW004 - 01RESD0004 202,590 8,902,861 0.0439

 9 01RESD0004-RES SRVC 243,376,697 472,158

 10 01RESD0004-RES SRVC -25,696,576

 11 01RESD0013-3 PHASE RES SR -18

 12 01RESD004T - RES Time Option 893,181 1,363

 13 01RESD004T - RES Time Opt BPA -97,264

 14 01UPPL000R-BASE SCH FALL 4

 15 01VIR04136-OR RES VOL INCTV 3,194 19

 16 01VIR04136-OR RES VOL INCTV -344

 17 BPA BALANCING ACCOUNT -774,369

 18 OR GAIN ON SALE OF ASSET 330,826

 19 OR SB408 RECOVERY 717,937

 20 OR SB838 RECOVERY -2,139,500

 21 REV. ACCOUNTING ADJ. -24,768

 22 SMUD REVENUE IMPUTATIONS 560,635

 23 UNBILLED REV - UNCOLLECTIBLE 12,000

 24 UNBILLED REVENUE -58,075 -3,992,000 0.0687

 25 UTAH

 26 08BLSKY01R-BLUESKY ENERGY -2

 27 08CFR00001-MTH FACILITY S 1,265

 28 08CHCK000R-UT RES CHECK M 1

 29 08COOLKPRR-Utah Cool Keeper 90,971

 30 08LNX00001-MTHLY 80% GUAR 3,120

 31 08LNX00005- MNTHLY MIN GUAR 949

 32 08LNX00013-80% MTHLY MIN 30,115

 33 08LNX00016-80% annual gty 605

 34 08LNX00108-ANN COST MTHLY 2,604

 35 08MHTP0025-MOBILE HOME & 12,092 870,739 11 1,099,273 0.0720

 36 08NETMT135 - Net Metering 4,538 397,868 571 7,947 0.0877

 37 08OALT007R-SECURITY AR LG 2,803 791,092 3,084 909 0.2822

 38 08PTLD000R-POST TOP LIGHT 2 125 3 667 0.0625

 39 08RESD0001-RES SRVC 6,292,269 553,304,441 670,049 9,391 0.0879

 40 08RESD0002-RES SRVC-OPTIO 3,069 264,693 352 8,719 0.0862

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.1

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 08RESD0003-LIFELINE PRGRM 257,586 22,409,951 31,622 8,146 0.0870

 2 08RESD0150-RES ALL E NOT5 -4

 3 08UPPL000R-BASE SCH FALL 4

 4 REV. ACCOUNTING ADJ. 5,572,698

 5 SMUD REVENUE IMPUTATIONS 3,386,349

 6 UNBILLED REV - UNCOLLECTIBLE -19,000

 7 UNBILLED REVENUE -23,209 -1,558,000 0.0671

 8 WASHINGTON

 9 02NETMT135 - WA RES NET MTR 320 26,121 15 21,333 0.0816

 10 02NETMT135 - WA RES NET BPA -1,417

 11 02OALTB15R-WA OUTD AR LGT 1,102 156,939 1,184 931 0.1424

 12 02OALTB15R-OUTD AR LGT BPA -4,930

 13 02RESD0016-WA RES SRVC 1,529,247 116,774,628 99,824 15,319 0.0764

 14 02RESD0016-WA RES SRVC -6,774,259

 15 02RESD0017-BILL ASSISTANCE 63,121 4,810,129 3,977 15,872 0.0762

 16 02RESD0017-BILL ASSISTANCE -279,723

 17 02RESD0018-WA 3 PHASE RES 2,437 204,156 89 27,382 0.0838

 18 02RESD0018-WA 3 PHASE RES -10,829

 19 02RESD018X-WA 3 PHASE RES 516 42,442 22 23,455 0.0823

 20 02RESD018X-WA 3 PHASE RES -2,287

 21 02RFNDCENT - CENTRALIA RFND 2

 22 02ZZMERGCR-MERGER CREDITS 2

 23 ACQUISITION COMMIT-A&G CR -43

 24 BPA BALANCING ACCOUNT -542,831

 25 REV. ACCOUNTING ADJ. -3,928,254

 26 SMUD REVENUE IMPUTATIONS 158,816

 27 WA - CHEHALIS DEFERRAL -1,320,000

 28 UNBILLED REV - UNCOLLECTIBLE -8,000

 29 UNBILLED REVENUE 24,434 2,323,000 0.0951

 30 WYOMING

 31 05BLSKY01R-BLUE SKY ENERGY -1

 32 05LNX00102-LINE EXT 80% G 152

 33 05LNX00109-REF/NREF ADV + 129

 34 05NETMT135-EXPERIMENTAL 910 76,631 67 13,582 0.0842

 35 05OALT015R-OUTD AR LGT SR 930 135,210 1,092 852 0.1454

 36 05RESD0002-WY RES SRVC 925,080 77,385,266 96,607 9,576 0.0837

 37 05RESD018X-RES 3 PHASE SR 11 935 1 11,000 0.0850

 38 REV. ACCOUNTING ADJ. 16,692

 39 SMUD REVENUE IMPUTATIONS 83,234

 40 UNBILLED REV - UNCOLLECTIBLE -11,000

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.2

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 UNBILLED REVENUE 3,889 454,000 0.1167

 2 05RESD0002-WY RES SRVC 132,092 11,040,106 12,608 10,477 0.0836

 3 09OALT207R-SECURITY AR LG 78 23,901 92 848 0.3064

 4 05NETMT135 - EXPERIMENTAL 205 16,519 10 20,500 0.0806

 5 09RES0002 2

 6 09RESD0002 -10 -657 4 -2,500 0.0657

 7 UNBILLED REVENUE 404 51,000 0.1262

 8 LESS MULTIPLE BILLINGS -108,183

 9

 10 TOTAL RESIDENTIAL SALES 15,794,444 1,357,826,906 1,474,909 10,709 0.0860

 11

 12 COMMERCIAL SALES

 13 CALIFORNIA

 14 06CHCK000N-CA NRES CHECK 1

 15 06GNSV0025-CA GEN SRVC 58,364 7,902,097 6,854 8,515 0.1354

 16 06GNSV025F-GEN SRVC-< 20 938 141,832 92 10,196 0.1512

 17 06GNSV0A32-GEN SRVC-20 KW 81,098 8,985,799 965 84,039 0.1108

 18 06LGSV048T-LRG GEN SERV 66,219 4,638,318 13 5,093,769 0.0700

 19 06LGSV0A36-LRG GEN SRVC-O 80,706 7,355,985 185 436,249 0.0911

 20 06LNX00102-LINE EXT 80% G 13,662

 21 06LNX00105-CNTRCT $ MIN G 4,591

 22 06LNX00109-REF/NREF ADV + 68,238

 23 06LNX00300-80% MTHLY MIN GU 28,779

 24 06LNX00311-LINE EXT 80% GUAR 3,247

 25 06NMT36135-CA GEN SVC NET 373 37,912 1 373,000 0.1016

 26 06OALT015N-OUTD AR LGT SR 740 160,277 532 1,391 0.2166

 27 06RCFL0042-AIRWAY & ATHLE 204 32,957 38 5,368 0.1616

 28 06WHS31025-COMM WTR HEATI 1 125 28 36 0.1250

 29 06WHSV0031-COMM WTR HEATI 201 23,108 28 7,179 0.1150

 30 06NMT25135-GN SVC NET<20K 33 4,084 1 33,000 0.1238

 31 06NMT32135-GN SVC NET>20K 296 32,856 2 148,000 0.1110

 32 REVENUE ADJ. - DEFERRED NPC 915,488

 33 REV. ACCOUNTING ADJ. -663,108

 34 SMUD REVENUE IMPUTATIONS 33,005

 35 06LNX00110-REF/NREF ADV + 5,305

 36 UNBILLED REVENUE -67 -74,000 1.1045

 37 IDAHO

 38 07CISH0019-COMM & IND SPA 6,348 437,576 123 51,610 0.0689

 39 07GNSV0006-GEN SRVC-LRG P 191,906 12,705,424 947 202,646 0.0662

 40 07GNSV0009-GEN SRVC-HI VO 40,080 1,865,169 1 40,080,000 0.0465

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.3

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 07GNSV0023-GEN SRVC-SML P 129,527 10,399,651 6,299 20,563 0.0803

 2 07GNSV0035-GEN SRVCOPTION 515 29,333 2 257,500 0.0570

 3 07GNSV006A-GEN SRVC-LRG P 30,126 2,088,256 203 148,404 0.0693

 4 07GNSV023A-GEN SRVC-SML P 19,091 1,582,974 1,348 14,162 0.0829

 5 07GNSV023F-GEN SRVC SML P 18 2,652 7 2,571 0.1473

 6 07LNX00010-MNTHLY 80%GUAR 6,302

 7 07LNX00035-ADV 80%MO GUAR 334,092

 8 07LNX00040-ADV+REFCHG+80% 68,273

 9 07OALT007N-SECURITY AR LG 239 87,998 182 1,313 0.3682

 10 07OALT07AN-SECURITY AR LG 12 4,710 14 857 0.3925

 11 07LNX00312 - ID LINE EXT 3,069

 12 07NMT23135-NET MTR-SM GEN 50 4,273 4 12,500 0.0855

 13 07LNX00015-ANNUAL 80%GUAR 2,262

 14 07LNX00311-LINE EXT 80% GUAR 69,214

 15 07LNX00020 -MTHLY CONTRACT 278

 16 07LNX00300-80% MTHLY MIN GU 6,214

 17 BPA BALANCING ACCOUNT 97,039

 18 SMUD REVENUE IMPUTATIONS 45,218

 19 UNBILLED REVENUE -23,780 -1,500,000 0.0631

 20 OREGON

 21 01COST0023-OR GEN SRV-COST 968,227 44,159,121 0.0456

 22 01COST0048 - 01LGSV0048 716,816 30,152,501 0.0421

 23 01COST023F-OR GEN SRV-COST 3,059 147,959 0.0484

 24 01COSTB023-OR GEN SRV-COST 84,379 3,985,038 0.0472

 25 01COSTL030-OR LG GEN SRV 1,043,038 44,636,396 0.0428

 26 01COSTS028-OR GEN SRV -COST 1,913,017 88,237,991 0.0461

 27 01COSTS030-OR GEN SRV -CBS 432 15,272 0.0354

 28 01GNSB0023-BPA DISC<30kW -399,778

 29 01GNSB0023-OR GEN SRV -BPA 5,365,390 14,361

 30 01GNSB0028-OR GEN SRV -BPA -585,975

 31 01GNSB0028-OR GEN SRV -BPA 2,765,447 537

 32 01GNSB023T-OR GEN SRV-TOU 25,212 52

 33 01GNSB023T-OR GEN SRVC-TOU -2,360

 34 01GNSV0023-OR GEN SRV <30kW 40,514,698 57,229

 35 01GNSV0028-OR GEN SRV >30kW 42,000,539 8,971

 36 01GNSV023F-OR GEN SRV -FLAT 9,360 1,331,826 801 11,685 0.1423

 37 01GNSV023M-OR GEN SRV -MANU 42 3,197 1 42,000 0.0761

 38 01GNSV023T-OR GEN SRV-TOU 157,342 232

 39 01HABT0023-OR HABITAT BLEND 2,378 109,892 0.0462

 40 01HABTB023-OR HABITAT BLEND 209 9,845 0.0471

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.4

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01LGSB0030-GEN DEL SRV >200 -221,985

 2 01LGSB0030-GEN DEL SRV >200 797,643 27

 3 01LGSV0030 - OR LRG GEN SRV, 19,041,024 635

 4 01LGSV0048-1000KW AND OVR 8,520,124 97

 5 01LGSV048M-LRG GEN SRVC 1 65,247 3,117,450 1 65,247,000 0.0478

 6 01LNX00100-LINE EXT 60% GUAR 4,918

 7 01LNX00102-LINE EXT 80% GUAR 486,323

 8 01LNX00103-LINE EXT 80% GUAR 3,994

 9 01LNX00105-CNTRCT $ MIN G 15,726

 10 01LNX00109-REF/NREF ADV + 1,789,218

 11 01LNX00110-REF/NREF ADV + 8,502

 12 01LNX00120-LINE EXT 60% GUAR 5,165

 13 01LNX00300-LINE EXT 80% GUAR 124,916

 14 01LNX00311-LINE EXT 80% GUAR 111,367

 15 01LNX00314-LINE EXT 60% GUAR 5,717

 16 01LPRS047M-PART REQ SRVC 11,335 961,860 3 3,778,333 0.0849

 17 01NMT23135 - OR NET MTR, GEN, 72,645 100

 18 01NMT23135 - OR NET MTR, GEN, -86

 19 01OALT014N-OUTD AR LGT NR 1,555 255,017 1,155 1,346 0.1640

 20 01OALT014N-OUTD AR LGT NR -7,588

 21 01OALT015N-OUTD AR LGT NR 5,812 809,585 3,061 1,899 0.1393

 22 01PTOU0023, OR GEN SRV, TOU 3,563 163,149 0.0458

 23 01PTOUB023, OR GEN SRV, TOU 534 24,295 0.0455

 24 01RCFL0054-REC FIELD LGT 1,087 101,517 104 10,452 0.0934

 25 01RENW0023, OR RENW USAGE 8,142 378,344 0.0465

 26 01RENWB023 - OR RENEWABLE 479 23,120 0.0483

 27 01STDAY023 - OR DAY STD OFR, 2,037 126,970 0.0623

 28 01STDAY028 - OR DAY STD OFF, 7,103 431,998 0.0608

 29 01STDAY030 - OR STD DAY OFF, 4,350 256,620 0.0590

 30 01VIR23136-OR VOLUME INCENTV 45 3

 31 01VIR28136-OR VOLUME INCENTV 1,398 2

 32 01ZZMERGCR-MERGER CREDITS -1

 33 BPA BALANCING ACCOUNT -31,738

 34 01LGSB0048 - LG GEN SVC > -14,577

 35 01LGSB0048 - LG GEN SVC > 49,026 1

 36 01NMT28135 - OR NET MTR, GEN, 204,692 41

 37 01NMT30135 - OR NET MTR, GEN, 246,217 10

 38 01LGSV028M - OR LGSV, <1000 458 32,451 1 458,000 0.0709

 39 01GNSV030M - OR GEN SRV, 200 1,650 93,399 1 1,650,000 0.0566

 40 01GNSV0728 - OR GEN SVC DIR 255,071 8

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.5

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01GNSV0730 -OR GEN SVC DIR 2,461,768 33

 2 01GNSV0748 LG GEN SVC DIR 542,541 2

 3 OR GAIN ON SALE OF ASSET 297,113

 4 OR SB408 RECOVERY 628,755

 5 OR SB 838 RECOVERY -1,592,366

 6 REV. ACCOUNTING ADJ. -20,866

 7 SMUD REVENUE IMPUTATIONS 496,288

 8 UNBILLED REVENUE -63,458 -3,371,000 0.0531

 9 UTAH

 10 08CFR00051-MTH FAC SRVCHG 39,713

 11 08CFR00052-ANN FAC SVCCHG 2

 12 08COOLKPRN - A/C DIRECT LOAD 3,554

 13 08GNSV0006-GEN SRVC-DISTR 4,771,840 330,746,047 10,914 437,222 0.0693

 14 08GNSV0009-GEN SRVC-HI VO 267,105 12,837,629 25 10,684,200 0.0481

 15 08GNSV0023-GEN SRVC-DISTR 1,251,393 103,757,349 72,903 17,165 0.0829

 16 08GNSV006A-GEN SRVC-ENERG 196,244 18,643,401 1,760 111,502 0.0950

 17 08GNSV006B-GEN SRVC-DEM& 9,130 620,766 21 434,762 0.0680

 18 08GNSV006M-MNL DIST VOLTG 3,463 204,018 7 494,714 0.0589

 19 08GNSV009A-GEN SRVC HI VO 24,022 1,239,923 2 12,011,000 0.0516

 20 08GNSV023F-GEN SRVC FIXED 1,388 160,765 130 10,677 0.1158

 21 08GNSV023M-GNSV DIST VOLT 109 8,869 5 21,800 0.0814

 22 08GNSV06AM-MNL ENERGY TOD 795 1

 23 08GNSV06MN-GNSV DIST VOLT 26,380 1,726,284 446 59,148 0.0654

 24 08LNX00002-MTHLY 80% GUAR 545,339

 25 08LNX00004-ANNUAL 80%GUAR 86,151

 26 08LNX00006-FIXD MTHLY MIN 1,816

 27 08LNX00008-ANNUALMIN GUAR 12,167

 28 08LNX00014-80% MIN MNTHLY 2,073,877

 29 08LNX00017-ADV/REF&80%ANN 341,431

 30 08LNX00158-ANNUALCOST MTH 34,209

 31 08LNX00300 - LINE EXT 80% PLUS 124,444

 32 08LNX00310 - IRR, 80% ANNUAL 3,758

 33 08LNX00312 UT IRG LINE EXT 10,579

 34 08NMT06135 - UT NET MTR, GEN, 10,298 739,943 19 542,000 0.0719

 35 08NMT08135 -NET METERING 5,751 335,791 1 5,751,000 0.0584

 36 08NMT23135 - UT NET MTR, GEN, 1,022 85,836 51 20,039 0.0840

 37 08NMT6A135-NET METERING GEN 19 3,108 1 19,000 0.1636

 38 08OALT007N-SECURITY AR LG 8,639 1,983,135 4,499 1,920 0.2296

 39 08POLE0075-POLES W/LIGHT 61 1

 40 08PRSV031M-BKUP MNT&SUPPL 10,713 692,801 2 5,356,500 0.0647

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.6

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 08PTLD000N-POST TOP LIGHT 6 454 2 3,000 0.0757

 2 08TOSS015F-TRAFFIC SIG NM 149 15,045 26 5,731 0.1010

 3 08TOSS0015-TRAF & OTHER S 1,240 116,009 559 2,218 0.0936

 4 08MONL0015-MTR OUTDONIGHT 14,397 1,008,800 371 38,806 0.0701

 5 REV. ACCOUNTING ADJ. 5,787,624

 6 SMUD REVENUE IMPUTATIONS 3,895,349

 7 08LNX00311 - LINE EXT 80% 210,085

 8 08GNSV0008 - UT GEN SVC TOU > 952,000 56,593,171 150 6,346,667 0.0594

 9 08GNSV008M - UT GEN SVC TOU 33,691 2,152,344 5 6,738,200 0.0639

 10 UNBILLED REVENUE -5,703 327,000 -0.0573

 11 WASHINGTON

 12 02GNSB0024-WA GEN SRVC DO 40,251 3,327,361 3,179 12,662 0.0827

 13 02GNSB0024-WA GEN SRVC DO -177,594

 14 02GNSB024F-GEN SRVC DOM/F 154 16,065 6 25,667 0.1043

 15 02GNSB024F-GEN SRVC DOM/F -4

 16 02GNSB24FP-WA GEN SVC 351 114,460 100 3,510 0.3261

 17 02GNSB24FP-WA GEN SVC -1,558

 18 02GNSV0024-WA GEN SRVC 467,368 35,405,704 14,411 32,431 0.0758

 19 02GNSV024F-WA GEN SRVC-FL 1,115 124,826 112 9,955 0.1120

 20 02LGSB0036-LRG GEN SVC IRG 82,828 5,227,389 98 845,184 0.0631

 21 02LGSB0036-LRG GENSVC IRG -359,983

 22 02LGSV0036-WA LRG GEN SRV 680,624 43,770,704 819 831,043 0.0643

 23 02LGSV048T-LRG GEN SRVC 1 143,366 8,336,036 26 5,514,077 0.0581

 24 02LNX00102-LINE EXT 80% G 123,739

 25 02LNX00103-LINE EXT 80% G 6,553

 26 02LNX00105-CNTRCT $ MIN G 652

 27 02LNX00109-REF/NREF ADV + 390,446

 28 02LNX00110-REF/NREF ADV + 14,283

 29 02LNX00112-YR INCURRED CH 669

 30 02LNX00300-LINE EXT 80% G 3,070

 31 02LNX00310 - IRG, 80% ANNUAL 4,351

 32 02LNX00311 - LINE EXT 80% 26,159

 33 02LNX00312 - WA IRG LINE EXT 2,769

 34 02OALT015N-WA OUTD AR LGT 1,650 217,376 856 1,928 0.1317

 35 02OALTB15N-WA OUTD AR LGT 603 85,036 523 1,153 0.1410

 36 02OALTB15N-WA OUTD AR LGT -2,687

 37 02RCFL0054-WA REC FIELD L 278 24,091 29 9,586 0.0867

 38 02RFNDCENT - CENTRALIA RFND 175

 39 02ZZMERGCR-MERGER CREDITS -23

 40 02NMT24135, Net metering, WA 73 6,307 0.0864

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.7

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 02NMT36135-WA NET METER LRG 110 10,388 0.0944

 2 ACQUISITION COMMIT-A&G CR -38

 3 BPA BALANCING ACCOUNT -31,111

 4 REV. ACCOUNTING ADJ. -3,090,281

 5 SMUD REVENUE IMPUTATIONS 140,164

 6 WA - CHEHALIS DEFERRAL -1,020,000

 7 UNBILLED REVENUE -18,246 -924,000 0.0506

 8 WYOMING

 9 05CHCK000N-WY NRES 1

 10 05GNS28025-GEN SVC 31,513 2,237,603 1,767 17,834 0.0710

 11 05GNSC0025 - WY SMALL 269 18,481 25 10,760 0.0687

 12 05GNSV0025-WY GEN SRVC 155,755 13,027,409 16,346 9,529 0.0836

 13 05GNSV0028-GEN SVC > 15 KW 922,357 66,652,138 4,044 228,080 0.0723

 14 05GNSV025F-GEN SRVC-FL RA 974 132,395 190 5,126 0.1359

 15 05LGSV0046-WY LRG GEN SRV 222,489 12,532,839 20 11,124,450 0.0563

 16 05LGSV046M-WY LRG GEN SERV 23,362 1,317,396 1 23,362,000 0.0564

 17 05LGSV048T-LRG GENSRV TIM 9,940 621,563 1 9,940,000 0.0625

 18 05LNX00100-LINE EXT 60% G 102

 19 05LNX00102-LINE EXT 80% G 565,208

 20 05LNX00103-LINE EXT 80% 808

 21 05LNX00105-CNTRCT $ MIN G 5,343

 22 05LNX00109-REF/NREF ADV + 612,454

 23 05LNX00110-REF/NREF ADV+ 838

 24 05LNX00114-TEMP SVC 12MO> 5,191

 25 05N2825135 - NET METERING 12 1,056 1 12,000 0.0880

 26 05NMT25135 - WY NET MTR, GEN, 172 11,827 8 21,500 0.0688

 27 05NMT28135-NET MTR SMALL 1,283 116,025 7 183,286 0.0904

 28 05OALT015N-OUTD AR LGT SR 2,871 420,027 1,749 1,642 0.1463

 29 05RCFL0054-WY REC FIELD L 664 49,983 50 13,280 0.0753

 30 05LNX00300 - LINE EXT 80% 191,062

 31 05LNX00311 - LINE EXT 80% 63,037

 32 REV. ACCOUNTING ADJ. 20,691

 33 SMUD REVENUE IMPUTATIONS 116,998

 34 UNBILLED REVENUE -2,016 -229,000 0.1136

 35 05GNS28025-GEN SVC 4,750 342,254 279 17,025 0.0721

 36 05GNSC0025 - WY SMALL 42 2,746 3 14,000 0.0654

 37 05GNSV0025 - WY GEN SRVC 20,596 1,699,429 2,067 9,964 0.0825

 38 05GNSV0028-GEN SVC > 15 KW 115,540 8,260,171 550 210,073 0.0715

 39 05GNSV025F-GEN SRVC-FL RA 195 19,337 32 6,094 0.0992

 40 05GNSV028M-GEN SVC>15 KW 1,865 129,994 1 1,865,000 0.0697

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.8

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 05LNX00102-LINE EXT 80% G 5,167

 2 05LNX00109-REF/NREF ADV + 167,539

 3 05LNX00110-REF/NREF ADV + 257

 4 05LNX00114-TEMP SVC 481

 5 09GNSV0025-GEN SVC-SINGLE -9 -816 0.0907

 6 05NMT25135 - WY NET MTR, GEN, 24 1,734 1 24,000 0.0723

 7 05NMT28135-NET MTR SMALL 165 15,516 1 165,000 0.0940

 8 09OALT207N-SECURITY AR LG 278 75,336 139 2,000 0.2710

 9 09MONL0213-WY MTR OUTDOOR 21 1,738 3 7,000 0.0828

 10 05LNX00300 - LINE EXT 80% -34,511

 11 05LNX00311 - LINE EXT 80% 6,662

 12 UNBILLED REVENUE -1,769 -105,000 0.0594

 13 LESS MULTIPLE BILLINGS -28,068

 14

 15 TOTAL COMMERCIAL SALES 15,969,253 1,146,322,741 220,171 72,531 0.0718

 16

 17 INDUSTRIAL SALES

 18 CALIFORNIA

 19 06GNSV0025-CA GEN SRVC 728 101,075 96 7,583 0.1388

 20 06GNSV0A32-GEN SRVC-20 KW 1,868 231,485 27 69,185 0.1239

 21 06LGSV048T-LRG GEN SERV 38,459 2,661,481 5 7,691,800 0.0692

 22 06LGSV0A36-LRG GEN SRVC-O 5,103 519,076 14 364,500 0.1017

 23 06LNX00109-REF/NREF ADV + 236

 24 REVENUE ADJ.-DEFERRED NPPC 173,488

 25 REV. ACCOUNTING ADJ. -77,920

 26 SMUD REVENUE IMPUTATIONS 5,175

 27 UNBILLED REVENUE 7 -11,000 -1.5714

 28 IDAHO

 29 07CFR00001-MTH FACILITY S 2,217

 30 07CISH0019-COMM & IND 132 9,564 3 44,000 0.0725

 31 07GNSV0006-GEN SRVC-LRG P 91,682 5,170,021 112 818,589 0.0564

 32 07GNSV0009-GEN SRVC-HI VO 77,002 3,665,442 11 7,000,182 0.0476

 33 07GNSV0023-GEN SRVC-SML P 10,709 835,814 353 30,337 0.0780

 34 07GNSV0035-GEN SRVCOPTION 1,192 67,630 1 1,192,000 0.0567

 35 07GNSV006A-GEN SRVC-LRG P 4,651 326,841 31 150,032 0.0703

 36 07GNSV023A-GEN SRVC-SML P 2,026 187,140 245 8,269 0.0924

 37 07GNSV023S-ID TRAFFIC 8 1,055 3 2,667 0.1319

 38 07LNX00035-ADV 80%MO GUAR 693

 39 07LNX00108-ANN COST MTHLY 1,996

 40 07LNX00300 - 80% MONTHLY MIN 1,876

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.9

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 07OALT007N-SECURITY AR LG 13 4,970 17 765 0.3823

 2 07OALT07AN-SECURITY AR LG 1 284 2 500 0.2840

 3 07SPCL0001 1,381,900 61,415,663 1 1,381,900,000 0.0444

 4 07SPCL0002 104,026 4,418,677 1 104,026,000 0.0425

 5 BPA BALANCING ACCOUNT 14,963

 6 SMUD REVENUE IMPUTATIONS 138,631

 7 UNBILLED REVENUE -6,118 216,000 -0.0353

 8 OREGON

 9 01COST0023, OR GEN SRV, COST 20,565 940,856 0.0458

 10 01COST0048 - 01LGSV0048 1,558,066 64,298,860 0.0413

 11 01COST023F - OR GEN SRV - 2 112 0.0560

 12 01COSTB023 - OR GEN SRV, 407 18,984 0.0466

 13 01COSTL030 - OR LRG GEN SRV, 189,674 8,158,845 0.0430

 14 01COSTS028, OR GEN SERV, 92,687 4,272,414 0.0461

 15 01GNSB0023 - BPA DISC, < 30 -1,914

 16 01GNSB0023, OR GEN SRV, BPA, 27,173 65

 17 01GNSB0028 - OR GEN SRVC, -2,344

 18 01GNSB0028, OR GEN SRV, BPA, 15,778 5

 19 01GNSV0023, OR GEN SRV, < 30 917,833 1,158

 20 01GNSV0028, OR GEN SRV > 30 2,716,922 493

 21 01GNSV023F - OR GEN SRV - 2 756 2 1,000 0.3780

 22 01GNSV023M - OR GEN SRV, 40 9,066 1 40,000 0.2267

 23 01GNSV023T, OR GEN SRV, TOU 2,763 4

 24 01GNSV0728 - OR GEN SVC DIR 4,386 1

 25 01GNSV0748 - OR GEN SVC DIR 544,025 3

 26 01HABT0023, OR HABITAT 11 518 0.0471

 27 01LGSV0030 - OR LRG GEN SRV, 5,269,124 155

 28 01LGSV0048-1000KW AND OVR 15,192,976 106

 29 01LGSV048M-LRG GEN SRVC 1 194,954 9,744,333 5 38,990,800 0.0500

 30 01LNX00102-LINE EXT 80% G 18,092

 31 01LNX00105-CNTRCT $ MIN 131

 32 01LNX00120 - Line Extension 60% G 25,234

 33 01LNX00300 - LINE EXT 80% 10,293

 34 01LPRS047M-PART REQ 199,856 9,466,247 3 66,618,667 0.0474

 35 01NMT23135 - OR NET MTR, GEN, 869 1

 36 01NMT28135 - OR NET MTR, GEN, 5,790 1

 37 01OALT014N-OUTD AR LGT NR 4 640 5 800 0.1600

 38 01OALT014N-OUTD AR LGT -22

 39 01OALT015N-OUTD AR LGT 320 43,249 143 2,238 0.1352

 40 01PTOU0023, OR GEN SRV, TOU 52 2,403 0.0462

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.10

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01RENW0023, OR RENW USAGE 164 7,445 0.0454

 2 01RENWB023 - OR RENEWABLE 1 35 0.0350

 3 BPA BALANCING ACCOUNT -99

 4 01STDAY023 - OR DAY STD OFR, 21 1,303 0.0620

 5 01STDAY028 - OR DAY STD OFR, 165 10,629 0.0644

 6 OR GAIN ON SALE OF ASSET 205,340

 7 OR SB 408 RECOVERY 405,978

 8 OR SB 838 RECOVERY -857,468

 9 REV. ACCOUNTING ADJ. -13,854

 10 SMUD REVENUE IMPUTATIONS 249,554

 11 UNBILLED REVENUE -28,893 -1,026,000 0.0355

 12 UTAH

 13 08CFR00051-MTH FAC SRVCHG 14,047

 14 08EFOP0021-ELEC FURNACE O 1,733 141,072 2 866,500 0.0814

 15 08EFOP021M-ELEC FURNACE O 1,199 142,548 3 399,667 0.1189

 16 08GNSV0006-GEN SRVC-DISTR 687,733 50,759,257 1,181 582,331 0.0738

 17 08GNSV0009-GEN SRVC-HI VO 2,643,518 116,750,885 111 23,815,477 0.0442

 18 08GNSV0023-GEN SRVC-DISTR 59,315 4,998,451 3,645 16,273 0.0843

 19 08GNSV006A-GEN SRVC-ENERG 53,164 5,347,875 244 217,885 0.1006

 20 08GNSV006B-GEN 7,397 523,850 8 924,625 0.0708

 21 08GNSV009A-GEN SRVC HI VO 17,270 1,164,639 6 2,878,333 0.0674

 22 08GNSV009M-MANL HIGH 837,489 34,846,273 11 76,135,364 0.0416

 23 08GNSV023F-GEN SRVC FIXED 4 1,892 1 4,000 0.4730

 24 08GNSV06MN-GNSV DIST VOLT 1,242 93,158 30 41,400 0.0750

 25 08GNSV09AM-MAN TOD HIVOLT 2,072 208,656 1 2,072,000 0.1007

 26 08LNX00002-MTHLY 80% GUAR 28,800

 27 08LNX00004-ANNUAL 80%GUAR 753,230

 28 08LNX00014-80% MIN 57,387

 29 08LNX00017-ADV/REF&80%ANN 2,944

 30 08LNX00311 - LINE EXT 80% 2,126

 31 08LNX00300 - LINE EXT 80% PLUS 91,742

 32 08LNX00310 - IRR, 80% ANNUAL 5,424

 33 08OALT007N-SECURITY AR 1,395 292,894 504 2,768 0.2100

 34 08TOSS0015-TRAF & OTHER S 26 2,358 10 2,600 0.0907

 35 08MONL0015-MTR OUTDONIGHT 11 2,820 6 1,833 0.2564

 36 08NMT06135-UT NET MTR,GEN, 271 21,751 1 271,000 0.0803

 37 08NMT23135-UT NET MTR, GEN, 85 5,542 1 85,000 0.0652

 38 08PRSV031M-BKUP MNT&SUPP 3,514 516,205 1 3,514,000 0.1469

 39 08SPCL0001 472,728 18,433,648 1 472,728,000 0.0390

 40 08SPCL0002 861,461 25,718,913 1 861,461,000 0.0299

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.11

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 08SPCL0003 721,792 26,133,414 1 721,792,000 0.0362

 2 08SPCL0005 241,092 9,435,337 1 241,092,000 0.0391

 3 REV. ACCOUNTING ADJ. 3,576,966

 4 SMUD REVENUE IMPUTATIONS 3,923,014

 5 08GNSV06AM-MNL ENERGY TOD 348 38,191 2 174,000 0.1097

 6 08GNSV0008 - UT GEN SVC TOU > 918,970 57,686,601 115 7,991,043 0.0628

 7 08GNSV008M - UT GEN SVC TOU 58,689 3,626,179 7 8,384,143 0.0618

 8 UNBILLED REVENUE 37,497 1,256,000 0.0335

 9 WASHINGTON

 10 02GNSB0024-WA GEN SRVC 1,885 160,423 95 19,842 0.0851

 11 02GNSB0024-WA GEN SRVC DO -8,196

 12 02GNSB24FP-WA GEN SVC 7 2,263 1 7,000 0.3233

 13 02GNSB24FP-WA GEN SVC -31

 14 02GNSV0024-WA GEN SRVC 16,378 1,264,050 367 44,627 0.0772

 15 02GNSV024F-WA GEN 33 6,885 4 8,250 0.2086

 16 02LGSV0036-WA LRG GEN SRV 121,064 7,930,744 118 1,025,966 0.0655

 17 02LGSV048T-WA LRG GEN SRV 670,444 34,417,221 32 20,951,375 0.0513

 18 02OALT015N-WA OUTD AR LGT 122 15,098 42 2,905 0.1238

 19 02OALTB15N-WA OUTD AR LGT 30 4,283 17 1,765 0.1428

 20 02OALTB15N-WA OUTD AR LGT -135

 21 02PRSV47TM-LRG PART REQMT 1,799 257,200 1 1,799,000 0.1430

 22 02LGSB0036-LRG GEN SVC IRG 4,093 422,382 29 141,138 0.1032

 23 02LGSB0036-LRG GENSVC IRG -18,131

 24 ACQUISITION COMMIT-A & G CR -29

 25 BPA BALANCING ACCOUNT -2,046

 26 REV. ACCOUNTING ADJ. -1,456,657

 27 SMUD REVENUE IMPUTATIONS 80,837

 28 WA - CHEHALIS DEFERRAL -510,000

 29 UNBILLED REVENUE -14,562 -700,000 0.0481

 30 WYOMING

 31 05GNS28025-GEN SVC 7,459 473,749 179 41,670 0.0635

 32 05GNSV0025-WY GEN SRVC 14,734 1,114,868 1,033 14,263 0.0757

 33 05GNSV0028-GEN SRVC > 15 KW 264,730 16,740,816 504 525,258 0.0632

 34 05GNSV025F-GEN SRVC-FL RA 21 2,568 5 4,200 0.1223

 35 05LGSV0046-WY LRG GEN 1,575,373 83,641,666 54 29,173,574 0.0531

 36 05LGSV046M-WY LRG GEN 119,548 5,944,882 2 59,774,000 0.0497

 37 05LGSV048M-TOU>1000KW MAN 1,310,345 54,432,211 3 436,781,667 0.0415

 38 05LGSV048T-LRG GENSRV TIM 1,308,474 55,771,163 10 130,847,400 0.0426

 39 05LNX00100-LINE EXT 60% G 45,122

 40 05LNX00102-LINE EXT 80% G 228,759

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.12

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 05LNX00105-CNTRCT $ MIN G 46,426

 2 05LNX00109-REF/NREF ADV + 184,865

 3 05OALT015N-OUTD AR LGT SR 85 11,429 44 1,932 0.1345

 4 05PRSV033M-PART SERV REQ 870,129 44,191,804 5 174,025,800 0.0508

 5 REV. ACCOUNTING ADJ. 62,172

 6 SMUD REVENUE IMPUTATIONS 523,920

 7 05LNX00300 - LINE EXT 80% 47,766

 8 05LNX00311 - LINE EXT 80% 11,623

 9 UNBILLED REVENUE 12,655 794,000 0.0627

 10 05GNS28025-WY GEN SVC 1,023 71,018 32 31,969 0.0694

 11 05GNSV0025-WY GEN SRVC 2,668 224,869 272 9,809 0.0843

 12 05GNSV0028-GEN SVC > 15 KW 34,076 2,255,888 77 442,545 0.0662

 13 05GNSV028M -GEN SVC > 15 KW 4,937 263,562 4 1,234,250 0.0534

 14 05LGSV0046-WY LRG GEN SRV 26,215 1,687,664 4 6,553,750 0.0644

 15 05LGSV048M-TOU>1000KW MAN 312,528 13,131,323 3 104,176,000 0.0420

 16 05LGSV048T-LRG GENSRV 1,099,328 47,549,355 9 122,147,556 0.0433

 17 05LNX00102-LINE EXT 80% G 6,096

 18 05LNX00109-REF/NREF ADV 23

 19 05PRSV033M-PART SERV REQ 110,469 5,060,947 3 36,823,000 0.0458

 20 09OALT207N-SECURITY AR 5 1,120 3 1,667 0.2240

 21 UNBILLED REVENUE -1,733 -16,000 0.0092

 22 LESS MULTIPLE BILLINGS -1,131

 23

 24 TOTAL INDUSTRIAL SALES 19,445,864 943,745,752 10,788 1,802,546 0.0485

 25

 26 IRRIGATION SALES

 27 CALIFORNIA

 28 06APSV0020-AG PMP SRVC 60,763 6,268,966 1,360 44,679 0.1032

 29 06LGSV048T-LRG GEN SERV 800 72,053 1 800,000 0.0901

 30 06LNX00102-LINE EXT 80% G 1,109

 31 06LNX00103-LINE EXT 80% G 5,526

 32 06LNX00110-REF/NREF ADV + 32,953

 33 06LNX00312 - CA IRG LINE EXT 2,261

 34 06USBR0020-KLAM IRG ONPRJ 28,501 3,135,630 658 43,315 0.1100

 35 06LNX00109-REF/NREF ADV + 327

 36 IRRIGATION UNBILLED 8 1,000 0.1250

 37 REV. ACCOUNTING ADJ. -184,958

 38 IDAHO

 39 07APSA010L - IRG & Pump Large 432,645 31,523,280 3,253 132,999 0.0729

 40 07APSA010S - IRG & PUMP BPA -14

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.13

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 07APSA010S - IRG & Pump Small 4,763 433,869 409 11,645 0.0911

 2 07APSAL10X - IRG & PUMP - Large 82,903 6,147,887 785 105,609 0.0742

 3 07APSAS10X - IRG & PUMP - Small 1,840 180,573 219 8,402 0.0981

 4 07APSVCNLL-LRG LOAD CANAL 31,184 2,037,751 80 389,800 0.0653

 5 07APSVCNLS-SML LOAD CANAL 125 13,233 18 6,944 0.1059

 6 07BPADEBIT-BPA ADJUST FEE 2,982

 7 07LNX00015-ANNUAL 80%GUAR 4,532

 8 07LNX00040-ADV+REFCHG+80% 211,106

 9 07LNX00107-SUBD ADV & AIC 1,097

 10 07LNX00310 80% ANNUAL 6,511

 11 07LNX00312 - ID LINE EXT 31,387

 12 07APSN010L - ID LG IRR & PUMP 3,357 278,453 47 71,426 0.0829

 13 07APSN010S - IRRIGATION, 320 28,142 20 16,000 0.0879

 14 07APSNS10X - IRRIGATION, 4 819 2 2,000 0.2048

 15 IRRIGATION BPA BAL ACCT -1,149,332

 16 UNBILLED REV - IRRIGATION 87 6,000 0.0690

 17 OREGON

 18 01APSV0041-AG PMP SRVC BP 1,800,072 4,702

 19 01APSV0041-AG PMP SRVC BP -175,195

 20 01APSV041L-OR Pumping Serv 2,432,864 1,058

 21 01APSV041L-OR Pumping Serv -294,717

 22 01APSV041T - AGR PUMP SRV -2,480

 23 01APSV041T - AGR PUMP 25,685 58

 24 01APSV041X-AG PMP SRVC 85,403 256

 25 01APSV41XL-OR Pumping Serv no 224,729 63

 26 01BPADEBIT-BPA ADJUST FEE 28,605

 27 108,450 4,972,929 0.0459

 28 01COST0048 - 01LGSV0048 6,048 250,337 0.0414

 29 01COSTS028, OR GEN SERV, 279 12,913 0.0463

 30 01GNSV0028, OR GEN SRV > 30 9,124 2

 31 01HABIT041 - 01APSV0041 AG 3 141 0.0470

 32 01LGSB0048 - LG GEN SVC > -28,365

 33 01LGSB0048 - LG GEN SVC > 77,312 1

 34 01LNX00103-LINE EXT 80% G 15,846

 35 01LNX00109-REF/NREF ADV + 9,901

 36 01LNX00110-REF/NREF ADV + 155,647

 37 01LNX00310-LINE EXTENSION 2,896

 38 01PTOU0041 - 01APSV0041 AG 546 22,668 0.0415

 39 01RENEW041 - 01APSV0041 AG 97 4,480 0.0462

 40 01SLX00005-KLAMATH FALLS 181,173

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.14

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01SLX00013-K FALLS IRG MI 8,626

 2 01SLX00014-K FALLS IRG MI 1,556

 3 01STDAY041 - Daily Standard Offer 35 2,162 0.0618

 4 01USBGV033-KLAMATH IRG TOU -57

 5 01USBOF033-KLAMATH BASIN 43,991 1,485,667 640 68,736 0.0338

 6 01USBOF033-KLAMATH BASIN -169,715

 7 01USBON033-KLAMATH BASIN 47,229 1,468,399 1,375 34,348 0.0311

 8 01USBON033-KLAMATH BASIN -181,356

 9 01USBGV033-IRG TOU W/O BPA 2,008 43,528 10 200,800 0.0217

 10 IRRIGATION BPA BAL ACCT 51,940

 11 IRRIGATION UNBILLED -118 -11,000 0.0932

 12 01LNX00312 - OR IRG LINE EXT 13,458

 13 01NMT33135 - OR NET MTR - 6 174 1 6,000 0.0290

 14 01NMT33135 - NETMTR AG PMP -22

 15 01NMT41135 - NETMTR AG PMP 162 1

 16 OR GAIN ON SALE OF ASSET 15,494

 17 OR Irrigation - BPA adjustment 11,597

 18 OR SB408 RECOVERY 33,130

 19 OR SB 838 RECOVERY -84,044

 20 REV. ACCOUNTING ADJ. 1

 21 UTAH

 22 08APSV0010-IRR & SOIL DRA 191,267 11,752,335 2,662 71,851 0.0614

 23 08APSV10NS- Irg Soil Drain Pump N 15,013 880,706 94 159,713 0.0587

 24 08LNX00002-MTHLY 80% GUAR 842

 25 08LNX00004-ANNUAL 80%GUAR 9,123

 26 08LNX00014-80% MIN MNTHLY 1,998

 27 08LNX00017-ADV/REF&80%ANN 153,527

 28 08LNX00310 - IRR, 80% ANNUAL 11,601

 29 08LNX00312 UT IRG LINE EXT 9,728

 30 08NMT10135-UT IRR_SOIL DRNG 15 1,211 1 15,000 0.0807

 31 REV. ACCOUNTING ADJ. 138,166

 32 UNBILLED REV - IRRIGATION 90 3,000 0.0333

 33 WASHINGTON

 34 02APSV0040-WA AG PMP SRVC 128,040 9,382,914 4,580 27,956 0.0733

 35 02APSV0040-WA AG PMP SRVC -566,728

 36 02APSV040X-WA AG PMP SRVC 22,420 1,631,029 703 31,892 0.0727

 37 02BPADEBIT-BPA ADJUST FEE 12,958

 38 02LNX00102-LINE EXT 80% G 805

 39 02LNX00103-LINE EXT 80% G 5,541

 40 02LNX00105-CNTRCT $ MIN G 30

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.15

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 02LNX00110-REF/NREF ADV + 129,070

 2 02LNX00310-IRG, 80% ANN MIN + 1,569

 3 02LNX00311 - LINE EXT 80% 49

 4 02LNX00312 - WA IRG LINE EXT 12,626

 5 02ZZMERGCR-MERGER CREDITS 6

 6 REV. ACCOUNTING ADJ. -356,266

 7 WA - CHEHALIS DEFERRAL -120,000

 8 IRRIGATION BPA BAL ACCT -2,706

 9 IRRIGATION UNBILLED 151 10,000 0.0662

 10 WYOMING

 11 05APS00040-AG PUMPING SVC 17,447 1,276,733 633 27,562 0.0732

 12 05LNX00110-REF/NREF ADV + 59,697

 13 05LNX00103-LINE EXT 80% G 8,519

 14 05LNX00310 - WY IRG LINE EXT 351

 15 05LNX00312 - WY IRG LINE EXT 377

 16 IRRIGATION UNBILLED -16 -1,000 0.0625

 17 05APS00040-AG PUMPING SVC 28 1,820 1 28,000 0.0650

 18 05LNX00103-LINE EXT 80%G 1,958

 19 05LNX00110-REF/NREF ADV + 14,667

 20 09APSV0210-IRR & SOIL DRA 3,260 245,862 70 46,571 0.0754

 21 LESS MULTIPLE BILLINGS -697

 22

 23 TOTAL IRRIGATION SALES 1,233,589 86,306,929 23,066 53,481 0.0700

 24

 25 PUBLIC STREET & HWY LIGHTING

 26 CALIFORNIA

 27 06CUSL053F-SPECIAL CUST O 1,441 175,930 120 12,008 0.1221

 28 06CUSL058F-CUST OWND STR 242 33,988 23 10,522 0.1404

 29 06HPSV0051-HI PRESSURE SO 692 171,246 78 8,872 0.2475

 30 REV.ACCOUNTING ADJ. -8,830

 31 UNBILLED REVENUE -34 -6,000 0.1765

 32 IDAHO

 33 07GNSV023S-ID TRAFFIC 152 14,967 25 6,080 0.0985

 34 07SLCO0011-STR LGT CO-OWN 100 44,235 29 3,448 0.4424

 35 07SLCU012E-ENGY STR 247 26,286 17 14,529 0.1064

 36 07SLCU012F-FULL MNT STR 1,930 364,957 281 6,868 0.1891

 37 07SLCU012P-PART MNT STR LGT 192 26,435 16 12,000 0.1377

 38 UNBILLED REVENUE -38 -6,000 0.1579

 39 OREGON

 40 01COSL0052-STR LGT SRVC C 943 122,013 60 15,717 0.1294

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.16

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01CUSL0053-CUS-OWNED MTRD 815 58,101 70 11,643 0.0713

 2 01CUSL053E-STR LGT SVC 8,441 604,207 166 50,849 0.0716

 3 01CUSL053F-STR LGT SRVC C 261 27,956 21 12,429 0.1071

 4 01HPSV0051-HI PRESSURE SO 17,751 3,702,764 699 25,395 0.2086

 5 01LEDSL055-OR LED PIOT 31 1

 6 01MVSL0050-MERC VAPSTR LG 9,422 1,208,653 259 36,378 0.1283

 7 01OALT014N-OUTD AR LGT NR 4 793 4 1,000 0.1983

 8 01OALT014N-OUTD AR LGT NR -18

 9 01OALT015N-OUTD AR LGT NR 9 1,495 4 2,250 0.1661

 10 OR GAIN ON SALE OF ASSET 2,554

 11 OR SB408 RECOVERY 5,014

 12 OR SB 838 RECOVERY -8,905

 13 REV. ACCOUNTING ADJ. 1

 14 UNBILLED REVENUE -443 -36,000 0.0813

 15 UTAH

 16 08CFR00012-STR LGTS (CONV 54

 17 08CFR00051-MTH FAC SRVCHG 4,529

 18 08CFR00062-STREET LIGHTS 79

 19 08OALT007N-SECURITY AR LG 13 3,759 10 1,300 0.2892

 20 08TOSS015F-TRAFFIC SIG NM 1,159 88,101 123 9,423 0.0760

 21 08SLCO0011-STR LGT CO-OWN 20,490 6,008,760 969 21,146 0.2933

 22 08TOSS0015-TRAF & OTHER S 2,911 282,499 1,504 1,936 0.0970

 23 08MONL0015-MTR OUTDONIGHT 1,023 81,307 57 17,947 0.0795

 24 08SLCU012P-STR LGT CUST-O 5,721 703,896 240 23,838 0.1230

 25 08SLCU012F-STR LGT CUST-O 2,706 369,890 121 22,364 0.1367

 26 08SLCU012E-DECOR CUST-OWN 45,193 2,967,340 446 101,330 0.0657

 27 08THIK0077-STR LIGHT SPEC 141 17,277 1 141,000 0.1225

 28 REV. ACCOUNTING ADJ. 276,332

 29 UNBILLED REVENUE 1,152 108,000 0.0938

 30 WASHINGTON

 31 02CFR00012-STR LGTS (CONV 91

 32 02COSL0052-WA STR LGT SRV 406 58,221 19 21,368 0.1434

 33 02CUSL053F-WA STR LGT SRV 3,589 244,583 105 34,181 0.0681

 34 02CUSL053M-WA STR LGT SRV 1,172 78,805 93 12,602 0.0672

 35 02HPSV0051-WA HI PRESSURE 3,216 593,553 152 21,158 0.1846

 36 02MVSL0057-WA MERC VAPSTR 1,994 236,627 45 44,311 0.1187

 37 WA - CHEHALIS DEFERRAL -30,000

 38 REV. ACCOUNTING ADJ. -23,544

 39 UNBILLED REVENUE 648 79,000 0.1219

 40 WYOMING

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.17

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 05COSL0057-CO-OWND STR LG 317 63,540 21 15,095 0.2004

 2 05CUSL058M-CUST OWND STR 74 4,557 11 6,727 0.0616

 3 05CUSL0E58-WY CUST OWND 1,083 66,985 31 34,935 0.0619

 4 05CUSL0M58-CUST OWNED 49 3,724 4 12,250 0.0760

 5 05HPSV0051-HI PRESSURE SO 4,808 988,331 156 30,821 0.2056

 6 05MVS00053-MERCURY VAPOR 3,843 479,615 259 14,838 0.1248

 7 REV. ACCOUNTING ADJ. 400

 8 UNBILLED REVENUE -160 -26,000 0.1625

 9 09MONL0213-WY MTR OUTDOOR 29 2,197 1 29,000 0.0758

 10 09SLCO0211-STR LGT CO-OWN 1,335 389,145 49 27,245 0.2915

 11 09SLCUP212-STR LGT CUST-O 72 11,231 9 8,000 0.1560

 12 09TOSS0213-TRAF & OTHER S 67 2,604 14 4,786 0.0389

 13 UNBILLED REVENUE -146 -51,000 0.3493

 14 LESS MULTIPLE BILLINGS -2,445

 15

 16 TOTAL PUBLIC STREET & HWY 145,032 20,610,361 3,868 37,495 0.1421

 17

 18 OTHER SALES TO PUBLIC AUTH

 19 UTAH

 20 08GNSV0006-GEN SRVC-DISTR 2,355 153,647 4 588,750 0.0652

 21 08GNSV0023-GEN SRVC-DISTR 29 2,855 3 9,667 0.0984

 22 08GNSV009M-MANL HIGH VOLT 421,143 19,402,446 4 105,285,750 0.0461

 23 08OALT007N-SECURITY AR LG 18 4,468 2 9,000 0.2482

 24 UNBILLED REVENUE 3,807 207,000 0.0544

 25

 26 TOTAL OTHER SALES TO PUBLIC 427,352 19,770,416 13 32,873,231 0.0463

 27

 28 FORFEITED DISCOUNTS

 29 CALIFORNIA

 30 Late Fees 285,011

 31 IDAHO

 32 Late Fees 406,930

 33 OREGON

 34 Late Fees 2,666,385

 35 UTAH

 36 Late Fees 2,957,255

 37 WASHINGTON

 38 Late Fees 542,237

 39 WYOMING

 40 Late Fees 554,070

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.18

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1

 2 TOTAL FORFEITED DISCOUNTS 7,411,888

 3

 4 MISCELLANEOUS SERVICE REV

 5 CALIFORNIA

 6 06CFR00003-MTH MAINTENANC 1,454

 7 06CONN0300-CA RECONNECTIO 32,380

 8 06FCBUYOUT 53,332

 9 06RCHK0300-CA RET CHK CHR 12,096

 10 06TAMP0300-CA TAMP & UNAU 1,050

 11 06TEMP0300-CA TEMP SRVC C 1,870

 12 06XMTRTAMP-TAMPERING - 288

 13 Home Comfort 1,003

 14 Other -4,185

 15 IDAHO

 16 07CFR00001-MTH FAC SRVCHG 1,682

 17 07CONN0300-ID RECONNECTIO 46,055

 18 07RCHK0300-ID RET CHK CHR 37,980

 19 07TAMP0300 1,275

 20 07TEMP0014-TEMP SRVC CONN 9,380

 21 07XMTRTAMP-TAMPERING - 121

 22 Weatherization Loans ID 146

 23 Other 4,350

 24 OREGON

 25 01CFR00001-MTH FACILITY S 61,661

 26 01CFR00003-MTH MAINTENANC 25,964

 27 01CFR00004-EMRGNCY ST&BY 22,439

 28 01CFR00005-INTERMTNT 41,861

 29 01CFR00013-MTH MISC CHRG 2,284

 30 01CFR00014-YR MISC CHRG 5

 31 01CONN0300-RECONNECTION C 316,525

 32 01CONTSERV-OR 3RD PARTY 2,093

 33 01DPAC0300-DEMAND PULSE 6,000

 34 01ESSC0600 - ESS charges 90

 35 01FCBUYOUT-FAC CHG BUYOUT 260,885

 36 01LNX00109-REF/NREF ADV + -34,997

 37 01MTRVR300-METR VERIF FEE 20

 38 010RRA0300-OR RETAIL ACCESS 5

 39 01RCHK0300-RETURNED CHECK 290,980

 40 01TAMP0300-TAMP & UNAUTH 12,975

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.19

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 01TEMP0300-TEMP SRVC CHRG 77,875

 2 01XMTRTAMP-TAMPERING - 12,654

 3 Other 21,358

 4 UTAH

 5 08CFR00013-MTH MISC CHRG 148,885

 6 08CFR00051-MTH FAC SRVCHG 107,746

 7 08CFR00052-ANN FAC SVCCHG 424

 8 08CFR00053-MTHLY MAINTFEE 11,272

 9 08CFR00063-MTH MISC CHARG 2,408

 10 08CFR00064-ANN MISC CHARG 6,660

 11 08CONN0300-RECONN&DISCONN 329,135

 12 08CONTSERV-3RD PARTY O/S 285,840

 13 08FCBUYOUT-FAC CHG BUYOUT 186,556

 14 08NCON0300-UT FEE NRES RE 6,760

 15 08RCHK0300-UT RET CHK CHR 464,220

 16 08RCON0001-CONNECT FEE 1,541,400

 17 08TAMP0300-TAMPERING&UNAU 18,000

 18 08TEMP0014-TEMP SRVC CONN 297,285

 19 08UPPL000N-BASE SCH FALL -11

 20 08XMTRTAMP-TAMPERING - 5,705

 21 Energy Finanswer 12,000 430

 22 Energy Finanswer new Com 23,631

 23 Other -31,066

 24 08VISIT300 - UT Visit, Service Ca 281,590

 25 WASHINGTON

 26 02CFR00003-MTH MAINTENANC 1,320

 27 02CFR00004-EMRGNCY ST&BY 5,879

 28 02CFR00005-INTERMTNT SRVC 4,302

 29 02CONN0300-WA RECONNECTIO 58,130

 30 02FCBUYOUT - FAC CHG BUYOUT 22,397

 31 02RCHK0300-WA RET CHK CHR 57,660

 32 02TAMP0300-WA TAMP & UNAU 4,650

 33 02TEMP0300-WA TEMP SRVC C 16,325

 34 02XMTRTAMP-TAMPERING - 2,571

 35 Energy Finanswer new Com 2,784

 36 Home Comfort 3,148

 37 Other -7,674

 38 WYOMING

 39 05CFR00003-MTH MAINTENANC 7,510

 40 05CFR00004-EMRGNCY ST&BY 18,891

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.20

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 05CFR00005-INTERMTNT SRVC 9,943

 2 05CFR00013-MTH MISC CHRG 3,186

 3 05CONN0300-WY RECONNECTIO 63,560

 4 05FCBUYOUT - FAC CHG BUYOUT 294,099

 5 05RCHK0300-WY RET CHK CHR 69,000

 6 05SERV0300-WY SRVC CALLS 120

 7 05TAMP0300 1,650

 8 05TEMP0300-WY TEMP SRVC C 27,430

 9 Other -2,985

 10 05XMTRTAMP-TAMPERING - 170

 11 09CFR00005-INTERMTNT SRVC 339

 12 05CONN0300-WY RECONNECTIO 13,300

 13 05FCBUYOUT - FAC CHG BUYOUT 215,167

 14 05RCHK0300-WY RET CHK CHR 11,670

 15 05TAMP0300 150

 16 05TEMP0300-WY TEMP SRVC C 1,360

 17 05XMTRTAMP-TAMPERING - 27

 18 09CFR00001-MTH FAC SRVCHG 5,067

 19 Energy Finanswer 12,000 301

 20

 21 TOTAL MISC SERVICE REV 5,919,271

 22

 23 SALES OF WATER AND WTR PWR

 24 UTAH 1,609

 25 WYOMING 1,000

 26 TOTAL WATER AND WATER PWR 2,609

 27

 28 RENT FROM ELEC PROPERTIES

 29 CALIFORNIA

 30 06CFR00006-MTH RNTAL CHRG 1,710

 31 Rent Revenue - Subleases 17,693

 32 Joint use 531,229

 33 IDAHO

 34 07CFR00009-YR LSE CHRG-EQ 730

 35 07INVCHG00-INVEST MNT CHG 178

 36 07LOOP0014-MTH FEE PRE-AS 210

 37 07POLE0075-STEEL POLES US 276

 38 07XTRN0013-RNT/LSE L& PRO 34,369

 39 RENT REVENUE-HYDRO 66,682

 40 RENT REV-TRANSMISS 900

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.21

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 RENT REV-DISTRIBUT 300

 2 Rent Revenue - Subleases 2,216

 3 Joint use 172,973

 4 OREGON

 5 01CFR00006-MTH RNTAL CHRG 600,081

 6 RENTS - COMMON 462,545

 7 Rents - Non Common 25

 8 MCI FOGWIRE REVENUE 3,350,038

 9 Rent Revenue - Subleases 335,325

 10 RENT REVENUE-HYDRO 21,068

 11 RENT REV-TRANSMISS 230,034

 12 RENT REV-DISTRIBUT 50,979

 13 RENT REV-GEN(COMM) 42,260

 14 Joint use 4,492,037

 15 UTAH

 16 08CFR00056-MTH EQUIP RENT 33

 17 08CFR00058-MTH EQUIP LEAS 729,329

 18 08INVCHG0N-INVEST MNT CHG 4,740

 19 08INVCHG0R-INVEST MNT CHG 283

 20 08LOOP014N-TEMP SERV CONN 2,736

 21 08POLE0075-STEEL POLES US 59,537

 22 08XTRN0013-RNT/LSE L& PRO 56,388

 23 RENTS - COMMON -20,446

 24 Rents - Non Common 9,174

 25 RENT REVENUE-STEAM 90,946

 26 RENT REVENUE-HYDRO 86,704

 27 RENT REV-TRANSMISS 840,373

 28 RENT REV-DISTRIBUT 431,916

 29 RENT REV-GEN(COMM) 6,691

 30 Rent Revenue - Subleases 2,464,310

 31 Joint use 2,152,980

 32 WASHINGTON

 33 02CFR00001-MTH FACILITY S 2,104

 34 02CFR00006-MTH RNTAL CHRG 29,871

 35 RENT REVENUE-HYDRO 641,359

 36 RENT REV-DISTRIBUT 17,233

 37 RENT REV-GEN(COMM) 39,573

 38 RENT REV-TRANSMISS 7,517

 39 Rent Revenue - Subleases 45,245

 40 Joint use 999,785

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.22

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 WYOMING

 2 05CFR00001-MTH FACILITY S 11,524

 3 05CFR00006-MTH RNTAL CHRG 2,482

 4 RENT REVENUE-STEAM 66,695

 5 RENT REV-TRANSMISS 850

 6 RENT REV-DISTRIBUT 7,814

 7 RENT REV-GEN(COMM) -6,947

 8 Rent Revenue - Subleases 15,912

 9 Joint use 309,340

 10 09LOOP0214-MTH FEE PRE-AS 62

 11 09POLE0075-STEEL POLES US 17,403

 12 RENT REVENUE-STEAM 7,062

 13 Joint use 14,660

 14

 15 TOTAL RENT FROM ELEC PROP 19,559,096

 16

 17 WIND BASED ANCILLARY SVC 7,281,432

 18 ELEC INC-OTHR 5,339

 19 OTHER ELEC ESTIMATE -597,217

 20 RENEWABLE ENERGY CREDIT 93,760,900

 21 NON-WHEELING SYSTEM 8,951,958

 22 Other Elec (exclud Wheel) 678,251

 23 CALIFORNIA

 24 ALL BLUE SKY RES 119,595

 25 07XTRN0011-SALE ORDERS 111

 26 DSM REV-CA SBC OFF 865,247

 27 Fish, Wildlife, Recr 6,190

 28 IDAHO

 29 ALL BLUE SKY RES 83,377

 30 DSM REV-ID SBC 5,939,833

 31 Other Elec (exclud Wheel) -71

 32 OREGON

 33 ALL BLUE SKY RES 1,110,611

 34 M&S INVENTORY REVENUE 67,699

 35 3RD PARTY TRANS 281,550

 36 DSM REVENUE - OREGON ECC 18,762,568

 37 Other Elec (exclud Wheel) 1,564,645

 38 Other Elec DSR carry chrg 236,371

 39 UTAH

 40 ALL BLUE SKY RES 2,473,756

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.23

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES OF ELECTRICITY BY RATE SCHEDULES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Number and Title of Rate schedule MWh Sold

(a) (b)

Revenue

(c)

Average Number

of Customers (d)

KWh of Sales

Per Customer (e)

Revenue Per

KWh Sold

(f)

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh 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.

 1 M&S INVENTORY REVENUE 385,196

 2 ELEC INC-OTHR 89,749

 3 FLYASH SALES 1,735,998

 4 3RD PARTY TRANS 150,755

 5 DSM REV-UT SBC OFFSET 62,981,154

 6 Fish, Wildlife, Recr 2,280

 7 other Elec (exclud Wheel) -828

 8 WASHINGTON

 9 ALL BLUE SKY RES 159,211

 10 DSM REVENUE - WA SBC 8,855,002

 11 Other Elec (exclud Wheel) 123

 12 Fish, Wildlife, Recr 18,060

 13 Wash Colstrip 3 -52,188

 14 WYOMING

 15 ALL BLUE SKY RES 220,490

 16 M&S INVENTORY REVENUE 21,493

 17 FLYASH SALES 910,611

 18 WY Regulatory Recovery Fee 239,529

 19 3RD PARTY TRANS 62,482

 20 DSM REVENUE - WY SBC - CAT 1 701,985

 21 DSM REVENUE - WY SBC - CAT 2 795,949

 22 DSM REVENUE - WY SBC - CAT 3 545,133

 23 FLYASH SALES 12,212

 24 DSM REVENUE - WY SBC - CAT 1 215,502

 25 DSM REVENUE - WY SBC - CAT 2 131,341

 26 DSM REVENUE - WY SBC - CAT 3 301,427

 27 Other Elec (exclud Wheel) 9

 28 TOTAL OTHER ELEC REVENUE 220,074,820

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 53,015,534 3,827,550,789 1,732,815 30,595 0.0722

 -170,392 -8,430,000 0 0 0.0495

 53,185,926 3,835,980,789 1,732,815 30,693 0.0721

FERC FORM NO. 1 (ED. 12-95) Page 304.24

41 TOTAL Billed

42 Total Unbilled Rev.(See Instr. 6)

43 TOTAL
Schedule Page: 304.14 Line No.: 27 Column: a

01COST0041 - 01APSV0041 - 01APSV041X AG PMP

Schedule Page: 304 Line No.: 41 Column: b

The following table is a reconciliation of the billed and unbilled MWh for the year 2010.

 MWh

Total billed in 2010 53,185,926

12/31/2009 unbilled MWh reversal (3,380,278)

Total MWh earned and billed in 2010 49,805,648

12/31/2010 unbilled MWh accrual 3,209,886

Total MWh (unbilled and billed) in 2010 53,015,534

Schedule Page: 304 Line No.: 41 Column: c

The following table is a reconciliation of the billed and unbilled revenue for the year 2010.

Revenue

Total billed in 2010 $ 3,906,998,905

12/31/2009 unbilled revenue reversal (213,989,000)

Total revenue earned and billed in 2010 3,693,009,905

12/31/2010 unbilled revenue accrual 205,559,000

Total revenue (unbilled and billed) in 2010 $ 3,898,568,905

Schedule Page: 304 Line No.: 42 Column: c

For further discussion on unbilled revenue refer to page 300, Electric Operating Revenues, line 12, column(b).

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Requirement Sales

 2 Brigham City RQ T-12 19 19 17

 3 Deaver, Town of RQ T-4 0.2 0.1 0.1

 4 Helper City RQ T-6 1 11

 5 Helper City Annex RQ T-6 0.7 0.6 0.6

 6 Navajo Tribal Util Auth (Mexican Hat) RQ T-6 0.2 0.2 0.2

 7 Navajo Tribal Util Auth (Red Mesa) RQ T-6 1 11

 8 Portland General Electric Company RQ 147 NA NA NA

 9 Price City RQ T-12 13 12 12

 10 Accrual True-up RQ NA NA NA NA

 11

 12 Nonrequirement Sales

 13 Anaheim, City of SF T-12 NA NA NA

 14 Arizona Public Service Company AD T-12 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Arizona Public Service Company SF T-12 NA NA NA

 2 Avista Corporation SF T-13 NA NA NA

 3 Avista Corporation SF T-12 NA NA NA

 4 BP Energy Company SF T-12 NA NA NA

 5 Barclays Bank PLC AD T-12 NA NA NA

 6 Barclays Bank PLC SF T-12 NA NA NA

 7 Basin Electric Power Cooperative AD T-11 NA NA NA

 8 Basin Electric Power Cooperative LF T-11 NA NA NA

 9 Basin Electric Power Cooperative OS T-12 NA NA NA

 10 Basin Electric Power Cooperative SF T-11 NA NA NA

 11 Basin Electric Power Cooperative SF T-12 NA NA NA

 12 Black Hills Power, Inc. LF 441 50 50 48

 13 Black Hills Power, Inc. OS T-12 NA NA NA

 14 Black Hills Power, Inc. SF T-12 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.1

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Bonneville Power Administration AD 519 NA NA NA

 2 Bonneville Power Administration AD T-11 NA NA NA

 3 Bonneville Power Administration AD T-12 NA NA NA

 4 Bonneville Power Administration LF 368 NA NA NA

 5 Bonneville Power Administration LF T-11 NA NA NA

 6 Bonneville Power Administration LU 519 NA NA NA

 7 Bonneville Power Administration SF T-11 NA NA NA

 8 Bonneville Power Administration SF T-13 NA NA NA

 9 Bonneville Power Administration SF T-12 NA NA NA

 10 British Columbia Transmission Corp. SF T-13 NA NA NA

 11 California Independent System Operator AD T-12 NA NA NA

 12 California Independent System Operator SF T-12 NA NA NA

 13 Cargill Power Markets, LLC AD T-12 NA NA NA

 14 Cargill Power Markets, LLC SF T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.2

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Cargill Power Markets, LLC SF T-12 NA NA NA

 2 Citigroup Energy, Inc. AD T-12 NA NA NA

 3 Citigroup Energy, Inc. SF T-12 NA NA NA

 4 City of Burbank SF T-12 NA NA NA

 5 City of Redding SF T-12 NA NA NA

 6 Clatskanie People's Utility District SF T-12 NA NA NA

 7 Colorado Springs Utilities OS T-12 NA NA NA

 8 Colorado Springs Utilities SF T-12 NA NA NA

 9 ConocoPhillips Company SF T-12 NA NA NA

 10 Constellation Energy Commodities Group SF T-11 NA NA NA

 11 Constellation Energy Commodities Group SF T-11 NA NA NA

 12 Constellation Energy Commodities Group SF T-12 NA NA NA

 13 Credit Suisse Energy LLC AD T-12 NA NA NA

 14 Credit Suisse Energy LLC SF T-12 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.3

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 DB Energy Trading LLC AD T-12 NA NA NA

 2 DB Energy Trading LLC SF T-12 NA NA NA

 3 Deseret Power Electric Cooperative SF T-11 NA NA NA

 4 EDF Trading North America, LLC SF T-12 NA NA NA

 5 El Paso Electric Company SF T-12 NA NA NA

 6 Endure Energy, LLC SF T-12 NA NA NA

 7 Eugene Water & Electric Board SF T-11 NA NA NA

 8 Eugene Water & Electric Board SF T-12 NA NA NA

 9 Gila River Power, L.P. AD T-12 NA NA NA

 10 Gila River Power, L.P. SF T-11 NA NA NA

 11 Gila River Power, L.P. SF T-12 NA NA NA

 12 Glendale, City of SF T-12 NA NA NA

 13 Hurricane, City of LF T-12 NA NA NA

 14 Iberdrola Renewables, Inc. LF T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.4

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Iberdrola Renewables, Inc. SF T-11 NA NA NA

 2 Iberdrola Renewables, Inc. SF T-12 NA NA NA

 3 Idaho Power Company LF T-11 NA NA NA

 4 Idaho Power Company SF T-11 NA NA NA

 5 Idaho Power Company SF T-13 NA NA NA

 6 Idaho Power Company SF T-12 NA NA NA

 7 Intermountain Renewable Power, LLC LF T-11 NA NA NA

 8 Intermountain Renewable Power, LLC LF T-11 NA NA NA

 9 J. Aron & Company SF T-12 NA NA NA

 10 JP Morgan Ventures Energy Corporation AD T-12 NA NA NA

 11 JP Morgan Ventures Energy Corporation SF T-11 NA NA NA

 12 JP Morgan Ventures Energy Corporation SF T-12 NA NA NA

 13 Los Angeles Dept. of Water & Power LU 301 NA NA NA

 14 Los Angeles Dept. of Water & Power SF T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.5

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Los Angeles Dept. of Water & Power SF T-12 NA NA NA

 2 Macquarie Energy LLC SF T-11 NA NA NA

 3 Macquarie Energy LLC SF T-12 NA NA NA

 4 Metropolitan Water District of S. Cal. SF T-12 NA NA NA

 5 Modesto Irrigation District SF T-12 NA NA NA

 6 Morgan Stanley Capital Group, Inc. AD T-12 NA NA NA

 7 Morgan Stanley Capital Group, Inc. SF T-11 NA NA NA

 8 Morgan Stanley Capital Group, Inc. SF T-12 NA NA NA

 9 Municipal Energy Agency of Nebraska SF T-11 NA NA NA

 10 Municipal Energy Agency of Nebraska SF T-12 NA NA NA

 11 Nevada Power Company IF T-12 NA NA NA

 12 NextEra Energy Power Marketing, LLC AD T-11 NA NA NA

 13 NextEra Energy Power Marketing, LLC LF T-11 NA NA NA

 14 NextEra Energy Power Marketing, LLC SF T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.6

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 NextEra Energy Power Marketing, LLC SF T-12 NA NA NA

 2 NorthWestern Corporation SF T-13 NA NA NA

 3 NorthWestern Corporation SF T-12 NA NA NA

 4 Northern California Power Agency SF T-12 NA NA NA

 5 Northpoint Energy Solutions Inc. SF T-12 NA NA NA

 6 PPL EnergyPlus, LLC SF T-12 NA NA NA

 7 PPL Montana, LLC SF T-11 NA NA NA

 8 Pacific Gas & Electric Company IF T-12 NA NA NA

 9 Pacific Gas & Electric Company SF T-12 NA NA NA

 10 Pacific Northwest Generating Coop. SF T-12 NA NA NA

 11 Pacific Summit Energy LLC SF T-12 NA NA NA

 12 Portland General Electric Company SF T-11 NA NA NA

 13 Portland General Electric Company SF T-12 NA NA NA

 14 Portland General Electric Company SF T-13 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.7

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Powerex Corporation AD T-12 NA NA NA

 2 Powerex Corporation LF T-11 NA NA NA

 3 Powerex Corporation SF T-11 NA NA NA

 4 Powerex Corporation SF T-12 NA NA NA

 5 Public Service Company of Colorado AD 320 NA NA NA

 6 Public Service Company of Colorado LF 320 71 65 59

 7 Public Service Company of Colorado SF T-11 NA NA NA

 8 Public Service Company of Colorado SF T-12 NA NA NA

 9 Public Service Company of New Mexico SF T-12 NA NA NA

 10 PUD #1 of Snohomish County SF T-12 NA NA NA

 11 PUD #2 of Grant County SF T-13 NA NA NA

 12 PUD #2 of Grant County SF T-12 NA NA NA

 13 Puget Sound Energy, Inc. SF T-13 NA NA NA

 14 Puget Sound Energy, Inc. SF T-12 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.8

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Rainbow Energy Marketing Corporation SF T-11 NA NA NA

 2 Rainbow Energy Marketing Corporation SF T-12 NA NA NA

 3 Sacramento Municipal Utility District AD 250 NA NA NA

 4 Sacramento Municipal Utility District LF 250 NA NA NA

 5 Sacramento Municipal Utility District SF T-13 NA NA NA

 6 Sacramento Municipal Utility District SF T-12 NA NA NA

 7 Salt River Project IF T-12 NA NA NA

 8 Salt River Project SF T-11 NA NA NA

 9 Salt River Project SF T-12 NA NA NA

 10 San Diego Gas & Electric Company AD T-12 NA NA NA

 11 San Diego Gas & Electric Company IF T-12 NA NA NA

 12 San Diego Gas & Electric Company SF T-12 NA NA NA

 13 Santa Clara, City of SF T-12 NA NA NA

 14 Seattle City Light LF T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.9

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Seattle City Light SF T-11 NA NA NA

 2 Seattle City Light SF T-13 NA NA NA

 3 Seattle City Light SF T-12 NA NA NA

 4 Sempra Energy Trading LLC AD T-12 NA NA NA

 5 Sempra Energy Trading LLC SF T-12 NA NA NA

 6 Sempra Generation SF T-12 NA NA NA

 7 Shell Energy North America (US), L.P. AD T-12 NA NA NA

 8 Shell Energy North America (US), L.P. OS T-12 NA NA NA

 9 Shell Energy North America (US), L.P. SF T-11 NA NA NA

 10 Shell Energy North America (US), L.P. SF T-12 NA NA NA

 11 Sierra Pacific Power Company LF T-11 NA NA NA

 12 Sierra Pacific Power Company SF T-11 NA NA NA

 13 Sierra Pacific Power Company SF T-13 NA NA NA

 14 Southern California Edison Company IF T-12 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.10

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Southern California Edison Company SF T-11 NA NA NA

 2 Southern California Edison Company SF T-11 NA NA NA

 3 Southern California Edison Company SF T-12 NA NA NA

 4 Southwestern Public Service Company SF T-12 NA NA NA

 5 Tacoma Power SF T-13 NA NA NA

 6 Tacoma Power SF T-12 NA NA NA

 7 The Energy Authority SF T-11 NA NA NA

 8 The Energy Authority SF T-12 NA NA NA

 9 TransAlta Energy Marketing Inc. IF T-12 NA NA NA

 10 TransAlta Energy Marketing Inc. SF T-11 NA NA NA

 11 TransAlta Energy Marketing Inc. SF T-12 NA NA NA

 12 TransCanada Energy Sales Ltd. SF T-12 NA NA NA

 13 Tri-State Gen. & Trans. SF T-11 NA NA NA

 14 Tri-State Gen. & Trans. SF T-12 0.4 0.4 0.1

FERC FORM NO. 1 (ED. 12-90) Page 310.11

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Tucson Electric Power Company SF T-12 NA NA NA

 2 Turlock Irrigation District SF T-12 NA NA NA

 3 UNS Electric, Inc. SF T-12 NA NA NA

 4 Utah Associated Municipal Power Systems OS T-12 NA NA NA

 5 Utah Associated Municipal Power Systems SF T-11 NA NA NA

 6 Utah Associated Municipal Power Systems SF T-12 NA NA NA

 7 Utah Municipal Power Agency LF 433 34 34 34

 8 Utah Municipal Power Agency SF T-3 NA NA NA

 9 Western Area Power Administration AD T-11 NA NA NA

 10 Western Area Power Administration LF T-11 NA NA NA

 11 Western Area Power Administration SF T-11 NA NA NA

 12 Western Area Power Administration SF T-12 NA NA NA

 13 Test Generation AD NA NA NA NA

 14 Bookout Sales AD NA NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 310.12

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average Monthly NCP Demand Monthly CP Demand

1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other 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.

 1 Trade Sales IF NA NA NA NA

 2 Accrual True-up NA NA NA NA NA

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

FERC FORM NO. 1 (ED. 12-90) Page 310.13

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 0

 0
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1

 111,872 1,968,417 2,384,916 4,353,333 2

 988 15,734 17,761 33,495 3

 6,480 118,283 114,594 232,877 4

 3,783 72,379 66,920 139,299 5

 1,253 21,717 21,818 43,535 6

 8,728 133,792 152,041 285,833 7

 11,214 1,021,053 5,006 1,026,059 8

 74,337 1,287,308 1,576,451 2,863,759 9

 2,197 62,547 62,547 10

 11

 12

 6,200 238,700 238,700 13

 400 12,800 12,800 14

FERC FORM NO. 1 (ED. 12-90) Page 311

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 25,328 915,108 915,108 1

 57 2,254 2,254 2

 51,725 1,651,335 1,651,335 3

 19,368 598,764 598,764 4

 409 20,568 20,568 5

 620,313 38,439,814 38,439,814 6

 2,991 91,095 91,095 7

 232 9,766 9,766 8

 78 3,582 3,582 9

 1,116 39,915 39,915 10

 138,207 5,054,254 5,054,254 11

 352,993 7,310,280 5,662,460 12,972,740 12

 6,037 217,404 217,404 13

 82,726 3,104,002 3,104,002 14

FERC FORM NO. 1 (ED. 12-90) Page 311.1

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 206,336 206,336 1

 5 216 216 2

 120,206 120,206 3

 1,850 61,133 61,133 4

 2,571 90,898 90,898 5

 35,570 2,614,039 2,614,039 6

 1 25 25 7

 8 336 336 8

 81,992 2,826,672 2,826,672 9

 21 549 549 10

 170 112,274 112,274 11

 408,091 12,480,046 12,480,046 12

 2,022 44,817 44,817 13

 6,754 196,574 196,574 14

FERC FORM NO. 1 (ED. 12-90) Page 311.2

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1,116,467 42,447,033 42,447,033 1

 166 14,111 14,111 2

 933,729 48,006,404 48,006,404 3

 19,800 682,800 682,800 4

 15,043 553,579 553,579 5

 72 2,712 2,712 6

 160 2,960 2,960 7

 335 6,478 6,478 8

 56,256 2,005,952 2,005,952 9

 512 17,987 17,987 10

 55 2,064 2,064 11

 95,659 3,434,253 3,434,253 12

 151 20,012 20,012 13

 43,400 2,888,900 2,888,900 14

FERC FORM NO. 1 (ED. 12-90) Page 311.3

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 17 136 136 1

 596,590 35,081,629 35,081,629 2

 39 1,305 1,305 3

 423,350 14,962,652 14,962,652 4

 12,407 513,122 513,122 5

 7,380 294,285 294,285 6

 140 4,707 4,707 7

 10,995 357,676 357,676 8

 -1 9

 31 940 940 10

 105,390 3,743,525 3,743,525 11

 3,000 92,000 92,000 12

 202 15,150 15,150 13

 2,884 95,640 95,640 14

FERC FORM NO. 1 (ED. 12-90) Page 311.4

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1,513 51,070 51,070 1

 287,727 9,679,291 9,679,291 2

 2,644 90,235 90,235 3

 3,581 131,365 131,365 4

 715 24,013 24,013 5

 11,557 425,780 425,780 6

 1,411 43,199 43,199 7

 629 24,449 24,449 8

 28,981 1,005,662 1,005,662 9

 184 4,426 4,426 10

 1,881 53,987 53,987 11

 145,535 5,911,745 5,911,745 12

 564,732 27,947,142 27,947,142 13

 1,693 58,344 58,344 14

FERC FORM NO. 1 (ED. 12-90) Page 311.5

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 445,890 16,841,099 16,841,099 1

 58 1,526 1,526 2

 62,553 2,199,869 2,199,869 3

 49,975 1,859,359 1,859,359 4

 12,240 530,360 530,360 5

 2,825 82,161 82,161 6

 7,656 251,595 251,595 7

 1,395,927 65,086,374 65,086,374 8

 87 2,883 2,883 9

 17,060 629,545 629,545 10

 996,819 33,732,523 33,732,523 11

 2 78 78 12

 10,897 347,368 347,368 13

 275 8,086 8,086 14

FERC FORM NO. 1 (ED. 12-90) Page 311.6

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1,406 43,428 43,428 1

 251 8,595 8,595 2

 554 23,943 23,943 3

 2,134 92,460 92,460 4

 95 4,175 4,175 5

 53,471 1,831,155 1,831,155 6

 620 21,898 21,898 7

 653,474 22,907,829 22,907,829 8

 4,357 159,704 159,704 9

 945 37,325 37,325 10

 6,800 203,200 203,200 11

 369 12,044 12,044 12

 78,647 2,632,681 2,632,681 13

 178 5,820 5,820 14

FERC FORM NO. 1 (ED. 12-90) Page 311.7

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 31 1,000 1,000 1

 14,932 477,737 477,737 2

 13,177 389,753 389,753 3

 405,582 11,590,434 11,590,434 4

 -772,626 -772,626 5

 465,388 9,295,320 21,453,044 30,748,364 6

 1,179 35,818 35,818 7

 211,075 6,832,397 6,832,397 8

 154,575 5,933,724 5,933,724 9

 14,140 511,530 511,530 10

 8 314 314 11

 15,232 530,880 530,880 12

 184 6,720 6,720 13

 80,059 2,658,692 2,658,692 14

FERC FORM NO. 1 (ED. 12-90) Page 311.8

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1,305 36,998 36,998 1

 130,568 4,381,839 4,381,839 2

 -146,668 -146,668 3

 551,131 13,238,167 13,238,167 4

 6 134 134 5

 54,683 1,843,055 1,843,055 6

 25 913 913 7

 708 20,372 20,372 8

 82,888 2,646,978 2,646,978 9

 319 12,058 12,058 10

 341,410 10,831,286 10,831,286 11

 3,206 71,045 71,045 12

 3,390 69,095 69,095 13

 2,249 69,711 69,711 14

FERC FORM NO. 1 (ED. 12-90) Page 311.9

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1 24 24 1

 1 43 43 2

 15,006 488,987 488,987 3

 491 22,389 22,389 4

 403,363 21,197,505 21,197,505 5

 14,000 497,016 497,016 6

 91 6,798 6,798 7

 100 4,800 4,800 8

 24 875 875 9

 901,993 41,185,881 41,185,881 10

 817 26,442 26,442 11

 84 3,531 3,531 12

 222 8,438 8,438 13

 327,600 11,148,438 11,148,438 14

FERC FORM NO. 1 (ED. 12-90) Page 311.10

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 1,526 47,259 47,259 1

 433 12,832 12,832 2

 14,130 587,480 587,480 3

 45,957 1,764,174 1,764,174 4

 7 184 184 5

 1,375 25,175 25,175 6

 1 39 39 7

 9,937 354,075 354,075 8

 1,314,945 46,545,738 46,545,738 9

 250 9,358 9,358 10

 225,794 7,921,333 7,921,333 11

 15 404 404 12

 19 645 645 13

 206,863 16,991 6,891,467 6,908,458 14

FERC FORM NO. 1 (ED. 12-90) Page 311.11

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 136,728 5,217,828 5,217,828 1

 7,987 252,416 252,416 2

 190,872 6,054,106 6,054,106 3

 61,410 1,748,072 1,748,072 4

 142 4,197 4,197 5

 875 34,941 34,941 6

 215,938 4,396,200 5,018,399 9,414,599 7

 1,530 67,900 67,900 8

 142 59,501 59,501 9

 1,633 97,482 97,482 10

 5,801 99,338 99,338 11

 203,267 8,482,416 8,482,416 12

 -41,215 -556,235 -556,235 13

 -5,780,963 -184,282,163 -184,282,163 14

FERC FORM NO. 1 (ED. 12-90) Page 311.12

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SALES FOR RESALE (Account 447) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Sold (h+i+j)

Total ($) REVENUE

($) ($) ($)

OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

 -17,492,110 -17,492,110 1

 7,286 150,119 150,119 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

FERC FORM NO. 1 (ED. 12-90) Page 311.13

 5,355,554

 670,763,569

 676,119,123

 220,852

 11,193,740

 11,414,592

 67,553 9,040,737

 -199,259,887

 -199,192,334

 492,522,473

 501,563,210

 3,617,630

 21,018,791

 24,636,421
Schedule Page: 310 Line No.: 6 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “NAVAJO TRIBAL UTIL AUTH (MEXICAN HAT)” ON PAGES 310

– 311: Complete name is Navajo Tribal Utility Authority (Mexican Hat).

Schedule Page: 310 Line No.: 7 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “NAVAJO TRIBAL UTIL AUTH (RED MESA)” ON PAGES 310 –

311: Complete name is Navajo Tribal Utility Authority (Red Mesa).

Schedule Page: 310 Line No.: 8 Column: j

Settlement Adjustment

Schedule Page: 310 Line No.: 10 Column: j

Represents the difference between actual requirement sales revenues for the period as reflected on the individual line items within this

schedule, and the accruals charged to account 447 during the period.

Schedule Page: 310 Line No.: 14 Column: b

Settlement Adjustment.

Schedule Page: 310 Line No.: 14 Column: j

Settlement Adjustment 

Schedule Page: 310.1 Line No.: 2 Column: j

Reserve Share

Schedule Page: 310.1 Line No.: 5 Column: b

Settlement Adjustment.

Schedule Page: 310.1 Line No.: 5 Column: j

Settlement Adjustment

Schedule Page: 310.1 Line No.: 7 Column: b

Settlement Adjustment.

Schedule Page: 310.1 Line No.: 7 Column: j

Settlement Adjustment

Schedule Page: 310.1 Line No.: 8 Column: b

Basin Electric Power Company - FERC T-11 [Evergreen Network Transmission Service under the Open Access Transmission Tariff

(S.A. 505)] - Contract termination date: no earlier than 12 months from notice by the customer.

Schedule Page: 310.1 Line No.: 8 Column: j

Transmission Losses

Schedule Page: 310.1 Line No.: 9 Column: b

Secondary, Economy and/or non-firm sales, including some hourly firm transactions.

Schedule Page: 310.1 Line No.: 10 Column: j

Transmission Losses

Schedule Page: 310.1 Line No.: 12 Column: b

Black Hills Power & Light Company - FERC 441 - Contract termination date: December 31, 2023.

Schedule Page: 310.1 Line No.: 13 Column: b

Secondary, Economy and/or non-firm sales, including some hourly firm transactions.

Schedule Page: 310.2 Line No.: 1 Column: b

Settlement Adjustment.

Schedule Page: 310.2 Line No.: 1 Column: j

Settlement Adjustment

Schedule Page: 310.2 Line No.: 2 Column: b

Settlement Adjustment.

Schedule Page: 310.2 Line No.: 2 Column: j

Settlement Adjustment

Schedule Page: 310.2 Line No.: 3 Column: b

Settlement Adjustment.

Schedule Page: 310.2 Line No.: 3 Column: j

Settlement Adjustment

Schedule Page: 310.2 Line No.: 4 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Bonneville Power Administration - FERC R.S. 368 [Use of Facilities Agreement for the Malin Transformer under the AC Intertie

Agreement with BPA] - Contract termination date: Upon mutual agreement.

Schedule Page: 310.2 Line No.: 4 Column: j

Transmission Losses

Schedule Page: 310.2 Line No.: 5 Column: b

Bonneville Power Administration - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff

(S.A. 179)] - Contract termination date: September 30, 2025.

Schedule Page: 310.2 Line No.: 5 Column: j

Transmission Losses

Schedule Page: 310.2 Line No.: 6 Column: b

Bonneville Power Administration - FERC 519 - Contract termination date: April 22, 2024.

Schedule Page: 310.2 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.2 Line No.: 8 Column: j

Reserve Share

Schedule Page: 310.2 Line No.: 10 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “BRITISH COLUMBIA TRANSMISSION CORP.” ON PAGES 310 –

311: Complete name is British Columbia Transmission Corporation.

Schedule Page: 310.2 Line No.: 10 Column: j

Reserve Share

Schedule Page: 310.2 Line No.: 11 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CALIFORNIA INDEPENDENT SYSTEM OPERATOR” ON PAGES

310 – 311: Complete name is California Independent System Operator Corporation.

Schedule Page: 310.2 Line No.: 11 Column: b

Settlement Adjustment.

Schedule Page: 310.2 Line No.: 11 Column: j

Settlement Adjustment

Schedule Page: 310.2 Line No.: 13 Column: b

Settlement Adjustment.

Schedule Page: 310.2 Line No.: 13 Column: j

Settlement Adjustment

Schedule Page: 310.2 Line No.: 14 Column: j

Transmission Losses

Schedule Page: 310.3 Line No.: 2 Column: b

Settlement Adjustment.

Schedule Page: 310.3 Line No.: 2 Column: j

Settlement Adjustment

Schedule Page: 310.3 Line No.: 7 Column: b

Secondary, Economy and/or non-firm sales, including some hourly firm transactions.

Schedule Page: 310.3 Line No.: 10 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CONSTELLATION ENERGY COMMODITIES GROUP” ON

PAGES 310 – 311: Complete name is Constellation Energy Commodities Group, Inc.

Schedule Page: 310.3 Line No.: 10 Column: j

Transmission Losses

Schedule Page: 310.3 Line No.: 11 Column: j

Unauthorized use charges

Schedule Page: 310.3 Line No.: 13 Column: b

Settlement Adjustment.

Schedule Page: 310.3 Line No.: 13 Column: j

Settlement Adjustment

Schedule Page: 310.4 Line No.: 1 Column: b

Settlement Adjustment.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Schedule Page: 310.4 Line No.: 1 Column: j

Settlement Adjustment

Schedule Page: 310.4 Line No.: 3 Column: j

Transmission Losses

Schedule Page: 310.4 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.4 Line No.: 9 Column: b

Settlement Adjustment.

Schedule Page: 310.4 Line No.: 10 Column: j

Transmission Losses

Schedule Page: 310.4 Line No.: 13 Column: b

Hurricane, City of - FERC T-12 - Contract termination date: August 31, 2007.

Schedule Page: 310.4 Line No.: 14 Column: b

Iberdrola Renewables, Inc. - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th revised

S.A. 279)] - Contract termination date: April 30, 2014.

Schedule Page: 310.4 Line No.: 14 Column: j

Transmission Losses

Schedule Page: 310.5 Line No.: 1 Column: j

Transmission Losses

Schedule Page: 310.5 Line No.: 3 Column: b

Idaho Power Company - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th revised

S.A. 212)] - Contract termination date: May 31, 2012.

Schedule Page: 310.5 Line No.: 3 Column: j

Transmission Losses

Schedule Page: 310.5 Line No.: 4 Column: j

Transmission Losses

Schedule Page: 310.5 Line No.: 5 Column: j

Reserve Share

Schedule Page: 310.5 Line No.: 7 Column: b

Intermountain Renewable Power, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff

(S.A. 568)] - Contract termination date: April 30, 2029.

Schedule Page: 310.5 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.5 Line No.: 8 Column: b

Intermountain Renewable Power, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff

(S.A. 568)] - Contract termination date: April 30, 2029.

Schedule Page: 310.5 Line No.: 8 Column: j

Unauthorized use charges

Schedule Page: 310.5 Line No.: 10 Column: b

Settlement Adjustment.

Schedule Page: 310.5 Line No.: 10 Column: j

Settlement Adjustment

Schedule Page: 310.5 Line No.: 11 Column: j

Transmission Losses

Schedule Page: 310.5 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “LOS ANGELES DEPT. OF WATER & POWER” ON PAGES 310 –

311: Complete name is Los Angeles Department of Water and Power.

Schedule Page: 310.5 Line No.: 13 Column: b

Los Angeles Department of Water and Power - FERC 301 - Contract termination date: June 15, 2027.

Schedule Page: 310.5 Line No.: 14 Column: j

Transmission Losses

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
Schedule Page: 310.6 Line No.: 2 Column: j

Transmission Losses

Schedule Page: 310.6 Line No.: 4 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “METROPOLITAN WATER DISTRICT OF S. CAL.” ON PAGES

310 – 311: Complete name is Metropolitan Water District of Southern California.

Schedule Page: 310.6 Line No.: 6 Column: b

Settlement Adjustment.

Schedule Page: 310.6 Line No.: 6 Column: j

Settlement Adjustment

Schedule Page: 310.6 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.6 Line No.: 9 Column: j

Transmission Losses

Schedule Page: 310.6 Line No.: 11 Column: b

Nevada Power Company - WSPP - Contract termination date: December 31, 2010

Schedule Page: 310.6 Line No.: 12 Column: b

Settlement Adjustment.

Schedule Page: 310.6 Line No.: 12 Column: j

Settlement Adjustment

Schedule Page: 310.6 Line No.: 13 Column: b

NextEra Energy Power Marketing, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission

Tariff (S.A. 626)] - Contract termination date: December 31, 2011.

Schedule Page: 310.6 Line No.: 13 Column: j

Transmission Losses

Schedule Page: 310.6 Line No.: 14 Column: j

Unauthorized use charges

Schedule Page: 310.7 Line No.: 2 Column: j

Reserve Share

Schedule Page: 310.7 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.7 Line No.: 8 Column: b

Pacific Gas & Electric Company - WSPP - Contract termination date: December 31, 2012

Schedule Page: 310.7 Line No.: 10 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PACIFIC NORTHWEST GENERATING COOP.” ON PAGES 310 –

311: Complete name is Pacific Northwest Generating Cooperative, Inc.

Schedule Page: 310.7 Line No.: 12 Column: j

Transmission Losses

Schedule Page: 310.7 Line No.: 14 Column: j

Reserve Share

Schedule Page: 310.8 Line No.: 1 Column: b

Settlement Adjustment.

Schedule Page: 310.8 Line No.: 1 Column: j

Settlement Adjustment

Schedule Page: 310.8 Line No.: 2 Column: b

PowerEX - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff (4th revised S.A. 169)] -

Contract termination date: September 30, 2012.

Schedule Page: 310.8 Line No.: 2 Column: j

Transmission Losses

Schedule Page: 310.8 Line No.: 3 Column: j

Transmission Losses

Schedule Page: 310.8 Line No.: 5 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.4
Settlement Adjustment.

Schedule Page: 310.8 Line No.: 5 Column: j

Settlement Adjustment

Schedule Page: 310.8 Line No.: 6 Column: b

Public Service Company of Colorado - FERC 320 - Contract termination date: December 31, 2011.

Schedule Page: 310.8 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.8 Line No.: 10 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #1 OF SNOHOMISH COUNTY” ON PAGES 310 – 311:

Complete name is Public Utility District No. 1 of Snohomish County.

Schedule Page: 310.8 Line No.: 11 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #2 OF GRANT COUNTY” ON PAGES 310 – 311: Complete

name is Public Utility District No. 2 of Grant County.

Schedule Page: 310.8 Line No.: 11 Column: j

Reserve Share

Schedule Page: 310.8 Line No.: 13 Column: j

Reserve Share

Schedule Page: 310.9 Line No.: 1 Column: j

Transmission Losses

Schedule Page: 310.9 Line No.: 3 Column: b

Settlement Adjustment.

Schedule Page: 310.9 Line No.: 3 Column: j

Settlement Adjustment

Schedule Page: 310.9 Line No.: 4 Column: b

Sacramento Municipal Utility District - FERC 250 - Contract termination date: December 31, 2014.

Schedule Page: 310.9 Line No.: 5 Column: j

Reserve Share

Schedule Page: 310.9 Line No.: 7 Column: b

Salt River Project - WSPP - Contract termination date: December 31, 2009.

Schedule Page: 310.9 Line No.: 8 Column: j

Transmission Losses

Schedule Page: 310.9 Line No.: 10 Column: b

Settlement Adjustment.

Schedule Page: 310.9 Line No.: 10 Column: j

Settlement Adjustment

Schedule Page: 310.9 Line No.: 11 Column: b

San Diego Gas & Electric Company - WSPP - Contract termination date: December 31, 2010

Schedule Page: 310.9 Line No.: 14 Column: b

Seattle City Light - FERC T-11 [Point-to-Point Transmission Service under the Open Access Transmission Tariff (7th revised S.A.

289)] - Contract termination date: October 31, 2014.

Schedule Page: 310.9 Line No.: 14 Column: j

Transmission Losses

Schedule Page: 310.10 Line No.: 1 Column: j

Transmission Losses

Schedule Page: 310.10 Line No.: 2 Column: j

Reserve Share

Schedule Page: 310.10 Line No.: 4 Column: b

Settlement Adjustment.

Schedule Page: 310.10 Line No.: 4 Column: j

Settlement Adjustment

Schedule Page: 310.10 Line No.: 7 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.5
Settlement Adjustment.

Schedule Page: 310.10 Line No.: 7 Column: j

Settlement Adjustment

Schedule Page: 310.10 Line No.: 8 Column: b

Secondary, Economy and/or non-firm sales, including some hourly firm transactions.

Schedule Page: 310.10 Line No.: 9 Column: j

Transmission Losses

Schedule Page: 310.10 Line No.: 11 Column: b

Sierra Pacific Power Company - FERC T-11 [Pavant Capacitor Ownership, Operation and Maintenance Letter Agreement dated

November 9, 2000] - Contract termination date: 90 days notification.

Schedule Page: 310.10 Line No.: 11 Column: j

Transmission Losses

Schedule Page: 310.10 Line No.: 12 Column: j

Transmission Losses

Schedule Page: 310.10 Line No.: 13 Column: j

Reserve Share

Schedule Page: 310.10 Line No.: 14 Column: b

Southern California Edison Company - FERC T-12 - Contract termination date: December 31, 2012

Schedule Page: 310.11 Line No.: 1 Column: j

Transmission Losses

Schedule Page: 310.11 Line No.: 2 Column: j

Unauthorized use charges

Schedule Page: 310.11 Line No.: 5 Column: j

Reserve Share

Schedule Page: 310.11 Line No.: 7 Column: j

Transmission Losses

Schedule Page: 310.11 Line No.: 9 Column: b

TransAlta Energy Marketing Inc. - FERC T-12 - Contract termination date: December 31, 2010.

Schedule Page: 310.11 Line No.: 10 Column: j

Transmission Losses

Schedule Page: 310.11 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “TRI-STATE GEN. & TRANS.” ON PAGES 310 – 311: Complete

name is Tri-State Generation and Transmission Association, Inc. 

Schedule Page: 310.11 Line No.: 13 Column: j

Transmission Losses

Schedule Page: 310.12 Line No.: 4 Column: b

Secondary, Economy and/or non-firm sales, including some hourly firm transactions.

Schedule Page: 310.12 Line No.: 5 Column: j

Transmission Losses

Schedule Page: 310.12 Line No.: 7 Column: b

Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.

Schedule Page: 310.12 Line No.: 9 Column: b

Settlement Adjustment.

Schedule Page: 310.12 Line No.: 9 Column: j

Settlement Adjustment

Schedule Page: 310.12 Line No.: 10 Column: b

Western Area Power Administration - FERC R.S. 664 [Purchase of Capacity in the 230kV Casper-Dave Johnston Transmission LineUse of transmission Service during times when Western's capacity is de-rated] - Contract termination date: 50 years after commercial

operation of the transmission line.

Schedule Page: 310.12 Line No.: 10 Column: j

Transmission Losses

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.6
Schedule Page: 310.12 Line No.: 11 Column: j

Transmission Losses

Schedule Page: 310.12 Line No.: 13 Column: b

Secondary, Economy and/or non-firm sales, including some hourly firm transactions.

Schedule Page: 310.12 Line No.: 13 Column: j

The negative revenue reported on this line reflects test energy generated at the Dunlap Ranch I wind-powered generating facility that

was transferred to construction. Energy generated during testing was delivered to PacifiCorp’s electric system for sale, as required by

the guidance in 18 CFR Electric Plant Instructions 18(a), is a component of construction and is the fair value of the energy delivered.

Schedule Page: 310.12 Line No.: 14 Column: j

Recognition and reporting of gains and losses on bookouts under generally accepted accounting principles.

Schedule Page: 310.13 Line No.: 1 Column: j

Recognition and reporting of gains and losses on energy trading contracts under generally accepted accounting principles.

Schedule Page: 310.13 Line No.: 2 Column: j

Represents the difference between actual requirement sales revenues for the period as reflected on the individual line items within this

schedule, and the accruals charged to account 447 during the period.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.7
ELECTRIC OPERATION AND MAINTENANCE EXPENSES

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 1 1. POWER PRODUCTION EXPENSES

 2 A. Steam Power Generation

 3 Operation

 4 (500) Operation Supervision and Engineering 20,107,030 21,376,391

 5 (501) Fuel 646,729,745 620,266,055

 6 (502) Steam Expenses 38,472,021 35,509,089

 7 (503) Steam from Other Sources 3,655,727 3,597,576

 8 (Less) (504) Steam Transferred-Cr.

 9 (505) Electric Expenses 4,285,137 3,904,528

 10 (506) Miscellaneous Steam Power Expenses 48,042,874 43,559,253

 11 (507) Rents 338,685 450,415

 12 (509) Allowances

 13 TOTAL Operation (Enter Total of Lines 4 thru 12) 761,631,219 728,663,307

 14 Maintenance

 15 (510) Maintenance Supervision and Engineering 6,462,258 5,970,114

 16 (511) Maintenance of Structures 25,480,955 22,825,065

 17 (512) Maintenance of Boiler Plant 112,922,881 94,433,581

 18 (513) Maintenance of Electric Plant 38,934,338 33,727,522

 19 (514) Maintenance of Miscellaneous Steam Plant 12,066,167 12,681,273

 20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 195,866,599 169,637,555

 21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 957,497,818 898,300,862

 22 B. Nuclear Power Generation

 23 Operation

 24 (517) Operation Supervision and Engineering

 25 (518) Fuel

 26 (519) Coolants and Water

 27 (520) Steam Expenses

 28 (521) Steam from Other Sources

 29 (Less) (522) Steam Transferred-Cr.

 30 (523) Electric Expenses

 31 (524) Miscellaneous Nuclear Power Expenses

 32 (525) Rents

 33 TOTAL Operation (Enter Total of lines 24 thru 32)

 34 Maintenance

 35 (528) Maintenance Supervision and Engineering

 36 (529) Maintenance of Structures

 37 (530) Maintenance of Reactor Plant Equipment

 38 (531) Maintenance of Electric Plant

 39 (532) Maintenance of Miscellaneous Nuclear Plant

 40 TOTAL Maintenance (Enter Total of lines 35 thru 39)

 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)

 42 C. Hydraulic Power Generation

 43 Operation

 44 (535) Operation Supervision and Engineering 3,825,666 9,385,219

 45 (536) Water for Power 212,409 290,209

 46 (537) Hydraulic Expenses 3,449,509 3,518,610

 47 (538) Electric Expenses

 48 (539) Miscellaneous Hydraulic Power Generation Expenses 20,295,293 15,385,413

 49 (540) Rents 117,398 183,444

 50 TOTAL Operation (Enter Total of Lines 44 thru 49) 27,900,275 28,762,895

 51 C. Hydraulic Power Generation (Continued)

 52 Maintenance

 53 (541) Mainentance Supervision and Engineering 469 84,358

 54 (542) Maintenance of Structures 1,430,392 1,207,112

 55 (543) Maintenance of Reservoirs, Dams, and Waterways 1,959,700 1,600,540

 56 (544) Maintenance of Electric Plant 1,635,171 1,515,716

 57 (545) Maintenance of Miscellaneous Hydraulic Plant 2,654,790 2,539,316

 58 TOTAL Maintenance (Enter Total of lines 53 thru 57) 7,680,522 6,947,042

 59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 35,580,797 35,709,937

FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 60 D. Other Power Generation

 61 Operation

 62 (546) Operation Supervision and Engineering 358,628 316,964

 63 (547) Fuel 432,620,733 461,743,015

 64 (548) Generation Expenses 14,638,002 15,739,485

 65 (549) Miscellaneous Other Power Generation Expenses 18,701,556 18,635,853

 66 (550) Rents 3,558,679 1,861,264

 67 TOTAL Operation (Enter Total of lines 62 thru 66) 469,877,598 498,296,581

 68 Maintenance

 69 (551) Maintenance Supervision and Engineering

 70 (552) Maintenance of Structures 1,240,594 1,544,031

 71 (553) Maintenance of Generating and Electric Plant 8,996,404 14,986,840

 72 (554) Maintenance of Miscellaneous Other Power Generation Plant 2,196,699 1,321,906

 73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 12,433,697 17,852,777

 74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 482,311,295 516,149,358

 75 E. Other Power Supply Expenses

 76 (555) Purchased Power 380,007,678 456,211,649

 77 (556) System Control and Load Dispatching 877,454 1,514,461

 78 (557) Other Expenses 63,870,496 49,819,215

 79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 444,755,628 507,545,325

 80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 1,920,145,538 1,957,705,482

 81 2. TRANSMISSION EXPENSES

 82 Operation

 83 (560) Operation Supervision and Engineering 5,041,115 6,088,583

 84 (561) Load Dispatching 650,305

 85 (561.1) Load Dispatch-Reliability

 86 (561.2) Load Dispatch-Monitor and Operate Transmission System 7,847,328 8,347,455

 87 (561.3) Load Dispatch-Transmission Service and Scheduling

 88 (561.4) Scheduling, System Control and Dispatch Services

 89 (561.5) Reliability, Planning and Standards Development 816,883

 90 (561.6) Transmission Service Studies 83,476 76,671

 91 (561.7) Generation Interconnection Studies 938,904 899,582

 92 (561.8) Reliability, Planning and Standards Development Services

 93 (562) Station Expenses 2,124,825 1,506,478

 94 (563) Overhead Lines Expenses 120,209 245,152

 95 (564) Underground Lines Expenses

 96 (565) Transmission of Electricity by Others 136,854,649 117,161,210

 97 (566) Miscellaneous Transmission Expenses 4,257,862 2,393,112

 98 (567) Rents 1,312,382 1,656,975

 99 TOTAL Operation (Enter Total of lines 83 thru 98) 160,047,938 138,375,218

 100 Maintenance

 101 (568) Maintenance Supervision and Engineering 1,334,303 35,453

 102 (569) Maintenance of Structures 395 788

 103 (569.1) Maintenance of Computer Hardware 36,440 79,505

 104 (569.2) Maintenance of Computer Software 1,065,683 974,621

 105 (569.3) Maintenance of Communication Equipment 3,567,267 3,005,647

 106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant

 107 (570) Maintenance of Station Equipment 10,092,385 10,549,624

 108 (571) Maintenance of Overhead Lines 19,173,510 19,620,066

 109 (572) Maintenance of Underground Lines 36,881 51,599

 110 (573) Maintenance of Miscellaneous Transmission Plant 273,467 182,001

 111 TOTAL Maintenance (Total of lines 101 thru 110) 35,580,331 34,499,304

 112 TOTAL Transmission Expenses (Total of lines 99 and 111) 195,628,269 172,874,522

FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 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

 122 (575.8) Rents

 123 Total Operation (Lines 115 thru 122)

 124 Maintenance

 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)

 132 4. DISTRIBUTION EXPENSES

 133 Operation

 134 (580) Operation Supervision and Engineering 15,625,451 19,654,389

 135 (581) Load Dispatching 13,735,481 13,439,746

 136 (582) Station Expenses 3,812,831 3,879,687

 137 (583) Overhead Line Expenses 5,762,152 5,794,824

 138 (584) Underground Line Expenses 287 305

 139 (585) Street Lighting and Signal System Expenses 209,265 207,152

 140 (586) Meter Expenses 6,564,361 6,713,560

 141 (587) Customer Installations Expenses 12,634,849 12,459,259

 142 (588) Miscellaneous Expenses 5,887,263 7,441,400

 143 (589) Rents 3,253,672 3,196,255

 144 TOTAL Operation (Enter Total of lines 134 thru 143) 67,485,612 72,786,577

 145 Maintenance

 146 (590) Maintenance Supervision and Engineering 5,493,229 7,535,970

 147 (591) Maintenance of Structures 1,828,870 2,015,990

 148 (592) Maintenance of Station Equipment 12,622,071 12,800,357

 149 (593) Maintenance of Overhead Lines 84,730,396 83,336,655

 150 (594) Maintenance of Underground Lines 22,786,414 22,486,595

 151 (595) Maintenance of Line Transformers 883,285 1,105,880

 152 (596) Maintenance of Street Lighting and Signal Systems 4,084,559 4,217,687

 153 (597) Maintenance of Meters 5,890,644 5,637,023

 154 (598) Maintenance of Miscellaneous Distribution Plant 2,745,222 3,546,007

 155 TOTAL Maintenance (Total of lines 146 thru 154) 141,064,690 142,682,164

 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 208,550,302 215,468,741

 157 5. CUSTOMER ACCOUNTS EXPENSES

 158 Operation

 159 (901) Supervision 2,497,682 2,554,096

 160 (902) Meter Reading Expenses 22,553,488 22,520,219

 161 (903) Customer Records and Collection Expenses 54,938,892 56,280,326

 162 (904) Uncollectible Accounts 12,590,656 12,175,795

 163 (905) Miscellaneous Customer Accounts Expenses 169,927 254,571

 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 92,750,645 93,785,007

FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

If the amount for previous year is not derived from previously reported figures, explain in footnote.

 165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES

 166 Operation

 167 (907) Supervision 263,903 286,417

 168 (908) Customer Assistance Expenses 124,155,800 66,102,006

 169 (909) Informational and Instructional Expenses 4,435,033 4,924,267

 170 (910) Miscellaneous Customer Service and Informational Expenses 90,169 150,054

 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 128,944,905 71,462,744

 172 7. SALES EXPENSES

 173 Operation

 174 (911) Supervision

 175 (912) Demonstrating and Selling Expenses

 176 (913) Advertising Expenses

 177 (916) Miscellaneous Sales Expenses

 178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)

 179 8. ADMINISTRATIVE AND GENERAL EXPENSES

 180 Operation

 181 (920) Administrative and General Salaries 66,458,826 72,874,820

 182 (921) Office Supplies and Expenses 9,973,883 11,031,087

 183 (Less) (922) Administrative Expenses Transferred-Credit 28,375,128 25,866,775

 184 (923) Outside Services Employed 9,404,302 11,039,350

 185 (924) Property Insurance 23,341,430 23,970,317

 186 (925) Injuries and Damages 8,492,514 7,434,336

 187 (926) Employee Pensions and Benefits

 188 (927) Franchise Requirements

 189 (928) Regulatory Commission Expenses 17,926,840 16,464,747

 190 (929) (Less) Duplicate Charges-Cr. 6,130,867 3,420,842

 191 (930.1) General Advertising Expenses 20,382 35,761

 192 (930.2) Miscellaneous General Expenses 16,291,649 19,659,625

 193 (931) Rents 6,337,703 6,199,584

 194 TOTAL Operation (Enter Total of lines 181 thru 193) 123,741,534 139,422,010

 195 Maintenance

 196 (935) Maintenance of General Plant 22,334,950 23,197,501

 197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 146,076,484 162,619,511

 198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 2,692,096,143 2,673,916,007

FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 187 Column: b

Pensions and benefits expense is associated with labor and generally charged to operations and maintenance expense and construction

work in progress. During the years ended December 31, 2010 and 2009, pensions and benefits expense was $153,429,891 and

$143,975,955, respectively. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Power Purchases

 2 Albany, City of LU NA NA NA

 3 Alberta Power Pool SF NA NA NA

 4 Amy Ranch Hydro LU NA NA NA

 5 Anaheim, City of SF NA NA NA

 6 Arizona Public Service Company AD NA NA NA

 7 Arizona Public Service Company OS NA NA NA

 8 Arizona Public Service Company LF NA NA NA

 9 Arizona Public Service Company SF NA NA NA

 10 Avista Corporation SF NA NA NA

 11 BNP Paribas Energy Trading GP SF NA NA NA

 12 BP Corporation North America, Inc. SF NA NA NA

 13 BP Energy Company SF NA NA NA

 14 Ballard Hog Farms Inc. LU 0.01 0.01 0.01

FERC FORM NO. 1 (ED. 12-90) Page 326

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Barclays Bank PLC AD NA NA NA

 2 Barclays Bank PLC AD NA NA NA

 3 Barclays Bank PLC SF NA NA NA

 4 Beaver City Corporation LF NA NA NA

 5 Bell Mountain Hydro, LLC AD NA NA NA

 6 Bell Mountain Hydro, LLC LU NA NA NA

 7 Big Top, LLC LU NA NA NA

 8 Biomass One, L.P. LU 22.5 20.9 13.7

 9 Birch Creek Hydro LU NA NA NA

 10 Black Hills Power, Inc. AD NA NA NA

 11 Black Hills Power, Inc. LU NA NA NA

 12 Black Hills Power, Inc. OS NA NA NA

 13 Black Hills Power, Inc. SF NA NA NA

 14 Black Hills Wyoming, Inc. SF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.1

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Blanding City Corporation LF NA NA NA

 2 Bonneville Power Administration LF 575 575 461

 3 Bonneville Power Administration LF NA NA NA

 4 Bonneville Power Administration OS NA NA NA

 5 Bonneville Power Administration SF NA NA NA

 6 British Columbia Transmission Corp. SF NA NA NA

 7 Butter Creek Power, LLC LU NA NA NA

 8 CDM Hydroelectric Company LU NA NA NA

 9 California Independent System Operator AD NA NA NA

 10 California Independent System Operator SF NA NA NA

 11 Cameron A. Curtiss LU NA NA NA

 12 Cargill Power Markets, LLC AD NA NA NA

 13 Cargill Power Markets, LLC SF NA NA NA

 14 Central Oregon Irrigation District LU 3.6 3.7 2.7

FERC FORM NO. 1 (ED. 12-90) Page 326.2

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Chevron U.S.A. Inc. LU NA NA NA

 2 Citigroup Energy, Inc. AD NA NA NA

 3 Citigroup Energy, Inc. SF NA NA NA

 4 City of Burbank SF NA NA NA

 5 City of Preston Idaho LU NA NA NA

 6 City of Redding SF NA NA NA

 7 City of Walla Walla LU 1.1 1.7 1.5

 8 Clatskanie People's Utility District SF NA NA NA

 9 Colorado River Commission of Nevada AD NA NA NA

 10 Colorado River Commission of Nevada SF NA NA NA

 11 Commercial Energy Management, Inc. LU NA NA NA

 12 ConocoPhillips Company SF NA NA NA

 13 Constellation Energy Commodities Group OS NA NA NA

 14 Constellation Energy Commodities Group SF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.3

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Cottonwood Hydro LLC IU NA NA NA

 2 Credit Suisse Energy LLC AD NA NA NA

 3 Credit Suisse Energy LLC SF NA NA NA

 4 DB Energy Trading LLC AD NA NA NA

 5 DB Energy Trading LLC SF NA NA NA

 6 Deschutes Valley Water District LU 5.92 4.5 3.5

 7 Deseret Power Electric Cooperative LF 100 100 84

 8 Deseret Power Electric Cooperative OS NA NA NA

 9 Deutsche Bank AG AD NA NA NA

 10 Deutsche Bank AG SF NA NA NA

 11 Douglas County Inc. IU NA NA NA

 12 Douglas County Public Works LU 0.2 0.7 0.5

 13 Draper Irrigation Company IU NA NA NA

 14 Dry Creek LLC LU NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.4

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 EDF Trading North America, LLC SF NA NA NA

 2 Eagle Point Irrigation District LU 0.8 0.5 0.4

 3 El Paso Electric Company AD NA NA NA

 4 El Paso Electric Company SF NA NA NA

 5 Endure Energy, LLC SF NA NA NA

 6 Eugene Water & Electric Board SF NA NA NA

 7 Eurus Combine Hills I, LLC LU NA NA NA

 8 Evergreen BioPower, LLC LU NA NA NA

 9 ExxonMobile Production Company LU NA NA NA

 10 Falls Creek H.P. Limited Partnership LU 3.5 3.7 1.6

 11 Farmers Irrigation District LU 3.92 3.6 2.9

 12 Fillmore City LF NA NA NA

 13 Finley BioEnergy, LLC LU NA NA NA

 14 Four Corners Windfarm, LLC LU NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.5

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Four Mile Canyon Windfarm, LLC LU NA NA NA

 2 General Chemical Corporation OS NA NA NA

 3 George DeRuyter & Sons Dairy LU 0.8 1 0.8

 4 Georgetown Irrigation Company LU NA NA NA

 5 Gila River Power, L.P. AD NA NA NA

 6 Gila River Power, L.P. OS NA NA NA

 7 Gila River Power, L.P. SF NA NA NA

 8 Glendale, City of SF NA NA NA

 9 Grand Valley Power LF NA NA NA

 10 Grays Harbor Public Utility District SF NA NA NA

 11 HDI Associates V, LP LU 0.35 0.5 0.2

 12 Harold Foster & Robert Walker LU NA NA NA

 13 Heber Light & Power Company LF NA NA NA

 14 Hermiston Generating Company, L.P. AD NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.6

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Hermiston Generating Company, L.P. LU 240 239 216

 2 Hill Air Force Base AD NA NA NA

 3 Hill Air Force Base LU NA NA NA

 4 Hurricane, City of LF NA NA NA

 5 Iberdrola Renewables, Inc. AD NA NA NA

 6 Iberdrola Renewables, Inc. SF NA NA NA

 7 Idaho Falls, City of AD NA NA NA

 8 Idaho Falls, City of LU NA NA NA

 9 Idaho Power Company SF NA NA NA

 10 Intermountain Power Agency LU NA NA NA

 11 J. Aron & Company SF NA NA NA

 12 JP Morgan Ventures Energy Corporation AD NA NA NA

 13 JP Morgan Ventures Energy Corporation SF NA NA NA

 14 KEI (USA) Power Management Inc. LU 2.2 4.3 2.1

FERC FORM NO. 1 (ED. 12-90) Page 326.7

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Kennecott Utah Copper LLC LU NA NA NA

 2 L&M Angus Ranch, LLC LU NA NA NA

 3 Lacomb Irrigation District LU NA NA NA

 4 Los Angeles Dept. of Water & Power IF NA NA NA

 5 Los Angeles Dept. of Water & Power OS NA NA NA

 6 Los Angeles Dept. of Water & Power SF NA NA NA

 7 Lower Valley Energy, Inc. AD NA NA NA

 8 Lower Valley Energy, Inc. IU NA NA NA

 9 Loyd Fery LU NA NA NA

 10 Macquarie Energy LLC SF NA NA NA

 11 Marsh Valley Hydro & Electric Company LU NA NA NA

 12 Metropolitan Water District of S. Cal. SF NA NA NA

 13 Middle Fork Irrigation District LU NA NA NA

 14 Mink Creek Hydro LU NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.8

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Modesto Irrigation District SF NA NA NA

 2 Monsanto Company IU NA NA NA

 3 Morgan City Corporation LF NA NA NA

 4 Morgan Stanley Capital Group, Inc. AD NA NA NA

 5 Morgan Stanley Capital Group, Inc. IF 100 50 50

 6 Morgan Stanley Capital Group, Inc. SF NA NA NA

 7 Mountain Wind Power II, LLC AD NA NA NA

 8 Mountain Wind Power II, LLC LU NA NA NA

 9 Mountain Wind Power, LLC LU NA NA NA

 10 Municipal Energy Agency of Nebraska SF NA NA NA

 11 Nephi City Corporation LF NA NA NA

 12 Nevada Power Company SF NA NA NA

 13 NextEra Energy Power Marketing, LLC SF NA NA NA

 14 Nicholson Sunnybar Ranch AD NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.9

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Nicholson Sunnybar Ranch LU NA NA NA

 2 NorthWestern Corporation SF NA NA NA

 3 Northpoint Energy Solutions Inc. SF NA NA NA

 4 Nucor Corporation IF NA NA NA

 5 O.J. Power Company LU NA NA NA

 6 Odell Creek Hydroelectric Investors LU 0.01 0 0

 7 Oregon Environmental Industries, LLC LU NA NA NA

 8 Oregon Institute of Technology LU NA NA NA

 9 Oregon Trail Windfarm, LLC LU NA NA NA

 10 PPL EnergyPlus, LLC SF NA NA NA

 11 Pacific Canyon Windfarm, LLC LU NA NA NA

 12 Pacific Gas & Electric Company SF NA NA NA

 13 Pacific Northwest Generating Coop. SF NA NA NA

 14 Pacific Summit Energy LLC SF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.10

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Paul Luckey LU NA NA NA

 2 Payson City Corporation LF NA NA NA

 3 Platte River Power Authority SF NA NA NA

 4 Portland General Electric Company AD NA NA NA

 5 Portland General Electric Company LF NA NA NA

 6 Portland General Electric Company OS NA NA NA

 7 Portland General Electric Company SF NA NA NA

 8 Powerex Corporation AD NA NA NA

 9 Powerex Corporation SF NA NA NA

 10 Provo City Corporation LF NA NA NA

 11 Public Service Company of Colorado OS NA NA NA

 12 Public Service Company of Colorado SF NA NA NA

 13 Public Service Company of New Mexico SF NA NA NA

 14 PUD #1 of Chelan County LU NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.11

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 PUD #1 of Chelan County SF NA NA NA

 2 PUD #1 of Cowlitz County OS NA NA NA

 3 PUD #1 of Douglas County AD NA NA NA

 4 PUD #1 of Douglas County AD NA NA NA

 5 PUD #1 of Douglas County LF NA NA NA

 6 PUD #1 of Douglas County LU NA NA NA

 7 PUD #1 of Douglas County SF NA NA NA

 8 PUD #1 of Snohomish County SF NA NA NA

 9 PUD #2 of Grant County AD NA NA NA

 10 PUD #2 of Grant County LF 14 NA NA

 11 PUD #2 of Grant County LU NA NA NA

 12 PUD #2 of Grant County SF NA NA NA

 13 PUD #1 of Lewis County AD NA NA NA

 14 PUD #1 of Lewis County LF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.12

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Puget Sound Energy, Inc. SF NA NA NA

 2 Rainbow Energy Marketing Corporation SF NA NA NA

 3 Ralphs Ranch, Inc. AD NA NA NA

 4 Ralphs Ranch, Inc. LU NA NA NA

 5 Rock River 1, LLC LU NA NA NA

 6 Rocky Mountain Generation Coop. SF NA NA NA

 7 Roseburg Forest Products Co. LU NA NA NA

 8 Roseburg Forest Products Co. OS NA NA NA

 9 Rough & Ready Lumber Company LU NA NA NA

 10 Roush Hydro Inc. LU NA NA NA

 11 Sacramento Municipal Utility District AD NA NA NA

 12 Sacramento Municipal Utility District LF NA NA NA

 13 Sacramento Municipal Utility District SF NA NA NA

 14 Salt River Project SF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.13

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 San Diego Gas & Electric Company AD NA NA NA

 2 San Diego Gas & Electric Company SF NA NA NA

 3 Sand Ranch Windfarm, LLC LU NA NA NA

 4 Santiam Water Control District LU 0.2 0.2 0.2

 5 Seattle City Light SF NA NA NA

 6 Sempra Energy Trading LLC AD NA NA NA

 7 Sempra Energy Trading LLC SF NA NA NA

 8 Sempra Generation SF NA NA NA

 9 Shell Energy North America (US), L.P. AD NA NA NA

 10 Shell Energy North America (US), L.P. SF NA NA NA

 11 Shoshone Irrigation District LU 2.5 1.4 1

 12 Sierra Pacific Power Company SF NA NA NA

 13 Sierra Pacific Power Company SF NA NA NA

 14 Sierra Pacific Power Company SF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.14

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Simplot Phosphates LLC LU 10 13 9

 2 Slate Creek Hydro Company, Inc. LU 3.2 2.7 1.8

 3 Southern California Edison Company OS NA NA NA

 4 Southern California Edison Company SF NA NA NA

 5 Southwestern Public Service Company SF NA NA NA

 6 Spanish Fork City Corporation LF NA NA NA

 7 Spanish Fork Wind Park 2, LLC LU NA NA NA

 8 Springville City Corporation LF NA NA NA

 9 Stahlbush Island Farms, Inc. IU NA NA NA

 10 Strawberry Electric Service District LF NA NA NA

 11 Sunderland Dairy Inc. LU 0.02 0.03 0.02

 12 Sunnyside Cogeneration Associates LU 52 53 43

 13 Swalley Irrigation District LU NA NA NA

 14 Tacoma Power AD NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.15

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Tacoma Power SF NA NA NA

 2 Tesoro Refining and Marketing Company LU NA NA NA

 3 Thayn Hydro LLC LU 0.3 0.4 0.3

 4 The Energy Authority SF NA NA NA

 5 The Town of the City of Buffalo LU 0.23 0.2 0.2

 6 Three Buttes Windpower, LLC LU NA NA NA

 7 Threemile Canyon Wind I, LLC AD NA NA NA

 8 Threemile Canyon Wind I, LLC LU NA NA NA

 9 Top of The World Wind Energy LLC LU NA NA NA

 10 TransAlta Energy Marketing Inc. IF NA NA NA

 11 TransAlta Energy Marketing Inc. SF NA NA NA

 12 TransCanada Energy Sales Ltd. SF NA NA NA

 13 Tri-State Gen. & Trans. LF 30 29 26

 14 Tri-State Gen. & Trans. SF NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.16

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Tucson Electric Power Company OS NA NA NA

 2 Tucson Electric Power Company SF NA NA NA

 3 Turlock Irrigation District SF NA NA NA

 4 UNS Electric, Inc. SF NA NA NA

 5 US Magnesium LLC IU NA NA NA

 6 US Magnesium LLC LF NA NA NA

 7 Utah Associated Municipal Power OS NA NA NA

 8 Utah Associated Municipal Power SF NA NA NA

 9 Utah Municipal Power Agency SF NA NA NA

 10 Wadeland South LLC LU NA NA NA

 11 Wagon Trail, LLC LU NA NA NA

 12 Ward Butte Windfarm, LLC LU NA NA NA

 13 Warm Springs Forest Products LU NA NA NA

 14 Wasatch Integrated Waste Management LU NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.17

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Weber County, State of Utah LU NA NA NA

 2 Western Area Power Administration AD NA NA NA

 3 Western Area Power Administration SF NA NA NA

 4 Western Area Power Administration SF NA NA NA

 5 Western Area Power Administration SF NA NA NA

 6 Whitney, A. C. AD NA NA NA

 7 Wolverine Creek Energy LLC LU NA NA NA

 8 Yakima-Tieton Irrigation District LU NA NA NA

 9 Accrual/Net Power Cost Deferrals NA NA NA NA

 10 Settlement/Reserves AD NA NA NA

 11 Bookout Purchases AD NA NA NA

 12 Trade Purchases AD NA NA NA

 13

 14

FERC FORM NO. 1 (ED. 12-90) Page 326.18

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Power Exchanges

 2 Arizona Public Service Company EX 306 NA NA NA

 3 Avista Corporation EX 554 NA NA NA

 4 Basin Electric Power Cooperative EX T-11 NA NA NA

 5 Black Hills Power, Inc. EX 246 NA NA NA

 6 Bonneville Power Administration AD 237 NA NA NA

 7 Bonneville Power Administration AD -17 NA NA NA

 8 Bonneville Power Administration EX 237 NA NA NA

 9 Bonneville Power Administration EX 256 NA NA NA

 10 Bonneville Power Administration EX 411 NA NA NA

 11 Bonneville Power Administration EX 368 NA NA NA

 12 Bonneville Power Administration EX 554 NA NA NA

 13 Bonneville Power Administration EX -17 NA NA NA

 14 Bonneville Power Administration EX T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.19

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 Bonneville Power Administration EX T-12 NA NA NA

 2 Bonneville Power Administration EX T-12 NA NA NA

 3 City of Redding EX 364 NA NA NA

 4 City of St. George EX 280 NA NA NA

 5 Colockum Transmission Company EX T-12 NA NA NA

 6 Constellation Energy Commodities Group EX T-11 NA NA NA

 7 Deseret Power Electric Cooperative AD 280 NA NA NA

 8 Deseret Power Electric Cooperative EX 280 NA NA NA

 9 Emerald People's Utility District AD 351 NA NA NA

 10 Emerald People's Utility District EX 351 NA NA NA

 11 Eugene Water & Electric Board EX T-12 NA NA NA

 12 Iberdrola Renewables, Inc. EX T-11 NA NA NA

 13 Idaho Power Company EX 380 NA NA NA

 14 Intermountain Renewable Power, LLC EX T-11 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.20

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 JP Morgan Ventures Energy Corporation EX T-11 NA NA NA

 2 Los Angeles Dept. of Water & Power AD OV-1 NA NA NA

 3 Los Angeles Dept. of Water & Power EX OV-1 NA NA NA

 4 Milford Wind Corridor Phase I, LLC AD OV-1 NA NA NA

 5 Milford Wind Corridor Phase I, LLC EX OV-1 NA NA NA

 6 NextEra Energy Power Marketing, LLC EX T-11 NA NA NA

 7 Noble Americas Energy Solutions LLC EX T-11 NA NA NA

 8 Portland General Electric Company EX 554 NA NA NA

 9 Powerex Corporation EX T-11 NA NA NA

 10 Public Service Company of Colorado EX 319 NA NA NA

 11 Public Service Company of Colorado EX 320 NA NA NA

 12 Public Service Company of Colorado EX T-12 NA NA NA

 13 PUD #1 of Chelan County EX 554 NA NA NA

 14 PUD #1 of Chelan County EX 555 NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.21

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER (Account 555)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

FERC Rate

Monthly Billing

Average

(d)

Statistical

cation

Classifi- Schedule or

Tariff Number Demand (MW)

(e) (f)

(Footnote Affiliations)

Actual Demand (MW)

Average Average

Monthly NCP Demand Monthly CP Demand

(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.

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 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

than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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

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 for each adjustment.

 1 PUD #1 of Cowlitz County EX 554 NA NA NA

 2 Seattle City Light EX 554 NA NA NA

 3 Seattle City Light EX T-11 NA NA NA

 4 Southern California Edison Company EX T-11 NA NA NA

 5 Tri-State Gen. & Trans. AD 319 NA NA NA

 6 Tri-State Gen. & Trans. EX 319 NA NA NA

 7 Tri-State Gen. & Trans. EX T-11 NA NA NA

 8 Utah Associated Municipal Power AD T-11 NA NA NA

 9 Utah Associated Municipal Power EX T-11 NA NA NA

 10 Utah Municipal Power Agency EX T-11 NA NA NA

 11 Warm Springs Power Enterprises EX T-11 NA NA NA

 12 Western Area Power Administration AD LAS-4 NA NA NA

 13 Western Area Power Administration EX LAS-4 NA NA NA

 14 System Deviation NA NA NA NA

FERC FORM NO. 1 (ED. 12-90) Page 326.22

Total
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 1

 1,223 79,398 79,398 2

 59 1,720 1,720 3

 1,862 96,961 96,961 4

 15 278 278 5

 400 33,450 33,450 6

 256 8,210 8,210 7

 83,299 2,557,725 2,557,725 8

 69,286 2,396,446 2,396,446 9

 128,850 4,219,641 15,946 4,235,587 10

 6,000 207,290 207,290 11

 -37,170,962 -37,170,962 12

 32,905 654,037 654,037 13

 49 213 2,449 2,662 14

FERC FORM NO. 1 (ED. 12-90) Page 327

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 -4,004 -4,004 1

 350 26,590 26,590 2

 106,053 4,702,174 -68,131,914 -63,429,740 3

 71 5,994 5,994 4

 -15,139 -15,139 5

 996 67,272 67,272 6

 2,928 186,911 186,911 7

 143,000 2,666,250 19,785,327 3,691,677 26,143,254 8

 13,847 758,820 758,820 9

 25,637 25,637 10

 318 2,848,604 2,848,604 11

 130 2,990 2,990 12

 14,635 459,485 459,485 13

 400 8,400 8,400 14

FERC FORM NO. 1 (ED. 12-90) Page 327.1

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 423 31,753 31,753 1

 57,615,000 57,615,000 2

 1,706,104 1,706,104 3

 1,674 70,681 70,681 4

 90,060 1,757,934 162,853 1,920,787 5

 264 7,696 7,696 6

 11,316 717,291 717,291 7

 25,566 1,396,492 1,396,492 8

 -16,617 730,460 730,460 9

 529,098 17,865,500 17,865,500 10

 69 3,008 3,008 11

 1,805 141,722 141,722 12

 637,442 25,047,500 402,724 25,450,224 13

 22,660 400,660 2,134,677 2,535,337 14

FERC FORM NO. 1 (ED. 12-90) Page 327.2

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 38,584 2,076,638 21,959 2,098,597 1

 91 3,425 3,425 2

 249,311 7,356,095 -26,425,184 -19,069,089 3

 22,800 974,450 974,450 4

 1,579 77,193 77,193 5

 1,014 22,425 22,425 6

 12,135 138,741 1,653,967 1,792,708 7

 1,445 45,110 45,110 8

 94 7,088 7,088 9

 154 13,588 13,588 10

 1,627 85,375 85,375 11

 123,362 3,736,216 3,736,216 12

 4,581 237,718 237,718 13

 187,716 9,491,237 -37,165 9,454,072 14

FERC FORM NO. 1 (ED. 12-90) Page 327.3

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 2,704 149,623 149,623 1

 50 9,069 9,069 2

 400 17,320 -1,559,739 -1,542,419 3

 18 869 869 4

 205,612 8,339,074 8,339,074 5

 31,327 582,894 3,330,042 3,912,936 6

 833,314 14,238,038 15,126,801 3,747,224 33,112,063 7

 5,336 5,336 8

 -3,391 -3,391 9

 -2,633,858 -2,633,858 10

 1,427 45,925 45,925 11

 4,388 41,414 523,107 564,521 12

 -1,378 -1,378 13

 11,980 618,711 618,711 14

FERC FORM NO. 1 (ED. 12-90) Page 327.4

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 172,839 7,289,824 -432,543 6,857,281 1

 3,248 44,501 363,935 408,436 2

 1 40 40 3

 25,486 950,250 58 950,308 4

 11,600 358,550 358,550 5

 18,796 550,261 550,261 6

 104,663 3,671,564 3,671,564 7

 42,924 2,328,875 2,328,875 8

 652,410 31,711,273 31,711,273 9

 17,303 225,624 1,823,788 2,049,412 10

 24,385 338,031 2,589,659 2,927,690 11

 182 19,680 19,680 12

 27,071 1,758,942 1,758,942 13

 23,146 1,469,252 1,469,252 14

FERC FORM NO. 1 (ED. 12-90) Page 327.5

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 21,849 1,390,126 1,390,126 1

 2,583 38,485 38,485 2

 6,698 13,360 410,812 424,172 3

 2,112 113,503 113,503 4

 671 63,592 63,592 5

 150 8,250 8,250 6

 53,877 2,134,549 2,134,549 7

 1,200 42,200 42,200 8

 132 23,873 23,873 9

 4,320 62,160 62,160 10

 2,282 37,268 250,129 287,397 11

 843 29,827 29,827 12

 6,037 511,075 511,075 13

 1 -238,483 -238,483 14

FERC FORM NO. 1 (ED. 12-90) Page 327.6

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 1,592,856 35,316,527 59,644,334 326,730 95,287,591 1

 6,533 6,533 2

 14,185 678,405 678,405 3

 1,992 149,378 149,378 4

 4,366 4,366 5

 480,053 14,588,523 -4,210,685 10,377,838 6

 -31,788 -31,788 7

 39,813 2,915,697 2,915,697 8

 1,901 66,180 3,316 69,496 9

 564,732 27,947,142 27,947,142 10

 8,600 256,870 -2,236,873 -1,980,003 11

 20 726 726 12

 142,558 5,165,634 936,569 6,102,203 13

 22,983 288,507 2,559,977 2,848,484 14

FERC FORM NO. 1 (ED. 12-90) Page 327.7

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 169,414 7,210,874 10,102,863 17,313,737 1

 1,511 82,985 82,985 2

 4,733 165,359 33,822 199,181 3

 23,000 1,149,080 1,149,080 4

 3,150 15,750 15,750 5

 90,577 3,804,020 3,804,020 6

 -12 -687 -687 7

 5,175 291,324 291,324 8

 232 15,020 15,020 9

 116,134 3,502,713 123,376 3,626,089 10

 4,555 250,058 250,058 11

 41 1,445 1,445 12

 23,610 1,267,429 1,267,429 13

 8,036 423,842 423,842 14

FERC FORM NO. 1 (ED. 12-90) Page 327.8

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 1,200 47,600 47,600 1

 17,705,685 17,705,685 2

 25 2,902 2,902 3

 2,837 101,468 101,468 4

 245,575 3,057,000 10,682,513 13,739,513 5

 1,132,331 52,870,919 -22,101,625 30,769,294 6

 8,166 8,166 7

 202,072 13,119,063 13,119,063 8

 149,425 8,274,548 8,274,548 9

 500 17,640 17,640 10

 19 1,824 1,824 11

 40,963 1,485,790 83,907 1,569,697 12

 600 24,150 24,150 13

 -38 -2,475 -2,475 14

FERC FORM NO. 1 (ED. 12-90) Page 327.9

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 1,852 100,426 100,426 1

 588 19,994 19,994 2

 400 12,200 12,200 3

 4,885,800 4,885,800 4

 708 35,249 35,249 5

 439 4 443 6

 20,978 1,123,946 1,123,946 7

 322 5,902 5,902 8

 22,057 1,399,186 1,399,186 9

 52,235 1,573,131 1,573,131 10

 16,242 1,035,088 1,035,088 11

 1,600 46,000 46,000 12

 10,075 264,080 264,080 13

 12,348 398,797 398,797 14

FERC FORM NO. 1 (ED. 12-90) Page 327.10

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 253 29,309 29,309 1

 7 764 764 2

 2,776 77,767 77,767 3

 -14,939 -14,939 4

 12,001 141,000 141,000 5

 1,200 1,200 6

 53,247 1,691,178 24,481 1,715,659 7

 31 1,255 1,255 8

 150,257 5,866,328 166,508 6,032,836 9

 301 25,400 25,400 10

 26 885 885 11

 20,720 752,474 752,474 12

 73,104 2,489,686 137,681 2,627,367 13

 306,009 3,964,408 3,964,408 14

FERC FORM NO. 1 (ED. 12-90) Page 327.11

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 43,360 802,570 5,445 808,015 1

 -8,136 -8,136 2

 -68,903 -68,903 3

 -198,867 -198,867 4

 34,958 758,612 758,612 5

 198,970 2,958,681 2,958,681 6

 33,391 1,056,220 1,560 1,057,780 7

 79,896 2,018,714 2,018,714 8

 -3,588,743 -3,588,743 9

 87,600 94,138 5,791,025 318,779 6,203,942 10

 981,806 12,896,650 7,780,156 20,676,806 11

 32,107 956,570 6,840 963,410 12

 -178 -7,377 -7,377 13

 8,104 243,034 243,034 14

FERC FORM NO. 1 (ED. 12-90) Page 327.12

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 167,918 5,547,977 27,072 5,575,049 1

 75,863 2,531,434 2,531,434 2

 -18 -2,214 -2,214 3

 37 4,426 4,426 4

 138,204 4,903,494 4,903,494 5

 5,815 159,221 159,221 6

 168,638 9,626,855 9,626,855 7

 11 14,362 14,362 8

 8,463 550,664 550,664 9

 236 15,257 15,257 10

 43,800 43,800 11

 213,709 3,748,456 3,748,456 12

 21,930 799,882 2,157 802,039 13

 98,968 3,938,386 127 3,938,513 14

FERC FORM NO. 1 (ED. 12-90) Page 327.13

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 357 11,387 11,387 1

 9,509 397,974 397,974 2

 19,888 1,265,980 1,265,980 3

 1,521 13,632 144,445 158,077 4

 119,532 3,277,977 10,245 3,288,222 5

 81 348 348 6

 273,914 13,453,560 -19,996,534 -6,542,974 7

 15 525 525 8

 90 3,028 3,028 9

 291,446 10,665,574 -44,238,031 -33,572,457 10

 9,713 163,673 391,435 555,108 11

 72 2,336 2,336 12

 152 9,154 9,154 13

 9,725 382,995 382,995 14

FERC FORM NO. 1 (ED. 12-90) Page 327.14

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 82,452 444,600 3,501,940 3,946,540 1

 15,289 212,588 1,516,653 1,729,241 2

 2,600 62,200 62,200 3

 37,921 1,246,943 1,246,943 4

 1,996 66,883 66,883 5

 24 2,776 2,776 6

 46,929 2,442,876 2,442,876 7

 60 7,333 7,333 8

 3,660 243,120 243,120 9

 58 4,921 4,921 10

 109 1,503 3,479 4,982 11

 377,727 9,681,949 13,803,144 23,485,093 12

 2,225 144,327 144,327 13

 21 1,239 1,239 14

FERC FORM NO. 1 (ED. 12-90) Page 327.15

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 20,896 702,195 4,332 706,527 1

 47,654 1,974,079 1,974,079 2

 2,525 67,772 188,643 256,415 3

 37,082 1,040,588 1,040,588 4

 1,753 30,348 155,069 185,417 5

 299,989 19,117,682 379,646 19,497,328 6

 153,684 153,684 7

 20,689 1,338,382 1,338,382 8

 188,825 12,172,889 12,172,889 9

 1,315,200 44,909,806 -727,224 44,182,582 10

 120,630 4,207,360 4,207,360 11

 20,600 1,095,750 1,095,750 12

 169,419 6,861,600 4,460,802 11,322,402 13

 26,166 624,161 325,564 949,725 14

FERC FORM NO. 1 (ED. 12-90) Page 327.16

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 75 1,425 1,425 1

 37,947 1,229,053 235 1,229,288 2

 815 25,800 437 26,237 3

 8,271 188,579 188,579 4

 184,521 7,786,278 7,786,278 5

 4,909,716 4,909,716 6

 61,950 2,075,988 2,075,988 7

 332 13,250 13,250 8

 590 25,050 25,050 9

 77 77 10

 6,319 402,580 402,580 11

 15,323 970,618 970,618 12

 45 1,138 1,138 13

 560 28,747 28,747 14

FERC FORM NO. 1 (ED. 12-90) Page 327.17

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 3,298 149,019 149,019 1

 87 2

 18,457 543,719 543,719 3

 4 121 121 4

 14,122 505,597 505,597 5

 -1 -1 6

 162,305 8,944,609 8,944,609 7

 5,773 351,212 351,212 8

 -17,674,999 -17,674,999 9

 1,516,071 1,516,071 10

 -5,780,807 -184,282,163 -184,282,163 11

 -17,492,110 -17,492,110 12

 13

 14

FERC FORM NO. 1 (ED. 12-90) Page 327.18

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 1

 569,935 570,430 -910,873 -910,873 2

 1,512 3

 9,160 223 291,446 291,446 4

 50 5

 8,969 81,350 81,350 6

 -896,528 -896,528 7

 -3,786 -3,786 8

 2,243 2,243 -17,944 -17,944 9

 1,485,806 1,489,199 -170,000 -170,000 10

 242,938 242,939 11

 189,270 14,313 12

 9,292,882 9,292,882 -35,921,147 -35,921,147 13

 13,246 8,108 166,932 166,932 14

FERC FORM NO. 1 (ED. 12-90) Page 327.19

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 126,893 91,824 1,390,386 1,390,386 1

 -74,371 -74,371 2

 116,660 119,121 -84,002 -84,002 3

 38 6,164 6,164 4

 268,153 5

 1,239 583 25,430 25,430 6

 355 -4,976 382,311 382,311 7

 29,857 57,629 -1,286,349 -1,286,349 8

 13 -324 -324 9

 541 -13,538 -13,538 10

 17,731 17,832 -7,138 -7,138 11

 6,352 4,096 69,113 69,113 12

 389,768 219,081 13

 4,003 1,337 83,479 83,479 14

FERC FORM NO. 1 (ED. 12-90) Page 327.20

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 2,408 1,949 4,667 4,667 1

 -75 -75 2

 3,236 217,616 217,616 3

 75 75 4

 3,236 -217,616 -217,616 5

 121,108 95,145 743,856 743,856 6

 31,487 2,576 875,110 875,110 7

 140,017 138,959 8

 526 1,277 -23,772 -23,772 9

 8,745 10

 875,971 873,663 3,600,000 3,600,000 11

 71,480 71,273 -76,258 -76,258 12

 17,655 13

 9,024 -6,151 -6,151 14

FERC FORM NO. 1 (ED. 12-90) Page 327.21

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASED POWER(Account 555) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

COST/SETTLEMENT OF POWER

($) ($) ($)

(Including power exchanges)

POWER EXCHANGES

MegaWatt Hours

Received

MegaWatt Hours

Delivered

(l) (m)

of Settlement ($)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an 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.

9. Footnote entries as required and provide explanations following all required data.

 213,594 252,784 1

 300,994 297,971 -315,670 -315,670 2

 7,210 5,478 30,845 30,845 3

 16,851 12,193 133,132 133,132 4

 19,219 19,219 5

 8,745 48,050 48,050 6

 3,028 2,973 8,810 8,810 7

 -24 -64 230 230 8

 118,752 68,167 1,755,000 1,755,000 9

 45,631 4,272 1,509,447 1,509,447 10

 1,991 6,571 -160,936 -160,936 11

 265 -3,886 -256,850 -256,850 12

 21,802 23,332 -209,558 -209,558 13

 -27,973 14

FERC FORM NO. 1 (ED. 12-90) Page 327.22

 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
Schedule Page: 326 Line No.: 3 Column: l

Reserve Share.

Schedule Page: 326 Line No.: 6 Column: b

Settlement adjustment.

Schedule Page: 326 Line No.: 6 Column: l

Settlement adjustment.

Schedule Page: 326 Line No.: 7 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326 Line No.: 8 Column: b

Arizona Public Service Company - Contract Termination Date: October 31, 2020.

Schedule Page: 326 Line No.: 10 Column: l

Reserve Share.

Schedule Page: 326 Line No.: 12 Column: l

Financial Swap.

Schedule Page: 326.1 Line No.: 1 Column: b

Settlement adjustment.

Schedule Page: 326.1 Line No.: 1 Column: l

Financial Swap.

Schedule Page: 326.1 Line No.: 2 Column: b

Settlement adjustment.

Schedule Page: 326.1 Line No.: 2 Column: l

Settlement adjustment.

Schedule Page: 326.1 Line No.: 3 Column: l

Financial Swap.

Schedule Page: 326.1 Line No.: 4 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.1 Line No.: 5 Column: b

Settlement adjustment.

Schedule Page: 326.1 Line No.: 5 Column: l

Settlement adjustment.

Schedule Page: 326.1 Line No.: 8 Column: l

Non-generation agreement.

Schedule Page: 326.1 Line No.: 10 Column: b

Settlement adjustment.

Schedule Page: 326.1 Line No.: 10 Column: l

Operation and maintenance expense associated with the combustion turbine located in Rapid City, South Dakota.

Schedule Page: 326.1 Line No.: 11 Column: l

Operation and maintenance expense associated with the combustion turbine located in Rapid City, South Dakota.

Schedule Page: 326.1 Line No.: 12 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.2 Line No.: 1 Column: b

Blanding City Corporation - Contract Termination Date: March 31, 2012.

Schedule Page: 326.2 Line No.: 2 Column: b

Bonneville Power Administration - Contract Termination Date: August 31, 2011.

Schedule Page: 326.2 Line No.: 3 Column: b

Bonneville Power Administration - Contract Termination Date: 30 days written notice.

Schedule Page: 326.2 Line No.: 3 Column: l

Ancillary services.

Schedule Page: 326.2 Line No.: 4 Column: b

Secondary, economy and/or non-firm.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Schedule Page: 326.2 Line No.: 4 Column: l

Ancillary services.

Schedule Page: 326.2 Line No.: 5 Column: l

Reserve Share.

Schedule Page: 326.2 Line No.: 6 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “BRITISH COLUMBIA TRANSMISSION CORP.” ON PAGES 326 –

327: Complete name is British Columbia Transmission Corporation.

Schedule Page: 326.2 Line No.: 6 Column: l

Reserve Share.

Schedule Page: 326.2 Line No.: 9 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CALIFORNIA INDEPENDENT SYSTEM OPERATOR” ON PAGES

326 – 327: Complete name is California Independent System Operator Corporation.

Schedule Page: 326.2 Line No.: 9 Column: b

Settlement adjustment.

Schedule Page: 326.2 Line No.: 9 Column: l

Settlement adjustment.

Schedule Page: 326.2 Line No.: 12 Column: b

Settlement adjustment.

Schedule Page: 326.2 Line No.: 12 Column: l

Settlement adjustment.

Schedule Page: 326.2 Line No.: 13 Column: l

Financial Swap.

Schedule Page: 326.3 Line No.: 1 Column: l

Compensation for voluntary curtailment.

Schedule Page: 326.3 Line No.: 2 Column: b

Settlement adjustment.

Schedule Page: 326.3 Line No.: 2 Column: l

Settlement adjustment.

Schedule Page: 326.3 Line No.: 3 Column: l

Financial Swap.

Schedule Page: 326.3 Line No.: 9 Column: b

Settlement adjustment.

Schedule Page: 326.3 Line No.: 9 Column: l

Settlement adjustment.

Schedule Page: 326.3 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CONSTELLATION ENERGY COMMODITIES GROUP” ON

PAGES 326 – 327: Complete name is Constellation Energy Commodities Group, Inc.

Schedule Page: 326.3 Line No.: 13 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.3 Line No.: 14 Column: l

Financial Swap.

Schedule Page: 326.4 Line No.: 2 Column: b

Settlement adjustment.

Schedule Page: 326.4 Line No.: 2 Column: l

Settlement adjustment.

Schedule Page: 326.4 Line No.: 3 Column: l

Financial Swap.

Schedule Page: 326.4 Line No.: 4 Column: b

Settlement adjustment.

Schedule Page: 326.4 Line No.: 4 Column: l

Settlement adjustment.

Schedule Page: 326.4 Line No.: 7 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Deseret Power Electric Cooperative - Contract Termination Date: September 30, 2024.

Schedule Page: 326.4 Line No.: 7 Column: l

Operation and maintenance expense associated with a coal fired generating facility located in Vernal, Utah.

Schedule Page: 326.4 Line No.: 8 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.4 Line No.: 8 Column: l

Liquidated damages.

Schedule Page: 326.4 Line No.: 9 Column: b

Settlement adjustment.

Schedule Page: 326.4 Line No.: 9 Column: l

Financial Swap.

Schedule Page: 326.4 Line No.: 10 Column: l

Financial Swap.

Schedule Page: 326.5 Line No.: 1 Column: l

Financial Swap.

Schedule Page: 326.5 Line No.: 3 Column: b

Settlement adjustment.

Schedule Page: 326.5 Line No.: 3 Column: l

Line loss.

Schedule Page: 326.5 Line No.: 4 Column: l

Line loss.

Schedule Page: 326.5 Line No.: 12 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.6 Line No.: 2 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.6 Line No.: 5 Column: b

Settlement adjustment.

Schedule Page: 326.6 Line No.: 5 Column: l

Settlement adjustment.

Schedule Page: 326.6 Line No.: 6 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.6 Line No.: 9 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.6 Line No.: 13 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.6 Line No.: 14 Column: a

Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is jointly owned. PacifiCorp owns 50% of the

plant. See page 402.3 column (c) of this Form No. 1 for further information on the Hermiston Generating Plant.

Schedule Page: 326.6 Line No.: 14 Column: b

Settlement adjustment.

Schedule Page: 326.6 Line No.: 14 Column: l

Settlement adjustment.

Schedule Page: 326.7 Line No.: 1 Column: a

Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is jointly owned. PacifiCorp owns 50% of the

plant. See page 402.3 column (c) of this Form No. 1 for further information on the Hermiston Generating Plant.

Schedule Page: 326.7 Line No.: 1 Column: l

On peak incentive, supplemental dispatch efficiency expense, start-up charges and committee settlements.

Schedule Page: 326.7 Line No.: 2 Column: b

Settlement adjustment.

Schedule Page: 326.7 Line No.: 2 Column: l

Settlement adjustment.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
Schedule Page: 326.7 Line No.: 4 Column: b

Hurricane, City of - Contract Termination Date: August 31, 2012.

Schedule Page: 326.7 Line No.: 5 Column: b

Settlement adjustment.

Schedule Page: 326.7 Line No.: 5 Column: l

Financial Swap.

Schedule Page: 326.7 Line No.: 6 Column: l

Financial Swap.

Schedule Page: 326.7 Line No.: 7 Column: b

Settlement adjustment.

Schedule Page: 326.7 Line No.: 7 Column: l

Labor, equipment and administration fees associated with hydro project in Idaho Falls, Idaho.

Schedule Page: 326.7 Line No.: 8 Column: l

Labor, equipment and administration fees associated with hydro project in Idaho Falls, Idaho.

Schedule Page: 326.7 Line No.: 9 Column: l

Reserve Share.

Schedule Page: 326.7 Line No.: 11 Column: l

Financial Swap.

Schedule Page: 326.7 Line No.: 12 Column: b

Settlement adjustment.

Schedule Page: 326.7 Line No.: 12 Column: l

Settlement adjustment. Financial Swap.

Schedule Page: 326.7 Line No.: 13 Column: l

Financial Swap.

Schedule Page: 326.8 Line No.: 1 Column: l

Compensation for self-generation.

Schedule Page: 326.8 Line No.: 3 Column: l

Fixed annual payment.

Schedule Page: 326.8 Line No.: 4 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “LOS ANGELES DEPT. OF WATER & POWER" ON PAGES 326 –

327: Complete name is Los Angeles Department of Water and Power.

Schedule Page: 326.8 Line No.: 5 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.8 Line No.: 7 Column: b

Settlement adjustment.

Schedule Page: 326.8 Line No.: 7 Column: l

Settlement adjustment.

Schedule Page: 326.8 Line No.: 10 Column: l

Financial Swap.

Schedule Page: 326.8 Line No.: 12 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “METROPOLITAN WATER DISTRICT OF S. CAL." ON PAGES

326 – 327: Complete name is Metropolitan Water District of Southern California.

Schedule Page: 326.9 Line No.: 2 Column: l

Compensation for interruptible service and operating reserves.

Schedule Page: 326.9 Line No.: 3 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.9 Line No.: 4 Column: b

Settlement adjustment.

Schedule Page: 326.9 Line No.: 4 Column: l

Settlement adjustment.

Schedule Page: 326.9 Line No.: 6 Column: l

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.4
Financial Swap.

Schedule Page: 326.9 Line No.: 7 Column: b

Settlement adjustment.

Schedule Page: 326.9 Line No.: 7 Column: l

Settlement adjustment.

Schedule Page: 326.9 Line No.: 11 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.9 Line No.: 12 Column: l

Line loss.

Schedule Page: 326.9 Line No.: 14 Column: b

Settlement adjustment.

Schedule Page: 326.9 Line No.: 14 Column: l

Settlement adjustment.

Schedule Page: 326.10 Line No.: 2 Column: l

Reserve Share.

Schedule Page: 326.10 Line No.: 4 Column: l

Ancillary services.

Schedule Page: 326.10 Line No.: 6 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “ODELL CREEK HYDROELECTRIC INVESTORS" ON PAGES 326

– 327: Complete name is Odell Creek Hydroelectric Investors, Ltd.

Schedule Page: 326.10 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PACIFIC NORTHWEST GENERATING COOP." ON PAGES 326 –

327: Complete name is Pacific Northwest Generating Cooperative, Inc.

Schedule Page: 326.11 Line No.: 2 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.11 Line No.: 3 Column: l

Line loss.

Schedule Page: 326.11 Line No.: 4 Column: b

Settlement adjustment.

Schedule Page: 326.11 Line No.: 4 Column: l

Operation expense plus amortization of unrecovered costs of Cove Project.

Schedule Page: 326.11 Line No.: 5 Column: b

Portland General Electric Company - Contract Termination Date: Round Butte project no longer operating for power production

purposes.

Schedule Page: 326.11 Line No.: 5 Column: l

Operation expense plus amortization of unrecovered costs of Cove Project.

Schedule Page: 326.11 Line No.: 6 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.11 Line No.: 6 Column: l

Liability associated with paper pond at hydro facility located on the Lewis River in the state of Washington. 

Schedule Page: 326.11 Line No.: 7 Column: l

Reserve Share.

Schedule Page: 326.11 Line No.: 8 Column: b

Settlement adjustment.

Schedule Page: 326.11 Line No.: 8 Column: l

Settlement adjustment.

Schedule Page: 326.11 Line No.: 9 Column: l

Financial Swap.

Schedule Page: 326.11 Line No.: 10 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.11 Line No.: 11 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.5
Secondary, economy and/or non-firm.

Schedule Page: 326.11 Line No.: 11 Column: l

Line loss.

Schedule Page: 326.11 Line No.: 13 Column: l

Line loss.

Schedule Page: 326.11 Line No.: 14 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #1 OF CHELAN COUNTY" ON PAGES 326 – 327: Complete

name is Public Utility District No. 1 of Chelan County.

Schedule Page: 326.11 Line No.: 14 Column: l

Operating expense, bond interest, amortization and taxes.

Schedule Page: 326.12 Line No.: 1 Column: l

Reserve Share.

Schedule Page: 326.12 Line No.: 2 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #1 OF COWLITZ COUNTY” ON PAGES 326 – 327: Complete

name is Public Utility District No. 1 of Cowlitz County.

Schedule Page: 326.12 Line No.: 2 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.12 Line No.: 2 Column: l

Liability associated with paper pond at hydro facility located on the Lewis River in the state of Washington. 

Schedule Page: 326.12 Line No.: 3 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #1 OF DOUGLAS COUNTY" ON PAGES 326 – 327: 

Complete name is Public Utility District No. 1 of Douglas County.

Schedule Page: 326.12 Line No.: 3 Column: b

Settlement adjustment.

Schedule Page: 326.12 Line No.: 3 Column: l

Settlement adjustment.

Schedule Page: 326.12 Line No.: 4 Column: b

Settlement adjustment.

Schedule Page: 326.12 Line No.: 4 Column: l

Operating expense, bond interest, amortization and taxes.

Schedule Page: 326.12 Line No.: 5 Column: b

Public Utility District No. 1 of Douglas County - Contract Termination Date: August 31, 2018.

Schedule Page: 326.12 Line No.: 6 Column: l

Operating expense, bond interest, amortization and taxes.

Schedule Page: 326.12 Line No.: 7 Column: l

Reserve Share.

Schedule Page: 326.12 Line No.: 8 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #1 OF SNOHOMISH COUNTY" ON PAGES 326 – 327:

Complete name is Public Utility District No. 1 of Snohomish County.

Schedule Page: 326.12 Line No.: 9 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #2 OF GRANT COUNTY" ON PAGES 326 – 327: Complete

name is Public Utility District No. 2 of Grant County.

Schedule Page: 326.12 Line No.: 9 Column: b

Settlement adjustment.

Schedule Page: 326.12 Line No.: 9 Column: l

Operating expense, bond interest, amortization and taxes.

Schedule Page: 326.12 Line No.: 10 Column: b

Public Utility District No. 2 of Grant County - Contract Termination Date: 2 years written notice.

Schedule Page: 326.12 Line No.: 10 Column: l

Ancillary services.

Schedule Page: 326.12 Line No.: 11 Column: l

Operating expense, bond interest, amortization and taxes.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.6
Schedule Page: 326.12 Line No.: 12 Column: l

Reserve Share.

Schedule Page: 326.12 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUD #1 OF LEWIS COUNTY" ON PAGES 326 – 327: Complete

name is Public Utility District No. 1 of Lewis County.

Schedule Page: 326.12 Line No.: 13 Column: b

Settlement adjustment.

Schedule Page: 326.12 Line No.: 13 Column: l

Settlement adjustment.

Schedule Page: 326.12 Line No.: 14 Column: b

Public Utility District No. 1 of Lewis County - Contract Termination Date: 60 days written notice.

Schedule Page: 326.13 Line No.: 1 Column: l

Reserve Share.

Schedule Page: 326.13 Line No.: 3 Column: b

Settlement adjustment.

Schedule Page: 326.13 Line No.: 3 Column: l

Settlement adjustment.

Schedule Page: 326.13 Line No.: 6 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “ROCKY MOUNTAIN GENERATION COOP." ON PAGES 326 –

327: Complete name is Rocky Mountain Generation Cooperative, Inc.

Schedule Page: 326.13 Line No.: 8 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.13 Line No.: 11 Column: b

Settlement adjustment.

Schedule Page: 326.13 Line No.: 11 Column: l

Settlement adjustment.

Schedule Page: 326.13 Line No.: 12 Column: b

Sacramento Municipal Utility District - Contract Termination Date: December 31, 2014.

Schedule Page: 326.13 Line No.: 13 Column: l

Reserve Share.

Schedule Page: 326.13 Line No.: 14 Column: l

 Line loss.

Schedule Page: 326.14 Line No.: 1 Column: b

Settlement adjustment.

Schedule Page: 326.14 Line No.: 1 Column: l

Settlement adjustment.

Schedule Page: 326.14 Line No.: 5 Column: l

Reserve Share.

Schedule Page: 326.14 Line No.: 6 Column: b

Settlement adjustment.

Schedule Page: 326.14 Line No.: 6 Column: l

Settlement adjustment. Financial Swap.

Schedule Page: 326.14 Line No.: 7 Column: l

Financial Swap.

Schedule Page: 326.14 Line No.: 9 Column: b

Settlement adjustment.

Schedule Page: 326.14 Line No.: 9 Column: l

Settlement adjustment.

Schedule Page: 326.14 Line No.: 10 Column: l

Financial Swap.

Schedule Page: 326.14 Line No.: 12 Column: l

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.7
Reserve Share.

Schedule Page: 326.14 Line No.: 13 Column: l

 Line loss.

Schedule Page: 326.15 Line No.: 3 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.15 Line No.: 6 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.15 Line No.: 8 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.15 Line No.: 10 Column: b

Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.15 Line No.: 14 Column: b

Settlement adjustment.

Schedule Page: 326.15 Line No.: 14 Column: l

Settlement adjustment.

Schedule Page: 326.16 Line No.: 1 Column: l

Reserve Share.

Schedule Page: 326.16 Line No.: 6 Column: l

Compensation for voluntary curtailment.

Schedule Page: 326.16 Line No.: 7 Column: b

Settlement adjustment.

Schedule Page: 326.16 Line No.: 7 Column: l

Settlement adjustment.

Schedule Page: 326.16 Line No.: 10 Column: l

 Operating reserve reimbursement.

Schedule Page: 326.16 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “TRI-STATE GEN. & TRANS." ON PAGES 326 – 327: Complete

name is Tri-State Generation and Transmission Association, Inc. 

Schedule Page: 326.16 Line No.: 13 Column: b

Tri-State Generation and Transmission Association - Contract Termination Date: December 31, 2020.

Schedule Page: 326.16 Line No.: 14 Column: l

Line loss.

Schedule Page: 326.17 Line No.: 1 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.17 Line No.: 2 Column: l

Line loss.

Schedule Page: 326.17 Line No.: 3 Column: l

Reserve Share.

Schedule Page: 326.17 Line No.: 6 Column: b

US Magnesium LLC - Contract Termination Date: December 31, 2014.

Schedule Page: 326.17 Line No.: 6 Column: l

Ancillary services.

Schedule Page: 326.17 Line No.: 7 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “UTAH ASSOCIATED MUNICIPAL POWER" ON PAGES 326 –

327: Complete name is Utah Associated Municipal Power Systems.

Schedule Page: 326.17 Line No.: 7 Column: b

Secondary, economy and/or non-firm.

Schedule Page: 326.17 Line No.: 14 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “WASATCH INTEGRATED WASTE MANAGEMENT" ON PAGES

326 – 327: Complete name is Wasatch Integrated Waste Management District.

Schedule Page: 326.18 Line No.: 2 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.8
Settlement adjustment.

Schedule Page: 326.18 Line No.: 4 Column: l

Reserve Share.

Schedule Page: 326.18 Line No.: 5 Column: l

Line loss.

Schedule Page: 326.18 Line No.: 6 Column: b

Settlement adjustment.

Schedule Page: 326.18 Line No.: 6 Column: l

Settlement adjustment.

Schedule Page: 326.18 Line No.: 9 Column: l

Represents the difference between actual purchase expenses for the period as reflected on the individual line items within this

schedule, and the accruals charged to account 555 during this period and excess net power cost deferrals.

Schedule Page: 326.18 Line No.: 10 Column: l

Reserve for potential liabilities associated with curtailment on receipt of energy and settlement for unmetered megawatt hours.

Schedule Page: 326.18 Line No.: 11 Column: l

Recognition and reporting of gains and losses on bookouts under generally accepted accounting principles.

Schedule Page: 326.18 Line No.: 12 Column: l

Recognition and reporting of gains and losses on energy trading contracts under generally accepted accounting principles.

Schedule Page: 326.19 Line No.: 2 Column: l

Exchange energy expense.

Schedule Page: 326.19 Line No.: 4 Column: l

Imbalance energy.

Schedule Page: 326.19 Line No.: 6 Column: b

Settlement adjustment.

Schedule Page: 326.19 Line No.: 6 Column: l

Storage and exchange charges.

Schedule Page: 326.19 Line No.: 7 Column: b

Settlement adjustment.

Schedule Page: 326.19 Line No.: 7 Column: l

Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff, Original Volume No. 1.

Schedule Page: 326.19 Line No.: 8 Column: l

These megawatt hours represent book entry only. No actual energy transfer took place.

Schedule Page: 326.19 Line No.: 9 Column: l

These megawatt hours represent book entry only. No actual energy transfer took place.

Schedule Page: 326.19 Line No.: 10 Column: l

Exchange energy expense.

Schedule Page: 326.19 Line No.: 13 Column: l

Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff, Original Volume No. 1.

Schedule Page: 326.19 Line No.: 14 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 1 Column: l

Exchange energy expense.

Schedule Page: 326.20 Line No.: 2 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 3 Column: l

Exchange energy expense.

Schedule Page: 326.20 Line No.: 4 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 6 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 7 Column: b

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.9
Settlement adjustment.

Schedule Page: 326.20 Line No.: 7 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 8 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 9 Column: b

Settlement adjustment.

Schedule Page: 326.20 Line No.: 9 Column: l

Storage and exchange charges.

Schedule Page: 326.20 Line No.: 10 Column: l

Storage and exchange charges.

Schedule Page: 326.20 Line No.: 11 Column: l

Exchange energy expense.

Schedule Page: 326.20 Line No.: 12 Column: l

Imbalance energy.

Schedule Page: 326.20 Line No.: 14 Column: l

Imbalance energy.

Schedule Page: 326.21 Line No.: 1 Column: l

Imbalance energy.

Schedule Page: 326.21 Line No.: 2 Column: b

Settlement adjustment.

Schedule Page: 326.21 Line No.: 2 Column: l

Station service for third party wind project.

Schedule Page: 326.21 Line No.: 3 Column: l

Station service for third party wind project.

Schedule Page: 326.21 Line No.: 4 Column: b

Settlement adjustment.

Schedule Page: 326.21 Line No.: 4 Column: l

Reimbursement for providing station service to third party wind project.

Schedule Page: 326.21 Line No.: 5 Column: l

Reimbursement for providing station service to third party wind project.

Schedule Page: 326.21 Line No.: 6 Column: l

Imbalance energy.

Schedule Page: 326.21 Line No.: 7 Column: l

Imbalance energy.

Schedule Page: 326.21 Line No.: 9 Column: l

Imbalance energy.

Schedule Page: 326.21 Line No.: 11 Column: l

Storage and exchange charges.

Schedule Page: 326.21 Line No.: 12 Column: l

Exchange energy expense.

Schedule Page: 326.21 Line No.: 14 Column: l

Storage and exchange charges.

Schedule Page: 326.22 Line No.: 2 Column: l

Exchange energy expense.

Schedule Page: 326.22 Line No.: 3 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 4 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 5 Column: b

Settlement adjustment.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.10
Schedule Page: 326.22 Line No.: 5 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 6 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 7 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 8 Column: b

Settlement adjustment.

Schedule Page: 326.22 Line No.: 8 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 9 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 10 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 11 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 12 Column: b

Settlement adjustment.

Schedule Page: 326.22 Line No.: 12 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 13 Column: l

Imbalance energy.

Schedule Page: 326.22 Line No.: 14 Column: b

Not applicable: adjustment for inadavertent interchange.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.11
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Payment By

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

Statistical

cation

Classifi-

(Footnote Affiliation)

(Including transactions referred to as 'wheeling')

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

Energy Received From Energy Delivered To

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,

qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.

2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).

3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company 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.

 1 Arizona Public Service Company Arizona Public Service Company OS

 2 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO

 3 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD

 4 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO

 5 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD

 6 Basin Electric Power Cooperative Western Area Power Administration NF

 7 Barclay's Bank NF

 8 Black Hills/Colorado Electric Utility Company NF

 9 Black Hills/Colorado Electric Utility Company SFP

 10 Black Hills, Inc. Montana-Dakota Utilities FNO

 11 Black Hills, Inc. Montana-Dakota Utilities AD

 12 Black Hills, Inc. NF

 13 Black Hills, Inc. AD

 14 Black Hills, Inc. SFP

 15 Black Hills, Inc. Black Hills, Inc. LFP

 16 Black Hills, Inc. Black Hills, Inc. AD

 17 Bonneville Power Administration OS

 18 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS

 19 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD

 20 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP

 21 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS

 22 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD

 23 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO

 24 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD

 25 Bonneville Power Administration Bonneville Power Administration Benton REA FNO

 26 Bonneville Power Administration Bonneville Power Administration Benton REA AD

 27 Bonneville Power Administration Bonneville Power Administration FNO

 28 Bonneville Power Administration Bonneville Power Administration AD

 29 Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP

 30 Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration AD

 31 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS

 32 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD

 33 Bonneville Power Administration Bonneville Power Administration Yakama Power FNO

 34 Bonneville Power Administration Bonneville Power Administration Yakama Power AD

FERC FORM NO. 1 (ED. 12-90) Page 328

TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Payment By

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

Statistical

cation

Classifi-

(Footnote Affiliation)

(Including transactions referred to as 'wheeling')

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

Energy Received From Energy Delivered To

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,

qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.

2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).

3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company 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.

 1 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS

 2 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD

 3 Bonneville Power Administration SFP

 4 Bonneville Power Administration NF

 5 Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO

 6 Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD

 7 Cargill Power Markets, LLC NF

 8 Cargill Power Markets, LLC AD

 9 Cargill Power Markets, LLC SFP

 10 Citigroup NF

 11 Constellation Energy Commodities Group NF

 12 Constellation Energy Commodities Group AD

 13 Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS

 14 Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD

 15 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. OS

 16 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. AD

 17 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. OS

 18 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. AD

 19 Deseret Generation & Trans. Deseret Generation & Trans. SFP

 20 Eagle Energy Partners NF

 21 Endure Energy, LLC. AD

 22 Enel Cove Fort, LLC Enel Cove Fort, LLC LFP

 23 Eugene Water & Electric Board NF

 24 Eugene Water & Electric Board AD

 25 Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS

 26 Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD

 27 Foote Creek III, LLC Foote Creek III, LLC OS

 28 Foote Creek III, LLC Foote Creek III, LLC AD

 29 Gila River Power, L.P. NF

 30 Iberdrola Renewables Inc. NF

 31 Iberdrola Renewables Inc. AD

 32 Iberdrola Renewables Inc. Iberdrola Renewables Inc. Iberdrola Renewables Inc. OS

 33 Iberdrola Renewables Inc. Iberdrola Renewables Inc. Iberdrola Renewables Inc. AD

 34 Iberdrola Renewables Inc. Iberdrola Renewables Inc. OS

FERC FORM NO. 1 (ED. 12-90) Page 328.1

TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Payment By

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

Statistical

cation

Classifi-

(Footnote Affiliation)

(Including transactions referred to as 'wheeling')

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

Energy Received From Energy Delivered To

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,

qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.

2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).

3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company 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.

 1 Iberdrola Renewables Inc. Iberdrola Renewables Inc. AD

 2 Iberdrola Renewables Inc. Exxon Mobile Nevada Power Company LFP

 3 Iberdrola Renewables Inc. Exxon Mobile Nevada Power Company AD

 4 Idaho Power Company Idaho Power Company Idaho Power Company OS

 5 Idaho Power Company Nevada Power Company Idaho Power Company LFP

 6 Idaho Power Company NF

 7 Idaho Power Company SFP

 8 Idaho Power Company OS

 9 Idaho Power Company AD

 10 Idaho Power Company OS

 11 Idaho Power Company AD

 12 JP Morgan Ventures Energy Corp. NF

 13 JP Morgan Ventures Energy Corp. JP Morgan Ventures Energy Corp. OS

 14 JP Morgan Ventures Energy Corp. AD

 15 Los Angeles Dept of Water & Power NF

 16 Macquarie Energy, LLC NF

 17 Macquarie Energy, LLC AD

 18 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS

 19 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD

 20 Morgan Stanley Capital Group, Inc. NF

 21 Morgan Stanley Capital Group, Inc. AD

 22 Morgan Stanley Capital Group, Inc. SFP

 23 Municipal Energy Agency of Nebraska NF

 24 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP

 25 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD

 26 NextEra Energy Resources, LLC NF

 27 Pacific Gas & Electric Company OS

 28 Pacific Gas & Electric Company OS

 29 Pacific Gas & Electric Company NF

 30 Powerex Corporation Bonneville Power Administration CAISO LFP

 31 Powerex Corporation Bonneville Power Administration CAISO AD

 32 Powerex Corporation NF

 33 Powerex Corporation AD

 34 Powerex Corporation SFP

FERC FORM NO. 1 (ED. 12-90) Page 328.2

TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Payment By

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

Statistical

cation

Classifi-

(Footnote Affiliation)

(Including transactions referred to as 'wheeling')

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

Energy Received From Energy Delivered To

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,

qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.

2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).

3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company 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.

 1 PPL Energy Plus, LLC NF

 2 PPL Energy Plus, LLC AD

 3 PPL Energy Plus, LLC SFP

 4 Public Svc. Co. of CO NF

 5 Public Svc. Co. of CO AD

 6 Public Svc. Co. of CO SFP

 7 Rainbow Energy Marketing Corporation NF

 8 Rainbow Energy Marketing Corporation AD

 9 Rainbow Energy Marketing Corporation SFP

 10 Raser Power Systems, Inc. Raser Power Systems, Inc. Raser Power Systems, Inc. LFP

 11 Raser Power Systems, Inc. Raser Power Systems, Inc. Raser Power Systems, Inc. AD

 12 Salt River Project NF

 13 Seattle City & Light FPL Energy Vansycle, LLC Grant County PUD LFP

 14 Seattle City & Light FPL Energy Vansycle, LLC Grant County PUD AD

 15 Seattle City & Light NF

 16 Sempra Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO

 17 Sempra Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD

 18 Shell Energy North America NF

 19 Shell Energy North America AD

 20 Sierra Pacific Power Company OS

 21 Sierra Pacific Power Company NF

 22 Sierra Pacific Power Company AD

 23 Sierra Pacific Power Company AD

 24 Southern California Edison SFP

 25 Southern California Edison NF

 26 Southern California Edison OS

 27 State of South Dakota Western Area Power Administration Black Hills Power & Light Company LFP

 28 State of South Dakota Western Area Power Administration Black Hills Power & Light Company AD

 29 The Energy Authority NF

 30 The Energy Authority AD

 31 TransAlta Energy Marketing Corporation NF

 32 TransAlta Energy Marketing Corporation AD

 33 Tri-State Generation & Trans. Tri-State Generation & Trans. OS

 34 Tri-State Generation & Trans. Tri-State Generation & Trans. AD

FERC FORM NO. 1 (ED. 12-90) Page 328.3

TOTAL
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Payment By

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

Statistical

cation

Classifi-

(Footnote Affiliation)

(Including transactions referred to as 'wheeling')

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

(Footnote Affiliation)

(Company of Public Authority)

Energy Received From Energy Delivered To

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,

qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.

2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).

3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company 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.

 1 Tri-State Generation & Trans. NF

 2 Tri-State Generation & Trans. Tri-State Generation & Trans. FNO

 3 United States Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO

 4 United States Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD

 5 United States Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS

 6 United States Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv. OS

 7 United States Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv. AD

 8 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power OS

 9 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power AD

 10 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power SFP

 11 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS

 12 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD

 13 Warm Springs Power Enterprises Warm Springs Enterprises Portland General Electric Co OS

 14 Warm Springs Power Enterprises Warm Springs Enterprises Portland General Electric Co AD

 15 Western Area Power Administration Western Area Power Administration OS

 16 Western Area Power Administration Western Area Power Administration AD

 17 Western Area Power Administration Western Area Power Administration OS

 18 Western Area Power Administration Western Area Power Administration AD

 19 Western Area Power Administration Western Area Power Administration NF

 20 Western Area Power Administration Western Area Power Administration AD

 21 Western Area Power Administration Western Area Power Administration OS

 22 Western Area Power Administration Western Area Power Administration AD

 23 Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO

 24 Western Area Power Administration Western Area Power Administration Western Area Power Administration AD

 25 Accrual True-up

 26

 27

 28

 29

 30

 31

 32

 33

 34

FERC FORM NO. 1 (ED. 12-90) Page 328.4

TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(Including transactions reffered to as 'wheeling')

FERC Rate

Schedule of

Tariff Number

(e)

Point of Receipt

(Subsatation or Other

Designation)

(f)

Point of Delivery

(Substation or Other

(g)

Billing

Demand

(MW)

(h)

TRANSFER OF ENERGY

MegaWatt Hours

Received

(i)

Delivered

(j)

MegaWatt Hours Designation)

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.

R.S. 436 Borah/Brady Sub 1

7V11-3,4 Yellowtail Sub Sheridan Substation 2 4,331 4,331 2

7V11-3,4 Yellowtail Sub Sheridan Substation 2 1,633 1,633 3

7V11 Yellowtail Sub Sheridan Substation 11 7,416 7,416 4

7V11 Yellowtail Sub Sheridan Substation 11 7,602 7,602 5

7V11-8 Various Various 25,789 25,789 6

7V11-8 Various Various 7

7V11-8 Various Various 88 88 8

7V11-7 Various Various 90 90 9

7V11 Various Sheridan Substation 43 32,344 32,344 10

7V11 Various Sheridan Substation 43 6,646 6,646 11

7V11-8 Various Various 12,374 12,374 12

7V11-8 Various Various 816 816 13

7V11-7 Various Various 16,438 16,438 14

7V11-7 Various Wyodak Substation 50 157,346 157,346 15

7V11-7 Various Wyodak Substation 50 3,705 3,705 16

R.S. 369 Midpoint Substation Summer Lake Sub 17

R.S. 237 Various Various 189 1,102,930 1,102,930 18

R.S. 237 Various Various 189 115,754 115,754 19

7V11-3,4 Alvey Substation 56 51,289 51,289 20

R.S. 324 Various 167,011 167,011 21

R.S. 324 Various 12,695 12,695 22

7V11-3,4 Bonneville Power Adm Gazley Substation 3 23,150 23,150 23

7V11-3 Bonneville Power Adm Gazley Substation 3 2,372 2,372 24

7V11-3,4 Bonneville Power Adm Tieton Substation 2 4,666 4,666 25

7V11-3,4 Bonneville Power Adm Tieton Substation 2 937 937 26

7V11-3,4 McNary Substation Hinkle Substation 1 848 848 27

7V11-3,4 McNary Substation Hinkle Substation 1 153 153 28

7V11-7 USBR Green Springs Bonneville Power Adm 18 52,471 52,471 29

7V11-7 USBR Green Springs Bonneville Power Adm 18 5,569 5,569 30

R.S. 368 Malin Substation Malin Substation 618,730 618,730 31

R.S. 368 Malin Substation Malin Substation 63,710 63,710 32

7V11-3,4 Bonneville Power Adm White Swan/Toppenish 7 32,925 32,925 33

7V11-3,4 Bonneville Power Adm White Swan/Toppenish 7 3,910 3,910 34

FERC FORM NO. 1 (ED. 12-90) Page 329

 3,483 13,164,045 13,164,045
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(Including transactions reffered to as 'wheeling')

FERC Rate

Schedule of

Tariff Number

(e)

Point of Receipt

(Subsatation or Other

Designation)

(f)

Point of Delivery

(Substation or Other

(g)

Billing

Demand

(MW)

(h)

TRANSFER OF ENERGY

MegaWatt Hours

Received

(i)

Delivered

(j)

MegaWatt Hours Designation)

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.

R.S. 299 Various Various 160 1,416,059 1,416,059 1

R.S. 299 Various Various 160 208,173 208,173 2

7V11-7 Various Various 24,791 24,791 3

7V11-8 Various Various 4

7V11-3,4 Cardwell-Merwin 24 104,239 104,239 5

7V11-3,4 Cardwell-Merwin 24 16,619 16,619 6

7V11-8 Various Various 149,117 149,117 7

7V11-8 Various Various 7,432 7,432 8

7V11-7 Various Various 11,430 11,430 9

7V11-8 Various Various 10

7V11-8, 9, 11 Various Various 9,670 9,670 11

7V11-8 Various Various 4,330 4,330 12

R.S. 234 Swift Unit No. 2 Woodland Substation 13

R.S. 234 Swift Unit No. 2 Woodland Substation 14

R.S. 280 Various Various 105 438,585 438,585 15

R.S. 280 Various Various 105 204,213 204,213 16

R.S. 590 Various Various 17

R.S. 590 Various Various 18

7V11-7 Various Various 864 864 19

7V11-8 Various Various 20

7V11-8 Various Various 21

7V11-7 Enel Cove Fort Mona Substation 22

7V11-8 Various Various 2,988 2,988 23

7V11-8 Various Various 1,010 1,010 24

R.S. 322 Targhee Substation Goshen Substation 4,346 4,346 25

R.S. 322 Targhee Substation Goshen Substation 26

S.A. 130 Foote Creek Sub Various 27

S.A. 130 Foote Creek Sub Various 28

7V11-8 Various Various 682 682 29

7V11-8 Various Various 33,286 33,286 30

7V11-8 Various Various 3,010 3,010 31

7V11-5,6,9,11 Wallula Substation Wallula Substation 32

7V11-5,6,9 Wallula Substation Wallula Substation 33

7V11-5,6,9,11 34

FERC FORM NO. 1 (ED. 12-90) Page 329.1

 3,483 13,164,045 13,164,045
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(Including transactions reffered to as 'wheeling')

FERC Rate

Schedule of

Tariff Number

(e)

Point of Receipt

(Subsatation or Other

Designation)

(f)

Point of Delivery

(Substation or Other

(g)

Billing

Demand

(MW)

(h)

TRANSFER OF ENERGY

MegaWatt Hours

Received

(i)

Delivered

(j)

MegaWatt Hours Designation)

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.

7V11-5,6,9,11 1

7V11-7 Trona Substation Red Butte/Mona Sub 30 56,556 56,556 2

7V11-7 Trona Substation Red Butte/Mona Sub 30 7,829 7,829 3

R.S. 427 Goshen Substation Goshen Substation 4

7V11-7 Red Butte Substation Borah/Brady Sub 75 61,018 61,018 5

7V11-8 Various Various 27,680 27,680 6

7V11-7 Various Various 66,989 66,989 7

R.S. 257 Antelope Substation Antelope Substation 15,678 15,678 8

R.S. 257 Antelope Substation Antelope Substation 9

R.S. 203 Jim Bridger Sub Bridger Pump Station 10

R.S. 203 Jim Bridger Sub Bridger Pump Station 11

7V11-8 Various Various 36,957 36,957 12

7V11-5,6,9,11 Various Various 13

7V11-8 Various Various 14

7V11-8 Various Various 37,787 37,787 15

7V11-8 Various Various 1,290 1,290 16

7V11-8 Various Various 11 11 17

R.S. 302 Duchesne Duchesne 3 17,434 17,434 18

R.S. 302 Duchesne Duchesne 3 1,541 1,541 19

7V11-8 Various Various 159,217 159,217 20

7V11-8 Various Various 12,873 12,873 21

7V11-7 Various Various 2,647 2,647 22

7V11-8 Various Various 1,935 1,935 23

7V11-5,6,9,11 Wallula Substation Wala-MID-C Path 80 255,567 255,567 24

7V11-5,6,9,11 Wallula Substation Wala-MID-C Path 80 13,863 13,863 25

7V11-8 Various Various 26

R.S. 607 27

R.S. 298 Sigurd-Glen Canyon Pinto-Four Corners 28

7V11-8 Various Various 9 9 29

7V11-7 Bonneville Power Adm Weed Jct. Substation 80 290,447 290,447 30

7V11-7 Bonneville Power Adm Weed Jct. Substation 80 18,922 18,922 31

7V11-5,6,8 Various Various 365,059 365,059 32

7V11-5,6,8 Various Various 9,217 9,217 33

7V11-7 Various Various 948 948 34

FERC FORM NO. 1 (ED. 12-90) Page 329.2

 3,483 13,164,045 13,164,045
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(Including transactions reffered to as 'wheeling')

FERC Rate

Schedule of

Tariff Number

(e)

Point of Receipt

(Subsatation or Other

Designation)

(f)

Point of Delivery

(Substation or Other

(g)

Billing

Demand

(MW)

(h)

TRANSFER OF ENERGY

MegaWatt Hours

Received

(i)

Delivered

(j)

MegaWatt Hours Designation)

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.

7V11-8 Various Various 9,586 9,586 1

7V11-8 Various Various 1,066 1,066 2

7V11-7 Various Various 3,688 3,688 3

7V11-8 Various Various 8,685 8,685 4

7V11-8 Various Various 32 32 5

7V11-7 Various Various 17,628 17,628 6

7V11-8 Various Various 11,260 11,260 7

7V11-8 Various Various 419 419 8

7V11-7 Various Various 17,866 17,866 9

7V11-5,6,7,9 South Milford Sub Mona Substation 11 45,680 45,680 10

7V11-5,6,7,9 South Milford Sub Mona Substation 11 3,892 3,892 11

7V11-8 Various Various 15,803 15,803 12

7V11-5,6,7,9 Wallula Substation Wala-MID-C Path 25 46,496 46,496 13

7V11-5,6,7,9 Wallula Substation Wala-MID-C Path 25 1,883 1,883 14

7V11-8 Various Various 17 17 15

7V11-3,4 Bonneville Power Adm Various 15 116,828 116,828 16

7V11-3,4 Bonneville Power Adm Various 15 6,627 6,627 17

7V11-8 Various Various 530 530 18

7V11-8 Various Various 448 448 19

R.S. 674 Sigurd Sub 20

7V11-8 Various Various 1,891 1,891 21

7V11-8 Various Various 947 947 22

7V11-7 Various Various 1,000 1,000 23

7V11-5,6,7 Various Various 5,845 5,845 24

7V11-8,9,11 Various Various 16,199 16,199 25

R.S. 298 Sigurd-Glen Canyon Pinto-Four Corners 26

7V11-7 Yellowtail Sub Wyodak Substation 4 16,864 16,864 27

7V11-7 Yellowtail Sub Wyodak Substation 4 1,505 1,505 28

7V11-8 Various Various 25 25 29

7V11-8 Various Various 11 11 30

7V11-8 Various Various 5,406 5,406 31

7V11-8 Various Various 1,749 1,749 32

R.S. 123 Various Various 31 144,112 144,112 33

R.S. 123 Various Various 31 17,166 17,166 34

FERC FORM NO. 1 (ED. 12-90) Page 329.3

 3,483 13,164,045 13,164,045
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(Including transactions reffered to as 'wheeling')

FERC Rate

Schedule of

Tariff Number

(e)

Point of Receipt

(Subsatation or Other

Designation)

(f)

Point of Delivery

(Substation or Other

(g)

Billing

Demand

(MW)

(h)

TRANSFER OF ENERGY

MegaWatt Hours

Received

(i)

Delivered

(j)

MegaWatt Hours Designation)

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.

7V11-8 Various Various 436 436 1

7V11-3,4 DJ Substation Thermopolis Sub 18 17,613 17,613 2

7V11-3 Walla Walla Sub Burbank Pumps 1 2,195 2,195 3

7V11-3 Walla Walla Sub Burbank Pumps 1 4

R.S. 67 Redmond Substation Crooked River Pumps 4 7,347 7,347 5

R.S. 286 Various Various 24,196 24,196 6

R.S. 286 Various Various 1,415 1,415 7

R.S. 297 Various Various 338 2,898,693 2,898,693 8

R.S. 297 Various Various 338 292,993 292,993 9

7V11-8 Various Various 3,174 3,174 10

R.S. 637 Various Various 101 557,192 557,192 11

R.S. 637 Various Various 101 52,250 52,250 12

R.S. 591 Pelton Reregulating Round Butte Sub 80,634 80,634 13

R.S. 591 Pelton Reregulating Round Butte Sub 7,355 7,355 14

R.S. 262 Various Various 330 1,479,333 1,479,333 15

R.S. 262 Various Various 330 156,206 156,206 16

R.S. 263 Various Various 83,483 83,483 17

R.S. 263 Various Various 8,520 8,520 18

7V11-8 Various Various 129,311 129,311 19

7V11-8 Various Various 13,208 13,208 20

R.S. 664 Dave Johnston Sub Various 166,992 166,992 21

R.S. 664 Dave Johnston Sub Various 11,912 11,912 22

7V11 Wyoming Distribution Wyoming Distribution 1 10,374 10,374 23

7V11 Wyoming Distribution Wyoming Distribution 1 3 3 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

FERC FORM NO. 1 (ED. 12-90) Page 329.4

 3,483 13,164,045 13,164,045
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other Charges)

($)

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.

 1

 9,538 23,488 33,026 2

 3,945 3,945 3

 13,707 13,707 4

 13,707 13,707 5

 118,279 118,279 6

 152 152 7

 514 514 8

 584 584 9

 625,143 625,143 10

 55,690 55,690 11

 74,511 74,511 12

 4,701 4,701 13

 65,957 65,957 14

 1,113,750 1,113,750 15

 101,250 101,250 16

 17

 4,164,320 67,947 4,232,267 18

 384,761 384,761 19

 340,200 340,200 20

 208,184 208,184 21

 26,023 26,023 22

 45,398 141,776 187,174 23

 16,230 16,230 24

 19,043 747 19,790 25

 2,513 2,513 26

 9,566 142 9,708 27

 1,331 1,331 28

 400,950 400,950 29

 36,450 36,450 30

 246,946 246,946 31

 22,450 22,450 32

 85,621 29,840 115,461 33

 25,535 25,535 34

FERC FORM NO. 1 (ED. 12-90) Page 330

 27,323,230 8,990,099 31,498,786 67,812,115
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other Charges)

($)

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.

 887,859 1,024,573 1,912,432 1

 176,622 176,622 2

 1,401 1,401 3

 6 6 4

 291,796 22,633 314,429 5

 30,970 30,970 6

 1,300,770 1,300,770 7

 43,014 43,014 8

 65,225 65,225 9

 6 6 10

 53,924 37,138 91,062 11

 14,553 17,465 32,018 12

 75,239 75,239 13

 36,813 36,813 14

 1,561,042 27,248 1,588,290 15

 608,352 180,667 789,019 16

 1,257,296 1,257,296 17

 427,560 427,560 18

 3,348 3,348 19

 3,733 3,733 20

 1,168 1,168 21

 50,625 50,625 22

 17,690 17,690 23

 5,898 5,898 24

 138,699 138,699 25

 12,609 12,609 26

 33,168 33,168 27

 3,015 3,015 28

 3,291 3,291 29

 469,369 469,369 30

 74,297 74,297 31

 27,553 27,553 32

 2,939 2,939 33

 252,362 252,362 34

FERC FORM NO. 1 (ED. 12-90) Page 330.1

 27,323,230 8,990,099 31,498,786 67,812,115
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other Charges)

($)

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.

 59,727 59,727 1

 486,000 182,250 668,250 2

 60,750 60,750 3

 4

 756,740 756,740 5

 159,197 159,197 6

 708,750 708,750 7

 67,672 67,672 8

 6,152 6,152 9

 14,927 14,927 10

 1,357 1,357 11

 463,390 463,390 12

 5,965 5,965 13

 6 6 14

 213,028 213,028 15

 9,297 9,297 16

 64 64 17

 18,123 18,123 18

 1,677 1,677 19

 1,007,429 1,007,429 20

 79,431 79,431 21

 11,675 11,675 22

 12,474 12,474 23

 1,546,995 961,687 2,508,682 24

 219,921 219,921 25

 254,642 254,642 26

 20,000,000 20,000,000 27

 310,869 310,869 28

 374 374 29

 1,782,000 1,782,000 30

 145,161 145,161 31

 2,494,533 19,603 2,514,136 32

 58,574 58,574 33

 8,325 8,325 34

FERC FORM NO. 1 (ED. 12-90) Page 330.2

 27,323,230 8,990,099 31,498,786 67,812,115
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other Charges)

($)

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.

 57,841 57,841 1

 7,131 7,131 2

 19,180 19,180 3

 53,591 53,591 4

 23,325 23,325 5

 102,884 102,884 6

 74,529 74,529 7

 2,681 2,681 8

 92,879 92,879 9

 245,025 33,638 278,663 10

 25,221 25,221 11

 113,303 113,303 12

 718,875 43,591 762,466 13

 50,625 50,625 14

 1,460 1,460 15

 177,344 73,927 251,271 16

 9,496 9,496 17

 4,491 4,491 18

 2,938 2,938 19

 68,919 68,919 20

 11,717 11,717 21

 4,650 4,650 22

 5,530 5,530 23

 30,987 5,350 36,337 24

 98,781 801,708 900,489 25

 310,869 310,869 26

 89,100 89,100 27

 8,100 8,100 28

 146 146 29

 339 339 30

 43,567 43,567 31

 11,756 11,756 32

 116,313 116,313 33

 9,437 9,437 34

FERC FORM NO. 1 (ED. 12-90) Page 330.3

 27,323,230 8,990,099 31,498,786 67,812,115
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other Charges)

($)

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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.

 2,617 2,617 1

 58,905 12,057 70,962 2

 4,106 9,403 13,509 3

 -23,159 -23,159 4

 12,433 12,433 5

 24,196 24,196 6

 1,415 1,415 7

 7,085,533 657,883 7,743,416 8

 660,917 660,917 9

 18,414 18,414 10

 1,991,594 98,395 2,089,989 11

 181,181 181,181 12

 109,725 109,725 13

 9,975 9,975 14

 2,057,249 550,000 2,607,249 15

 226,753 226,753 16

 43,299 43,299 17

 3,555 3,555 18

 527,899 527,899 19

 141,871 141,871 20

 17,136 17,136 21

 3,796 3,796 22

 18,733 38,212 56,945 23

 5,310 5,310 24

 -160,122 -160,122 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

FERC FORM NO. 1 (ED. 12-90) Page 330.4

 27,323,230 8,990,099 31,498,786 67,812,115
Schedule Page: 328 Line No.: 1 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 1 Column: d

Legacy Contract executed between PacifiCorp and Arizona Public Service Company concerning the exchange of transmission services

over agreed-upon facilities (Restated Transmission Agreement Between PacifiCorp and Arizona Public Service Company ("Restated

TSA"), Rate Schedule 436). The contract terminates October 31, 2020. See also FERC Account 565 - Transmission of Electricity by

Others, page 332 of this Form No. 1.

Schedule Page: 328 Line No.: 1 Column: f

Glen Canyon/Four Corners Substation.

Schedule Page: 328 Line No.: 2 Column: d

Network Transmission Service under the Open Access Transmission Tariff (1st Revised Service Agreement 505) terminating no

earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 2 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response. 

Schedule Page: 328 Line No.: 3 Column: d

Network Transmission Service under the Open Access Transmission Tariff (1st Revised Service Agreement 505) terminating no

earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 3 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response. Penalty revenues covering

imbalance charges per Schedules 4 and 9. December 2009 Service.

Schedule Page: 328 Line No.: 4 Column: d

Network Transmission Service under the Open Access Transmission Tariff (S.A. 505). Load service for this delivery point terminated

February 28, 2010.

Schedule Page: 328 Line No.: 5 Column: d

Network Transmission Service under the Open Access Transmission Tariff (S.A. 505). Load service for this delivery point terminated

February 28, 2010.

Schedule Page: 328 Line No.: 5 Column: m

December 2009 Service.

Schedule Page: 328 Line No.: 6 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 6 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 7 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 7 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 7 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 8 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “BLACK HILLS/COLORADO ELECTRIC UTILITY COMPANY”

ON PAGES 328 – 330: 

Complete name is Black Hills/Colorado Electric Utility Company, LP.

Schedule Page: 328 Line No.: 8 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 8 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 8 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 9 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 9 Column: c

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 9 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 10 Column: b

PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and commodity trading activities.

Schedule Page: 328 Line No.: 10 Column: d

Network Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 347) terminating on

December 31, 2017.

Schedule Page: 328 Line No.: 11 Column: b

PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and commodity trading activities.

Schedule Page: 328 Line No.: 11 Column: d

Network Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 347) terminating on

December 31, 2017.

Schedule Page: 328 Line No.: 11 Column: m

December 2009 Service.

Schedule Page: 328 Line No.: 12 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 12 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 12 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 13 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 13 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 13 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 13 Column: m

December 2009 Service.

Schedule Page: 328 Line No.: 14 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 14 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 14 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328 Line No.: 15 Column: b

PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and commodity trading activities.

Schedule Page: 328 Line No.: 15 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st revised Service Agreement 67) terminating on

December 31, 2033.

Schedule Page: 328 Line No.: 16 Column: b

PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and commodity trading activities.

Schedule Page: 328 Line No.: 16 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st revised Service Agreement 67) terminating on

December 31, 2033.

Schedule Page: 328 Line No.: 16 Column: m

December 2009 Service.

Schedule Page: 328 Line No.: 17 Column: b

Capacity exchanged and operated by each transmission provider with no receipt or delivery of energy.

Schedule Page: 328 Line No.: 17 Column: c

Capacity exchanged and operated by each transmission provider with no receipt or delivery of energy.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Schedule Page: 328 Line No.: 17 Column: d

Legacy Contract executed between PacifiCorp and Bonneville Power Administration concerning the exchange of transmission services

over agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369). This agreement runs concurrently

with the AC Intertie Agreement, (Rate Schedule 368), which terminates when the facilities subject to that agreement are taken out of

service. See also FERC Account 565 - Transmission of Electricity by Others, page 332.

Schedule Page: 328 Line No.: 18 Column: d

Evergreen Legacy Contract (Rate Schedule 237) executed between PacifiCorp and Bonneville Power Administration for transmission

service over agreed-upon facilities and/or subject to a sole-use or facilities charge. 

Schedule Page: 328 Line No.: 18 Column: m

Sole use/direct assigned facilities charge.

Schedule Page: 328 Line No.: 19 Column: d

Evergreen Legacy Contract (Rate Schedule 237) executed between PacifiCorp and Bonneville Power Administration for transmission

service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328 Line No.: 19 Column: m

Sole use/direct assigned facilities charge. December 2009 service.

Schedule Page: 328 Line No.: 20 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service Agreement 656) terminating on August 31,

2030.

Schedule Page: 328 Line No.: 20 Column: f

Lost Creek Hydro Plant.

Schedule Page: 328 Line No.: 21 Column: d

Legacy Contract (Rate Schedule 324) executed between PacifiCorp and Bonneville Power Administration for transmission service

over agreed-upon facilities and/or subject to a sole-use or facilities charge. Contract terminated September 4, 2010.

Schedule Page: 328 Line No.: 21 Column: f

Lost Creek Hydro Plant.

Schedule Page: 328 Line No.: 21 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and/or proportional use as defined in the contract.

Schedule Page: 328 Line No.: 22 Column: d

Legacy Contract (Rate Schedule 324) executed between PacifiCorp and Bonneville Power Administration for transmission service

over agreed-upon facilities and/or subject to a sole-use or facilities charge. Contract terminated September 4, 2010.

Schedule Page: 328 Line No.: 22 Column: f

Lost Creek Hydro Plant.

Schedule Page: 328 Line No.: 22 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and/or proportional use as defined in the contract. December 2009 Service. 

Schedule Page: 328 Line No.: 23 Column: d

Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (4th revised Service

Agreement 229) terminating on September 30, 2028.

Schedule Page: 328 Line No.: 23 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response.

Schedule Page: 328 Line No.: 24 Column: d

Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (4th revised Service

Agreement 229) terminating on September 30, 2028.

Schedule Page: 328 Line No.: 24 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response. December 2009 Service.

Schedule Page: 328 Line No.: 25 Column: c

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “BENTON REA” ON PAGES 328 – 330: 

Complete name is Benton Rural Electric Association.

Schedule Page: 328 Line No.: 25 Column: d

Network Transmission and Distribution Delivery Service under the Open Access Transmission Tariff (Service Agreement 539)

terminating on November 30, 2013.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
Schedule Page: 328 Line No.: 25 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328 Line No.: 26 Column: d

Network Transmission and Distribution Delivery Service under the Open Access Transmission Tariff (Service Agreement 539)

terminating on November 30, 2013.

Schedule Page: 328 Line No.: 26 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009 Service. 

Schedule Page: 328 Line No.: 27 Column: c

Umatilla Electric Cooperative Association and Columbia Basin Electric Cooperative, Inc.

Schedule Page: 328 Line No.: 27 Column: d

Network Transmission Service under the Open Access Transmission Tariff (Service Agreement 538) terminating on December 31,

2013.

Schedule Page: 328 Line No.: 27 Column: m

Regulation & Frequency Response. 

Schedule Page: 328 Line No.: 28 Column: c

Umatilla Electric Cooperative Association and Columbia Basin Electric Cooperative, Inc.

Schedule Page: 328 Line No.: 28 Column: d

Network Transmission Service under the Open Access Transmission Tariff (Service Agreement 538) terminating on December 31,

2013.

Schedule Page: 328 Line No.: 28 Column: m

December 2009 Service.

Schedule Page: 328 Line No.: 29 Column: b

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “U.S. BUREAU OF RECLAMATION” ON PAGES 328 – 330: 

Complete name is United States Bureau of Reclamation.

Schedule Page: 328 Line No.: 29 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 179) terminating on

September 30, 2025.

Schedule Page: 328 Line No.: 30 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 179) terminating on

September 30, 2025.

Schedule Page: 328 Line No.: 30 Column: m

December 2009 Service.

Schedule Page: 328 Line No.: 31 Column: d

Legacy Contract (Rate Schedule 368) executed between PacifiCorp and Bonneville Power Administration for transmission service

over agreed-upon facilities and/or subject to a sole-use or facilities charge. Subject to termination upon mutual agreement.

Schedule Page: 328 Line No.: 31 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and or proportional use as defined in the contract.

Schedule Page: 328 Line No.: 32 Column: d

Legacy Contract (Rate Schedule 368) executed between PacifiCorp and Bonneville Power Administration for transmission service

over agreed-upon facilities and/or subject to a sole-use or facilities charge. Subject to termination upon mutual agreement.

Schedule Page: 328 Line No.: 32 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and or proportional use as defined in the contract. December 2009 Service.

Schedule Page: 328 Line No.: 33 Column: d

Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (Service Agreement 328)

terminating on September 30, 2011.

Schedule Page: 328 Line No.: 33 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response. Penalty revenues covering

imbalance charges per Schedules 4 and 9.

Schedule Page: 328 Line No.: 34 Column: d

Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (Service Agreement 328)

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.4
terminating on September 30, 2011.

Schedule Page: 328 Line No.: 34 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response. Penalty revenues covering

imbalance charges per Schedules 4 and 9. December 2009 Service.

Schedule Page: 328.1 Line No.: 1 Column: d

Evergreen Legacy Contract (Rate Schedule 299) executed between PacifiCorp and Bonneville Power Administration for transmission

service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.1 Line No.: 1 Column: m

Sole use/direct assigned facilities charge. Charges for load following and operating reserves.

Schedule Page: 328.1 Line No.: 2 Column: d

Evergreen Legacy Contract (Rate Schedule 299) executed between PacifiCorp and Bonneville Power Administration for transmission

service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.1 Line No.: 2 Column: m

Sole use/direct assigned facilities charge. Charges for load following and operating reserves. December 2009 Service.

Schedule Page: 328.1 Line No.: 3 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 3 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 3 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 4 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 4 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 4 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 5 Column: d

Network Transmission Service under the Open Access Transmission Tariff (Service Agreement 370) terminating on December 7, 2012

or with 6 months written notice.

Schedule Page: 328.1 Line No.: 5 Column: g

Chelatchie/View 115 KV.

Schedule Page: 328.1 Line No.: 5 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328.1 Line No.: 6 Column: d

Network Transmission Service under the Open Access Transmission Tariff (Service Agreement 370) terminating on December 7, 2012

or with 6 months written notice.

Schedule Page: 328.1 Line No.: 6 Column: g

Chelatchie/View 115 KV.

Schedule Page: 328.1 Line No.: 6 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009 Service.

Schedule Page: 328.1 Line No.: 7 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 7 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 7 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 8 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 8 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 8 Column: d

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.5
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 8 Column: m

December 2009 Service.

Schedule Page: 328.1 Line No.: 9 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 9 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 9 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 10 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 10 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 10 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 11 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CONSTELLATION ENERGY COMMODITIES GROUP” ON

PAGES 328 – 330: 

Complete name is Constellation Energy Commodities Group, Inc.

Schedule Page: 328.1 Line No.: 11 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 11 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 11 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 11 Column: m

Unauthorized Use of Transmission Service. Penalty revenues covering imbalance charges per Schedules 4 and 9. 

Schedule Page: 328.1 Line No.: 12 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 12 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 12 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 12 Column: m

Unauthorized Use of Transmission Service. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009

Service.

Schedule Page: 328.1 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “COWLITZ COUNTY PUD” ON PAGES 328 – 330: 

Complete name is Public Utility District No. 1 of Cowlitz County.

Schedule Page: 328.1 Line No.: 13 Column: d

Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift Hydroelectric Plant No. 2, and for

transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be terminated

subsequent to the termination of the Power Contract as defined in the agreement by the customer providing at least six months written

notice and specifying the date on which the customer will assume responsibility of operations and maintenance of Swift Hydroelectric

Plant No. 2. 

Schedule Page: 328.1 Line No.: 13 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and/or proportional use as defined in the contract.

Schedule Page: 328.1 Line No.: 14 Column: d

Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift Hydroelectric Plant No. 2, and for

transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be terminated

subsequent to the termination of the Power Contract as defined in the agreement by the customer providing at least six months written

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.6
notice and specifying the date on which the customer will assume responsibility of operations and maintenance of Swift Hydroelectric

Plant No. 2.

Schedule Page: 328.1 Line No.: 14 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and/or proportional use as defined in the contract. December 2009 Service.

Schedule Page: 328.1 Line No.: 15 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “DESERET GENERATION & TRANS.” ON PAGES 328 – 330: 

Complete name is Deseret Generation and Transmission Cooperative.

Schedule Page: 328.1 Line No.: 15 Column: d

Legacy Contract executed between PacifiCorp and Deseret Generation and Transmission Cooperative for transmission service over

agreed-upon facilities (Second Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 280).

Agreement subject to termination upon mutual agreement.

Schedule Page: 328.1 Line No.: 15 Column: m

Scheduling and load following charges. Distribution Voltage Service Charge.

Schedule Page: 328.1 Line No.: 16 Column: d

Legacy Contract executed between PacifiCorp and Deseret Generation and Transmission Cooperative for transmission service over

agreed-upon facilities (Second Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 280).

Agreement subject to termination upon mutual agreement.

Schedule Page: 328.1 Line No.: 16 Column: m

Scheduling and load following charges. Distribution Voltage Service Charge. December 2009 Service.

Schedule Page: 328.1 Line No.: 17 Column: d

Control Area Services Agreement (Rate Schedule 590) for charges associated with providing control area support and ancillary

services. Agreement terminating July 2011.

Schedule Page: 328.1 Line No.: 17 Column: m

Regulation & Frequency Response. Spinning and/or supplemental reserve services. Meter interrogation charge.

Schedule Page: 328.1 Line No.: 18 Column: d

Control Area Services Agreement (Rate Schedule 590) for charges associated with providing control area support and ancillary

services. Agreement terminating July 2011.

Schedule Page: 328.1 Line No.: 18 Column: m

Regulation & Frequency Response. Spinning and/or supplemental reserve services. Meter interrogation charge. December 2009

Service.

Schedule Page: 328.1 Line No.: 19 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 19 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 20 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 20 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 20 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 21 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 21 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 21 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 21 Column: m

December 2009 Service.

Schedule Page: 328.1 Line No.: 22 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 22 Column: d

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.7
Point-to-Point Transmission Service under the Open Access Transmission Tariff, (Service Agreement 426) deferred until June 1, 2011.

Terminating April 30, 2043.

Schedule Page: 328.1 Line No.: 22 Column: m

Extension of commencement date fee.

Schedule Page: 328.1 Line No.: 23 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 23 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 23 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 24 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 24 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 24 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 24 Column: m

December 2009 Service.

Schedule Page: 328.1 Line No.: 25 Column: d

Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural Electric Cooperative for transmission service

over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminates July 31, 2027.

Schedule Page: 328.1 Line No.: 25 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and or proportional use as defined in the contract.

Schedule Page: 328.1 Line No.: 26 Column: d

Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural Electric Cooperative for transmission service

over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminates July 31, 2027.

Schedule Page: 328.1 Line No.: 26 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and or proportional use as defined in the contract. December 2009 Service.

Schedule Page: 328.1 Line No.: 27 Column: c

PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and commodity trading activities.

Schedule Page: 328.1 Line No.: 27 Column: d

Service Agreement 130 executed between PacifiCorp and Foote Creek III, LLC (Seawest) for transmission service over agreed-upon

facilities and/or subject to a sole-use or facilities charge. Terminating July 2014.

Schedule Page: 328.1 Line No.: 27 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.1 Line No.: 28 Column: c

PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and commodity trading activities.

Schedule Page: 328.1 Line No.: 28 Column: d

Service Agreement 130 executed between PacifiCorp and Foote Creek III, LLC (Seawest) for transmission service over agreed-upon

facilities and/or subject to a sole-use or facilities charge. Terminating July 2014.

Schedule Page: 328.1 Line No.: 28 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. December 2009 Service.

Schedule Page: 328.1 Line No.: 29 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 29 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 29 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 30 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.8
Schedule Page: 328.1 Line No.: 30 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 30 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 31 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 31 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.1 Line No.: 31 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.1 Line No.: 31 Column: m

December 2009 Service.

Schedule Page: 328.1 Line No.: 32 Column: d

Ancillary Services under the Open Access Transmission Tariff (Service Agreement 475) in effect until superseded. Contract assigned

to JP Morgan Ventures Energy Corporation.

Schedule Page: 328.1 Line No.: 32 Column: m

Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance

charges per Schedules 4 and 9. 

Schedule Page: 328.1 Line No.: 33 Column: d

Ancillary Services under the Open Access Transmission Tariff (Service Agreement 475) in effect until superseded. Contract assigned

to JP Morgan Ventures Energy Corporation.

Schedule Page: 328.1 Line No.: 33 Column: m

Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance charges per Schedules 4 and 9. December

2009 Service.

Schedule Page: 328.1 Line No.: 34 Column: c

Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.

Schedule Page: 328.1 Line No.: 34 Column: d

Ancillary Services under the Open Access Transmission Tariff (Service Agreement 315) in effect until superseded.

Schedule Page: 328.1 Line No.: 34 Column: f

Long Hollow, Wyoming Switching Station.

Schedule Page: 328.1 Line No.: 34 Column: g

Long Hollow, Wyoming Switching Station.

Schedule Page: 328.1 Line No.: 34 Column: m

Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance

charges per Schedules 4 and 9. 

Schedule Page: 328.2 Line No.: 1 Column: c

Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.

Schedule Page: 328.2 Line No.: 1 Column: d

Ancillary Services under the Open Access Transmission Tariff (Service Agreement 315) in effect until superseded.

Schedule Page: 328.2 Line No.: 1 Column: f

Long Hollow, Wyoming Switching Station.

Schedule Page: 328.2 Line No.: 1 Column: g

Long Hollow, Wyoming Switching Station.

Schedule Page: 328.2 Line No.: 1 Column: m

Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance

charges per Schedules 4 and 9. December 2009 Service.

Schedule Page: 328.2 Line No.: 2 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th revised Service Agreement 279). Terminates

April 30, 2014.

Schedule Page: 328.2 Line No.: 3 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th revised Service Agreement 279). Terminates

April 30, 2014.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.9
Schedule Page: 328.2 Line No.: 3 Column: m

December 2009 Service.

Schedule Page: 328.2 Line No.: 4 Column: d

Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idaho Power Company concerning the exchange of

transmission services over agreed-upon facilities (Draft Transmission Services Agreement between PacifiCorp and Idaho Power

Company, Draft 1 – 5/19/95 (“Goshen Agreement”)). Termination of this agreement occurs at the end of the calendar month following

the earlier of the effectiveness of a replacement contract, or upon three years written notice of termination as long as PacifiCorp has

facilities in place to serve PacifiCorp's Big Grassy load. See also FERC Account 565 - Transmission of Electricity by Others, page

332.

Schedule Page: 328.2 Line No.: 5 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th revised Service Agreement 212) terminating May

31, 2014.

Schedule Page: 328.2 Line No.: 6 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 6 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 6 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 7 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 7 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 7 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 8 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 8 Column: c

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 8 Column: d

Legacy Contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge for the Antelope Substation terminating coterminous with the

Idaho/USDOE Supply Agreement.

Schedule Page: 328.2 Line No.: 8 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.2 Line No.: 9 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 9 Column: c

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 9 Column: d

Legacy Contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge for the Antelope Substation terminating coterminous with the

Idaho/USDOE Supply Agreement.

Schedule Page: 328.2 Line No.: 9 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. December 2009 Service.

Schedule Page: 328.2 Line No.: 10 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 10 Column: c

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 10 Column: d

Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge for the Jim Bridger Pump. Termination upon 12-months written

notice.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.10
Schedule Page: 328.2 Line No.: 10 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.2 Line No.: 11 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 11 Column: c

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 11 Column: d

Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge for the Jim Bridger Pump. Termination upon 12-months written

notice.

Schedule Page: 328.2 Line No.: 11 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. December 2009 Service.

Schedule Page: 328.2 Line No.: 12 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “JP MORGAN VENTURES ENERGY CORP.” ON PAGES 328 –

330: Complete name is JP Morgan Ventures Energy Corporation.

Schedule Page: 328.2 Line No.: 12 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 12 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 12 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 13 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 13 Column: d

Assignment of Ancillary Services under the Open Access Transmission Tariff (Service Agreement 475) from Iberdrola Renewables,

Inc. Terminated December 20, 2010.

Schedule Page: 328.2 Line No.: 13 Column: m

Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance

charges per Schedules 4 and 9. 

Schedule Page: 328.2 Line No.: 14 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 14 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 14 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 14 Column: m

December 2009 Service.

Schedule Page: 328.2 Line No.: 15 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “LOS ANGELES DEPT OF WATER & POWER” ON PAGES 328 –

330: 

Complete name is Los Angeles Department of Water and Power.

Schedule Page: 328.2 Line No.: 15 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 15 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 15 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 16 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 16 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 16 Column: d

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.11
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 17 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 17 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 17 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 17 Column: m

December 2009 Service.

Schedule Page: 328.2 Line No.: 18 Column: d

Legacy Contract (Rate Schedule 302) executed between PacifiCorp and Moon Lake Electric Association for transmission and

interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Either party may terminate the

agreement at any time after October 14, 2011, by providing two years' written notice.

Schedule Page: 328.2 Line No.: 18 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and/or proportional use as defined in the contract. 

Schedule Page: 328.2 Line No.: 19 Column: d

Legacy Contract (Rate Schedule 302) executed between PacifiCorp and Moon Lake Electric Association for transmission and

interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Either party may terminate the

agreement at any time after October 14, 2011, by providing two years' written notice.

Schedule Page: 328.2 Line No.: 19 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and/or proportional use as defined in the contract. December 2009 Service.

Schedule Page: 328.2 Line No.: 20 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 20 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 20 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 21 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 21 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 21 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 21 Column: m

December 2009 Service.

Schedule Page: 328.2 Line No.: 22 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 22 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 22 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 23 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 23 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 23 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 24 Column: c

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “GRANT COUNTY PUD” ON PAGES 328 – 330: 

Complete name is Grant County Public Utility District.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.12
Schedule Page: 328.2 Line No.: 24 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service Agreement 626), assignment from Seattle

City & Light, terminating December 31, 2011.

Schedule Page: 328.2 Line No.: 24 Column: m

Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance

charges per Schedules 4 and 9. 

Schedule Page: 328.2 Line No.: 25 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service Agreement 626), assignment from Seattle

City & Light, terminating December 31, 2011.

Schedule Page: 328.2 Line No.: 25 Column: m

Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance

charges per Schedules 4 and 9. December 2009 Service.

Schedule Page: 328.2 Line No.: 26 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 26 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 26 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 27 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 27 Column: c

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 27 Column: d

Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric Company for transmission service over

agreed-upon facilities (Malin to Round Mountain) and/or subject to a sole-use or facilities charge. Terminating December 31, 2017.

See PacifiCorp, Docket No. ER07-882, et al, Settlement Agreement, Appendix 2 (filed November 20, 2007).

Schedule Page: 328.2 Line No.: 27 Column: f

Malin - Indian Springs line segment.

Schedule Page: 328.2 Line No.: 27 Column: g

Malin - Indian Springs line segment.

Schedule Page: 328.2 Line No.: 27 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. 

Schedule Page: 328.2 Line No.: 28 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 28 Column: c

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.2 Line No.: 28 Column: d

Legacy Contract (Rate Schedule 298) executed between PacifiCorp and Pacific Gas & Electric Company for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge (phase shifting transformers at Sigurd-Glen Canyon 230kv

transmission line and Pinto-Four Corners 345kv transmission line). Terminating February 12, 2020.

Schedule Page: 328.2 Line No.: 28 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.2 Line No.: 29 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 29 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 29 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 30 Column: c

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CAISO” ON PAGES 328 – 330: 

Complete name is California Independent System Operator Corporation.

Schedule Page: 328.2 Line No.: 30 Column: d

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.13
Point-to-Point Transmission Service under the Open Access Transmission Tariff (4th revised Service Agreement 169) terminating on

September 30, 2012. 

Schedule Page: 328.2 Line No.: 31 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (4th revised Service Agreement 169) terminating on

September 30, 2012. 

Schedule Page: 328.2 Line No.: 31 Column: m

December 2009 Service.

Schedule Page: 328.2 Line No.: 32 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 32 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 32 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 32 Column: m

Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328.2 Line No.: 33 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 33 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 33 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.2 Line No.: 33 Column: m

December 2009 Service.

Schedule Page: 328.2 Line No.: 34 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 34 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.2 Line No.: 34 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 1 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 1 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 1 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 2 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 2 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 2 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 2 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 3 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 3 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 3 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 4 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUBLIC SVC. CO. OF CO” ON PAGES 328 – 330: 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.14
Complete name is Public Service Company of Colorado.

Schedule Page: 328.3 Line No.: 4 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 4 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 4 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 5 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 5 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 5 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 5 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 6 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 6 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 6 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 7 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 7 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 7 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 8 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 8 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 8 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 8 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 9 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 9 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 9 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 10 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 568) terminating

April 30, 2029.

Schedule Page: 328.3 Line No.: 10 Column: m

Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328.3 Line No.: 11 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 568) terminating

April 30, 2029.

Schedule Page: 328.3 Line No.: 11 Column: m

Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance charges per Schedules 4 and 9. December

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.15
2009 Service.

Schedule Page: 328.3 Line No.: 12 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 12 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 12 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 13 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (7th revised Service Agreement 289), terminating

October 31, 2014.

Schedule Page: 328.3 Line No.: 13 Column: m

Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328.3 Line No.: 14 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (7th revised Service Agreement 289), terminating

October 31, 2014.

Schedule Page: 328.3 Line No.: 14 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 15 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 15 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 15 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 16 Column: d

Transmission Service under the Open Access Transmission Tariff (Service Agreement 299). Service provided pursuant to rules and

regulations of Oregon Direct Access. Termination upon notification pursuant to Oregon Direct Access and Open Access Transmission

Tariff.

Schedule Page: 328.3 Line No.: 16 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328.3 Line No.: 17 Column: d

Transmission Service under the Open Access Transmission Tariff (Service Agreement 299). Service provided pursuant to rules and 

regulations of Oregon Direct Access. Termination upon notification pursuant to Oregon Direct Access and Open Access Transmission

Tariff.

Schedule Page: 328.3 Line No.: 17 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009 Service.

Schedule Page: 328.3 Line No.: 18 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 18 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 18 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 19 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 19 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 19 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 19 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 20 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 20 Column: c

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.16
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 20 Column: d

Legacy Contract (Rate Schedule 647) executed between PacifiCorp and Sierra Pacific Power Company for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating forty-five years from the date the second

interconnection is placed in service and shall continue in effect beyond such time unless terminated by either party through written

notice given to the other party not later than four years in advance of the desired termination date.

Schedule Page: 328.3 Line No.: 20 Column: g

Utah-Nevada Border

Schedule Page: 328.3 Line No.: 20 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.3 Line No.: 21 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 21 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 21 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 22 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 22 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 22 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 22 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 23 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 23 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 23 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 23 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 24 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 24 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 24 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 24 Column: m

Charges for spinning and/or supplemental reserves.

Schedule Page: 328.3 Line No.: 25 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 25 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 25 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 25 Column: m

Unauthorized use of transmission service. Penalty revenues covering imbalance charges per Schedules 4 and 9.

Schedule Page: 328.3 Line No.: 26 Column: b

Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 26 Column: c

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.17
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 26 Column: d

Use of Facilities Agreement - Phase Shifting Transformers At Sigurd-Glen Canyon 230kv transmission line and Pinto-Four Corners

345kv transmission line (Rate Schedule 298), terminating February 12, 2020.

Schedule Page: 328.3 Line No.: 26 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.

Schedule Page: 328.3 Line No.: 27 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service Agreement 170) terminating on May 31,

2014.

Schedule Page: 328.3 Line No.: 28 Column: d

Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service Agreement 170) terminating on May 31,

2014.

Schedule Page: 328.3 Line No.: 28 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 29 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 29 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 29 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 30 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 30 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 30 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 30 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 31 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 31 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 31 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 32 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 32 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 32 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.3 Line No.: 32 Column: m

December 2009 Service.

Schedule Page: 328.3 Line No.: 33 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “TRI-STATE GENERATION & TRANS.” ON PAGES 328 – 330: 

Complete name is Tri-State Generation and Transmission Association, Inc. 

Schedule Page: 328.3 Line No.: 33 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.3 Line No.: 33 Column: d

Legacy Contract (Rate Schedule 123) executed between PacifiCorp and Tri-State Generation and Transmission Association, Inc. for

transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating October 1, 2014.

Schedule Page: 328.3 Line No.: 34 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.18
Schedule Page: 328.3 Line No.: 34 Column: d

Legacy Contract (Rate Schedule 123) executed between PacifiCorp and Tri-State Generation and Transmission Association, Inc. for

transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating October 1, 2014.

Schedule Page: 328.3 Line No.: 34 Column: m

December 2009 Service.

Schedule Page: 328.4 Line No.: 1 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 1 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 1 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.4 Line No.: 2 Column: b

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 2 Column: d

Network Transmission Service under the Open Access Transmission Tariff (second revised Service Agreement 628) terminating on

June 30, 2021.

Schedule Page: 328.4 Line No.: 2 Column: m

Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9. 

Schedule Page: 328.4 Line No.: 3 Column: d

Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (Service Agreement 506)

terminating upon written notification.

Schedule Page: 328.4 Line No.: 3 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response.

Schedule Page: 328.4 Line No.: 4 Column: d

Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (Service Agreement 506)

terminating upon written notification.

Schedule Page: 328.4 Line No.: 4 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. Primary delivery and distribution adjustments for 2008 and 2009.

December 2009 Service.

Schedule Page: 328.4 Line No.: 5 Column: d

Legacy Contract (Rate Schedule 67) executed between PacifiCorp and the United States Bureau of Reclamation Crooked River

Irrigation District for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating with

one year written notice.

Schedule Page: 328.4 Line No.: 6 Column: c

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “WEBER BASIN WATER CONSERV.” ON PAGES 328 – 330: 

Complete name is Weber Basin Water Conservancy District.

Schedule Page: 328.4 Line No.: 6 Column: d

Legacy Contract (Rate Schedule 286) executed between PacifiCorp and the United States Bureau of Reclamation Weber Basin Water

Conservancy District for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge for energy

deliveries at or below 138kv. Terminating any time after April 1, 2040 with four years written notice.

Schedule Page: 328.4 Line No.: 6 Column: m

Energy consumption charge for deliveries at and below 138kv.

Schedule Page: 328.4 Line No.: 7 Column: d

Legacy Contract (Rate Schedule 286) executed between PacifiCorp and the United States Bureau of Reclamation Weber Basin Water

Conservancy District for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge for energy

deliveries at or below 138kv. Terminating any time after April 1, 2040 with four years written notice.

Schedule Page: 328.4 Line No.: 7 Column: m

Energy consumption charge for deliveries at and below 138kv. December 2009 Service.

Schedule Page: 328.4 Line No.: 8 Column: b

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “UTAH ASSOCIATED MUNICIPAL POWER” ON PAGES 328 –

330: 

Complete name is Utah Associated Municipal Power Systems.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.19
Schedule Page: 328.4 Line No.: 8 Column: d

Legacy Contract executed between PacifiCorp and Utah Associated Municipal Power Systems for transmission service over

agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 297). Subject to

termination upon mutual agreement and replacement agreements are in effect.

Schedule Page: 328.4 Line No.: 8 Column: m

Charges for load following, spinning and/or supplemental reserves. Distribution Voltage Service Charge.

Schedule Page: 328.4 Line No.: 9 Column: d

Legacy Contract executed between PacifiCorp and Utah Associated Municipal Power Systems for transmission service over

agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 297). Subject to

termination upon mutual agreement and replacement agreements are in effect.

Schedule Page: 328.4 Line No.: 9 Column: m

Charges for monitoring, scheduling, load following, spinning and/or supplemental reserves. Distribution Voltage Service Charge.

December 2009 Service.

Schedule Page: 328.4 Line No.: 10 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.4 Line No.: 11 Column: d

Legacy Contract (Rate Schedule 637) executed between PacifiCorp and Utah Municipal Power Agency for transmission service over

agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement). Subject to termination upon mutual

agreement and replacement agreements are in effect.

Schedule Page: 328.4 Line No.: 11 Column: m

Charges for scheduling and load following.

Schedule Page: 328.4 Line No.: 12 Column: d

Legacy Contract (Rate Schedule 637) executed between PacifiCorp and Utah Municipal Power Agency for transmission service over

agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement). Subject to termination upon mutual

agreement and replacement agreements are in effect.

Schedule Page: 328.4 Line No.: 12 Column: m

Charges for scheduling and load following. December 2009 Service.

Schedule Page: 328.4 Line No.: 13 Column: d

Legacy Contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power Enterprises for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating January 1, 2032.

Schedule Page: 328.4 Line No.: 13 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and or proportional use as defined in the contract. 

Schedule Page: 328.4 Line No.: 14 Column: d

Legacy Contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power Enterprises for transmission service over

agreed-upon facilities and/or subject to a sole-use or facilities charge. Terminating January 1, 2032.

Schedule Page: 328.4 Line No.: 14 Column: m

Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor

and or proportional use as defined in the contract. December 2009 Service.

Schedule Page: 328.4 Line No.: 15 Column: c

Various Western Area Power Association Customers in Pacificorp's Control Area.

Schedule Page: 328.4 Line No.: 15 Column: d

Legacy Contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power Administration for transmission and

interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to preferential

customers for deliveries of Colorado River Storage Project power and energy. Termination upon three years after written notice and

mutual consent.

Schedule Page: 328.4 Line No.: 15 Column: m

Fixed Termination Fee associated with a contract cancellation applied for the duration of this agreement. 

Schedule Page: 328.4 Line No.: 16 Column: c

Various Western Area Power Association Customers in Pacificorp's Control Area.

Schedule Page: 328.4 Line No.: 16 Column: d

Legacy Contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power Administration for transmission and

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.20
interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to preferential

customers for deliveries of Colorado River Storage Project power and energy. Termination upon three years after written notice and

mutual consent.

Schedule Page: 328.4 Line No.: 16 Column: m

Fixed Termination Fee associated with a contract cancellation applied for the duration of this agreement. December 2009 service.

Schedule Page: 328.4 Line No.: 17 Column: c

Various Western Area Power Association Customers in Pacificorp's Control Area.

Schedule Page: 328.4 Line No.: 17 Column: d

Legacy Contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power Administration for transmission and

interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to low voltage

customers for deliveries of power and energy from Salt Lake City Area Integrated Projects, including the Colorado River Storage

Projects, to certain municipalities at service below 138kv. Termination upon three years after written notice and mutual consent.

Schedule Page: 328.4 Line No.: 17 Column: m

Charges for low-voltage transmission of power and energy.

Schedule Page: 328.4 Line No.: 18 Column: c

Various Western Area Power Association Customers in Pacificorp's Control Area.

Schedule Page: 328.4 Line No.: 18 Column: d

Legacy Contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power Administration for transmission and

interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to low voltage

customers for deliveries of power and energy from Salt Lake City Area Integrated Projects, including the Colorado River Storage

Projects, to certain municipalities at service below 138kv. Termination upon three years after written notice and mutual consent.

Schedule Page: 328.4 Line No.: 18 Column: m

December 2009 Service.

Schedule Page: 328.4 Line No.: 19 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 19 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.4 Line No.: 20 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 20 Column: d

Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.

Schedule Page: 328.4 Line No.: 20 Column: m

December 2009 Service.

Schedule Page: 328.4 Line No.: 21 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 21 Column: d

Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Western Area Power Administration concerning the exchange

of transmission services over agreed-upon facilities. The contract terminates fifty years from execution. See also FERC Account 565 -

Transmission of Electricity by Others, page 332 of this Form No. 1. 

Schedule Page: 328.4 Line No.: 22 Column: c

Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328.4 Line No.: 22 Column: d

Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Western Area Power Administration concerning the exchange

of transmission services over agreed-upon facilities. The contract terminates fifty years from execution. See also FERC Account 565 -

Transmission of Electricity by Others, page 332 of this Form No. 1.

Schedule Page: 328.4 Line No.: 22 Column: m

Adjustments for 2009 service per terms of the contract.

Schedule Page: 328.4 Line No.: 23 Column: d

Evergreen Network Transmission Service under the Open Access Transmission Tariff (Service Agreement 175).

Schedule Page: 328.4 Line No.: 23 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. 

Schedule Page: 328.4 Line No.: 24 Column: d

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.21
Evergreen Network Transmission Service under the Open Access Transmission Tariff (Service Agreement 175).

Schedule Page: 328.4 Line No.: 24 Column: m

Distribution Voltage Service Charge. Primary Delivery Service. December 2009 Service.

Schedule Page: 328.4 Line No.: 25 Column: m

Represents the difference between actual wheeling revenues for the period as reflected on the individual line items within this

schedule, and the accruals credited to account 456.1 during the period.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.22
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY BY ISO/RTOs

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Payment Received by Statistical

(a) (b)

(Transmission Owner Name) Classification

FERC Rate Schedule

or Tariff Number

(c)

Total Revenue by Rate

Schedule or Tarirff

(d)

Total Revenue

(e)

1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.

2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).

3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – 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.

6. Report in column (e) the total revenues distributed to the entity listed in column (a).

 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

Page 331

40 TOTAL

FERC FORM NO. 1/3-Q (REV 03-07)
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name of Company or Public

(a) (c) (d)

Authority (Footnote Affiliations)

TRANSFER OF ENERGY

Magawatt- hours

Received

MagawattDelivered

hours

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS

Demand

Charges ($)

(e)

Energy

Charges

(f)

($)

Other

Charges ($)

(g) ($)

Total Cost of

Transmission

(h)

(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.

7. Footnote entries and provide explanations following all required data.

Statistical

Classification

(b)

 1 Arizona Public Service OS

 2 Arizona Public Service LFP 370,348 370,348 1,093,316 1,093,316

 3 Arizona Public Service NF 20,773 20,773 80,392 80,392

 4 Arizona Public Service OS 6,197 3,745 9,942

 5 Arizona Public Service SFP 18,763 18,763 71,146 71,146

 6 Ashland, City of FNS 1,769 1,769 16,638 16,638

 7 Avista Corporation FNS 48,575 50,243 217,930 217,930

 8 Avista Corporation NF 12,732 12,732 73,464 73,464

 9 Basin Elect. Power Coop LFP 71,485 71,485

 10 Big Horn Rural Electric OS 181,813 181,813

 11 Bonneville Power Admin. OS

 12 Bonneville Power Admin. AD 9,021 9,021 17,000 9,121 26,121

 13 Bonneville Power Admin. FNS 6,555,934 6,555,934

 14 Bonneville Power Admin. LFP 5,394,463 5,394,463 53,476,903 3,010,860 56,487,763

 15 Bonneville Power Admin. NF 309,750 309,750 1,341,217 1,341,217

 16 Bonneville Power Admin. OS 5,049,853 5,226,006 30,813,868 165,008 1,557,921 32,536,797

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332

TOTAL 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name of Company or Public

(a) (c) (d)

Authority (Footnote Affiliations)

TRANSFER OF ENERGY

Magawatt- hours

Received

MagawattDelivered

hours

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS

Demand

Charges ($)

(e)

Energy

Charges

(f)

($)

Other

Charges ($)

(g) ($)

Total Cost of

Transmission

(h)

(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.

7. Footnote entries and provide explanations following all required data.

Statistical

Classification

(b)

 1 Bonneville Power Admin. SFP 52,522 52,522 208,244 208,244

 2 CA Ind. Sys. Operator AD -3,756 30,716 26,960

 3 CA Ind. Sys. Operator OS 1,829,210 1,829,210

 4 CA Ind. Sys. Operator SFP 533,427 533,427 2,867,483 2,867,483

 5 Deseret Pwr Elect. Coop AD 1,808 1,808 13,415 13,415

 6 Deseret Pwr Elect. Coop LFP 168,010 168,010 3,391,570 3,391,570

 7 Deseret Pwr Elect. Coop NF 183,089 183,089 1,327,332 1,327,332

 8 El Paso Elect. Co. AD 150 150 113 113

 9 El Paso Elect. Co. NF 200 200 181 181

 10 Flathead Elect. Coop. OS 63,922 63,922

 11 Hermiston Generating Co OS 175,965 175,965

 12 Idaho Power Company OS

 13 Idaho Power Company AD -183,020 697,502 514,482

 14 Idaho Power Company FNS 6,994 6,994

 15 Idaho Power Company LFP 3,206,147 3,257,310 6,121,548 6,121,548

 16 Idaho Power Company NF 311,953 365,715 1,050,762 1,050,762

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1

TOTAL 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name of Company or Public

(a) (c) (d)

Authority (Footnote Affiliations)

TRANSFER OF ENERGY

Magawatt- hours

Received

MagawattDelivered

hours

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS

Demand

Charges ($)

(e)

Energy

Charges

(f)

($)

Other

Charges ($)

(g) ($)

Total Cost of

Transmission

(h)

(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.

7. Footnote entries and provide explanations following all required data.

Statistical

Classification

(b)

 1 Idaho Power Company OS 10,767,019 10,767,019

 2 Idaho Power Company SFP 1,032 1,032 2,180 2,180

 3 Moon Lake Elect. Assoc. FNS 182,791 182,791

 4 Morgan City Corporation AD 41 41 434 434

 5 Nevada Power Company NF 60,588 60,588 200,194 200,194

 6 Nevada Power Company OS 69,299 69,299

 7 Nevada Power Company SFP 79,037 79,037 214,659 214,659

 8 NorthWestern Corp. NF 94,374 94,852 391,630 391,630

 9 NorthWestern Corp. OS 26,991 26,991

 10 NorthWestern Corp. SFP 27,233 27,233 118,134 118,134

 11 Platte River Power LFP 173,713 173,713 966,000 966,000

 12 Platte River Power OS 15,333 15,333

 13 Portland Gen. Electrric NF 1,617 1,617 1,759 1,759

 14 Portland Gen. Electric OS 908 908

 15 Portland Gen. Electric SFP -1,025,820 -1,025,820

 16 Powerex Corporation SFP -1,894,500 -1,894,500

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2

TOTAL 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name of Company or Public

(a) (c) (d)

Authority (Footnote Affiliations)

TRANSFER OF ENERGY

Magawatt- hours

Received

MagawattDelivered

hours

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS

Demand

Charges ($)

(e)

Energy

Charges

(f)

($)

Other

Charges ($)

(g) ($)

Total Cost of

Transmission

(h)

(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.

7. Footnote entries and provide explanations following all required data.

Statistical

Classification

(b)

 1 Public Service Co of CO LFP 169,116 177,879 901,862 901,862

 2 Public Service Co of CO NF 855 855 4,524 4,524

 3 Public Service Co of NM LFP 116,760 116,760 591,311 591,311

 4 Public Service Co of NM OS 21,148 21,148

 5 Salt River Project NF 160 160 499 499

 6 Sierra Pacific Power Co NF 6,480 6,480 41,504 41,504

 7 Sierra Pacific Power Co OS 5,986 5,986

 8 Surprise Valley Electr. OLF 9,523 9,523

 9 Tri-State Gen & Transm LFP 203,428 212,197 901,862 901,862

 10 Tri-State Gen & Transm NF 249,472 249,472 563,215 563,215

 11 Tri-State Gen & Transm OS 222,304 222,304

 12 Tucson Electric Power NF 218 218 1,093 1,093

 13 Tucson Electric Power OS 127 127

 14 Utah Assoc Muni Pwr Sys AD -1,512 -1,512 -107,800 -1,500 -109,300

 15 Utah Assoc Muni Pwr Sys NF 89 89 445 445

 16 Westport Field Srv LLC LFP -2,310,796 -2,310,796

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3

TOTAL 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name of Company or Public

(a) (c) (d)

Authority (Footnote Affiliations)

TRANSFER OF ENERGY

Magawatt- hours

Received

MagawattDelivered

hours

EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS

Demand

Charges ($)

(e)

Energy

Charges

(f)

($)

Other

Charges ($)

(g) ($)

Total Cost of

Transmission

(h)

(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.

7. Footnote entries and provide explanations following all required data.

Statistical

Classification

(b)

 1 Western Area Power Adm. OS

 2 Western Area Power Adm. AD -311 -311 -6,512 -819 -7,331

 3 Western Area Power Adm. FNS 4,812,992 4,812,992

 4 Western Area Power Adm. LFP 414,790 414,790 2,220,000 2,220,000

 5 Western Area Power Adm. NF 234,189 234,189 594,452 594,452

 6 Western Area Power Adm. OS 423,870 423,870

 7 Western Area Power Adm. SFP 45,948 45,948 80,650 80,650

 8 Accrual True-up 1,485,559 1,485,559

 9

 10

 11

 12

 13

 14

 15

 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4

TOTAL 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
Schedule Page: 332 Line No.: 1 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “ARIZONA PUBLIC SERVICE” ON PAGE 332: Complete name is

Arizona Public Service Company.

Schedule Page: 332 Line No.: 1 Column: b

Legacy Contract executed between PacifiCorp and Arizona Public Service Company concerning the exchange of transmission services

over agreed-upon facilities (Restated Transmission Agreement between PacifiCorp and Arizona Public Service Company, ("Restated

TSA"), Rate Schedule 436). The contract terminates October 31, 2020. See also FERC Account 456.1 - Transmission of Electricity

For Others, page 328 of this Form No. 1.

Schedule Page: 332 Line No.: 2 Column: b

Arizona Public Service Company - Contract Termination Dates: May 1, 2013, August 31, 2013, January 11, 2041 and May 31, 2047.

Schedule Page: 332 Line No.: 4 Column: g

Ancillary Services.

Schedule Page: 332 Line No.: 9 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BASIN ELECT. POWER COOP" ON PAGES 332: Complete name is

Basin Electric Power Cooperative.

Schedule Page: 332 Line No.: 9 Column: b

Basin Electric Power Cooperative - Contract Termination Date: One year written notice.

Schedule Page: 332 Line No.: 10 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “BIG HORN RURAL ELECTRIC” ON PAGE 332: Complete name is

Big Horn Rural Electric Cooperative.

Schedule Page: 332 Line No.: 10 Column: g

Use of Facilities.

Schedule Page: 332 Line No.: 11 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “BONNEVILLE POWER ADMIN.” ON PAGE 332: Complete name is

Bonneville Power Administration.

Schedule Page: 332 Line No.: 11 Column: b

Legacy Contract executed between PacifiCorp and Bonneville Power Administration concerning the exchange of transmission services

over agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369). This agreement runs concurrently

with the AC Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to that agreement are taken out of

service. See also FERC Account 456.1 - Transmission of Electricity For Others, page 328 of this Form No. 1.

Schedule Page: 332 Line No.: 12 Column: b

Settlement Adjustment. 

Schedule Page: 332 Line No.: 14 Column: b

Bonneville Power Administration - Contract Termination Dates: January 1, 2011, July 1, 2011, September 1, 2011, December 1, 2011,

April 1, 2012, July 1, 2012, November 1, 2012, July 1, 2013, September 1, 2013, October 1, 2013, December 1, 2013, January 1,

2014, October 1, 2027, November 1, 2033 and evergreen. 

Schedule Page: 332 Line No.: 14 Column: g

Ancillary Services.

Schedule Page: 332 Line No.: 16 Column: g

Ancillary Services. Use of Facilities.

Schedule Page: 332.1 Line No.: 2 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CA IND. SYS. OPERATOR” ON PAGE 332: Complete name is

California Independent System Operator Corporation.

Schedule Page: 332.1 Line No.: 2 Column: b

Settlement Adjustment. 

Schedule Page: 332.1 Line No.: 2 Column: g

Ancillary Services.

Schedule Page: 332.1 Line No.: 3 Column: g

Ancillary Services.

Schedule Page: 332.1 Line No.: 5 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “DESERET PWR ELECT. COOP” ON PAGE 332: Complete name is

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Deseret Power Electric Cooperative.

Schedule Page: 332.1 Line No.: 5 Column: b

Settlement Adjustment. 

Schedule Page: 332.1 Line No.: 6 Column: b

Deseret Power Electric Cooperative - Contract Termination Dates: October 31, 2012 and September 1, 2018.

Schedule Page: 332.1 Line No.: 8 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “EL PASO ELECT. CO.” ON PAGE 332: Complete name is El Paso

Electric Company.

Schedule Page: 332.1 Line No.: 8 Column: b

Settlement Adjustment. 

Schedule Page: 332.1 Line No.: 10 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “FLATHEAD ELECT. COOP.” ON PAGE 332: Complete name is

Flathead Electric Cooperative, Inc.

Schedule Page: 332.1 Line No.: 10 Column: g

Use of Facilities.

Schedule Page: 332.1 Line No.: 11 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “HERMISTON GENERATING CO” ON PAGE 332: Complete name

is Hermiston Generating Company, L.P.

Schedule Page: 332.1 Line No.: 11 Column: g

Use of Facilities.

Schedule Page: 332.1 Line No.: 12 Column: b

Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idaho Power Company concerning the exchange of

transmission services over agreed-upon facilities (Draft Transmission Services Agreement between PacifiCorp and Idaho Power

Company, Draft 1 – 5/19/95 (“Goshen Agreement”). Termination of this agreement occurs at the end of the calendar month following

the earlier of the effectiveness of a replacement contract, or upon three years written notice of termination as long as PacifiCorp has

facilities in place to serve PacifiCorp's Big Grassy load. See also FERC Account 456.1 - Transmission of Electricity For Others, page

328 of this Form No. 1.

Schedule Page: 332.1 Line No.: 13 Column: b

Settlement Adjustment. 

Schedule Page: 332.1 Line No.: 13 Column: g

Use of Facilities. Respondent's portion of specified costs of certain facilities.

Schedule Page: 332.1 Line No.: 15 Column: b

Idaho Power Company - Contract Termination Date: April 1, 2011. 

Schedule Page: 332.2 Line No.: 1 Column: g

Ancillary Services. Use of Facilities. Respondent's portion of specified costs of certain facilities.

Schedule Page: 332.2 Line No.: 3 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “MOON LAKE ELECT. ASSOC.” ON PAGE 332: Complete name is

Moon Lake Electric Association.

Schedule Page: 332.2 Line No.: 3 Column: g

Use of Facilities.

Schedule Page: 332.2 Line No.: 4 Column: b

Settlement Adjustment.

Schedule Page: 332.2 Line No.: 6 Column: g

Ancillary Services.

Schedule Page: 332.2 Line No.: 8 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “NORTHWESTERN CORP.” ON PAGE 332: Complete name is

NorthWestern Corporation.

Schedule Page: 332.2 Line No.: 9 Column: g

Ancillary Services.

Schedule Page: 332.2 Line No.: 11 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PLATTE RIVER POWER” ON PAGE 332: Complete name is Platte

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
River Power Authority.

Schedule Page: 332.2 Line No.: 11 Column: b

Platte River Power Authority - Contract Termination Date: October 31, 2012. 

Schedule Page: 332.2 Line No.: 12 Column: g

Ancillary Services.

Schedule Page: 332.2 Line No.: 13 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PORTLAND GEN. ELECTRIC” ON PAGE 332: Complete name is

Portland General Electric Company.

Schedule Page: 332.2 Line No.: 14 Column: g

Ancillary Services. Use of Facilities.

Schedule Page: 332.2 Line No.: 15 Column: e

Reassignment of Bonneville Power Administration transmission.

Schedule Page: 332.2 Line No.: 16 Column: e

Reassignment of Bonneville Power Administration transmission.

Schedule Page: 332.3 Line No.: 1 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUBLIC SERVICE CO OF CO” ON PAGE 332: Complete name is

Public Service Company of Colorado.

Schedule Page: 332.3 Line No.: 1 Column: b

Public Service Company of Colorado - Contract Termination Date: The date that all generating plants comprising PacifiCorp resources

have been retired from service or interests transferred.

Schedule Page: 332.3 Line No.: 3 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “PUBLIC SERVICE CO OF NM” ON PAGE 332: Complete name is

Public Service Company of New Mexico.

Schedule Page: 332.3 Line No.: 3 Column: b

Public Service Company of New Mexico - Contract Termination Date: December 1, 2012. 

Schedule Page: 332.3 Line No.: 4 Column: g

Ancillary Services.

Schedule Page: 332.3 Line No.: 6 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “SIERRA PACIFIC POWER CO” ON PAGE 332: Complete name is

Sierra Pacific Power Company.

Schedule Page: 332.3 Line No.: 7 Column: g

Ancillary Services.

Schedule Page: 332.3 Line No.: 8 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “SURPRISE VALLEY ELECTR.” ON PAGE 332: Complete name is

Surprise Valley Electrification Corp.

Schedule Page: 332.3 Line No.: 8 Column: b

Surprise Valley Electrification Corp. - Contract termination date: Evergreen.

Schedule Page: 332.3 Line No.: 8 Column: g

Use of Facilities.

Schedule Page: 332.3 Line No.: 9 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “TRI-STATE GEN & TRANSM” ON PAGE 332: Complete name is

Tri-State Generation and Transmission Association, Inc.

Schedule Page: 332.3 Line No.: 9 Column: b

Tri-State Generation and Transmission Association, Inc. - Contract Termination Date: The date that all generating plants comprising

PacifiCorp resources have been retired from service or interests transferred.

Schedule Page: 332.3 Line No.: 11 Column: g

Ancillary Services.

Schedule Page: 332.3 Line No.: 12 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “TUCSON ELECTRIC POWER” ON PAGE 332: Complete name is

Tucson Electric Power Company.

Schedule Page: 332.3 Line No.: 13 Column: g

Ancillary Services.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
Schedule Page: 332.3 Line No.: 14 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “UTAH ASSOC MUNI PWR SYS” ON PAGE 332: Complete name is

Utah Associated Municipal Power Systems.

Schedule Page: 332.3 Line No.: 14 Column: b

Settlement Adjustment. 

Schedule Page: 332.3 Line No.: 14 Column: g

Ancillary Services.

Schedule Page: 332.3 Line No.: 16 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “WESTPORT FIELD SRV LLC” ON PAGE 332: Complete name is

Westport Field Services, LLC.

Schedule Page: 332.3 Line No.: 16 Column: b

Westport Field Services, LLC - Contract Termination Date: Evergreen. 

Schedule Page: 332.3 Line No.: 16 Column: e

Reimbursement for providing third party service.

Schedule Page: 332.4 Line No.: 1 Column: a

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “WESTERN AREA POWER ADM.” ON PAGE 332: Complete name

is Western Area Power Administration.

Schedule Page: 332.4 Line No.: 1 Column: b

Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Western Area Power Administration concerning the exchange

of transmission services over agreed-upon facilities. The contract terminates fifty years from execution. See also FERC Account 456.1

- Transmission of Electricity For Others, page 328 of this Form No. 1. 

Schedule Page: 332.4 Line No.: 2 Column: b

Settlement Adjustment. 

Schedule Page: 332.4 Line No.: 2 Column: g

Ancillary Services.

Schedule Page: 332.4 Line No.: 4 Column: b

Western Area Power Administration - Contract Termination Date: May 31, 2022.

Schedule Page: 332.4 Line No.: 6 Column: g

Ancillary Services. Use of Facilities.

Schedule Page: 332.4 Line No.: 8 Column: g

Represents the difference between actual wheeling expenses for the period as reflected on the individual line items within this

schedule, and the accruals charged to account 565 during the period.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.4
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)

PacifiCorp X

04/18/2011 2010/Q4

Line Description Amount

No. (a) (b)

 1 Industry Association Dues 1,329,375

 2 Nuclear Power Research Expenses

 3 Other Experimental and General Research Expenses

 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities

 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000

 6

 7 Community & Economic Development and

 8 Corporate Memberships and Subscriptions

 9 Bend 2030 10,000

 10 CCD Business Development Corp 5,000

 11 Economic Development Corp of Utah 91,481

 12 Idaho Economic Development Association 7,500

 13 Governor's Utah Economic Summit 10,000

 14 Oregon Economic Development Association 10,000

 15 Port Of Columbia 8,000

 16 State of Utah 10,000

 17 Uintah County Economic Development 5,500

 18 Utah Center For Rural Life 5,000

 19 Utah Sports Commission 57,072

 20 Wyoming Business Council 5,000

 21 Americas' SAP User Group 5,000

 22 Associated Oregon Industries 28,000

 23 Four County Economic Development Corp 25,000

 24 Intermountain Electrical Association 9,000

 25 Northern Tier Transmission Group 418,088

 26 Oregon Business Association 11,000

 27 Oregon Business Council 33,228

 28 Oregon Solar Energy Industries Association 5,000

 29 Oregon Sports Authority Foundation 5,000

 30 Pacific Northwest Utilities Conference 69,069

 31 Portland Business Alliance 39,400

 32 Rocky Mountain Electrical League 18,000

 33 Salt Lake Area Chamber of Commerce 30,255

 34 The Climate Registry 10,000

 35 Utah Foundation 20,000

 36 Utah Manufacturers Association 6,000

 37 Utah Taxpayers Association 20,000

 38 Watson & Renner 16,408

 39 West Association 28,511

 40 Western Electricity Coordinating Council 3,786,077

 41 Western Energy Institute 42,004

 42 Wyoming Business Alliance 5,000

 43 Wyoming Taxpayers Association 9,523

 44 Yakima County Development 7,500

 45 Other 153,729

 16,291,649

FERC FORM NO. 1 (ED. 12-94) Page 335

46 TOTAL
Name of Respondent This Report Is: (1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)

PacifiCorp X

04/18/2011 2010/Q4

Line Description Amount

No. (a) (b)

 6

 7 Directors Fees - Regional Advisory Boards 16,240

 8

 9 General:

 10 MidAmerican Energy Holdings Company Management Fee 7,470,918

 11 Other -689

 12

 13 Regulatory Asset Amortization:

 14 Glenrock Mine Excluding Reclamation - UT 112,218

 15 Goodnoe Hills Settlement - WY 21,250

 16 Transition Plan - OR 2,289,365

 17 Lake Side Settlement - WY 27,627

 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

 16,291,649

FERC FORM NO. 1 (ED. 12-94) Page 335.1

46 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Functional Classification Depreciation

(a) (b) (d)

Amortization of 

Total

(Except amortization of aquisition adjustments)

A. Summary of Depreciation and Amortization Charges

Expense (Account 403)

Limited Term

Electric Plant

Amortization of

Other Electric

Plant (Acc 405)

(e) (f)

1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for 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.

(Account 404)

(c)

Depreciation Expense for Asset

Retirement Costs

(Account 403.1)

 1 Intangible Plant 31,747,938 31,747,938

 2 Steam Production Plant 129,276,321 129,276,321

 3 Nuclear Production Plant

 4 Hydraulic Production Plant-Conventional 15,836,545 169,186 16,005,731

 5 Hydraulic Production Plant-Pumped Storage

 6 Other Production Plant 107,805,700 107,805,700

 7 Transmission Plant 71,678,696 71,678,696

 8 Distribution Plant 142,300,998 142,300,998

 9 Regional Transmission and Market Operation

 10 General Plant 34,325,996 2,921,169 37,247,165

 11 Common Plant-Electric

 12 TOTAL 501,224,256 34,838,293 536,062,549

The amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.

FERC FORM NO. 1 (REV. 12-03) Page 336

B. Basis for Amortization Charges
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Account No.

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

C. Factors Used in Estimating Depreciation Charges

Depreciable

Plant Base

(In Thousands)

Estimated

Avg. Service Life

Net

Salvage

(Percent)

Applied

Depr. rates

Mortality

Curve

Type

Average

Remaining Life

(f) (g) (Percent)

 12 WIND GENERATION

 13 Dunlap Ranch I

 14 341.00 WY 366 24.87 -1.00 4.06

 15 343.00 WY 232,074 24.87 -1.00 4.06

 16

 17 DISTRIBUTION PLANT

 18 364.00 CA 51,952 50.00 -90.00 3.80 R1.5 37.94

 19 365.00 CA 32,245 65.00 -55.00 2.35 S-.5 51.70

 20 366.00 CA 15,315 50.00 -30.00 2.55 R5 34.58

 21 367.00 CA 16,737 45.00 1.07 S6 29.50

 22 368.00 CA 46,821 50.00 -52.00 3.36 R5 32.34

 23 369.10 CA 8,371 55.00 -5.00 1.56 R1 44.37

 24 369.20 CA 14,239 60.00 -5.00 1.50 R4 48.69

 25 370.00 CA 3,911 26.00 4.30 R2.5 13.24

 26 371.00 CA 271 25.00 -30.00 4.08 L0 13.85

 27 373.00 CA 662 35.00 -35.00 3.58 R3 16.36

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

 46

 47

 48

 49

 50

FERC FORM NO. 1 (REV. 12-03) Page 337
Schedule Page: 336 Line No.: 12 Column: b

Depreciation expense associated with transportation equipment is generally charged to operations and maintenance expense and

construction work in progress. During the year ended December 31, 2010, depreciation expense associated with transportation

equipment was $14,065,119.

Schedule Page: 336 Line No.: 12 Column: e

Generally, PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

REGULATORY COMMISSION EXPENSES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description Assessed by

(a) (b) (c)

Total 

Expense for Expenses 

of

(d)

(Furnish name of regulatory commission or body the Regulatory

docket or case number and a description of the case) Commission Utility Current Year

(b) + (c)

Deferred

in Account

182.3 at 

Beginning of Year

(e)

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.

 1 Public Service Commission of Utah:

 2 Annual Fee 3,648,134 3,648,134

 3 Rate Case 1,343,711 1,343,711

 4

 5 Public Utility Commission of Oregon:

 6 Annual Fee 2,145,364 2,145,364

 7 Rate Case 1,261,788 1,261,788

 8

 9 Public Service Commission of Wyoming:

 10 Annual Fee 1,210,427 1,210,427

 11 Rate Case 1,000,801 1,000,801

 12

 13 Washington Utilities and Transportation

 14 Commission:

 15 Annual Fee 576,475 576,475

 16 Rate Case 646,375 646,375

 17

 18 Idaho Public Utilities Commission:

 19 Annual Fee 353,980 353,980

 20 Rate Case 826,933 826,933

 21 Other State Regulatory Expenses 17,580 17,580

 22

 23 Public Utilities Commission of California:

 24 Annual Fee 952 952

 25 Rate Case 851,318 851,318

 26

 27 Rate Cases - All States 16,890 16,890

 28

 29 Federal Energy Regulatory Commission:

 30 Annual Fee 1,917,327 1,917,327

 31 Annual Land Use Fee 596,587 596,587

 32 Transmission Rate Case 762,536 762,536

 33 FERC Other Regulatory 704,704 704,704

 34

 35 Other Regulatory 44,958 44,958

 36

 37 Deferred Regulatory Commission Expense 61,378

 38

 39

 40

 41

 42

 43

 44

 45

FERC FORM NO. 1 (ED. 12-96) Page 350

46 TOTAL 10,449,246 7,477,594 17,926,840 61,378
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

REGULATORY COMMISSION EXPENSES (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(f) (i) (j) (k) (l)

EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR

CURRENTLY CHARGED TO

Department Account

No.

(g)

Amount

(h)

Deferred to

Account 182.3

Contra

Account

Amount Deferred in 

Account 182.3

End of Year

3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.

4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.

5. Minor items (less than $25,000) may be grouped.

 1

Electric 928 3,648,134 2

Electric 928 1,343,711 3

 4

 5

Electric 928 2,145,364 6

Electric 928 1,261,788 7

 8

 9

Electric 928 1,210,427 10

Electric 928 1,000,801 11

 12

 13

 14

Electric 928 576,475 15

Electric 928 646,375 16

 17

 18

Electric 928 353,980 19

Electric 928 826,933 20

Electric 928 17,580 21

 22

 23

Electric 928 952 24

Electric 928 851,318 25

 26

Electric 928 16,890 27

 28

 29

Electric 928 1,917,327 30

Electric 928 596,587 31

Electric 928 762,536 32

Electric 928 704,704 33

 34

Electric 928 44,958 35

 36

 37,081 928 17,580 80,879 37

 38

 39

 40

 41

 42

 43

 44

 45

FERC FORM NO. 1 (ED. 12-96) Page 351

 17,926,840 37,081 17,580 80,879 46
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Description

(a) (b)

Classification

1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &

D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(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 $50,000.)

 c. Internal combustion or gas turbine (7) Total Cost Incurred

 d. Nuclear B. Electric, R, D & D Performed Externally:

 e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric

 f. Siting and heat rejection Power Research Institute

 (2) Transmission

 1 B. Electric R, D & D Performed Externally

 2 (1) Research Support Electric Power Research Institute

 3 - Membership dues

 4 - Seismic studies of substation equipment program

 5 - Toxic release inventory reporting for power plants program

 6 - Utility gasification program

 7 (4) Research Support National Electric Testing, Research & Applications Center

 8 - Membership dues

 9 - Participation

 10 (4) Research Support Solar Electric Power Association

 11 - Membership dues

 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

FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

AMOUNTS CHARGED IN CURRENT YEAR

(e) (c)

Costs Incurred Internally

Current Year Costs Incurred Externally

Current Year

(d)

Account Amount

(f)

Unamortized 

Accumulation

(g)

 (2) Research Support to Edison Electric Institute

 (3) Research Support to Nuclear Power Groups

 (4) Research Support to Others (Classify)

 (5) Total Cost Incurred

3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,

briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).

Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &

D activity.

4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,

listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)

5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,

Development, and Demonstration Expenditures, Outstanding at the end of the year.

6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by

"Est."

7. Report separately research and related testing facilities operated by the respondent.

 1

 2

 547,651 930.2 547,651 3

 20,000 560 20,000 4

 12,000 557 12,000 5

 5,000 557 5,000 6

 7

 23,750 930.2 23,750 8

 4,501 580 4,501 9

 10

 7,000 930.2 7,000 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

FERC FORM NO. 1 (ED. 12-87) Page 353
Schedule Page: 352 Line No.: 9 Column: c

Estimate 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

DISTRIBUTION OF SALARIES AND WAGES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Classification

(a) (b) (c)

Direct Payroll Allocation of Total 

(d)

Distribution Payroll charged for

Clearing Accounts

Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts 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.

 1 Electric

 2 Operation

 3 Production 87,442,511

 4 Transmission 10,172,322

 5 Regional Market

 6 Distribution 41,229,347

 7 Customer Accounts 41,273,457

 8 Customer Service and Informational 5,288,051

 9 Sales

 10 Administrative and General 37,750,552

 11 TOTAL Operation (Enter Total of lines 3 thru 10) 223,156,240

 12 Maintenance

 13 Production 46,048,473

 14 Transmission 11,251,850

 15 Regional Market

 16 Distribution 69,824,793

 17 Administrative and General 1,869,579

 18 TOTAL Maintenance (Total of lines 13 thru 17) 128,994,695

 19 Total Operation and Maintenance

 20 Production (Enter Total of lines 3 and 13) 133,490,984

 21 Transmission (Enter Total of lines 4 and 14) 21,424,172

 22 Regional Market (Enter Total of Lines 5 and 15)

 23 Distribution (Enter Total of lines 6 and 16) 111,054,140

 24 Customer Accounts (Transcribe from line 7) 41,273,457

 25 Customer Service and Informational (Transcribe from line 8) 5,288,051

 26 Sales (Transcribe from line 9)

 27 Administrative and General (Enter Total of lines 10 and 17) 39,620,131

 28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 352,150,935 352,150,935

 29 Gas

 30 Operation

 31 Production-Manufactured Gas

 32 Production-Nat. Gas (Including Expl. and Dev.)

 33 Other Gas Supply

 34 Storage, LNG Terminaling and Processing

 35 Transmission

 36 Distribution

 37 Customer Accounts

 38 Customer Service and Informational

 39 Sales

 40 Administrative and General

 41 TOTAL Operation (Enter Total of lines 31 thru 40)

 42 Maintenance

 43 Production-Manufactured Gas

 44 Production-Natural Gas (Including Exploration and Development)

 45 Other Gas Supply

 46 Storage, LNG Terminaling and Processing

 47 Transmission

FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Classification

(a) (b) (c)

Direct Payroll Allocation of Total 

(d)

Distribution Payroll charged for

Clearing Accounts

DISTRIBUTION OF SALARIES AND WAGES (Continued)

 48 Distribution

 49 Administrative and General

 50 TOTAL Maint. (Enter Total of lines 43 thru 49)

 51 Total Operation and Maintenance

 52 Production-Manufactured Gas (Enter Total of lines 31 and 43)

 53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,

 54 Other Gas Supply (Enter Total of lines 33 and 45)

 55 Storage, LNG Terminaling and Processing (Total of lines 31 thru

 56 Transmission (Lines 35 and 47)

 57 Distribution (Lines 36 and 48)

 58 Customer Accounts (Line 37)

 59 Customer Service and Informational (Line 38)

 60 Sales (Line 39)

 61 Administrative and General (Lines 40 and 49)

 62 TOTAL Operation and Maint. (Total of lines 52 thru 61)

 63 Other Utility Departments

 64 Operation and Maintenance

 65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 352,150,935 352,150,935

 66 Utility Plant

 67 Construction (By Utility Departments)

 68 Electric Plant 147,587,388 147,587,388

 69 Gas Plant

 70 Other (provide details in footnote):

 71 TOTAL Construction (Total of lines 68 thru 70) 147,587,388 147,587,388

 72 Plant Removal (By Utility Departments)

 73 Electric Plant 9,659,614 9,659,614

 74 Gas Plant

 75 Other (provide details in footnote):

 76 TOTAL Plant Removal (Total of lines 73 thru 75) 9,659,614 9,659,614

 77 Other Accounts (Specify, provide details in footnote):

 78 Fuel Stock 27,117,060 27,117,060

 79 Miscellaneous Other Income Deductions 429,366 429,366

 80 Miscellaneous Nonoperating/Nonutility 689,699 689,699

 81

 82

 83

 84

 85

 86

 87

 88

 89

 90

 91

 92

 93

 94

 95 TOTAL Other Accounts 28,236,125 28,236,125

 96 TOTAL SALARIES AND WAGES 537,634,062 537,634,062

FERC FORM NO. 1 (ED. 12-88) Page 355
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

Year/Period of Report

End of

COMMON UTILITY PLANT AND EXPENSES

PacifiCorp X

04/18/2011 2010/Q4

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.

FERC FORM NO. 1 (ED. 12-87) Page 356
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of X

04/18/2011

2010/Q4

Line

 No.

Description of Item(s) Balance at End of

(a) (b) (c)

Balance at End of

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

Quarter 1 Quarter 2

Balance at End of

Quarter 3

(d) (e)

1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales 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.

Balance at End of

Year

 1 Energy

 2 Net Purchases (Account 555)

 3 Net Sales (Account 447)

 4 Transmission Rights

 5 Ancillary Services

 6 Other Items (list separately)

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

 45

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397

46 TOTAL
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PURCHASES AND SALES OF ANCILLARY SERVICES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Type of Ancillary Service

(a)

Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in 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.

Number of Units

Unit of

Measure Dollars

(b) (c) (d)

Number of Units

Unit of

Measure Dollars

(e) (f) (g)

Usage - Related Billing Determinant Usage - Related Billing Determinant

Amount Purchased for the Year Amount Sold for the Year

 1 Scheduling, System Control and Dispatch 144,444

 2 Reactive Supply and Voltage

 3 Regulation and Frequency Response 57,766,387 MWh 9,242,739 58,287,704 MWh 9,857,432

 4 Energy Imbalance -145,195 MWh -4,614,914

 5 Operating Reserve - Spinning 65,622,051 MWh 23,896,498 68,807,239 MWh 25,129,384

 6 Operating Reserve - Supplement 65,622,051 MWh 23,896,498 68,479,528 MWh 25,007,148

 7 Other -4,219

 8 Total (Lines 1 thru 7) 189,010,489 57,035,735 195,429,276 55,519,275

FERC FORM NO. 1 (New 2-04) Page 398
Schedule Page: 398 Line No.: 7 Column: g

Refund of Emergency Reserve service

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MONTHLY TRANSMISSION SYSTEM PEAK LOAD

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Monthly Peak

MW - Total

(a) (b) (c)

Month

NAME OF SYSTEM:

Day of

Monthly

Peak

(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not 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.

(d)

Hour of

Monthly

 Peak

(e)

Firm Network

Service for Self

(f)

Firm Network

Service for

 Others

(g)

Long-Term Firm

Point-to-point

Reservations

(h)

Other LongTerm Firm

Service

(i)

Short-Term Firm

Point-to-point

Reservation

(j)

Other

Service

 1 January 16,264 7 1800 8,152 118 5,276 1,050 1,668

 2 February 15,596 22 800 8,002 101 5,276 629 1,588

 3 March 15,814 9 1900 7,574 88 5,276 1,346 1,530

 4 Total for Quarter 1 47,674 23,728 307 15,828 3,025 4,786

 5 April 14,842 1 800 7,248 85 5,276 744 1,489

 6 May 14,708 6 800 7,092 88 5,276 828 1,424

 7 June 17,385 28 1700 8,824 84 6,111 549 1,817

 8 Total for Quarter 2 46,935 23,164 257 16,663 2,121 4,730

 9 July 18,078 27 1600 9,398 88 5,654 1,075 1,863

 10 August 18,299 17 1600 9,382 98 5,654 1,246 1,919

 11 September 16,809 3 1700 8,168 74 5,635 1,246 1,686

 12 Total for Quarter 3 53,186 26,948 260 16,943 3,567 5,468

 13 October 15,949 1 1600 7,426 69 5,667 1,244 1,543

 14 November 16,615 23 1800 8,592 121 4,800 1,515 1,587

 15 December 15,757 29 1800 8,402 110 4,800 842 1,603

 16 Total for Quarter 4 48,321 24,420 300 15,267 3,601 4,733

 196,116 98,260 1,124 64,701 12,314 19,717

Total Year to

Date/Year

 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 1 Column: d

PST

Schedule Page: 400 Line No.: 2 Column: d

PST

Schedule Page: 400 Line No.: 3 Column: d

PST

Schedule Page: 400 Line No.: 4 Column: e

Reflects actual demands of control area load at time of Transmission System Peak. 

Schedule Page: 400 Line No.: 4 Column: f

Reflects actual demands of control area load at time of Transmission System Peak. 

Schedule Page: 400 Line No.: 4 Column: g

Reflects reservations in OASIS at time of Transmission System Peak. 

Schedule Page: 400 Line No.: 4 Column: i

Reflects reservations in OASIS at time of Transmission System Peak. 

Schedule Page: 400 Line No.: 5 Column: d

PDT 

Schedule Page: 400 Line No.: 6 Column: d

PDT 

Schedule Page: 400 Line No.: 7 Column: d

PDT 

Schedule Page: 400 Line No.: 8 Column: e

Refer to footnote for line 4 column (e).

Schedule Page: 400 Line No.: 8 Column: f

Refer to footnote for line 4 column (f).

Schedule Page: 400 Line No.: 8 Column: g

Refer to footnote for line 4 column (g).

Schedule Page: 400 Line No.: 8 Column: i

Refer to footnote for line 4 column (i).

Schedule Page: 400 Line No.: 9 Column: d

PDT 

Schedule Page: 400 Line No.: 10 Column: d

PDT 

Schedule Page: 400 Line No.: 11 Column: d

PDT 

Schedule Page: 400 Line No.: 12 Column: e

Refer to footnote for line 4 column (e).

Schedule Page: 400 Line No.: 12 Column: f

Refer to footnote for line 4 column (f).

Schedule Page: 400 Line No.: 12 Column: g

Refer to footnote for line 4 column (g).

Schedule Page: 400 Line No.: 12 Column: i

Refer to footnote for line 4 column (i).

Schedule Page: 400 Line No.: 13 Column: d

PDT 

Schedule Page: 400 Line No.: 14 Column: d

PST

Schedule Page: 400 Line No.: 15 Column: d

PST

Schedule Page: 400 Line No.: 16 Column: e

Refer to footnote for line 4 column (e).

Schedule Page: 400 Line No.: 16 Column: f

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Refer to footnote for line 4 column (f).

Schedule Page: 400 Line No.: 16 Column: g

Refer to footnote for line 4 column (g).

Schedule Page: 400 Line No.: 16 Column: i

Refer to footnote for line 4 column (i).

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Monthly Peak

MW - Total

(a) (b) (c)

Month

NAME OF SYSTEM:

Day of

Monthly

Peak

(1) Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not 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).

(d)

Hour of

Monthly

 Peak

(e)

Imports into

ISO/RTO

(f)

Exports from

ISO/RTO

(g)

Through and

Out Service

(h)

Network

Service Usage

(i)

Point-to-Point

Service Usage

(j)

Total Usage

 1 January

 2 February

 3 March

 4 Total for Quarter 1

 5 April

 6 May

 7 June

 8 Total for Quarter 2

 9 July

 10 August

 11 September

 12 Total for Quarter 3

 13 October

 14 November

 15 December

 16 Total for Quarter 4

Total Year to

Date/Year

 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

ELECTRIC ENERGY ACCOUNT

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Item

(a) (b) (a) (b)

Line

 No. MegaWatt Hours Item MegaWatt Hours

 Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

1 SOURCES OF ENERGY

2 Generation (Excluding Station Use):

3 Steam 44,918,646

4 Nuclear

5 Hydro-Conventional 3,748,308

6 Hydro-Pumped Storage -2,784

7 Other 8,975,021

8 Less Energy for Pumping

Net Generation (Enter Total of lines 3 57,639,191

through 8)

9

10 Purchases 11,417,025

11 Power Exchanges:

12 Received 14,493,755

13 Delivered 14,289,088

14 Net Exchanges (Line 12 minus line 13) 204,667

15 Transmission For Other (Wheeling)

16 Received 13,164,045

17 Delivered 13,164,045

Net Transmission for Other (Line 16 minus

line 17)

18

19 Transmission By Others Losses -300,756

TOTAL (Enter Total of lines 9, 10, 14, 18 68,960,127

and 19)

20

21 DISPOSITION OF ENERGY

Sales to Ultimate Consumers (Including 53,015,534

Interdepartmental Sales)

22

Requirements Sales for Resale (See 220,852

instruction 4, page 311.)

23

Non-Requirements Sales for Resale (See 11,193,740

instruction 4, page 311.)

24

25 Energy Furnished Without Charge

Energy Used by the Company (Electric 142,578

Dept Only, Excluding Station Use)

26

27 Total Energy Losses 4,387,423

TOTAL (Enter Total of Lines 22 Through 68,960,127

27) (MUST EQUAL LINE 20)

28

FERC FORM NO. 1 (ED. 12-90) Page 401a
(d)

Day of Month

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

MONTHLY PEAKS AND OUTPUT

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Total Monthly Energy Megawatts

(a) (b) (c)

Hour

(e)

MONTHLY PEAK

Month

NAME OF SYSTEM:

Monthly Non-Requirments

Sales for Resale &

Associated Losses (See Instr. 4)

1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required

information for each non- integrated system. 

2. Report in column (b) by month the system’s output in Megawatt hours for each month.

3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.

4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.

5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).

(f)

 29 January 6,184,473 1,076,008 8,152 7 1800 PST

 30 February 5,381,058 878,419 8,002 22 0800 PST

 31 March 5,638,659 985,758 7,574 9 1900 PST

 32 April 5,371,748 1,034,439 7,264 6 0900 PDT

 33 May 5,510,114 1,091,408 7,092 6 0800 PDT

 34 June 5,488,340 800,018 8,824 28 1700 PDT

 35 July 6,264,414 759,612 9,398 27 1600 PDT

 36 August 6,053,365 783,730 9,418 16 1600 PDT

 37 September 5,428,087 866,699 8,168 3 1700 PDT

 38 October 5,498,485 898,230 7,426 1 1600 PDT

 39 November 5,777,818 924,018 8,592 23 1800 PST

 40 December 6,363,566 1,095,401 8,402 29 1800 PST

FERC FORM NO. 1 (ED. 12-90) Page 401b

41 TOTAL 68,960,127 11,193,740
Schedule Page: 401 Line No.: 26 Column: b

For metered locations only.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

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

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of

X

04/18/2011 2010/Q4

Line

 No.

Item

(a) (b) (c)

Plant

Name:

Plant

Name:

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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Outdoor Boiler Full Outdoor

 3 Year Originally Constructed 1954 1981

 4 Year Last Unit was Installed 1957 1981

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 188.60 414.00

 6 Net Peak Demand on Plant - MW (60 minutes) 175 397

 7 Plant Hours Connected to Load 8750 7834

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 172 395

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 69 0

 12 Net Generation, Exclusive of Plant Use - KWh 1296004000 2621160000

 13 Cost of Plant: Land and Land Rights 956546 2468743

 14 Structures and Improvements 15099265 58700214

 15 Equipment Costs 103140699 459194385

 16 Asset Retirement Costs 6587976 39000

 17 Total Cost 125784486 520402342

 18 Cost per KW of Installed Capacity (line 17/5) Including 666.9379 1257.0105

 19 Production Expenses: Oper, Supv, & Engr 45596 1808025

 20 Fuel 20657109 51488605

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 1489090 6994684

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 2113830 1199979

 26 Misc Steam (or Nuclear) Power Expenses 4334676 1936373

 27 Rents 0 440

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 1881910

 30 Maintenance of Structures 416124 411499

 31 Maintenance of Boiler (or reactor) Plant 2448463 7201452

 32 Maintenance of Electric Plant 1020130 783588

 33 Maintenance of Misc Steam (or Nuclear) Plant 266812 2811384

 34 Total Production Expenses 32791830 76517939

 35 Expenses per Net KWh 0.0253 0.0292

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Composite Coal Oil Composite

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons Barrels Tons Barrels

 38 Quantity (Units) of Fuel Burned 595236 1978 0 1461977 3855 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 11941 138000 0 9321 130414 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 33.592 103.502 0.000 32.778 93.395 0.000

 41 Average Cost of Fuel per Unit Burned 34.360 103.502 0.000 34.972 93.395 0.000

 42 Average Cost of Fuel Burned per Million BTU 1.439 17.858 1.452 1.876 17.051 1.888

 43 Average Cost of Fuel Burned per KWh Net Gen 0.016 0.000 0.016 0.020 0.000 0.020

 44 Average BTU per KWh Net Generation 10968.605 8.845 10977.450 10397.977 8.056 10406.033

FERC FORM NO. 1 (REV. 12-03) Page 402
Hayden Hunter Unit No. 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of

X

04/18/2011 2010/Q4

Line

 No.

Item

(a) (b) (c)

Plant

Name:

Plant

Name:

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Outdoor Boiler Outdoor Boiler

 3 Year Originally Constructed 1965 1978

 4 Year Last Unit was Installed 1976 1978

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 81.40 457.70

 6 Net Peak Demand on Plant - MW (60 minutes) 79 429

 7 Plant Hours Connected to Load 8760 7027

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 78 418

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 0 0

 12 Net Generation, Exclusive of Plant Use - KWh 658624000 2572955000

 13 Cost of Plant: Land and Land Rights 379735 9688975

 14 Structures and Improvements 6012420 63087853

 15 Equipment Costs 62566079 270326440

 16 Asset Retirement Costs 532363 948199

 17 Total Cost 69490597 344051467

 18 Cost per KW of Installed Capacity (line 17/5) Including 853.6928 751.6965

 19 Production Expenses: Oper, Supv, & Engr 230757 0

 20 Fuel 12449623 35497583

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 983622 2817013

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 266648 0

 26 Misc Steam (or Nuclear) Power Expenses 508004 1630831

 27 Rents 0 3850

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 300437 0

 30 Maintenance of Structures 255415 2681686

 31 Maintenance of Boiler (or reactor) Plant 915621 11140805

 32 Maintenance of Electric Plant 358309 4518436

 33 Maintenance of Misc Steam (or Nuclear) Plant 332185 165029

 34 Total Production Expenses 16600621 58455233

 35 Expenses per Net KWh 0.0252 0.0227

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Composite Coal Oil Composite

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons Barrels Tons Barrels

 38 Quantity (Units) of Fuel Burned 307335 254 0 1210133 8614 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 11542 137377 0 11272 138000 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 38.449 104.561 0.000 0.000 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 40.342 104.561 0.000 28.601 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 1.748 18.119 1.755 1.269 17.759 1.299

 43 Average Cost of Fuel Burned per KWh Net Gen 0.019 0.000 0.019 0.013 0.000 0.013

 44 Average BTU per KWh Net Generation 10771.255 2.225 10773.480 10603.331 19.405 10622.736

FERC FORM NO. 1 (REV. 12-03) Page 402.1
Huntington Jim Bridger

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of

X

04/18/2011 2010/Q4

Line

 No.

Item

(a) (b) (c)

Plant

Name:

Plant

Name:

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Outdoor Boiler Semi-Outdoor

 3 Year Originally Constructed 1974 1974

 4 Year Last Unit was Installed 1977 1979

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 996.00 1545.10

 6 Net Peak Demand on Plant - MW (60 minutes) 893 1426

 7 Plant Hours Connected to Load 8567 8754

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 911 1412

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 163 335

 12 Net Generation, Exclusive of Plant Use - KWh 6107379000 9833000000

 13 Cost of Plant: Land and Land Rights 2386782 1161925

 14 Structures and Improvements 115210321 139527507

 15 Equipment Costs 689981960 890582328

 16 Asset Retirement Costs 2342186 4557783

 17 Total Cost 809921249 1035829543

 18 Cost per KW of Installed Capacity (line 17/5) Including 813.1739 670.3964

 19 Production Expenses: Oper, Supv, & Engr 25706 16396216

 20 Fuel 86524665 171454601

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 8276929 4209728

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 5958

 26 Misc Steam (or Nuclear) Power Expenses 10696874 -12919410

 27 Rents 3311 263196

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 1346600 539711

 30 Maintenance of Structures 2296785 8534063

 31 Maintenance of Boiler (or reactor) Plant 13486036 23962462

 32 Maintenance of Electric Plant 4313740 7817940

 33 Maintenance of Misc Steam (or Nuclear) Plant 1237313 2669801

 34 Total Production Expenses 128207959 222934266

 35 Expenses per Net KWh 0.0210 0.0227

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Oil Composite Coal Oil Composite

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons Barrels Tons Barrels

 38 Quantity (Units) of Fuel Burned 2687375 12209 0 5450917 17766 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 11923 138000 0 9227 138000 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 32.847 105.056 0.000 32.259 93.298 0.000

 41 Average Cost of Fuel per Unit Burned 31.719 105.056 0.000 31.150 93.298 0.000

 42 Average Cost of Fuel Burned per Million BTU 1.330 18.126 1.349 1.688 16.097 1.703

 43 Average Cost of Fuel Burned per KWh Net Gen 0.014 0.000 0.014 0.017 0.000 0.017

 44 Average BTU per KWh Net Generation 10492.431 11.587 10504.018 10229.994 10.472 10240.466

FERC FORM NO. 1 (REV. 12-03) Page 402.2
Little Mountain Hermiston

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of

X

04/18/2011 2010/Q4

Line

 No.

Item

(a) (b) (c)

Plant

Name:

Plant

Name:

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Outdoor Boiler Outdoor

 3 Year Originally Constructed 1972 1996

 4 Year Last Unit was Installed 1972 1996

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 16.00 279.60

 6 Net Peak Demand on Plant - MW (60 minutes) 16 244

 7 Plant Hours Connected to Load 8150 8160

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 14 237

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 6 0

 12 Net Generation, Exclusive of Plant Use - KWh 100773000 1595689000

 13 Cost of Plant: Land and Land Rights 635 842245

 14 Structures and Improvements 337028 12844996

 15 Equipment Costs 5219987 156205792

 16 Asset Retirement Costs 0 214373

 17 Total Cost 5557650 170107406

 18 Cost per KW of Installed Capacity (line 17/5) Including 347.3531 608.3956

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 13355445 58376865

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 971137 6473512

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 177184 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 14503766 64850377

 35 Expenses per Net KWh 0.1439 0.0406

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Gas

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF

 38 Quantity (Units) of Fuel Burned 1822511 0 0 11617259 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1044 0 0 1015 0 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.328 0.000 0.000 5.025 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 7.328 0.000 0.000 5.025 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 7.018 0.000 0.000 4.948 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.133 0.000 0.000 0.037 0.000 0.000

 44 Average BTU per KWh Net Generation 18884.155 0.000 0.000 7393.052 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.3
Gadsby Gas Peakers Currant Creek

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

PacifiCorp End of

X

04/18/2011 2010/Q4

Line

 No.

Item

(a) (b) (c)

Plant

Name:

Plant

Name:

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) Outdoor Outdoor

 3 Year Originally Constructed 2002 2005

 4 Year Last Unit was Installed 2002 2006

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 181.10 566.90

 6 Net Peak Demand on Plant - MW (60 minutes) 124 567

 7 Plant Hours Connected to Load 8760 8480

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 120 550

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 0 19

 12 Net Generation, Exclusive of Plant Use - KWh 255281000 2536660000

 13 Cost of Plant: Land and Land Rights 0 3403277

 14 Structures and Improvements 4241952 43827265

 15 Equipment Costs 74726370 307413223

 16 Asset Retirement Costs 0 134848

 17 Total Cost 78968322 354778613

 18 Cost per KW of Installed Capacity (line 17/5) Including 436.0482 625.8222

 19 Production Expenses: Oper, Supv, & Engr 0 79852

 20 Fuel 21345038 131063441

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 1314264 2617822

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 874

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 184471 500930

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 2593345 1246435

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 25437118 135509354

 35 Expenses per Net KWh 0.0996 0.0534

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Gas

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF

 38 Quantity (Units) of Fuel Burned 2903816 0 0 17850615 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1044 0 0 1059 0 0

 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.351 0.000 0.000 7.342 0.000 0.000

 41 Average Cost of Fuel per Unit Burned 7.351 0.000 0.000 7.342 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 7.040 0.000 0.000 6.931 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.084 0.000 0.000 0.052 0.000 0.000

 44 Average BTU per KWh Net Generation 11877.508 0.000 0.000 7454.884 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.4
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.

Colstrip Craig Dave Johnston

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(e) (f)

Plant

Name:

Plant

Name:

(d)

Plant

Name:

(Continued)

Steam Steam Steam 1

Conventional Outdoor Boiler Semi-Outdoor 2

1984 1979 1959 3

1986 1980 1972 4

155.60 172.10 816.80 5

156 166 739 6

8759 8738 8760 7

0 0 0 8

148 165 762 9

0 0 0 10

0 0 179 11

1192652000 1280372000 4699767000 12

1355853 137086 10449793 13

58269930 36555498 136781636 14

158023784 131117558 720141128 15

39236 35149 11315101 16

217688803 167845291 878687658 17

1399.0283 975.2777 1075.7684 18

23305 359605 571600 19

12505908 20249991 45364783 20

0 0 0 21

916378 1483108 31079 22

0 0 0 23

0 0 0 24

30744 640260 0 25

2096039 1332605 17884777 26

11536 984 37178 27

0 0 0 28

244102 632833 0 29

337249 465703 3141444 30

2011204 4374004 15993970 31

221939 1340513 10163144 32

357053 905893 1078857 33

18755457 31785499 94266832 34

0.0157 0.0248 0.0201 35

Coal Oil Composite Coal Oil Composite Coal Oil Composite 36

Tons Barrels Tons Barrels Tons Barrels 37

734650 968 0 652589 116 0 3309283 41961 0 38

8432 140000 0 9968 133693 0 7956 138000 0 39

14.581 92.012 0.000 29.993 121.915 0.000 12.786 99.452 0.000 40

16.902 92.012 0.000 30.910 121.915 0.000 12.447 99.452 0.000 41

1.002 15.649 1.009 1.550 21.714 1.556 0.782 17.159 0.858 42

0.010 0.000 0.010 0.016 0.000 0.016 0.009 0.001 0.010 43

10387.667 4.774 10392.441 10161.294 0.511 10161.805 11204.623 51.749 11256.372 44

FERC FORM NO. 1 (REV. 12-03) Page 403
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.

Hunter Unit No. 2 Hunter Unit No. 3 Hunter - Total Plant

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(e) (f)

Plant

Name:

Plant

Name:

(d)

Plant

Name:

(Continued)

Steam Steam Steam 1

Outdoor Boiler Outdoor Boiler Outdoor Boiler 2

1980 1983 1978 3

1980 1983 1983 4

294.50 495.60 1247.80 5

259 470 1132 6

7845 8321 8741 7

0 0 0 8

259 460 1137 9

0 0 0 10

0 0 212 11

1667003000 3296437000 7536395000 12

9688975 10275401 29653351 13

51968521 91113950 206170324 14

157360861 409450822 837138123 15

948199 948199 2844597 16

219966556 511788372 1075806395 17

746.9153 1032.6642 862.1625 18

0 0 0 19

24501492 43724944 103724019 20

0 0 0 21

2809276 2805955 8432244 22

0 0 0 23

0 0 0 24

0 0 0 25

-2612326 3066567 2085072 26

3850 3850 11550 27

0 0 0 28

0 0 0 29

2408766 2140085 7230537 30

5719032 8712884 25572721 31

1407896 2127173 8053505 32

264114 316315 745458 33

34502100 62897773 155855106 34

0.0207 0.0191 0.0207 35

Coal Oil Composite Coal Oil Composite Coal Oil Composite 36

Tons Barrels Tons Barrels Tons Barrels 37

830460 5116 0 1490676 9850 0 3531269 23580 0 38

11397 138000 0 11179 138000 0 11262 138000 0 39

0.000 0.000 0.000 0.000 0.000 0.000 29.640 103.202 0.000 40

28.875 0.000 0.000 28.645 0.000 0.000 28.684 103.202 0.000 41

1.267 17.612 1.292 1.281 17.947 1.310 1.273 17.806 1.302 42

0.014 0.000 0.014 0.013 0.000 0.013 0.013 0.000 0.013 43

11355.695 17.786 11373.481 10110.225 17.319 10127.544 10554.063 18.134 10572.197 44

FERC FORM NO. 1 (REV. 12-03) Page 403.1
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.

Naughton Wyodak Gadsby Steam Plant

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(e) (f)

Plant

Name:

Plant

Name:

(d)

Plant

Name:

(Continued)

Steam Steam Steam 1

Outdoor Boiler Conventional Outdoor 2

1963 1978 1951 3

1971 1978 1955 4

707.20 289.70 251.60 5

708 278 194 6

8760 8025 1661 7

0 0 0 8

700 268 231 9

0 0 0 10

140 59 35 11

5339603000 2047508000 104123000 12

4290826 210526 1252090 13

69837827 50594075 15053899 14

370503279 281199857 63130224 15

11639026 490453 587008 16

456270958 332494911 80023221 17

645.1795 1147.7215 318.0573 18

192179 299719 97491 19

91410507 18768172 12131762 20

0 0 0 21

5648415 0 18 22

0 0 0 23

0 0 0 24

27718 0 0 25

10584401 4081592 3681887 26

1203 3041 0 27

0 0 0 28

1511638 5028 0 29

1441379 515248 209753 30

7944104 7060084 1788302 31

1500466 1683796 955412 32

1182830 289616 124725 33

121444840 32706296 18989350 34

0.0227 0.0160 0.1824 35

Coal Gas Composite Coal Oil Composite Gas 36

Tons MCF Tons Barrels MCF 0 0 37

2817478 247058 0 1537341 6245 0 1569575 0 0 38

9858 1029 0 7776 138000 0 1049 0 0 39

32.477 7.083 0.000 11.858 98.961 0.000 7.729 0.000 0.000 40

31.823 7.083 0.000 11.806 98.961 0.000 7.729 0.000 0.000 41

1.614 6.886 1.638 0.759 17.074 0.784 7.369 0.000 0.000 42

0.017 0.000 0.017 0.009 0.000 0.009 0.117 0.000 0.000 43

10403.644 47.592 10451.236 11676.499 17.677 11694.176 15811.771 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.2
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.

Blundell Camas Co-Gen Chehalis

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(e) (f)

Plant

Name:

Plant

Name:

(d)

Plant

Name:

(Continued)

Steam - Geothermal Steam Combined Cycle 1

Indoor Outdoor Boiler Outdoor 2

1984 1996 2003 3

2007 1996 2003 4

38.10 61.50 593.30 5

36 28 516 6

8607 7000 3651 7

0 0 0 8

34 22 520 9

0 0 0 10

22 0 17 11

247359000 94061000 1288256000 12

41195596 0 1973791 13

7906027 5733734 23249210 14

68805675 28716806 317858946 15

1336278 0 689117 16

119243576 34450540 343771064 17

3129.7527 560.1714 579.4220 18

56831 0 191030 19

0 0 79197671 20

0 0 0 21

6726 0 0 22

3655727 0 0 23

0 0 0 24

0 7 2392798 25

1739984 0 0 26

6246 0 34243 27

0 0 0 28

0 0 0 29

225755 0 3045 30

164458 0 0 31

721856 505521 1285471 32

64240 0 0 33

6641823 505528 83104258 34

0.0269 0.0054 0.0645 35

Gas 36

MCF 37

00 0 0 0 0 9348871 0 0 38

00 0 0 0 0 1035 0 0 39

0.000 0.000 0.000 0.000 0.000 0.000 8.471 0.000 0.000 40

0.000 0.000 0.000 0.000 0.000 0.000 8.471 0.000 0.000 41

0.000 0.000 0.000 0.000 0.000 0.000 8.183 0.000 0.000 42

0.000 0.000 0.000 0.000 0.000 0.000 0.061 0.000 0.000 43

0.000 0.000 0.000 0.000 0.000 0.000 7512.959 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.3
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.

Lake Side

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

(e) (f)

Plant

Name:

Plant

Name:

(d)

Plant

Name:

(Continued)

Combined Cycle 1

Outdoor 2

2007 3

2007 4

591.30 0.00 0.00 5

581 0 0 6

7569 0 0 7

0 0 0 8

558 0 0 9

0 0 0 10

21 0 0 11

2537046000 0 0 12

17296760 0 0 13

27697517 0 0 14

306449096 0 0 15

0 0 0 16

351443373 0 0 17

594.3571 0.0000 0.0000 18

87746 0 0 19

129282273 0 0 20

0 0 0 21

0 0 0 22

0 0 0 23

0 0 0 24

2935756 0 0 25

0 0 0 26

0 0 0 27

0 0 0 28

0 0 0 29

552149 0 0 30

0 0 0 31

1952086 0 0 32

0 0 0 33

134810010 0 0 34

0.0531 0.0000 0.0000 35

Gas 36

MCF 37

17932546 0 0 000 0 0 0 38

1030 0 0 000 0 0 0 39

7.209 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40

7.209 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41

7.002 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42

0.051 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43

7277.198 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.4
Schedule Page: 402 Line No.: -1 Column: c

Cholla

The Cholla Plant is operated by Arizona Public Service Company. PacifiCorp owns 100% of Unit No. 4 and 36.66% of common

facilities. Data reported in column (c) represents PacifiCorp's share. PacifiCorp does not have employees at the Cholla Plant.

Fuel oil is used for start-up purposes. 

Schedule Page: 402 Line No.: -1 Column: d

Colstrip

The Colstrip Plant is operated by PPL Montana, LLC and is jointly owned. PacifiCorp owns a 10.0% share of Colstrip Plant Units No.

3 and No. 4. Data reported in column (d) represents PacifiCorp's share. PacifiCorp does not have employees at the Colstrip Plant.

Fuel oil is used for start-up purposes. 

Schedule Page: 402 Line No.: -1 Column: e

Craig

The Craig Plant is operated by Tri-State Generation and Transmission Association and is jointly owned. PacifiCorp owns a 19.28%

share of Craig Plant Units No. 1 and No. 2 and 12.86% of common facilities. Data in column (e) represents PacifiCorp's share.

PacifiCorp does not have employees at the Craig Plant.

Fuel oil is used for start-up purposes. 

Schedule Page: 402.1 Line No.: -1 Column: b

Hayden

The Hayden Plant is operated by Public Service Company of Colorado and is jointly owned. PacifiCorp owns a 24.5% (45 MW) share

of Hayden Unit No. 1, 12.6% (33 MW) share of Hayden Unit No. 2 and 17.5% of common facilities. Data reported in column (b)

represents PacifiCorp's share. PacifiCorp does not have employees at the Hayden Plant.

Fuel oil is used for start-up purposes. 

Schedule Page: 402.1 Line No.: -1 Column: c

Hunter Plant Unit No. 1

Hunter Plant Unit No. 1 is owned by PacifiCorp and Utah Municipal Power Agency with an undivided interest of 93.75% and 6.25%,

respectively. Data reported in column (c) represents PacifiCorp's share. Costs to operate and maintain this unit are charged to

appropriate FERC accounts. Costs that were billed to minority owners for the operation and maintenance (excluding fuel) of this unit

for calendar year 2010 were $1.9 million and were primarily charged to account 506.

Fuel oil is used for start-up purposes. 

Schedule Page: 402.1 Line No.: -1 Column: d

Hunter Plant Unit No. 2

Hunter Plant Unit No. 2 is owned by PacifiCorp, Deseret Power Electric Cooperative and Utah Associated Municipal Power Systems,

each with an undivided interest of 60.31%, 25.108% and 14.582%, respectively. Data reported in column (d) represents PacifiCorp's

share. Costs to operate and maintain this unit are charged to appropriate FERC accounts. Costs that were billed to minority owners for

the operation and maintenance (excluding fuel) of this unit for calendar year 2010 were $7.1 million and were primarily charged to

account 506.

Fuel oil is used for start-up purposes. 

Schedule Page: 402.1 Line No.: -1 Column: f

Hunter

Hunter Unit No. 1 is owned by PacifiCorp and Utah Municipal Power Agency with an undivided interest of 93.75% and 6.25%,

respectively. Hunter Unit No. 2 is owned by PacifiCorp, Deseret Power Electric Cooperative and Utah Associated Municipal Power

Systems, each with an undivided interest of 60.31%, 25.108% and 14.582%, respectively. Data in column (f) represents PacifiCorp's

share. Costs to operate and maintain this plant are charged to appropriate FERC accounts. Costs that were billed to minority owners for

the operation and maintenance (excluding fuel) of this plant for calendar year 2010 were $9.0 million and were primarily charged to

account 506.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Fuel oil is used for start-up purposes. 

Schedule Page: 402.2 Line No.: -1 Column: c

Jim Bridger

The Jim Bridger Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Idaho Power Company with an undivided

interest of 66 2/3% and 33 1/3%, respectively. Data reported in column (c) represents PacifiCorp's share. Costs to operate and maintain

this plant are charged to appropriate FERC accounts. Costs that were billed to minority owners for the operation and maintenance

(excluding fuel) of this plant for calendar year 2010 were $25.6 million and were primarily charged to account 506.

Fuel oil is used for start-up purposes. 

Schedule Page: 402.2 Line No.: -1 Column: e

Wyodak

The Wyodak Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Black Hills Corporation with an undivided

interest of 80% and 20%, respectively. Data in column (e) represents PacifiCorp's share. Costs to operate and maintain this plant are

charged to appropriate FERC accounts. Costs that were billed to minority owners for the operation and maintenance (excluding fuel) of

this plant for calendar year 2010 were $3.9 million and were primarily charged to account 506.

Fuel oil is used for start-up purposes. 

Schedule Page: 402.3 Line No.: -1 Column: c

Hermiston

The Hermiston Plant is operated by Hermiston Generating Company, L.P. and is jointly owned. PacifiCorp owns a 50.0% share of the

Hermiston Plant. Data reported in column (c) represents PacifiCorp's share. See Page 326 - Purchased Power of this Form No. 1 for

further information on Hermiston Generating Company, L.P. PacifiCorp does not have employees at the Hermiston Plant. 

Schedule Page: 402.3 Line No.: -1 Column: d

Blundell

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards ("RPS") or other regulatory requirements or (b) sold to third parties in the form of

renewable energy credits or other environmental commodities. 

Schedule Page: 402.3 Line No.: -1 Column: e

Camas Co-Gen

PacifiCorp owns the steam turbine generator and associated systems directly related to the operation of this unit at Georgia-Pacific

Corporation’s Camas, Washington paper mill. Modifications and upgrades to the existing Camas paper mill were necessary to supply

steam to the turbine and to ensure continued operation of the unit in the event of mill closure. Georgia-Pacific retained ownership of

these modifications. Georgia-Pacific supplies the fuel and delivers the steam to PacifiCorp’s turbine. PacifiCorp is responsible for

major maintenance costs only on the repair of the turbine generator and auxiliary equipment. None of the facilities are jointly owned.

Each asset is wholly owned, either by PacifiCorp or Georgia-Pacific Corporation. PacifiCorp does not have employees at the Camas

Paper Mill.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards ("RPS") or other regulatory requirements or (b) sold to third parties in the form of

renewable energy credits or other environmental commodities.

Schedule Page: 402 Line No.: 36 Column: b2

Fuel oil is used for start-up purposes. 

Schedule Page: 402 Line No.: 36 Column: f2

Fuel oil is used for start-up purposes. 

Schedule Page: 402.1 Line No.: 36 Column: e2

Fuel oil is used for start-up purposes.

Schedule Page: 402.2 Line No.: 36 Column: b2

Fuel oil is used for start-up purposes. 

Schedule Page: 402.2 Line No.: 36 Column: d2

Natural gas is used for start-up purposes. 

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
 2082

Copco No. 2

 2082

Copco No. 1

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (c)

Plant Name:

FERC Licensed Project No.

Plant Name:

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)

2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

 1 Kind of Plant (Run-of-River or Storage) Storage Run-of-River

 2 Plant Construction type (Conventional or Outdoor) Conventional Conventional

 3 Year Originally Constructed 1918 1925

 4 Year Last Unit was Installed 1922 1925

 5 Total installed cap (Gen name plate Rating in MW) 20.00 27.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 22 27

 7 Plant Hours Connect to Load 8,445 8,442

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 28 34

 10 (b) Under the Most Adverse Oper Conditions 28 34

 11 Average Number of Employees 1 2

 12 Net Generation, Exclusive of Plant Use - Kwh 67,544,000 88,801,000

 13 Cost of Plant

 14 Land and Land Rights 180,375 20,914

 15 Structures and Improvements 1,605,323 2,227,581

 16 Reservoirs, Dams, and Waterways 2,645,475 2,954,724

 17 Equipment Costs 5,157,577 10,376,116

 18 Roads, Railroads, and Bridges 105,442 479,588

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 9,694,192 16,058,923

 21 Cost per KW of Installed Capacity (line 20 / 5) 484.7096 594.7749

 22 Production Expenses

 23 Operation Supervision and Engineering 56,118 34,346

 24 Water for Power 0 0

 25 Hydraulic Expenses 731 987

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 810,982 1,069,662

 28 Rents 296 400

 29 Maintenance Supervision and Engineering 23 31

 30 Maintenance of Structures 6,721 17,305

 31 Maintenance of Reservoirs, Dams, and Waterways 107,335 26,905

 32 Maintenance of Electric Plant 34,707 18,463

 33 Maintenance of Misc Hydraulic Plant 31,315 27,038

 34 Total Production Expenses (total 23 thru 33) 1,048,228 1,195,137

 35 Expenses per net KWh 0.0155 0.0135

FERC FORM NO. 1 (REV. 12-03) Page 406
 20

Grace

 1927

Fish Creek

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (c)

Plant Name:

FERC Licensed Project No.

Plant Name:

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)

2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

 1 Kind of Plant (Run-of-River or Storage) Run-of River Storage

 2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional

 3 Year Originally Constructed 1952 1908

 4 Year Last Unit was Installed 1952 1923

 5 Total installed cap (Gen name plate Rating in MW) 11.00 33.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 10 30

 7 Plant Hours Connect to Load 5,825 7,468

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 10 33

 10 (b) Under the Most Adverse Oper Conditions 10 33

 11 Average Number of Employees 1 3

 12 Net Generation, Exclusive of Plant Use - Kwh 37,477,000 63,490,000

 13 Cost of Plant

 14 Land and Land Rights 0 62,169

 15 Structures and Improvements 914,418 1,667,210

 16 Reservoirs, Dams, and Waterways 12,176,260 9,208,496

 17 Equipment Costs 1,791,282 4,271,582

 18 Roads, Railroads, and Bridges 533,015 94,793

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 15,414,975 15,304,250

 21 Cost per KW of Installed Capacity (line 20 / 5) 1,401.3614 463.7652

 22 Production Expenses

 23 Operation Supervision and Engineering -12,286 -335,332

 24 Water for Power 5,832 0

 25 Hydraulic Expenses 43,753 49,460

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 298,775 1,678,486

 28 Rents 247 257

 29 Maintenance Supervision and Engineering 13 0

 30 Maintenance of Structures 29,386 31,126

 31 Maintenance of Reservoirs, Dams, and Waterways 43,522 299,114

 32 Maintenance of Electric Plant 31,376 72,032

 33 Maintenance of Misc Hydraulic Plant 32,252 117,051

 34 Total Production Expenses (total 23 thru 33) 472,870 1,912,194

 35 Expenses per net KWh 0.0126 0.0301

FERC FORM NO. 1 (REV. 12-03) Page 406.1
 935

Merwin

 1927

Lemolo No. 2

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (c)

Plant Name:

FERC Licensed Project No.

Plant Name:

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)

2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

 1 Kind of Plant (Run-of-River or Storage) Run-of River Storage (Re-Reg)

 2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional

 3 Year Originally Constructed 1956 1931

 4 Year Last Unit was Installed 1956 1958

 5 Total installed cap (Gen name plate Rating in MW) 33.00 136.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 34 151

 7 Plant Hours Connect to Load 8,404 8,670

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 34 151

 10 (b) Under the Most Adverse Oper Conditions 34 151

 11 Average Number of Employees 1 2

 12 Net Generation, Exclusive of Plant Use - Kwh 138,473,000 559,382,000

 13 Cost of Plant

 14 Land and Land Rights 0 1,951,411

 15 Structures and Improvements 3,268,622 41,087,704

 16 Reservoirs, Dams, and Waterways 22,631,929 9,971,566

 17 Equipment Costs 11,742,273 16,513,797

 18 Roads, Railroads, and Bridges 1,879,245 2,156,440

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 39,522,069 71,680,918

 21 Cost per KW of Installed Capacity (line 20 / 5) 1,197.6385 527.0656

 22 Production Expenses

 23 Operation Supervision and Engineering -43,247 970,245

 24 Water for Power 20,414 20,085

 25 Hydraulic Expenses 153,136 587,098

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 720,144 1,132,153

 28 Rents 864 24,077

 29 Maintenance Supervision and Engineering 44 0

 30 Maintenance of Structures 76,756 18,363

 31 Maintenance of Reservoirs, Dams, and Waterways 63,925 80,444

 32 Maintenance of Electric Plant 17,557 89,947

 33 Maintenance of Misc Hydraulic Plant 110,475 257,490

 34 Total Production Expenses (total 23 thru 33) 1,120,068 3,179,902

 35 Expenses per net KWh 0.0081 0.0057

FERC FORM NO. 1 (REV. 12-03) Page 406.2
 20

Soda

 1927

Slide Creek

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (c)

Plant Name:

FERC Licensed Project No.

Plant Name:

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)

2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

 1 Kind of Plant (Run-of-River or Storage) Run-of-River Storage

 2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional

 3 Year Originally Constructed 1951 1924

 4 Year Last Unit was Installed 1951 1924

 5 Total installed cap (Gen name plate Rating in MW) 18.00 14.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 16 9

 7 Plant Hours Connect to Load 8,689 6,085

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 18 14

 10 (b) Under the Most Adverse Oper Conditions 18 14

 11 Average Number of Employees 1 2

 12 Net Generation, Exclusive of Plant Use - Kwh 79,059,000 13,592,000

 13 Cost of Plant

 14 Land and Land Rights 0 511,083

 15 Structures and Improvements 1,802,822 672,316

 16 Reservoirs, Dams, and Waterways 5,671,411 6,938,925

 17 Equipment Costs 1,365,045 2,203,018

 18 Roads, Railroads, and Bridges 16,778 0

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 8,856,056 10,325,342

 21 Cost per KW of Installed Capacity (line 20 / 5) 492.0031 737.5244

 22 Production Expenses

 23 Operation Supervision and Engineering -30,085 -134,734

 24 Water for Power 9,544 0

 25 Hydraulic Expenses 71,596 20,983

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 384,354 558,071

 28 Rents 404 109

 29 Maintenance Supervision and Engineering 21 0

 30 Maintenance of Structures 39,094 7,959

 31 Maintenance of Reservoirs, Dams, and Waterways 31,844 -5,189

 32 Maintenance of Electric Plant 9,878 27,677

 33 Maintenance of Misc Hydraulic Plant 52,146 43,766

 34 Total Production Expenses (total 23 thru 33) 568,796 518,642

 35 Expenses per net KWh 0.0072 0.0382

FERC FORM NO. 1 (REV. 12-03) Page 406.3
 0 0

Olmsted

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (c)

Plant Name:

FERC Licensed Project No.

Plant Name:

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)

2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

 1 Kind of Plant (Run-of-River or Storage) Run-of-River

 2 Plant Construction type (Conventional or Outdoor) Conventional

 3 Year Originally Constructed 1904

 4 Year Last Unit was Installed 1922

 5 Total installed cap (Gen name plate Rating in MW) 10.30 0.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 9 0

 7 Plant Hours Connect to Load 8,740 0

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 10 0

 10 (b) Under the Most Adverse Oper Conditions 10 0

 11 Average Number of Employees 4 0

 12 Net Generation, Exclusive of Plant Use - Kwh 18,451,000 0

 13 Cost of Plant

 14 Land and Land Rights 0 0

 15 Structures and Improvements 368,652 0

 16 Reservoirs, Dams, and Waterways 529,217 0

 17 Equipment Costs 31,914 0

 18 Roads, Railroads, and Bridges 12,641 0

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 942,424 0

 21 Cost per KW of Installed Capacity (line 20 / 5) 91.4975 0.0000

 22 Production Expenses

 23 Operation Supervision and Engineering -15,403 0

 24 Water for Power 0 0

 25 Hydraulic Expenses 13,521 0

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 279,741 0

 28 Rents 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 2,626 0

 31 Maintenance of Reservoirs, Dams, and Waterways 2,524 0

 32 Maintenance of Electric Plant 3,235 0

 33 Maintenance of Misc Hydraulic Plant 131,459 0

 34 Total Production Expenses (total 23 thru 33) 417,703 0

 35 Expenses per net KWh 0.0226 0.0000

FERC FORM NO. 1 (REV. 12-03) Page 406.4
 1927

Clearwater No. 1 Cutler

 2420

Clearwater No. 2

 1927

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

FERC Licensed Project No.

(d) (e) (f)

Plant Name:

FERC Licensed Project No.

Plant Name:

FERC Licensed Project No.

Plant Name:

Line

 No.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production 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.

Run-of-River Run-of-River Storage 1

Outdoor Outdoor Conventional 2

1953 1953 1927 3

1953 1953 1927 4

15.00 26.00 30.00 5

9 17 23 6

8,570 7,982 6,001 7

 8

18 31 29 9

18 31 29 10

1 1 3 11

31,476,000 29,705,000 48,987,000 12

 13

0 0 3,505,129 14

1,222,452 1,632,875 3,969,184 15

4,547,301 14,757,082 7,485,343 16

1,188,143 1,624,689 14,550,291 17

52,034 250,151 572,059 18

0 0 0 19

7,009,930 18,264,797 30,082,006 20

467.3287 702.4922 1,002.7335 21

 22

-10,077 -7,877 -28,846 23

7,953 13,786 0 24

59,664 103,417 39,382 25

0 0 0 26

300,090 518,109 759,667 27

337 584 0 28

17 30 0 29

47,860 46,455 3,663 30

25,264 57,255 40,533 31

22,337 130,785 8,822 32

45,805 74,692 217,199 33

499,250 937,236 1,040,420 34

0.0159 0.0316 0.0212 35

FERC FORM NO. 1 (REV. 12-03) Page 407
 2082

Iron Gate Lemolo No. 1

 1927

JC Boyle

 2082

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

FERC Licensed Project No.

(d) (e) (f)

Plant Name:

FERC Licensed Project No.

Plant Name:

FERC Licensed Project No.

Plant Name:

Line

 No.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production 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.

Storage Storage Storage 1

Outdoor Outdoor Outdoor 2

1962 1958 1955 3

1962 1958 1955 4

18.00 97.98 31.99 5

18 83 30 6

8,458 5,336 8,239 7

 8

19 83 32 9

19 83 32 10

1 2 1 11

96,256,000 193,133,000 111,394,000 12

 13

341,706 26,277 0 14

4,614,730 2,873,701 2,114,257 15

13,091,301 14,155,361 15,131,501 16

2,404,786 14,890,342 5,896,348 17

1,076,116 886,710 475,419 18

0 0 0 19

21,528,639 32,832,391 23,617,525 20

1,196.0355 335.0928 738.2784 21

 22

367,234 298,124 -46,461 23

0 0 16,962 24

658 3,581 127,243 25

0 0 0 26

769,556 657,449 654,914 27

267 298 718 28

18 112 37 29

639,872 15,644 84,758 30

52,214 32,677 80,793 31

67,152 31,089 139,175 32

18,025 70,419 158,417 33

1,914,996 1,109,393 1,216,556 34

0.0199 0.0057 0.0109 35

FERC FORM NO. 1 (REV. 12-03) Page 407.1
 1927

Toketee Prospect No. 2

 2630

Oneida

 20

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

FERC Licensed Project No.

(d) (e) (f)

Plant Name:

FERC Licensed Project No.

Plant Name:

FERC Licensed Project No.

Plant Name:

Line

 No.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production 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.

Storage Storage Run-of River 1

Conventional Conventional Conventional 2

1949 1915 1928 3

1950 1920 1928 4

42.50 30.00 32.00 5

43 25 36 6

8,298 8,752 8,420 7

 8

45 28 36 9

45 28 36 10

1 2 1 11

188,950,000 28,335,000 225,108,000 12

 13

0 36,698 105,168 14

2,210,324 1,406,986 2,946,404 15

10,706,970 6,475,575 25,003,207 16

3,270,264 5,155,281 3,599,742 17

264,441 503,332 305,071 18

0 0 0 19

16,451,999 13,577,872 31,959,592 20

387.1059 452.5957 998.7373 21

 22

-60,431 -314,475 212,037 23

22,535 0 20,803 24

169,047 44,963 2,826 25

0 0 0 26

725,356 983,833 685,121 27

954 233 2,706 28

49 0 37 29

68,552 18,692 46,539 30

79,036 0 129,919 31

129,613 71,597 20,553 32

121,953 118,567 50,833 33

1,256,664 923,410 1,171,374 34

0.0067 0.0326 0.0052 35

FERC FORM NO. 1 (REV. 12-03) Page 407.2
 1927

Soda Springs Yale

 2071

Swift No. 1

 2111

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

FERC Licensed Project No.

(d) (e) (f)

Plant Name:

FERC Licensed Project No.

Plant Name:

FERC Licensed Project No.

Plant Name:

Line

 No.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production 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.

Storage (Re-Reg) Storage Storage 1

Outdoor Conventional Conventional 2

1952 1958 1953 3

1952 1958 1953 4

11.00 240.00 134.00 5

12 255 164 6

8,670 6,235 6,339 7

 8

12 264 164 9

12 263 164 10

1 2 2 11

51,896,000 733,951,000 629,932,000 12

 13

0 7,813,808 8,349,393 14

1,165,632 11,153,113 7,183,730 15

13,609,199 41,214,434 27,489,478 16

2,177,660 16,263,319 14,830,132 17

56,124 1,012,079 1,426,051 18

0 0 0 19

17,008,615 77,456,753 59,278,784 20

1,546.2377 322.7365 442.3790 21

 22

-13,260 1,586,601 886,981 23

5,832 35,443 19,789 24

43,753 1,217,225 578,464 25

0 0 0 26

301,704 1,614,719 968,747 27

247 42,488 23,723 28

13 0 0 29

20,983 51,505 31,812 30

23,370 52,380 84,804 31

25,941 262,701 46,449 32

31,564 438,865 249,043 33

440,147 5,301,927 2,889,812 34

0.0085 0.0072 0.0046 35

FERC FORM NO. 1 (REV. 12-03) Page 407.3
 0 0 0

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

FERC Licensed Project No.

(d) (e) (f)

Plant Name:

FERC Licensed Project No.

Plant Name:

FERC Licensed Project No.

Plant Name:

Line

 No.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production 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.

 1

 2

 3

 4

0.00 0.00 0.00 5

0 0 0 6

0 0 0 7

 8

0 0 0 9

0 0 0 10

0 0 0 11

0 0 0 12

 13

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

 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

FERC FORM NO. 1 (REV. 12-03) Page 407.4
Schedule Page: 406 Line No.: -1 Column: b

Copco No. 1

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system. 

Schedule Page: 406 Line No.: -1 Column: c

Copco No. 2

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system. 

Schedule Page: 406 Line No.: -1 Column: d

Clearwater No. 1

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities. 

Schedule Page: 406 Line No.: -1 Column: e

Clearwater No. 2

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406 Line No.: -1 Column: f

Cutler

Costs reported for this plant do not include significant intangible costs due to relicensing, which are recorded in FERC account 302,

Franchises and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $963,138.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406 Line No.: 1 Column: b

Copco No. 1

Pondage for peaking - storage, Upper Klamath Lake 

Schedule Page: 406 Line No.: 1 Column: d

Clearwater No. 1

Forebay for peaking 

Schedule Page: 406 Line No.: 1 Column: e

Clearwater No. 2

Forebay for peaking 

Schedule Page: 406.1 Line No.: -1 Column: b

Fish Creek

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.1 Line No.: -1 Column: c

Grace

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the Bear

River system for the following projects at December 31, 2010 was $13,399,062: Grace, Oneida and Soda.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.1 Line No.: -1 Column: d

Iron Gate

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system. 

Schedule Page: 406.1 Line No.: -1 Column: e

JC Boyle

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system.

Schedule Page: 406.1 Line No.: -1 Column: f

Lemolo No. 1

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.1 Line No.: 1 Column: b

Fish Creek

Forebay for peaking 

Schedule Page: 406.1 Line No.: 1 Column: d

Iron Gate

Storage for regulation 

Schedule Page: 406.1 Line No.: 1 Column: e

JC Boyle

Pondage for peaking - storage, Upper Klamath Lake 

Schedule Page: 406.1 Line No.: 1 Column: f

Lemolo No. 1

Storage, Lemolo Lake 

Schedule Page: 406.2 Line No.: -1 Column: b

Lemolo No. 2

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities. 

Schedule Page: 406.2 Line No.: -1 Column: c

Merwin

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Lewis River system for the following projects at December 31, 2010 was $39,672,471: Merwin, Yale, and Swift No. 1.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities. 

Schedule Page: 406.2 Line No.: -1 Column: d

Toketee

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
energy credits or other environmental commodities. 

Schedule Page: 406.2 Line No.: -1 Column: e

Oneida

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the Bear

River system for the following projects at December 31, 2010 was $13,399,062: Grace, Oneida and Soda.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.2 Line No.: -1 Column: f

Prospect No. 2

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement at Prospect

Unit Nos. 1, 2, and 4 at December 31, 2010 was $6,987,430.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.2 Line No.: 1 Column: b

Lemolo No. 2

Storage, Lemolo Lake 

Schedule Page: 406.2 Line No.: 1 Column: d

Toketee

Pondage for peaking - storage, Lemolo Lake 

Schedule Page: 406.2 Line No.: 1 Column: f

Prospect No. 2

Forebay for peaking 

Schedule Page: 406.3 Line No.: -1 Column: b

Slide Creek

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.3 Line No.: -1 Column: c

Soda

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the Bear

River system for the following projects at December 31, 2010 was $13,399,062: Grace, Oneida and Soda.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.3 Line No.: -1 Column: d

Soda Springs

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.4
All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities. 

Schedule Page: 406.3 Line No.: -1 Column: e

Swift No. 1

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Lewis River system for the following projects at December 31, 2010 was $39,672,471: Merwin, Yale, and Swift No. 1.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.3 Line No.: -1 Column: f

Yale

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Lewis River system for the following projects at December 31, 2010 was $39,672,471: Merwin, Yale, and Swift No. 1.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Schedule Page: 406.4 Line No.: -1 Column: b

Olmsted

The Olmsted Plant is owned by the U.S. Bureau of Land Reclamation. PacifiCorp has a 25-year lease beginning in 1990. PacifiCorp

operates the plant and owns all the generation. The cost of the Olmsted plant includes leasehold improvements and facilities which

PacifiCorp holds title.

All or some of the renewable energy attributes associated with generation from this generating facility may be: (a) used in future years

to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable

energy credits or other environmental commodities.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.5
FERC Licensed Project No.

Plant Name:

(b)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

Item

(a)

1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings)

2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in

a footnote. Give project number.

3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.

4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each

plant.

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."

 1 Type of Plant Construction (Conventional or Outdoor)

 2 Year Originally Constructed

 3 Year Last Unit was Installed

 4 Total installed cap (Gen name plate Rating in MW)

 5 Net Peak Demaind on Plant-Megawatts (60 minutes)

 6 Plant Hours Connect to Load While Generating

 7 Net Plant Capability (in megawatts)

 8 Average Number of Employees

 9 Generation, Exclusive of Plant Use - Kwh

 10 Energy Used for Pumping

 11 Net Output for Load (line 9 - line 10) - Kwh

 12 Cost of Plant

 13 Land and Land Rights

 14 Structures and Improvements

 15 Reservoirs, Dams, and Waterways

 16 Water Wheels, Turbines, and Generators

 17 Accessory Electric Equipment

 18 Miscellaneous Powerplant Equipment

 19 Roads, Railroads, and Bridges

 20 Asset Retirement Costs

 21 Total cost (total 13 thru 20)

 22 Cost per KW of installed cap (line 21 / 4)

 23 Production Expenses

 24 Operation Supervision and Engineering

 25 Water for Power

 26 Pumped Storage Expenses

 27 Electric Expenses

 28 Misc Pumped Storage Power generation Expenses

 29 Rents

 30 Maintenance Supervision and Engineering

 31 Maintenance of Structures

 32 Maintenance of Reservoirs, Dams, and Waterways

 33 Maintenance of Electric Plant

 34 Maintenance of Misc Pumped Storage Plant

 35 Production Exp Before Pumping Exp (24 thru 34)

 36 Pumping Expenses

 37 Total Production Exp (total 35 and 36)

 38 Expenses per KWh (line 37 / 9)

FERC FORM NO. 1 (REV. 12-03) Page 408
FERC Licensed Project No.

Plant Name:

FERC Licensed Project No.

Plant Name:

(d)

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)

PacifiCorp X

04/18/2011 2010/Q4

Line

 No.

FERC Licensed Project No.

Plant Name:

(c) (e)

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.

 1

 2

 3

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 5

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 8

 9

 10

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 37

 38

FERC FORM NO. 1 (REV. 12-03) Page 409
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

GENERATING PLANT STATISTICS (Small Plants)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Plant

Installed Capacity

(a) (b) (c)

Cost of Plant

Net Peak

Demand

(d)

Year

Orig.

Const. Name Plate Rating

(In MW) MW

(60 min.)

Net Generation

Excluding

Plant Use

(e) (f)

1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and 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.

 1 Hydroelectric : Licensed Proj. No.

 2 Ashton 2381 1917 6.85 4.9 22,728,000 8,910,187

 3 Bend 1913 1.11 1.0 2,439,000 1,314,472

 4 Big Fork 2652 1910 4.15 4.6 32,262,000 7,207,761

 5 Cline Falls 1913 1.00

 6 Condit 2342 1913 13.70 15.0 95,220,000 6,935,270

 7 Eagle Point 1957 2.81 2.8 17,206,000 1,795,497

 8 East Side 2082 1924 3.20 3.0 4,399,000 1,991,695

 9 Fall Creek 2082 1903 2.20 2.0 11,086,000 1,365,095

 10 Fountain Green 1922 0.16 0.1 646,000 597,630

 11 Granite 1896 2.00 1.2 6,403,000 5,237,598

 12 Gunlock 1917 0.75 0.5 1,527,000 672,853

 13 Last Chance 1983 1.73 1.3 3,232,000 2,802,615

 14 Paris 1910 0.72 0.7 2,275,000 416,673

 15 Pioneer 2722 1897 5.00 4.0 15,484,000 10,807,561

 16 Powerdale 2659 1923 6.00 122,396

 17 Prospect No. 1 2630 1912 3.76 4.6 22,455,000 1,731,817

 18 Prospect No. 3 2337 1932 7.20 7.7 35,330,000 7,001,153

 19 Prospect No. 4 2630 1944 1.00 0.9 3,917,000 1,596,217

 20 Sand Cove 1926 0.80 0.5 1,542,000 933,993

 21 Snake Creek 1910 1.18 0.9 3,079,000 992,623

 22 Stairs 597 1895 1.00 1.2 5,587,000 1,607,647

 23 St. Anthony 2381 1915 0.50 1,337,279

 24 Veyo 1920 0.50 0.3 1,130,000 875,122

 25 Viva Naughton 1986 0.74 0.6 1,440,000 1,194,486

 26 Wallowa Falls 308 1921 1.10 1.0 7,925,000 2,833,031

 27 Weber 1744 1911 3.85 2.0 15,316,000 2,848,017

 28 West Side 2082 1908 0.60 0.6 288,000 468,574

 29 Keno Regulating Dam 2082 7,500,010

 30 Upper Klamath Lake 2082 3,847,005

 31 North Umpqua 1927 15,446,611

 32

 33 Pumping Plant:

 34 Lifton 1917 -4.50 -3.0 -2,784,000 19,198,557

 35

 36 Wind:

 37 Dunlap Ranch I 2010 111.00 111.0 102,429,000 238,882,767

 38 Foote Creek 1999 32.62 32.6 93,145,000 37,037,356

 39 Glenrock 2008 99.00 103.0 287,941,000 199,905,929

 40 Glenrock III 2009 39.00 38.0 99,967,000 87,185,602

 41 Rolling Hills 2009 99.00 99.0 252,669,000 201,242,950

 42 Goodnoe Hills 2008 94.00 95.0 212,268,000 180,512,024

 43 Leaning Juniper 1 2006 100.50 102.0 223,558,000 174,536,399

 44 Marengo 2007 140.40 137.0 330,943,000 237,368,036

 45 Marengo II 2008 70.20 68.0 165,475,000 128,127,213

 46 Seven Mile Hill 2008 99.00 102.0 324,123,000 199,246,447

FERC FORM NO. 1 (REV. 12-03) Page 410
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

GENERATING PLANT STATISTICS (Small Plants)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

Name of Plant

Installed Capacity

(a) (b) (c)

Cost of Plant

Net Peak

Demand

(d)

Year

Orig.

Const. Name Plate Rating

(In MW) MW

(60 min.)

Net Generation

Excluding

Plant Use

(e) (f)

1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and 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.

 1 Seven Mile Hill II 2008 19.50 19.0 67,722,000 41,819,719

 2 High Plains 2009 99.00 98.0 257,349,000 219,300,133

 3 McFadden Ridge I 2009 28.50 29.7 77,366,000 56,796,654

 4

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FERC FORM NO. 1 (REV. 12-03) Page 410.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

GENERATING PLANT STATISTICS (Small Plants) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. (g) (h) (i) (j) (k) (l)

Operation

Exc'l. Fuel

Production Expenses

Fuel Maintenance Kind of Fuel Fuel Costs (in cents

(per Million Btu)

3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,

Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped 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

Retire. Costs) Per MW

 1

 1,300,757 583,930 45,664 Water 2

 1,184,209 148,628 17,542 Water 3

 1,736,810 357,653 47,580 Water 4

 4,817 2,459 Water 5

 506,224 382,803 63,030 Water 6

 638,967 266,477 26,623 Water 7

 622,405 309,345 5,827 Water 8

 620,498 142,943 70,875 Water 9

 3,735,188 32,978 7,685 Water 10

 2,618,799 130,753 42,754 Water 11

 897,137 42,609 26,682 Water 12

 1,620,009 126,034 30,259 Water 13

 578,713 58,114 39,669 Water 14

 2,161,512 393,203 113,444 Water 15

 20,399 74,593 7,778 Water 16

 460,590 171,988 26,648 Water 17

 972,382 398,584 299,515 Water 18

 1,596,217 73,051 21,065 Water 19

 1,167,491 43,449 18,605 Water 20

 841,206 108,396 23,818 Water 21

 1,607,647 117,470 40,962 Water 22

 2,674,558 26,946 2,453 Water 23

 1,750,244 47,377 160,866 Water 24

 1,614,170 42,492 52,594 Water 25

 2,575,483 25,876 40,600 Water 26

 739,745 239,831 48,364 Water 27

 780,957 44,142 18,192 Water 28

 14,745 3,605 29

 318,425 27,325 30

 31

 32

 33

 -4,266,346 312,143 73,794 Water 34

 35

 36

 2,152,097 583,645 1,996 Wind 37

 1,135,419 1,919,055 Wind 38

 2,019,252 1,494,484 316,402 Wind 39

 2,235,528 365,258 120,223 Wind 40

 2,032,757 1,043,021 305,182 Wind 41

 1,920,341 2,142,887 487,584 Wind 42

 1,736,681 2,526,331 45,278 Wind 43

 1,690,656 5,295,498 49,266 Wind 44

 1,825,174 1,386,749 24,633 Wind 45

 2,012,590 1,877,605 168,426 Wind 46

FERC FORM NO. 1 (REV. 12-03) Page 411
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

GENERATING PLANT STATISTICS (Small Plants) (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. (g) (h) (i) (j) (k) (l)

Operation

Exc'l. Fuel

Production Expenses

Fuel Maintenance Kind of Fuel Fuel Costs (in cents

(per Million Btu)

3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,

Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped 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

Retire. Costs) Per MW

 2,144,601 353,524 34,025 Wind 1

 2,215,153 914,989 1,471,333 Wind 2

 1,992,865 254,778 408,712 Wind 3

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FERC FORM NO. 1 (REV. 12-03) Page 411.1
Schedule Page: 410 Line No.: 1 Column: a

Common river system costs for the operation of these facilities are allocated to each plant based upon the unit’s name plate rating.

This footnote applies to all hydroelectric generating facilities with current generation. All or some of the renewable energy attributes

associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio

standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental

commodities.

Schedule Page: 410 Line No.: 2 Column: a

Ashton

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $318,793.

Schedule Page: 410 Line No.: 3 Column: a

Bend

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $125,903.

Schedule Page: 410 Line No.: 4 Column: a

Big Fork

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $535,284.

Schedule Page: 410 Line No.: 5 Column: a

Cline Falls

The Cline Falls hydroelectric generating facility was retired in August 2010.

Schedule Page: 410 Line No.: 6 Column: a

Condit

In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectric facility was signed by PacifiCorp, state and

federal agencies and non-governmental organizations. In early February 2005, the parties agreed to modify the settlement agreement,

establishing a total cost to decommission not to exceed $21 million, excluding inflation. In October 2010, the Washington Department

of Ecology issued a Clean Water Act 401 certificate, and in December 2010, the FERC issued a surrender order for project

decommissioning. In January 2011, PacifiCorp filed a request for clarification and rehearing of the surrender order and a motion for

stay with the FERC. In April 2011, a motion for extension of time was filed with the FERC requesting that the FERC allow project

decommissioning to be delayed until 2012 as the FERC has not yet issued an order on PacifiCorp’s request for rehearing on the

surrender order. PacifiCorp will consider a 2011 decommissioning provided: (a) the FERC issues an order on rehearing in April 2011

granting all of PacifiCorp’s rehearing requests; (b) PacifiCorp’s contractor agrees to a later ‘notice to proceed date;’ (c) other parties to

the rehearing do not appeal the FERC’s order; and (d) PacifiCorp can feasibly manage a 2011 decommissioning. Remaining permitting

includes a Section 404 permit from the United States Army Corps of Engineers.

Schedule Page: 410 Line No.: 8 Column: a

East Side

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system.

Schedule Page: 410 Line No.: 9 Column: a

Fall Creek

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

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

Schedule Page: 410 Line No.: 12 Column: a

Gunlock

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $40,050.

Schedule Page: 410 Line No.: 15 Column: a

Pioneer

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $109,275.

Schedule Page: 410 Line No.: 16 Column: a

Powerdale

In June 2003, PacifiCorp entered into a settlement agreement to decommission the 6-MW Powerdale hydroelectric facility rather than

pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. In 2007, the FERC

authorized PacifiCorp to cease generation at the facility and approved PacifiCorp's proposed accounting entries to defer the remaining

net book value and any additional removal costs of the system as a regulatory asset. PacifiCorp received approval from its state

regulatory commissions to defer and recover these costs. In April 2010, PacifiCorp initiated removal of the Powerdale dam and

associated system features as stipulated in the FERC Surrender Order. As of October 31, 2010, decommissioning activities, including

dam removal and site restoration, were completed. PacifiCorp will monitor restored areas until early 2012 when the project land will

be transferred to the Columbia Land Trust, Oregon Department of Fish and Wildlife and Hood River County. Removal costs for the

Powerdale dam and associated system features were approximately $4 million, and additional monitoring costs are not expected to

exceed $1 million.

The remaining costs in column (f) represent land and equipment that will be transferred or sold after the plant is decommissioned.

Schedule Page: 410 Line No.: 17 Column: a

Prospect No. 1

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement at Prospect

Unit Nos. 1, 2, and 4 at December 31, 2010 was $6,987,430.

Schedule Page: 410 Line No.: 18 Column: a

Prospect No. 3

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at Prospect Unit No. 3 at December 31, 2010 was

$78,412.

Schedule Page: 410 Line No.: 19 Column: a

Prospect No. 4

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement at Prospect

Unit Nos. 1, 2, and 4 at December 31, 2010 was $6,987,430.

Schedule Page: 410 Line No.: 21 Column: a

Snake Creek

In March 2011, PacifiCorp entered into an agreement for the sale of the Snake Creek hydroelectric generating facility with Heber Light

& Power Company. The sale will close after all regulatory approvals have been obtained. PacifiCorp is in the process of filing

applications for approval of the sale with the Oregon Public Utility Commission, California Public Utilities Commission and Wyoming

Public Service Commission.

Schedule Page: 410 Line No.: 22 Column: a

Stairs

Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $85,726.

Schedule Page: 410 Line No.: 23 Column: a

St. Anthony

Licensed Project No. 2381 applicable to both Ashton and St. Anthony plants.

Schedule Page: 410 Line No.: 27 Column: a

Weber

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises

and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2010 was $290,688.

Schedule Page: 410 Line No.: 28 Column: a

West Side

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system.

Schedule Page: 410 Line No.: 29 Column: a

Keno Regulating Dam

Used in regulating the release of water from Klamath Lake and in maintaining proper water surface level in the Klamath River between

Klamath Falls and Keno, Oregon.

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system.

Schedule Page: 410 Line No.: 30 Column: a

Upper Klamath Lake

Storage reservoir for six plants on the Klamath River (Copco No. 1, Copco No. 2, East Side, West Side, JC Boyle and Iron Gate).

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No. 1, Copco No. 2, East Side, Fall

Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.

Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for an update regarding hydroelectric relicensing for PacifiCorp's

Klamath hydroelectric system.

Schedule Page: 410 Line No.: 31 Column: a

North Umpqua

Represents facilities that support the North Umpqua River system projects. All common roads, employee houses, control equipment,

etc. are in this account.

Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC

account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the

North Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No. 1, Lemolo No. 2,

Clearwater No. 1, Clearwater No. 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.

Schedule Page: 410 Line No.: 36 Column: a

This footnote applies to all wind-powered generating facilities. All or some of the renewable energy attributes associated with

generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other

regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

Schedule Page: 410 Line No.: 38 Column: a

Foote Creek

The Foote Creek wind-powered generating facility is operated by SeaWest Energy and owned by PacifiCorp and Eugene Water and

Electric Board with an undivided interest of 78.79% and 21.21%, respectively. Data reported in row 38 represents PacifiCorp's share.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 MALIN , OR PG&E ROUND MTN , CA 500.00 500.00 Steel Tower 47.00 1

 2 KLAMATH CO-GEN , OR CAPTAIN JACK , OR 500.00 500.00 Steel Tower 26.00 1

 3 MERIDIAN , OR KLAMATH CO-GEN , OR 500.00 500.00 Steel Tower 58.00 1

 4 ALVEY , OR DIXONVILLE 500 , OR 500.00 500.00 Steel Tower 58.00 1

 5 DIXONVILLE , OR MERIDIAN , OR 500.00 500.00 Steel Tower 74.00 1

 6 CAPTAIN JACK , OR MALIN , OR 500.00 500.00 Steel Tower 7.00 1

 7 MIDPOINT , OR MALIN , OR 500.00 500.00 Steel Tower 447.00 1

 8 COLSTRIP 4, MT Switchyard, MT 500.00 500.00 Steel Tower 1.00 1

 9 COLSTRIP, MT BROADVIEW A, MT 500.00 500.00 Steel Tower 112.00 1

 10 COLSTRIP, MT BROADVIEW B, MT 500.00 500.00 Steel Tower 116.00 1

 11 BROADVIEW, MT TOWNSEND A, MT 500.00 500.00 Steel Tower 133.00 1

 12 BROADVIEW, MT TOWNSEND B, MT 500.00 500.00 Steel Tower 133.00 1

 13 500 kV costs and expenses

 14

 15 Subtotal 500kV 1,212.00 12

 16

 17 BEN LOMOND , UT BORAH , ID 345.00 345.00 Wood - H 138.00 1

 18 BEN LOMOND , UT CAMP WILLIAMS , UT 345.00 345.00 Steel SP 70.00 1

 19 BEN LOMOND , UT TERMINAL , UT 345.00 345.00 47.00 1

 20 EMERY , UT CAMP WILLIAMS , UT 345.00 345.00 Steel Tower 121.00 1

 21 CAMP WILLIAMS , UT MONA #3 , UT 345.00 345.00 Wood - H 47.00 1

 22 NINETY SOUTH , UT CAMP WILLIAMS #1, UT 345.00 345.00 Steel SP 11.00 1

 23 CAMP WILLIAMS , UT MONA #1 , UT 345.00 345.00 Wood - H 47.00 1

 24 CAMP WILLIAMS , UT MONA #2 , UT 345.00 345.00 Steel Tower 47.00 1

 25 SPANISH FORK , UT CAMP WILLIAMS , UT 345.00 345.00 35.00 1

 26 TERMINAL , UT CAMP WILLIAMS #2,UT 345.00 345.00 Steel SP 26.00 1

 27 TERMINAL , UT CAMP WILLIAMS , UT 345.00 345.00 23.00 1

 28 EMERY , UT HUNTINGTON , UT 345.00 345.00 Wood - H 20.00 1

 29 EMERY , UT SIGURD #1 , UT 345.00 345.00 Steel - H 74.00 1

 30 EMERY , UT SIGURD #2 , UT 345.00 345.00 Steel - H 75.00 1

 31 FOUR CORNERS , NM PINTO , UT 345.00 345.00 Wood - H 101.00 1

 32 GOSHEN , ID KINPORT , ID 345.00 345.00 Wood - H 41.00 1

 33 HUNTINGTON , UT PINTO , UT 345.00 345.00 Wood - H 159.00 1

 34 HUNTINGTON , UT SPANISH FORK , UT 345.00 345.00 Wood - H 78.00 1

 35 TERMINAL , UT NINETY SOUTH , UT 345.00 345.00 Steel SP 16.00 1

FERC FORM NO. 1 (ED. 12-87) Page 422

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 MONA , UT SIGURD #1 , UT 345.00 345.00 Steel Tower 69.00 1

 2 MONA , UT SIGURD #2 , UT 345.00 345.00 69.00 1

 3 SIGURD , UT UT / NV BORDER , UT 345.00 345.00 Wood - H 190.00 1

 4 JIM BRIDGER , WY BORAH , ID 345.00 345.00 Steel Tower 240.00 1

 5 JIM BRIDGER , WY KINPORT , ID 345.00 345.00 Steel Tower 234.00 1

 6 MONA , UT HUNTINGTON , UT 345.00 345.00 Steel Tower 60.00 1

 7 CURRENT CREEK , UT MONA , UT 345.00 345.00 Steel SP 1.00 1

 8 CAMP WILLIAMS , UT MONA #4 , UT 345.00 345.00 Wood - H 5.00 42.00 1

 9 BEN LOMOND, UT TERMINAL, UT 345.00 345.00 Steel SP 47.00 1

 10 BEN LOMOND, UT TERMINAL, UT 345.00 345.00 47.00 1

 11 BEN LOMOND,UT POPULUS, ID 345.00 345.00 82.00 1

 12 BEN LOMOND, UT POPULUS, ID 345.00 345.00 Steel SP 86.00 1

 13 90TH SOUTH, UT CAMP WILLIAMS #4, UT 345.00 345.00 Steel SP 11.00 1

 14 90TH SOUTH, UT CAMP WILLIAMS #3, UT 345.00 345.00 11.00 1

 15 345 kV costs and expenses

 16

 17 Subtotal 345kV 1,987.00 383.00 33

 18

 19 ANTELOPE , ID ANACONDA , ID 230.00 230.00 Wood - H 76.00 1

 20 ANTELOPE , ID LOST RIVER , ID 230.00 230.00 Wood - H 20.00 1

 21 BEN LOMOND , UT NAUGHTON #1 , WY 230.00 230.00 Wood - H 88.00 1

 22 BEN LOMOND , UT NAUGHTON #2 , WY 230.00 230.00 Wood - H 88.00 1

 23 BIRCH CREEK , UT RAILROAD , WY 230.00 230.00 Wood - H 19.00 1

 24 TREASURETON , ID BRADY , ID 230.00 230.00 Wood - H 66.00 1

 25 GLEN CANYON , AZ SIGURD , UT 230.00 230.00 Wood - H 159.00 1

 26 GONDER (ELY) , UT PAVANT , UT 230.00 230.00 Wood - H 98.00 1

 27 NAUGHTON , WY TREASURETON , ID 230.00 230.00 Wood - H 80.00 1

 28 PAROWAN VALLEY , UT SIGURD , UT 230.00 230.00 Wood - H 94.00 1

 29 PAROWAN VALLEY , UT WEST CEDAR , UT 230.00 230.00 Wood - H 26.00 1

 30 PAVANT , UT SIGURD , UT 230.00 230.00 Wood - H 43.00 1

 31 ATLANTIC CITY, WY COLUMBIA GENEVA, WY 230.00 230.00 Wood - H 1.00 1

 32 PALISADES SS , WY BLUE RIM , WY 230.00 230.00 Wood - H 4.00 1

 33 BUFFALO , WY CASPER , WY 230.00 230.00 Wood - H 107.00 1

 34 GOOSE CREEK , WY BUFFALO , WY 230.00 230.00 Wood - H 43.00 1

 35 WYODAK , WY BUFFALO , WY 230.00 230.00 Wood - H 69.00 1

FERC FORM NO. 1 (ED. 12-87) Page 422.1

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 JIM BRIDGER , WY DAVE JOHNSTON , WY 230.00 230.00 Wood - H 229.00 1

 2 ROCK SPRINGS , WY JIM BRIDGER , WY 230.00 230.00 Wood - H 35.00 1

 3 JIM BRIDGER , WY SPENCE , WY 230.00 230.00 Wood - H 149.00 1

 4 BRIDGER PUMP, WY MANS FACE, WY 230.00 230.00 Wood - H 1.00 1

 5 CASPER , WY DAVE JOHNSTON , WY 230.00 230.00 Wood - H 33.00 1

 6 CASPER , WY RIVERTON , WY 230.00 230.00 Wood - H 110.00 1

 7 DAVE JOHNSTON , WY SPENCE , WY 230.00 230.00 Wood - H 31.00 1

 8 DAVE JOHNSTON , WY WYODAK , WY 230.00 230.00 Wood - H 70.00 1

 9 MONUMENT , WY SHUTE CREEK , WY 230.00 230.00 Wood - H 13.00 1

 10 FIREHOLE , WY MONUMENT , WY 230.00 230.00 Wood - H 49.00 1

 11 ROCK SPRINGS , WY FLAMING GORGE , UT 230.00 230.00 Wood - H 55.00 1

 12 YELLOWTAIL , MT GOOSE CREEK , WY 230.00 230.00 Wood - H 59.00 1

 13 NAUGHTON , WY MONUMENT , WY 230.00 230.00 Wood - H 30.00 1

 14 ROCK SPRINGS , WY MONUMENT , WY 230.00 230.00 Wood - H 41.00 1

 15 RIVERTON , WY ROCK SPRINGS , WY 230.00 230.00 Wood - H 118.00 1

 16 RIVERTON , WY THERMOPOLIS , WY 230.00 230.00 Wood - H 51.00 1

 17 THERMOPOLIS , WY YELLOWTAIL , MT 230.00 230.00 Wood - H 176.00 1

 18 CHAPPEL CREEK , WY CRAVEN CREEK , WY 230.00 230.00 Wood - H 30.00 1

 19 CRAVEN CREEK , WY NAUGHTON , WY 230.00 230.00 Wood - H 16.00 1

 20 CHAPPEL CREEK , WY JONAH GAS , WY 230.00 230.00 Wood - H 32.00 1

 21 CHAPPEL CREEK , WY CHIMNEY BUTTE, WY 230.00 230.00 Steel-SP 14.00 6.00 1

 22 MINERS , WY FOOTE CREEK , WY 230.00 230.00 Wood - H 39.00 1

 23 POINT OF ROCKS , WY ROCK SPRINGS , WY 230.00 230.00 Wood - H 27.00 1

 24 MONUMENT , WY CRAVEN CREEK , WY 230.00 230.00 Wood - H 20.00 1

 25 WINDSTAR, WY GLENROCK WIND, WY 230.00 230.00 Wood - H 13.00 1

 26 YAMSAY , OR KLAMATH FALLS , OR 230.00 230.00 Wood - H 63.00 1

 27 KLAMATH FALLS , OR MALIN , OR 230.00 230.00 Wood - H 35.00 1

 28 LONE PINE , OR KLAMATH FALLS , OR 230.00 230.00 Wood - H 76.00 1

 29 LONE PINE , OR MERIDIAN , OR 230.00 230.00 5.00 1

 30 GRANTS PASS , OR DIXONVILLE LINE 72, OR 230.00 230.00 Wood - H 62.00 1

 31 DIXONVILLE , OR RESTON BPA , OR 230.00 230.00 Wood - H 17.00 1

 32 TAP TO HANNA , OR HANNA BPA , OR 230.00 230.00 Wood - H 9.00 1

 33 DIXONVILLE 500 , OR DIXONVILLE 230 , OR 230.00 230.00 Wood - H 1.00 1

 34 MERIDIAN , OR GRANTS PASS , OR 230.00 230.00 Wood - H 35.00 1

 35 MERIDIAN , OR LONE PINE , OR 230.00 230.00 Steel SP 5.00 1

FERC FORM NO. 1 (ED. 12-87) Page 422.2

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 FAIRVIEW BPA , OR ISTHMUS , OR 230.00 230.00 Wood - H 12.00 1

 2 TROUTDALE BPA , OR PGE GRESHAM , OR 230.00 230.00 Steel Tow 6.00 1

 3 TROUTDALE BPA , OR LINNEMAN , OR 230.00 230.00 6.00 1

 4 SWIFT No. 1 , WA SWIFT No. 2 , WA 230.00 230.00 Wood - H 2.00 1

 5 SWIFT No. 2 , WA WOODLAND BPA SS , WA 230.00 230.00 Wood - H 23.00 1

 6 FRY , OR BETHEL , OR 230.00 230.00 Wood - H 26.00 1

 7 FRY , OR ALVEY , OR 230.00 230.00 Wood - H 45.00 1

 8 ALVEY , OR DIXONVILLE , OR 230.00 230.00 Wood - H 59.00 1

 9 HURRICANE , OR WALLA WALLA , WA 230.00 230.00 Wood - H 78.00 1

 10 MCNARY BPA , WA WALLA WALLA , WA 230.00 230.00 Wood - H 56.00 1

 11 WALLA WALLA , WA AVISTA LEWISTON , WA 230.00 230.00 Wood - H 45.00 1

 12 WALLA WALLA , WA WANAPUM , WA 230.00 230.00 Wood - H 33.00 1

 13 TALBOT , WA MARENGO , WA 230.00 230.00 Wood - H 8.00 1

 14 UNION GAP , WA MIDWAY BPA , WA 230.00 230.00 Wood - H 39.00 1

 15 WANAPUM , WA POMONA , WA 230.00 230.00 Wood - H 37.00 1

 16 POMONA , WA UNION GAP , WA 230.00 230.00 Wood - H 8.00 1

 17 230 kV costs and expenses

 18

 19 Subtotal 230kV 3,302.00 17.00 68

 20

 21 ID / MT BORDER , ID GOSHEN , ID 161.00 161.00 Wood - H 90.00 1

 22 ANTELOPE , ID GOSHEN , ID 161.00 161.00 Wood - H 45.00 1

 23 BONNEVILLE , ID EAGLEROCK , ID 161.00 161.00 Wood SP 9.00 1

 24 EAGLEROCK , ID SUGARMILL , ID 161.00 161.00 Wood SP 3.00 1

 25 GOSHEN , ID GRACE , ID 161.00 161.00 Wood - H 57.00 1

 26 GOSHEN , ID RIGBY , ID 161.00 161.00 Wood - H 31.00 1

 27 GOSHEN , ID SUGARMILL , ID 161.00 161.00 Wood SP 17.00 1

 28 SUGARMILL , ID RIGBY , ID 161.00 161.00 Wood SP 17.00 1

 29 EAGLEROCK , ID GOSHEN , ID 161.00 161.00 Wood - H 12.00 1

 30 YELLOWTAIL , MT RIMROCK , MT 161.00 161.00 Wood - H 46.00 1

 31 RIGBY , ID JEFFERSON , ID 161.00 161.00 Wood SP 18.00 1

 32 161 kV costs and expenses

 33

 34 Subtotal 161 kV 255.00 90.00 11

 35

FERC FORM NO. 1 (ED. 12-87) Page 422.3

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 WHEELON , ID AMERICAN FALLS , ID 138.00 138.00 Wood - H 86.00 1

 2 OQUIRRH , UT TOOELE , UT 138.00 138.00 Wood - SP 21.00 1

 3 OQUIRRH , UT KCC BARNEY , UT 138.00 138.00 Wood - H 5.00 1

 4 ANSCHTZ CO-GEN, WY RAILROAD , WY 138.00 138.00 Wood - H 22.00 1

 5 ANTELOPE , ID SCOVILLE #1 , ID 138.00 138.00 Wood - H 1.00 1

 6 ANTELOPE , ID SCOVILLE #2 , ID 138.00 138.00 Wood - H 1.00 1

 7 ASHLEY , UT CARBON , UT 138.00 138.00 Wood - H 92.00 1

 8 ASHLEY , UT VERNAL , UT 138.00 138.00 Wood - H 12.00 1

 9 BEKER INDUST , ID THREEMILE KNOLL , ID 138.00 138.00 Wood - H 4.00 1

 10 BEN LOMOND , UT BRIGHAM CITY , UT 138.00 138.00 Wood - H 14.00 1

 11 BEN LOMOND , UT EL MONTE , UT 138.00 138.00 Wood - H 14.00 1

 12 BEN LOMOND , UT EL MONTE , UT 138.00 138.00 Wood - H 13.00 1

 13 BEN LOMOND , UT HONEYVILLE , UT 138.00 138.00 22.00 1

 14 BEN LOMOND , UT CLINTON , UT 138.00 138.00 23.00 1

 15 BEN LOMOND , UT ANGEL , UT 138.00 138.00 Wood - SP 28.00 1

 16 BEN LOMOND , UT W ZIRCONIUM , UT 138.00 138.00 Wood - SP 14.00 1

 17 BEN LOMOND , UT WHEELON , UT 138.00 138.00 Steel Tower 42.00 1

 18 BRIGHAM CITY , UT WHEELON , UT 138.00 138.00 Wood - H 24.00 1

 19 CAMERON , UT PAROWAN , UT 138.00 138.00 Wood - H 35.00 1

 20 CAMERON , UT SIGURD , UT 138.00 138.00 Wood - H 64.00 1

 21 CARBON , UT HELPER , UT 138.00 138.00 Wood - H 2.00 1

 22 CARBON , UT HELPER , UT 138.00 138.00 Wood - H 2.00 1

 23 CARBON , UT SPANISH FORK , UT 138.00 138.00 Steel Tower 54.00 1

 24 CARBON , UT SPANISH FORK , UT 138.00 138.00 52.00 1

 25 THREEMILE KNOLL , ID GRACE #1 , ID 138.00 138.00 Wood - H 17.00 1

 26 THREEMILE KNOLL , ID GRACE #2 , ID 138.00 138.00 Wood - H 17.00 1

 27 THREEMILE KNOLL , ID MONSANTO 1 , ID 138.00 138.00 Wood - H 2.00 1

 28 THREEMILE KNOLL , ID MONSANTO 2 , ID 138.00 138.00 Wood - SP 2.00 1

 29 PAINTER , WY CLEAR CREEK , WY 138.00 138.00 Wood - SP 5.00 1

 30 COLUMBIA , WY MOUNDS SWRK , UT 138.00 138.00 Wood - H 7.00 1

 31 COTTONWOOD , UT MCCLELLAND , UT 138.00 138.00 Wood - SP 6.00 1

 32 COTTONWOOD , UT HAMMER , UT 138.00 138.00 Wood - SP 5.00 1

 33 COTTONWOOD , UT SILVER CREEK , UT 138.00 138.00 Wood - SP 29.00 1

 34 CUTLER , UT WHEELON , UT 138.00 138.00 Wood - SP 1.00 1

 35 ENTERPRISE , UT MIDDLETON , UT 138.00 138.00 Wood - H 20.00 1

FERC FORM NO. 1 (ED. 12-87) Page 422.4

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 WEST CEDAR , UT ENTERPRISE VALLEY, UT 138.00 138.00 Wood - H 33.00 1

 2 EVANSTON, WY RAILROAD, WY 138.00 138.00 Wood - SP 3.00 1

 3 FRANKLIN , UT SMITHFIELD , UT 138.00 138.00 Wood - SP 25.00 1

 4 FRANKLIN , ID TREASURETON , ID 138.00 138.00 Wood - SP 10.00 1

 5 JORDAN , UT MCCLELLAND , UT 138.00 138.00 Wood - SP 5.00 1

 6 GADSBY , UT TERMINAL , UT 138.00 138.00 Wood - SP 6.00 1

 7 JORDAN , UT TERMINAL , UT 138.00 138.00 Wood - SP 6.00 1

 8 TIMP , UT HALE , UT 138.00 138.00 Steel - SP 4.00 1

 9 TRI-CITY , UT AMERICAN FORK , UT 138.00 138.00 Steel - SP 14.00 1

 10 ABAJO , UT PINTO , UT 138.00 138.00 Wood - SP 44.00 1

 11 ONEIDA , ID GRACE , ID 138.00 138.00 Wood - H 19.00 1

 12 TREASURETON , ID GRACE 103 , ID 138.00 138.00 Steel Tower 25.00 1

 13 TREASURETON , ID GRACE 104 , ID 138.00 138.00 25.00 1

 14 NEBO , UT DRY CREEK , UT 138.00 138.00 Wood - H 37.00 1

 15 WESTFIELD, UT HIGHLAND, UT 138.00 138.00 Wood - H 42.00 1

 16 TIMP , UT SPANISH FORK , UT 138.00 138.00 Wood - SP 23.00 1

 17 HALE , UT TANNER , UT 138.00 138.00 Wood - H 7.00 1

 18 MOUNDS SWRK , UT HELPER , UT 138.00 138.00 Wood - H 29.00 1

 19 HONEYVILLE , UT WHEELON , UT 138.00 138.00 14.00 1

 20 HUNTINGTON , UT MCFADDEN , UT 138.00 138.00 Wood - H 7.00 1

 21 TERMINAL , UT KENNECOTT , UT 138.00 138.00 9.00 1

 22 KILN , UT NEBO , UT 138.00 138.00 Wood - H 30.00 1

 23 MCCLELLAND , UT MIDVALLEY , UT 138.00 138.00 Wood - SP 6.00 1

 24 MOUNDS SWRK , UT MOAB , UT 138.00 138.00 Wood - H 83.00 1

 25 MOAB , UT PINTO , UT 138.00 138.00 Wood - H 68.00 1

 26 NAUGHTON , WY NGPL , WY 138.00 138.00 Wood - H 35.00 1

 27 NAUGHTON , WY PAINTER , WY 138.00 138.00 Wood - H 45.00 1

 28 NGPL , WY TAP TO STR 204 , WY 138.00 138.00 Wood - H 12.00 1

 29 NGPL, WY WHITNEY, WY 138.00 138.00 Wood - H 1.00 1

 30 NINETY SOUTH , UT OQUIRRH , UT 138.00 138.00 Wood - SP 10.00 1

 31 TAYLORSVILLE , UT NINETY SOUTH , UT 138.00 138.00 Wood - SP 7.00 1

 32 MID VALLEY , UT NINETY SOUTH , UT 138.00 138.00 Wood - H 13.00 1

 33 NUCOR STEEL , UT WHEELON , UT 138.00 138.00 Wood - H 10.00 1

 34 ONEIDA , ID OVID , ID 138.00 138.00 Wood - H 23.00 1

 35 TREASURETON , ID ONEIDA , ID 138.00 138.00 Wood - H 6.00 1

FERC FORM NO. 1 (ED. 12-87) Page 422.5

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 PAINTER , WY RAILROAD , WY 138.00 138.00 Wood - H 7.00 1

 2 PAROWAN , UT WEST CEDAR , UT 138.00 138.00 Wood - H 21.00 1

 3 TAP TO ANGEL SOUTH, UT TAP TO PARRISH , UT 138.00 138.00 13.00 1

 4 PARRISH , UT TERMINAL , UT 138.00 138.00 Steel SP 16.00 1

 5 PARRISH , UT TERMINAL , UT 138.00 138.00 14.00 1

 6 RAILROAD , WY WHITNEY , WY 138.00 138.00 Wood - H 19.00 1

 7 BEN LOMOND , UT SYRACUSE , UT 138.00 230.00 Steel Tower 25.00 1

 8 TERMINAL , UT ROWLEY , UT 138.00 138.00 Wood - H 56.00 1

 9 GREEN CANYON , UT WHEELON , UT 138.00 138.00 Wood - SP 19.00 1

 10 SPANISH FORK , UT TANNER , UT 138.00 138.00 Wood - H 10.00 1

 11 TAP TO ANGEL NORTH, UT TAP TO PARRISH , UT 138.00 138.00 13.00 1

 12 TERMINAL , UT MIDVALLEY , UT 138.00 138.00 Wood - H 7.00 1

 13 TERMINAL , UT CENT / MIDVALLEY, UT 138.00 138.00 Steel - SP 7.00 1

 14 TERMINAL , UT TOOELE , UT 138.00 138.00 Wood - H 35.00 1

 15 WHEELON #103 , UT TREASURETON , ID 138.00 138.00 Steel Tower 29.00 1

 16 WHEELON #104 , UT TREASURETON , ID 138.00 138.00 29.00 1

 17 WHEELON #105 , UT TREASURETON , ID 138.00 138.00 Wood - H 29.00 1

 18 KCC BARNEY , UT KCCGRIND , UT 138.00 138.00 Wood - H 1.00 1

 19 TERMINAL , UT LAKE PARK , UT 138.00 138.00 Wood - H 14.00 1

 20 OQUIRRH , UT KCC BINGHAM , UT 138.00 138.00 Wood - H 8.00 1

 21 WEST CEDAR , UT THREE PEAKS, UT 138.00 138.00 Wood - SP 20.00 1

 22 HALE , UT SPANISH FORK , UT 138.00 138.00 Wood - H 18.00 1

 23 MID VALLEY , UT TAYLORSVILLE , UT 138.00 138.00 Wood - SP 5.00 1

 24 PARRISH , UT TERMINAL , UT 138.00 138.00 Steel - SP 14.00 1

 25 COLUMBIA, UT SUNNYSIDE, UT 138.00 138.00 Wood-H 2.00 1

 26 JERUSALM , UT NEBO , UT 138.00 138.00 Wood - H 26.00 1

 27 HALE , UT MIDWAY , UT 138.00 138.00 Wood - H 19.00 1

 28 DIMPLE DELL , UT DUMAS , UT 138.00 138.00 U/G 4.00 1

 29 HONEYVILLE , UT LAMPO , UT 138.00 138.00 Wood - H 25.00 1

 30 GADSBY , UT JORDAN , UT 138.00 138.00 Wood - SP 1.00 1

 31 MID VALLEY , UT COTTONWOOD , UT 138.00 138.00 Wood - SP 5.00 1

 32 NINETY SOUTH , UT SANDY , UT 138.00 138.00 Steel - SP 1.00 1

 33 MICRON , UT CAMP WILLIAMS , UT 138.00 138.00 9.00 1

 34 MCFADDEN , UT BLACKHAWK , UT 138.00 138.00 Wood - H 11.00 1

 35 NINETY SOUTH , UT QUARRY SUBSTATION, UT 138.00 138.00 Wood - SP 8.00 1

FERC FORM NO. 1 (ED. 12-87) Page 422.6

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

DESIGNATION

From To

(f) (g)

VOLTAGE (KV)

(Indicate where

other than

60 cycle, 3 phase)

Operating Designed

Type of

Supporting

Structure

LENGTH (Pole miles) (In the case of underground lines

report circuit miles)

On Structure

of Line

Designated

On Structures

of Another

Line

Number

Of

Circuits

(h)

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.

 1 EL MONTE , UT STR 30B , UT 138.00 138.00 Steel - SP 4.00 1

 2 EL MONTE , UT PIONEER , UT 138.00 138.00 Steel - SP 1.00 1

 3 SYRACUSE , UT CLEARFIELD SOUTH, UT 138.00 138.00 Steel - SP 1.00 1

 4 MID VALLEY , UT COTTONWOOD , UT 138.00 138.00 Steel - SP 5.00 1

 5 HAMMER , UT BUTLERVILLE , UT 138.00 138.00 2.00 1

 6 BUTLERVILLE , UT NINETY SOUTH , UT 138.00 138.00 Steel - SP 9.00 1

 7 KEARNS , UT TAYLORSVILLE , UT 138.00 138.00 Wood - SP 2.00 1

 8 SILVER CREEK SUB, UT JORDANELLE SUB , UT 138.00 138.00 Steel - SP 10.00 1

 9 KEARNS , UT WEST VALLEY , UT 138.00 138.00 Wood - SP 2.00 1

 10 RIVERDALE , UT 105 TAP , UT 138.00 138.00 Steel - SP 21.00 1

 11 OQUIRRH , UT SUNRISE / TRI-CITY, UT 138.00 138.00 Steel - SP 21.00 1

 12 OQUIRRH , UT BANGERTER / TRI-CITY, UT 138.00 138.00 23.00 1

 13 DYNAMO , UT TRI-CITY #2 , UT 138.00 138.00 5.00 1

 14 TIMP #2 , UT DYNAMO , UT 138.00 138.00 4.00 1

 15 MIDDLETON , UT ST. GEORGE , UT 138.00 138.00 Wood - H 1.00 1

 16 BRIDGERLAND , UT GREEN CANYON , UT 138.00 138.00 Steel - SP 16.00 1

 17 SYRACUSE , UT PARRISH, UT 138.00 230.00 Steel Tower 12.00 1

 18 BONANZA , UT CHAPITA , UT 138.00 138.00 Wood - H 8.00 1

 19 CENTRAL, UT SAINT GEORGE #1, UT 138.00 345.00 Steel - SP 20.00 1

 20 CENTRAL, UT SAINT GEORGE #2, UT 138.00 345.00 Steel - SP 20.00 1

 21 EBAY TAP, UT OQUIRRH, UT 138.00 138.00 Steel-SP 1.00 1

 22 138 kV costs and expenses

 23

 24 Subtotal 138 kV 1,945.00 277.00 126

 25

 26

 27 All 115 kV Lines 1,613.00

 28 All 69 kV Lines 2,978.00

 29 All 57 kV Lines 113.00

 30 All 46 kV Lines 2,610.00

 31

 32

 33

 34

 35

FERC FORM NO. 1 (ED. 12-87) Page 422.7

36 TOTAL 16,015.00 767.00 250
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

3-1852 ACSR 51/27 1

3-1272 ACSR 36/1 2

3-1272 ACSR 36/1 3

3-1272 ACSR 54/19 4

3-1272 ACSR 54/19 5

3-2250 AAC /91 6

3-1272 ACSR 36/1 7

 8

 9

 10

 11

 12

 13,778,585 269,650,316 283,428,901 1,361,408 39,666 1,401,074 13

 14

 13,778,585 269,650,316 283,428,901 1,361,408 39,666 1,401,074 15

 16

2-954 ACSR 54/7 17

2-1272 ACSR 45/7 18

2-1272 ACSR 45/7 19

2-1272 ACSR 45/7 20

2-954 ACSR 45/7 21

2-1272 ACSR 45/7 22

2-1272 ACSR 45/7 23

2-954 ACSR 54/7 24

2-1272 ACSR 45/7 25

2-1272 ACSR 45/7 26

2-1272 ACSR 45/7 27

2-954 ACSR 54/7 28

2-954 ACSR 54/7 29

2-954 ACSR 54/7 30

2-795 ACSR 45/7 31

2-795 ACSR 45/7 32

2-795 ACSR 45/7 33

2-1272 ACSR 45/7 34

2-1272 ACSR 45/7 35

FERC FORM NO. 1 (ED. 12-87) Page 423

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

2-795 ACSR 45/7 1

2-954 ACSR 54/7 2

2-954 ACSR 54/7 3

2-1272 ACSR 45/7 4

2-1272 ACSR 45/7 5

2-954 ACSR 54/7 6

2-954 ACSR 54/7 7

2-954 ACSR 54/7 8

2-1272 ACSR 45/7 9

2-1272 ACSR 45/7 10

2-1272 ACSR 45/7 11

2-1272 ACSR 45/7 12

 13

 14

 103,147,342 985,497,683 1,088,645,025 68,343 2,514,264 321,060 2,903,667 15

 16

 103,147,342 985,497,683 1,088,645,025 68,343 2,514,264 321,060 2,903,667 17

 18

1272 ACSR 45/7 19

795 ACSR 45/7 20

2-795 ACSR 26/7 21

2-795 ACSR 26/7 22

954 ACSR 54/7 23

795 ACSR 26/7 24

954 ACSR 45/7 25

795 ACSR 45/7 26

1272 ACSR 45/7 27

795 ACSR 45/7 28

795 ACSR 45/7 29

795 ACSR 45/7 30

1272 ACSR 36/1 31

1272 ACSR 36/1 32

1272 ACSR 36/1 33

795 ACSR 26/7 34

1272 ACSR 36/1 35

FERC FORM NO. 1 (ED. 12-87) Page 423.1

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

1272 ACSR 45/7 1

1272 ACSR 36/1 2

1272 ACSR 36/1 3

1272 ACSR 36/1 4

2-1272 ACSR 36/1 5

1272 ACSR 36/1 6

1272 ACSR 36/1 7

1272 ACSR 36/1 8

1272 ACSR 36/1 9

1272 ACSR 45/7 10

1272 ACSR 36/1 11

795 ACSR 26/7 12

1272 ACSR 36/1 13

1272 ACSR 36/1 14

1272 ACSR 36/1 15

1272 ACSR 36/1 16

1272 ACSR 36/1 17

954 ACSR 54/7 18

954 ACSR 54/7 19

1272 ACSR 45/7 20

1272 ACSR 36/1 21

1272 ACSR 36/1 22

1272 ACSR 36/1 23

1272 ACSR 45/7 24

1272 ACSR 45/7 25

795 ACSR 26/7 26

1272 ACSR 36/1 27

795 ACSR 26/7 28

1272 ACSR 36/1 29

1272 ACSR 36/1 30

795 ACSR 26/7 31

795 ACSR 26/7 32

1272 ACSR 36/1 33

1272 ACSR 36/1 34

1272 ACSR 54/19 35

FERC FORM NO. 1 (ED. 12-87) Page 423.2

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

1272 ACSR 36/1 1

954 ACSR 45/7 2

900 ACSR 54/7 3

954 ACSR 45/7 4

954 ACSR 45/7 5

1272 ACSR 36/1 6

1272 ACSR 36/1 7

1272 ACSR 36/1 8

1272 ACSR 36/1 9

1272 ACSR 36/1 10

1272 ACSR 36/1 11

1272 ACSR 36/1 12

795 ACSR 26/7 13

954 ACSR 45/7 14

1272 ACSR 36/1 15

1272 ACSR 36/1 16

 12,220,713 332,924,488 345,145,201 6,699 4,553,238 360,603 4,920,540 17

 18

 12,220,713 332,924,488 345,145,201 6,699 4,553,238 360,603 4,920,540 19

 20

250HH CU /7 21

397.5 ACSR 26/7 22

954 ACSR 45/7 23

954 ACSR 45/7 24

250HH CU /7 25

397.5 ACSR 26/7 26

397.5 ACSR 26/7 27

397.5 ACSR 26/7 28

1272 ACSR 45/7 29

556.5 ACSR 26/7 30

397.5 ACSR 26/7 31

 623,490 16,514,772 17,138,262 353,885 4,139 358,024 32

 33

 623,490 16,514,772 17,138,262 353,885 4,139 358,024 34

 35

FERC FORM NO. 1 (ED. 12-87) Page 423.3

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

250 CUHD /12 1

795 ACSR 45/7 2

795 ACSR 26/7 3

795 ACSR 26/7 4

397.5 ACSR 26/7 5

397.5 ACSR 26/7 6

397.5 ACSR 26/7 7

397.5 ACSR 26/7 8

795 ACSR 26/7 9

397.5 ACSR 26/7 10

795 ACSR 45/7 11

795 ACSR 45/7 12

250 CUHD /12 13

795 ACSR 45/7 14

795 ACSR 45/7 15

795 AAC /37 16

250 CUHD /12 17

795 ACSR 26/7 18

397.5 ACSR 26/7 19

397.5 ACSR 26/7 20

954 ACSR 54/7 21

556.5 ACSR 26/7 22

4/0 COMP 23

795 ACSR 26/7 24

250 CUHD /12 25

1272 ACSR 45/7 26

1272 ACSR 45/7 27

1272 ACSR 45/7 28

795 ACSR 26/7 29

266.8 ACSR 26/7 30

795 AAC /37 31

795 AAC /37 32

397.5 ACSR 26/7 33

397.5 ACSR 26/7 34

1272 ACSR 45/7 35

FERC FORM NO. 1 (ED. 12-87) Page 423.4

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

397.5 ACSR 26/7 1

795 ACSR 26/7 2

397.5 ACSR 26/7 3

795 ACSR 45/7 4

795 AAC /37 5

1272 ACSR 45/7 6

1272 AAC /61 7

 8

1272 ACSR 45/7 9

397.5 ACSR 26/7 10

250 CUHD /12 11

250 CUHD /12 12

250 CUHD /12 13

1272 ACSR 45/7 14

1272 ACSR 45/7 15

1272 ACSR 45/7 16

1272 ACSR 45/7 17

397.5 ACSR 26/7 18

250 CUHD /12 19

397.5 ACSR 26/7 20

795 ACSR 26/7 21

397.5 ACSR 26/7 22

795 ACSR 26/7 23

397.5 ACSR 26/7 24

397.5 ACSR 26/7 25

795 ACSR 26/7 26

1272 ACSR 45/7 27

795 ACSR 26/7 28

795 ACSR 26/7 29

1020 ACCC/TW BR. 30

795 AAC /37 31

1272 ACSR 45/7 32

795 ACSR 45/7 33

336.4 ACSR 26/7 34

250 CUHD /12 35

FERC FORM NO. 1 (ED. 12-87) Page 423.5

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

1272 ACSR 45/7 1

397.5 ACSR 26/7 2

795 AAC /37 3

795 ACSR 45/7 4

795 ACSR 26/7 5

795 ACSR 26/7 6

795 AAC /37 7

795 AAC /37 8

336.4 ACSR 26/7 9

1272 ACSR 45/7 10

795 AAC /37 11

1272 ACSR 45/7 12

1272 AAC /61 13

4/0 ACSR 6/1 14

250 CUHD /12 15

250 CUHD /12 16

250 CUHD /12 17

795 ACSR 26/7 18

1557.4 ACSR/TW 19

397.5 ACSR 26/7 20

795 ACSR 26/7 21

1272 ACSR 45/7 22

1272 AAC /61 23

795 ACSR 45/7 24

397.5 ACSR 26/7 25

397.5 ACSR 26/7 26

397.5 ACSR 26/7 27

1750 KCMIL 28

397.5 ACSR 26/7 29

1272 AAC /61 30

1557.4 ACSR/TW 31

795 AAC /37 32

795 ACSR 26/7 33

795 ACSR 26/7 34

795 AAC /37 35

FERC FORM NO. 1 (ED. 12-87) Page 423.6

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINE STATISTICS (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

COST OF LINE (Include in Column (j) Land,

Size of

Conductor

and Material

Land rights, and clearing right-of-way)

EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation

Expenses

Land Construction and Maintenance Rents Total

Other Costs

Total Cost

(i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote 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.

1272 ACSR 45/7 1

1272 ACSR 45/7 2

1272 ACSR 45/7 3

1557.4 ACSR/TW 4

795 ACSR 26/7 5

795 AAC /37 6

795 ACSR 26/7 7

795 ACSR 26/7 8

1557.4 ACSR/TW 9

795 ACSR 26/7 10

1557.4 ACSR/TW 11

1557.4 ACSR/TW 12

2-795 ACSR 26/7 13

1557.4 ACSR/TW 14

397.5 ACSR 26/7 15

1272 ACSR 45/7 16

1272 ACSR 45/7 17

795 ACSR 26/7 18

1272 ACSR 45/7 19

1272 ACSR 45/7 20

795 ACSR 26/7 21

 17,348,203 282,541,903 299,890,106 24,825 1,839,250 144,824 2,008,899 22

 23

 17,348,203 282,541,903 299,890,106 24,825 1,839,250 144,824 2,008,899 24

 25

 26

 4,086,733 151,293,779 155,380,512 2,280 3,526,193 233,226 3,761,699 27

 6,375,731 230,690,274 237,066,005 8,920 2,702,093 161,990 2,873,003 28

 45,458 9,679,030 9,724,488 43,553 3,516 47,069 29

 8,060,999 204,595,922 212,656,921 9,142 2,279,626 39,592 2,328,360 30

 31

 32

 33

 34

 35

FERC FORM NO. 1 (ED. 12-87) Page 423.7

 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335 36
Schedule Page: 422 Line No.: 1 Column: a

Certain transmission lines reported on pages 422-423 are part of exchange agreements with various third parties. Refer to the

footnotes on pages 328-330 of this FERC form No. 1 for further discussion.

Schedule Page: 422 Line No.: 4 Column: a

The Alvey - Dixonville 500kV line is jointly owned by the respondent and the Bonneville Power Adminstration ("the BPA").

Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondent's 50.0%

share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the

BPA 42.0%.

Schedule Page: 422 Line No.: 5 Column: a

The Dixonville - Meridian 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BPA"). 

Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondent's 50.0%

share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the

BPA 42.0%.

Schedule Page: 422 Line No.: 8 Column: a

The Colstrip 4 - Switchyard 500kV line is jointly owned by the respondent, NorthWestern Corporation, Puget Sound Power & Light,

Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 6.8%, all others

93.2%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.

Schedule Page: 422 Line No.: 9 Column: a

The Colstrip – Broadview A 500kV line is jointly owned by the respondent, NorthWestern Corporation, Puget Sound Power & Light,

Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 6.8%, all others

93.2%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.

Schedule Page: 422 Line No.: 10 Column: a

The Colstrip – Broadview B 500kV line is jointly owned by the respondent, NorthWestern Corporation, Puget Sound Power & Light,

Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 6.8%, all others

93.2%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.

Schedule Page: 422 Line No.: 11 Column: a

The Broadview – Townsend A 500kV line is jointly owned by the respondent, NorthWestern Corporation, Puget Sound Power &

Light, Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 8.1%, all

others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.

Schedule Page: 422 Line No.: 12 Column: a

The Broadview – Townsend B 500kV line is jointly owned by the respondent, NorthWestern Corporation, Puget Sound Power &

Light, Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 8.1%, all

others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.

Schedule Page: 422.1 Line No.: 13 Column: i

2-1557.4 ACSR/TW 36/7 

Schedule Page: 422.1 Line No.: 14 Column: i

2-1557.4 ACSR/TW 36/7

Schedule Page: 422.2 Line No.: 5 Column: a

A 1.5 mile segment of the Casper - Dave Johnston 230kV line is jointly owned by the respodent and Black Hills Power. Ownership of

the line is as follows: PacifiCorp 43.75%, Black Hills Power 56.25%. Plant cost and operation and maintenance costs reported for

this line reflects the respondent's share.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Schedule Page: 422.5 Line No.: 8 Column: i

1557.4 ACSR/TW 36/7

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINES ADDED DURING YEAR

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

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

LINE DESIGNATION

From To

Line

Length in

Miles

SUPPORTING STRUCTURE

Type Average

Number per

Miles

CIRCUITS PER STRUCTURE

Present Ultimate

(f) (g)

1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report

minor revisions of lines.

2. Provide separate subheadings for overhead and under- ground 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

 1 TERMINAL, UT BEN LOMOND, UT 46.60 Steel - SP 9.00 2 2

 2 BEN LOMOND, UT POPULUS, ID 85.70 Steel - SP 9.00 2 2

 3 NINETY SOUTH, UT CAMP WILLIAMS, UT 10.80 Steel - SP 9.00 2 2

 4 CENTRAL, UT ST. GEORGE, UT 20.10 Steel - SP 8.00 2 2

 5 STR 169, UT THREE PEAKS, UT 6.40 Wood - SP 12.00 1 1

 6 SHIRLEY BASIN, WY DUNLAP WIND, WY 9.00 Wood - H 8.00 1 1

 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

 178.60 55.00 10 10

FERC FORM NO. 1 (REV. 12-03) Page 424

44 TOTAL
Total

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSMISSION LINES ADDED DURING YEAR (Continued)

PacifiCorp X

04/18/2011

2010/Q4

Line

 No.

(h) (j) (k) (l) (m)

CONDUCTORS

Size Configuration

Voltage

KV

LINE COST

Land and Poles, Towers

and Fixtures

Conductors

(n) (p)

Specification and Spacing (Operating) Land Rights and Devices

(i)

costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads 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.

Asset

(o)

Retire. Costs

2-1272 ACSR Vertical 27' 345 12,897,280 118,199,855 29,549,964 160,647,099 1

2-1272 ACSR Vertical 27' 345 52,580,695 296,527,325 74,131,831 423,239,851 2

2-1557.4 ACSR Vertical 27' 345 386,194 20,797,840 5,199,460 26,383,494 3

2-1272 ACSR Vertical 27' 138 665,571 14,875,600 3,718,900 19,260,071 4

795 ACSR Vertical 12' 138 130,445 2,789,303 1,314,424 4,234,172 5

1272 ACSR Horizon 20' 230 365,952 3,738,719 1,739,258 5,843,929 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

 456,928,642 115,653,837

FERC FORM NO. 1 (REV. 12-03) Page 425

 67,026,137 639,608,616 44
Schedule Page: 424 Line No.: 1 Column: a

PacifiCorp removed from service a 13-mile 230kV single-circuit transmission line between the Ben Lomond substation and the

Terminal substation in Utah. In addition, PacifiiCorp removed from service a 13-mile 138kV single-circuit transmission line between

the Syracuse substation and the Terminal substation in Utah. 

Schedule Page: 424 Line No.: 4 Column: a

PacifiCorp removed from service a 20.1-mile 138kV single-circuit transmission line between the Red Butte substation and the St.

George substation in Utah.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 California

 2 BELMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 BIG SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 4 CANBY #2 DISTRIBUTION-UNATTEN 69.00 2.40

 5 CASTELLA SUB DISTRIBUTION-UNATTEN 69.00 2.40

 6 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 7 DOG CREEK SUB DISTRIBUTION-UNATTEN 69.00 2.40

 8 DORRIS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 9 FORT JONES SUB DISTRIBUTION-UNATTEN 69.00 12.47

 10 GASQUET SUB DISTRIBUTION-UNATTEN 115.00 12.47

 11 GREENHORN SUB DISTRIBUTION-UNATTEN 69.00 12.47

 12 HAMBURG SUB DISTRIBUTION-UNATTEN 69.00 2.40

 13 HAPPY CAMP SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 HORNBROOK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 15 INTERNATIONAL PAPER SUB DISTRIBUTION-UNATTEN 69.00 2.40

 16 LAKE EARL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 17 LITTLE SHASTA SUB DISTRIBUTION-UNATTEN 69.00 7.20

 18 LUCERNE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 19 MACDOEL SUB DISTRIBUTION-UNATTEN 69.00 20.80

 20 MCCLOUD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 21 MILLER REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 22 MONTAGUE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 23 MORRISON CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.50

 24 MOUNT SHASTA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 25 NEWELL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 NORTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 12.47

 27 NORTHCREST SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 NUTGLADE SUB DISTRIBUTION-UNATTEN 69.00 2.40

 29 PATRICKS CREEK SUB DISTRIBUTION-UNATTEN 115.00 7.20

 30 PEREZ SUB DISTRIBUTION-UNATTEN 69.00 12.47

 31 REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 32 SCOTT BAR SUB DISTRIBUTION-UNATTEN 69.00 12.47

 33 SEIAD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 34 SHASTINA SUB DISTRIBUTION-UNATTEN 69.00 20.80

 35 SHOTGUN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 36 SMITH RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 37 SNOW BRUSH SUB DISTRIBUTION-UNATTEN 69.00 7.20

 38 SOUTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 4.16

 39 TULELAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 40 TUNNEL SUB DISTRIBUTION-UNATTEN 69.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 WALKER BRYAN SUB DISTRIBUTION-UNATTEN 69.00 12.47

 2 WEED SUB DISTRIBUTION-UNATTEN 115.00 12.47

 3 YUBA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 4 YUROK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 5 Total 3105.00 468.36

 6 Number of Substations- 43

 7

 8 ALTURAS SUB T/D-UNATTENDED 115.00 12.47 69.00

 9 FALL CREEK HYDRO/SUB T/D-UNATTENDED 69.00 2.30

 10 YREKA SUB T/D-UNATTENDED 115.00 12.47 69.00

 11 Total 299.00 27.24 138.00

 12 Number of Substations- 3

 13

 14 AGER SUB TRANSMISSION-ATTENDE 115.00 69.00

 15 COPCO #1 HYDRO PLANT TRANSMISSION-ATTENDE 69.00 2.30

 16 COPCO #2 230 SUB TRANSMISSION-ATTENDE 230.00 115.00

 17 COPCO #2 HYDRO PLANT TRANSMISSION-ATTENDE 69.00 6.60

 18 COPCO #2 SUB TRANSMISSION-ATTENDE 115.00 69.00

 19 CRAG VIEW SUB TRANSMISSION-UNATTEN 115.00 69.00

 20 DEL NORTE SUB TRANSMISSION-UNATTEN 115.00 69.00

 21 IRON GATE HYDRO PLANT TRANSMISSION-UNATTEN 69.00 6.60

 22 WEED JUNCTION SUB TRANSMISSION-UNATTEN 115.00 69.00

 23 Total 1012.00 475.50

 24 Number of Substations- 9

 25

 26 Idaho

 27 ALEXANDER DISTRIBUTION-UNATTEN 46.00 12.47

 28 AMMON DISTRIBUTION-UNATTEN 69.00 12.47

 29 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47

 30 ARCO DISTRIBUTION-UNATTEN 69.00 12.47

 31 ARIMO DISTRIBUTION-UNATTEN 46.00 12.47

 32 BANCROFT SUB DISTRIBUTION-UNATTEN 46.00 12.47

 33 BELSON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 34 BERENICE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 35 CAMAS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 36 CANYON CREEK SUB DISTRIBUTION-UNATTEN 69.00 24.90

 37 CHESTERFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 38 CINDER BUTTE SUB DISTRIBUTION-UNATTEN 161.00 12.47

 39 CLEMENTS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 40 CLIFTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 COVE SUB DISTRIBUTION-UNATTEN 46.00 6.60

 2 DOWNEY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 3 DUBOIS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 4 EASTMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 5 EGIN SUB DISTRIBUTION-UNATTEN 69.00 12.47

 6 EIGHT MILE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 7 GEORGETOWN SUB DISTRIBUTION-UNATTEN 69.00 12.47

 8 GRACE CITY SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47

 9 HAMER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 10 HAYES SUB DISTRIBUTION-UNATTEN 69.00 12.47

 11 HENRY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 12 HOLBROOD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 13 HOOPES SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 HORSLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 15 IDAHO FALLS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 16 INDIAN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 17 JEFFCO SUB DISTRIBUTION-UNATTEN 69.00 24.90

 18 KETTLE SUB DISTRIBUTION-UNATTEN 69.00 24.90

 19 LAVA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 20 LUND SUB DISTRIBUTION-UNATTEN 46.00 12.47

 21 MCCAMMON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 MENAN SUB DISTRIBUTION-UNATTEN 69.00 12.47

 23 MERRILL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 24 MILLER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 25 MONTPELIER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 MOODY SUB DISTRIBUTION-UNATTEN 69.00 24.90

 27 NEWDALE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 OSGOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 29 PRESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 30 RAYMOND SUB DISTRIBUTION-UNATTEN 69.00 12.47

 31 RENO SUB DISTRIBUTION-UNATTEN 69.00 12.47

 32 REXBURG SUB DISTRIBUTION-UNATTEN 69.00 12.47

 33 RIRIE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 34 ROBERTS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 35 RUDY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 36 SAND CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 37 SANDUNE SUB DISTRIBUTION-UNATTEN 69.00 24.90

 38 SHELLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 39 SMITH SUB DISTRIBUTION-UNATTEN 69.00 12.47

 40 SOUTH FORK SUB DISTRIBUTION-UNATTEN 69.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 SPUD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 2 ST. CHARLES SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 SUGAR CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 4 SUNNYDELL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 5 TANNER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 6 TARGHEE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 7 THORNTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 8 UCON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 9 WATKINS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 10 WEBSTER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 11 WESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 12 WINDSPER SUB DISTRIBUTION-UNATTEN 69.00 24.90

 13 Total 4163.00 891.73

 14 Number of Substations- 66

 15

 16 MALAD SUB T/D-UNATTENDED 138.00 46.00 12.47

 17 MUD LAKE SUB T/D-UNATTENDED 69.00 12.47

 18 RIGBY SUB T/D-UNATTENDED 161.00 12.47 69.00

 19 SAINT ANTHONY SUB T/D-UNATTENDED 69.00 46.00 12.47

 20 Total 437.00 116.94 93.94

 21 Number of Substations- 4

 22

 23 GRACE HYDRO TRANSMISSION-ATTENDE 138.00 46.00 6.60

 24 AMPS SUB TRANSMISSION-UNATTEN 230.00 69.00

 25 ANTELOPE SUB TRANSMISSION-UNATTEN 230.00 161.00

 26 ASHTON PLANT TRANSMISSION-UNATTEN 46.00 2.40

 27 BIG GRASSY SUB TRANSMISSION-UNATTEN 161.00 69.00

 28 BONNEVILLE SUB TRANSMISSION-UNATTEN 161.00 69.00

 29 CONDA SUB TRANSMISSION-UNATTEN 138.00 46.00

 30 FISH CREEK SUB TRANSMISSION-UNATTEN 161.00 46.00

 31 FRANKLIN SUB TRANSMISSION-UNATTEN 138.00 46.00

 32 GOSHEN SUB TRANSMISSION-UNATTEN 345.00 161.00 46.00

 33 JEFFERSON SUB TRANSMISSION-UNATTEN 161.00 69.00

 34 LIFTON HYDRO TRANSMISSION-UNATTEN 69.00 2.30

 35 ONEIDA SUB TRANSMISSION-UNATTEN 138.00 25.00

 36 OVID SUB TRANSMISSION-UNATTEN 138.00 69.00

 37 SCOVILLE SUB TRANSMISSION-UNATTEN 138.00 69.00

 38 SUGARMILL SUB TRANSMISSION-UNATTEN 161.00 46.00 69.00

 39 THREEMILE KNOLL SUB TRANSMISSION-UNATTEN 345.00 138.00 46.00

 40 TREASURETON SUB TRANSMISSION-UNATTEN 230.00 138.00

FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 Total 3128.00 1271.70 167.60

 2 Number of Substations- 18

 3

 4 MONTANA

 5 YELLOWTAIL SUB TRANSMISSION-UNATTEN 230.00 161.00

 6 Total 230.00 161.00

 7 Number of Substations- 1

 8

 9 Oregon

 10 26TH STREET DISTRIBUTION-UNATTEN 20.80 4.16

 11 35TH STREET DISTRIBUTION-UNATTEN 20.80 2.40

 12 AGNESS AVE DISTRIBUTION-UNATTEN 115.00 12.47

 13 ALDERWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 ARLINGTON DISTRIBUTION-UNATTEN 69.00 12.47

 15 ATHENA DISTRIBUTION-UNATTEN 69.00 12.47

 16 BANDON TIE SUB DISTRIBUTION-UNATTEN 20.80 12.47

 17 BEACON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 18 BEALL LANE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 19 BEATTY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 20 BELKNAP SUB DISTRIBUTION-UNATTEN 69.00 12.47

 21 BLALOCK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 22 BLOSS SUB DISTRIBUTION-UNATTEN 115.00 12.47

 23 BLY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 24 BOISE CASCADE SUB DISTRIBUTION-UNATTEN 69.00 11.00

 25 BONANZA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 BOND STREET SUB DISTRIBUTION-UNATTEN 69.00 12.50

 27 BROOKHURST SUB DISTRIBUTION-UNATTEN 115.00 12.47

 28 BROWNSVILLE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 29 BRYANT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 30 BUCHANAN SUB DISTRIBUTION-UNATTEN 115.00 20.80

 31 BUCKAROO SUB DISTRIBUTION-UNATTEN 69.00 12.47

 32 CAMPBELL SUB DISTRIBUTION-UNATTEN 115.00 12.47

 33 CANNON BEACH SUB DISTRIBUTION-UNATTEN 115.00 12.47

 34 CARNES SUB DISTRIBUTION-UNATTEN 69.00 12.47

 35 CASEBEER SUB DISTRIBUTION-UNATTEN 69.00 20.80

 36 CAVEMAN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 37 CHERRY LANE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 38 CHILOQUIN MARKET SUB DISTRIBUTION-UNATTEN 69.00 12.47

 39 CHINA HAT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 40 CIRCLE BLVD SUB DISTRIBUTION-UNATTEN 115.00 20.80

FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 CLEVELAND AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 2 CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.47 2.40

 3 CLOAKE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 4 COBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80

 5 COLISEUM SUB DISTRIBUTION-UNATTEN 20.80 4.16

 6 COLUMBIA SUB DISTRIBUTION-UNATTEN 115.00 12.47 57.00

 7 COOS RIVER SUB DISTRIBUTION-UNATTEN 115.00 20.80

 8 COQUILLE SUB DISTRIBUTION-UNATTEN 115.00 20.80

 9 CREEK SUB DISTRIBUTION-UNATTEN 69.00 34.50

 10 CROOKED RIVER RANCH SUB DISTRIBUTION-UNATTEN 69.00 20.80

 11 CROWFOOT SUB DISTRIBUTION-UNATTEN 115.00 12.47

 12 CULLY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 13 CULVER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 CUTLER CITY SUB DISTRIBUTION-UNATTEN 20.80 4.16

 15 DAIRY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 16 DALLAS SUB DISTRIBUTION-UNATTEN 115.00 20.80

 17 DALREED SUB DISTRIBUTION-UNATTEN 230.00 34.50

 18 DESCHUTES SUB DISTRIBUTION-UNATTEN 69.00 12.47

 19 DEVILS LAKE SUB DISTRIBUTION-UNATTEN 115.00 20.80

 20 DIXON SUB DISTRIBUTION-UNATTEN 115.00 4.16

 21 DODGE BRIDGE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 22 DOWELL SUB DISTRIBUTION-UNATTEN 115.00 12.47

 23 EASY VALLEY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 24 EMPIRE SUB DISTRIBUTION-UNATTEN 115.00 20.80

 25 ENTERPRISE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 FERN HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47

 27 FIELDER CREEK SUB DISTRIBUTION-UNATTEN 115.00 20.80

 28 FOOTHILLS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 29 FRALEY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 30 GARDEN VALLEY SUB DISTRIBUTION-UNATTEN 69.00 20.80

 31 GAZLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 32 GLENDALE SUB DISTRIBUTION-UNATTEN 230.00 12.47

 33 GLENEDEN SUB DISTRIBUTION-UNATTEN 20.80 4.16

 34 GLIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 35 GOLD HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 36 GORDON HOLLOW SUB DISTRIBUTION-UNATTEN 69.00 12.47

 37 GOSHEN SUB (OR) DISTRIBUTION-UNATTEN 115.00 20.80

 38 GRANT STREET SUB DISTRIBUTION-UNATTEN 115.00 20.80

 39 GRASS VALLEY SUB DISTRIBUTION-UNATTEN 20.80 4.16

 40 GREEN SUB DISTRIBUTION-UNATTEN 69.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 GRIFFIN CREEK SUB DISTRIBUTION-UNATTEN 115.00 12.47

 2 HAMAKER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 HARRISBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80

 4 HENLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 5 HERMISTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 6 HILLVIEW SUB DISTRIBUTION-UNATTEN 115.00 20.80

 7 HINKLE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 8 HOLLADAY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 9 HOLLYWOOD SUB DISTRIBUTION-UNATTEN 115.00 12.47

 10 HOOD RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 11 HORNET SUB DISTRIBUTION-UNATTEN 69.00 12.47

 12 HUNTERS CIRCLE TEMP SUB DISTRIBUTION-UNATTEN 69.00 12.47

 13 ILLAHEE FLATS SUB DISTRIBUTION-UNATTEN 115.00 12.47

 14 INDEPENDENCE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 15 JACKSONVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00

 16 JEFFERSON SUB DISTRIBUTION-UNATTEN 69.00 20.80

 17 JEROME PRAIRIE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 18 JORDAN POINT SUB DISTRIBUTION-UNATTEN 115.00 12.47

 19 JOSEPH SUB DISTRIBUTION-UNATTEN 20.80 12.47

 20 JUNCTION CITY SUB DISTRIBUTION-UNATTEN 69.00 20.80

 21 KENWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47

 22 KILLINGSWORTH SUB DISTRIBUTION-UNATTEN 69.00 12.47

 23 KNAPPA SVENSEN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 24 LAKEPORT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 25 LAKEVIEW SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 LANCASTER SUB DISTRIBUTION-UNATTEN 69.00 20.80

 27 LEBANON SUB DISTRIBUTION-UNATTEN 115.00 20.80

 28 LINCOLN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 29 LOCKHART SUB DISTRIBUTION-UNATTEN 115.00 20.80

 30 LYONS SUB DISTRIBUTION-UNATTEN 69.00 20.80

 31 MADRAS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 32 MALLORY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 33 MARYS RIVER SUB DISTRIBUTION-UNATTEN 115.00 20.80

 34 MEDCO SUB DISTRIBUTION-UNATTEN 115.00 12.47

 35 MEDFORD DISTRIBUTION-UNATTEN 69.00 12.47

 36 MERLIN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 37 MERRILL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 38 MINAM SUB DISTRIBUTION-UNATTEN 69.00 12.47

 39 MODOC SUB DISTRIBUTION-UNATTEN 69.00 12.47

 40 MORO SUB DISTRIBUTION-UNATTEN 20.80 2.40

FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 MURDER CREEK SUB DISTRIBUTION-UNATTEN 115.00 20.80

 2 MYRTLE CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 MYRTLE POINT SUB DISTRIBUTION-UNATTEN 115.00 20.80

 4 NELSCOTT SUB DISTRIBUTION-UNATTEN 20.80 4.16

 5 NEW O'BRIEN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 6 OAK KNOLL SUB DISTRIBUTION-UNATTEN 115.00 12.47

 7 OAKLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47

 8 OREMET SUB DISTRIBUTION-UNATTEN 115.00 12.47

 9 OVERPASS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 10 PALLETTE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 11 PARK STREET SUB DISTRIBUTION-UNATTEN 115.00 12.47

 12 PARKROSE SUB DISTRIBUTION-UNATTEN 57.00 12.47

 13 PENDLETON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 PILOT ROCK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 15 POWELL BUTTE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 16 PRINEVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 17 PROVOLT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 18 QUEEN AVE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 19 RED BLANKET SUB DISTRIBUTION-UNATTEN 69.00 4.16

 20 REDMOND SUB DISTRIBUTION-UNATTEN 115.00 12.47

 21 RIDDLE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 22 RIDDLE VENEER SUB DISTRIBUTION-UNATTEN 115.00 12.47

 23 ROGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 24 ROSEBURG SUB DISTRIBUTION-UNATTEN 115.00 20.80

 25 ROSS AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 ROXY ANN SUB DISTRIBUTION-UNATTEN 115.00 12.50

 27 RUCH SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 RUNNING Y SUB DISTRIBUTION-UNATTEN 69.00 20.80

 29 RUSSELLVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 30 SAGE ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47

 31 SCENIC SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00

 32 SCIO SUB DISTRIBUTION-UNATTEN 69.00 12.47

 33 SEASIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 34 SELMA SUB DISTRIBUTION-UNATTEN 115.00 12.47

 35 SHASTA WAY SUB DISTRIBUTION-UNATTEN 12.47 4.16

 36 SHEVLIN PARK SUB DISTRIBUTION-UNATTEN 69.00 12.50

 37 SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.50 4.16

 38 SOUTH DUNES SUB DISTRIBUTION-UNATTEN 115.00 12.47

 39 SOUTHGATE SUB DISTRIBUTION-UNATTEN 69.00 20.80

 40 SPRAGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 STATE STREET SUB DISTRIBUTION-UNATTEN 115.00 20.80

 2 STAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 STEAMBOAT SUB DISTRIBUTION-UNATTEN 115.00 7.20

 4 STEVENS ROAD SUB DISTRIBUTION-UNATTEN 115.00 20.80

 5 SUTHERLIN SUB DISTRIBUTION-UNATTEN 115.00 12.00

 6 SWEET HOME SUB DISTRIBUTION-UNATTEN 115.00 20.80

 7 TAKELMA SUB DISTRIBUTION-UNATTEN 115.00 20.80

 8 TALENT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 9 TEXUM SUB DISTRIBUTION-UNATTEN 69.00 12.47

 10 TILLER SUB DISTRIBUTION-UNATTEN 115.00 12.47

 11 TOLO SUB DISTRIBUTION-UNATTEN 69.00 12.47

 12 TURKEY HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 13 UMAPINE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 UMATILLA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 15 VERNON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 16 VILAS SUB DISTRIBUTION-UNATTEN 115.00 12.47

 17 VILLAGE GREEN SUB DISTRIBUTION-UNATTEN 115.00 20.80

 18 VINE STREET SUB DISTRIBUTION-UNATTEN 69.00 20.80

 19 WALLOWA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 20 WARM SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 20.80

 21 WARRENTON SUB DISTRIBUTION-UNATTEN 115.00 12.47

 22 WASCO SUB DISTRIBUTION-UNATTEN 20.80 4.16

 23 WECOMA BEACH SUB DISTRIBUTION-UNATTEN 20.80 4.16

 24 WESTERN KRAFT SUB DISTRIBUTION-UNATTEN 115.00 12.47

 25 WESTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 WESTSIDE HYDRO/SUB DISTRIBUTION-UNATTEN 69.00 12.47

 27 WEYERHAUSER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 WHITE CITY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 29 WILLOW COVE SUB DISTRIBUTION-UNATTEN 34.50 4.16

 30 WINSTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 31 YEW AVENUE SUB DISTRIBUTION-UNATTEN 115.00 12.50

 32 YOUNGS BAY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 33 Total 15580.54 2522.27 195.00

 34 Number of Substations- 183

 35

 36 ALBINA SUB T/D-UNATTENDED 115.00 12.47 69.00

 37 APPLEGATE SUB T/D-UNATTENDED 115.00 69.00 12.47

 38 ASHLAND MTN AVE SUB T/D-UNATTENDED 115.00 69.00 12.47

 39 BEND PLANT T/D-UNATTENDED 69.00 4.16 12.47

 40 CAVE JUNCTION SUB T/D-UNATTENDED 115.00 12.47 69.00

FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 HAZELWOOD SUB T/D-UNATTENDED 115.00 69.00 12.47

 2 KNOTT SUB T/D-UNATTENDED 115.00 12.47 57.00

 3 MILE HI SUB T/D-UNATTENDED 115.00 69.00 12.47

 4 PILOT BUTTE SUB T/D-UNATTENDED 230.00 69.00 12.47

 5 WINCHESTER SUB T/D-UNATTENDED 115.00 12.47 69.00

 6 Total 1219.00 399.04 338.82

 7 Number of Substations- 10

 8

 9 CLEARWATER #1 HYDRO PLANT TRANSMISSION-ATTENDE 138.00 6.90

 10 FISH CREEK HYDRO TRANSMISSION-ATTENDE 115.00 6.90

 11 JC BOYLE HYDRO TRANSMISSION-ATTENDE 230.00 11.00

 12 LEMOLO #1 HYDRO TRANSMISSION-ATTENDE 11.30 12.50

 13 LEMOLO #2 HYDRO TRANSMISSION-ATTENDE 115.00 12.00

 14 PROSPECT 1 HYDRO TRANSMISSION-ATTENDE 69.00 2.30

 15 PROSPECT 2 HYDRO TRANSMISSION-ATTENDE 69.00 6.60

 16 PROSPECT 3 HYDRO TRANSMISSION-ATTENDE 69.00 12.47

 17 TOKETEE HYDRO TRANSMISSION-ATTENDE 115.00 6.90

 18 BEND PLANT TRANSMISSION-UNATTEN 4.16 2.40

 19 CALAPOOYA SUB TRANSMISSION-UNATTEN 230.00 69.00

 20 CHILOQUIN SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00

 21 COLD SPRINGS SUB TRANSMISSION-UNATTEN 230.00 69.00

 22 COVE SUB TRANSMISSION-UNATTEN 230.00 69.00

 23 DAYS CREEK SUB TRANSMISSION-UNATTEN 115.00 69.00

 24 DIAMOND HILL SUB TRANSMISSION-UNATTEN 230.00 69.00

 25 DIXONVILLE 115/230 SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00

 26 DIXONVILLE 500 SUB TRANSMISSION-UNATTEN 500.00 230.00

 27 EAGLE POINT HYDRO TRANSMISSION-UNATTEN 115.00 2.40

 28 EAST SIDE HYDRO TRANSMISSION-UNATTEN 46.00 12.47

 29 FISH HOLE SUB TRANSMISSION-UNATTEN 115.00 69.00

 30 FRY SUB TRANSMISSION-UNATTEN 230.00 115.00

 31 GRANTS PASS SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00

 32 GREEN SPRINGS PLANT/SUB TRANSMISSION-UNATTEN 115.00 69.00

 33 HURRICANE SUB TRANSMISSION-UNATTEN 230.00 69.00 2.40

 34 ISTHMUS SUB TRANSMISSION-UNATTEN 230.00 115.00

 35 KENNEDY SUB TRANSMISSION-UNATTEN 69.00 57.00

 36 KLAMATH FALLS SUB TRANSMISSION-UNATTEN 230.00 69.00

 37 LONE PINE SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00

 38 MERIDIAN SUB TRANSMISSION-UNATTEN 500.00 230.00

 39 MONPAC SUB TRANSMISSION-UNATTEN 115.00 69.00

 40 NICKEL MOUNTAIN TRANSMISSION-UNATTEN 230.00 115.00

FERC FORM NO. 1 (ED. 12-96) Page 426.9
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 PARRISH GAP SUB TRANSMISSION-UNATTEN 230.00 69.00 12.47

 2 PONDEROSA SUB TRANSMISSION-UNATTEN 230.00 115.00

 3 POWERDALE PLANT TRANSMISSION-UNATTEN 69.00 7.20

 4 PROSPECT CENTRAL SUB TRANSMISSION-UNATTEN 115.00 69.00

 5 ROBERTS CREEK SUB TRANSMISSION-UNATTEN 115.00 69.00

 6 SLIDE CREEK HYDRO TRANSMISSION-UNATTEN 115.00 7.00

 7 SODA SPRINGS HYDRO TRANSMISSION-UNATTEN 115.00 7.00

 8 TROUTDALE SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00

 9 TUCKER SUB TRANSMISSION-UNATTEN 115.00 69.00

 10 WALLOWA FALLS HYDRO TRANSMISSION-UNATTEN 20.80

 11 Total 6970.26 2634.04 359.87

 12 Number of Substations- 42

 13

 14 Utah

 15 106TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.50

 16 118TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47

 17 23RD ST SUB DISTRIBUTION-UNATTEN 46.00 12.47

 18 70TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47

 19 ALTAVIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47

 20 AMALGA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 21 AMERICAN FORK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 22 ARAGONITE DISTRIBUTION-UNATTEN 46.00 7.20

 23 AURORA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 24 BANGERTER SUB DISTRIBUTION-UNATTEN 138.00 12.47

 25 BEAR RIVER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 26 BENJAMIN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 27 BINGHAM SUB DISTRIBUTION-UNATTEN 46.00 12.47

 28 BLUE CREEK DISTRIBUTION-UNATTEN 46.00 12.47

 29 BLUFF SUB DISTRIBUTION-UNATTEN 69.00 12.47

 30 BLUFFDALE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 31 BOTHWELL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 32 BOX ELDER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 33 BRIAN HEAD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 34 BRICKYARD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 35 BRIGHTON SUB DISTRIBUTION-UNATTEN 46.00 24.90

 36 BROOKLAWN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 37 BRUNSWICK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 38 BURTON SUB DISTRIBUTION-UNATTEN 34.50 12.47

 39 BUSH SUB DISTRIBUTION-UNATTEN 46.00 12.47

 40 CANNON SUB DISTRIBUTION-UNATTEN 46.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.10
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 CANYONLANDS SUB DISTRIBUTION-UNATTEN 69.00 12.47

 2 CAPITOL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 3 CARBIDE SUB DISTRIBUTION-UNATTEN 46.00 7.20

 4 CARBONVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 5 CARLISLE SUB DISTRIBUTION-UNATTEN 138.00 12.50

 6 CASTO SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47

 7 CENTENNIAL SUB DISTRIBUTION-UNATTEN 138.00 12.47

 8 CENTERVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 9 CENTRAL SUB DISTRIBUTION-UNATTEN 43.80 12.47

 10 CHAPEL HILL SUB DISTRIBUTION-UNATTEN 138.00 12.47

 11 CHERRYWOOD SUB DISTRIBUTION-UNATTEN 138.00 12.47

 12 CIRCLEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 13 CLEAR CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 14 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 15 CLEARFIELD SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47

 16 CLINTON SUB DISTRIBUTION-UNATTEN 138.00 12.47

 17 CLIVE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 18 COALVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 19 COLD WATER CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47

 20 COLEMAN SUB DISTRIBUTION-UNATTEN 138.00 69.00 12.47

 21 COLTON WELL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 COMMERCE SUB DISTRIBUTION-UNATTEN 138.00 12.50

 23 CORINNE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 24 COVE FORT SUB DISTRIBUTION-UNATTEN 46.00 12.47

 25 COZYDALE SUB DISTRIBUTION-UNATTEN 138.00 12.50

 26 CRESCENT JUNCTION SUB DISTRIBUTION-UNATTEN 46.00 7.20

 27 CROSS HOLLOW SUB DISTRIBUTION-UNATTEN 138.00 12.47

 28 CUDAHY SUB DISTRIBUTION-UNATTEN 138.00 12.47

 29 DAMMERON VALLEY SUB DISTRIBUTION-UNATTEN 34.50 12.47

 30 DECADE SUB DISTRIBUTION-UNATTEN 138.00 12.50

 31 DECKER LAKE SUB DISTRIBUTION-UNATTEN 138.00 12.47

 32 DELLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 33 DELTA SUB DISTRIBUTION-UNATTEN 46.00 69.00

 34 DESERET SUB DISTRIBUTION-UNATTEN 46.00 4.16

 35 DEWEYVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 36 DIMPLE DELL SUB DISTRIBUTION-UNATTEN 138.00 12.47

 37 DIXIE DEER SUB DISTRIBUTION-UNATTEN 34.50 12.47

 38 DRAPER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 39 DUMAS SUB DISTRIBUTION-UNATTEN 138.00 12.47

 40 EAST BENCH SUB DISTRIBUTION-UNATTEN 138.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.11
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 EAST HYRUM SUB DISTRIBUTION-UNATTEN 46.00 12.47

 2 EAST LAYTON SUB DISTRIBUTION-UNATTEN 138.00 12.47

 3 EAST MILLCREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 4 EDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 5 ELBERTA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 6 ELK MEADOWS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 7 ELSINORE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 8 EMERY CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 9 EMIGRATION SUB DISTRIBUTION-UNATTEN 46.00 12.47

 10 ENOCH SUB DISTRIBUTION-UNATTEN 138.00 12.47

 11 ENTERPRISE VALLEY SUB DISTRIBUTION-UNATTEN 138.00 12.47

 12 EUREKA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 13 FARMINGTON SUB DISTRIBUTION-UNATTEN 138.00 12.47

 14 FAYETTE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 15 FERRON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 16 FIELDING SUB DISTRIBUTION-UNATTEN 46.00 12.00

 17 FIFTH WEST SUB DISTRIBUTION-UNATTEN 138.00 12.47

 18 FLUX SUB DISTRIBUTION-UNATTEN 46.00 12.47

 19 FOOL CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 20 FOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 21 FREEDOM SUBSTATION DISTRIBUTION-UNATTEN 46.00 7.20

 22 FRUIT HEIGHTS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 23 GARDEN CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 24 GATEWAY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 25 GOLD RUSH SUB DISTRIBUTION-UNATTEN 138.00 12.50

 26 GORDON AVENUE SUB DISTRIBUTION-UNATTEN 138.00 12.50

 27 GOSHEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 28 GRANGER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 29 GRANTSVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 30 GREEN RIVER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 31 GROW SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00

 32 GUNLOCK HYDRO DISTRIBUTION-UNATTEN 34.50 2.30

 33 GUNNISON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 34 HAMMER SUB DISTRIBUTION-UNATTEN 138.00 12.47

 35 HAVASU SUB DISTRIBUTION-UNATTEN 69.00 12.47

 36 HELPER CITY SUB DISTRIBUTION-UNATTEN 46.00 4.16

 37 HENEFER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 38 HERRIMAN SUB DISTRIBUTION-UNATTEN 138.00 12.47

 39 HIAWATHA SUB DISTRIBUTION-UNATTEN 46.00 4.16

 40 HIGHLAND DIST SUB DISTRIBUTION-UNATTEN 46.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 HOGGARD SUB DISTRIBUTION-UNATTEN 138.00 12.47

 2 HOGLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 3 HOLDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 4 HOLLADAY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 5 HUNTER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 6 HUNTINGTON CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 7 IRON MOUNTAIN SUB DISTRIBUTION-UNATTEN 34.50 7.20

 8 IRON SPRINGS SUB DISTRIBUTION-UNATTEN 34.50 12.47

 9 IRONTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 10 IVINS SUB DISTRIBUTION-UNATTEN 34.50 12.47

 11 JORDAN NARROWS SUB DISTRIBUTION-UNATTEN 46.00 2.40

 12 JORDAN PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 13 JORDANELLE SUB DISTRIBUTION-UNATTEN 138.00 12.47

 14 JUAB SUB DISTRIBUTION-UNATTEN 46.00 12.47

 15 JUNCTION SUB DISTRIBUTION-UNATTEN 69.00 12.47

 16 KAIBAB SUB DISTRIBUTION-UNATTEN 69.00 12.47

 17 KAMAS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 18 KEARNS SUB DISTRIBUTION-UNATTEN 138.00 12.47

 19 KENSINGTON SUB DISTRIBUTION-UNATTEN 46.00 4.16

 20 LAKE PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 21 LARK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 LAYTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 23 LEGRANDE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 24 LEWISTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 25 LINCOLN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 26 LINDON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 27 LISBON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 LITTLE MOUNTAIN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 29 LOAFER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 30 LOGAN CANYON SUB DISTRIBUTION-UNATTEN 46.00 7.20

 31 LONE TREE SUB DISTRIBUTION-UNATTEN 34.50 12.47

 32 LOWER BEAVER SUB DISTRIBUTION-UNATTEN 46.00 6.60

 33 LYNNDYL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 34 MAESER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 35 MAGNA SUB DISTRIBUTION-UNATTEN 138.00 12.47

 36 MANILA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 37 MANTUA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 38 MAPLETON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 39 MARRIOTT SUB DISTRIBUTION-UNATTEN 46.00 12.47

 40 MARYSVALE SUB DISTRIBUTION-UNATTEN 46.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.13
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 MATHIS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 2 MCCORNICK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 3 MCKAY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 4 MEADOWBROOK SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00

 5 MEDICAL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 6 MELLING SUB DISTRIBUTION-UNATTEN 34.50 4.16

 7 MIDLAND SUB DISTRIBUTION-UNATTEN 138.00 12.47

 8 MIDVALE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 9 MILFORD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 10 MILFORD TV SUB DISTRIBUTION-UNATTEN 46.00 13.20

 11 MILLVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 12 MINERSVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 13 MOAB CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 MONTEZUMA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 15 MOORE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 16 MORGAN SUB DISTRIBUTION-UNATTEN 46.00 4.16

 17 MORONI SUB DISTRIBUTION-UNATTEN 46.00 12.47

 18 MORTON COURT SUB DISTRIBUTION-UNATTEN 138.00 12.47

 19 MOSS JUNCTION SUB DISTRIBUTION-UNATTEN 46.00 12.47

 20 MOUNTAIN DELL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 21 MOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 MYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 23 NEW HARMONY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 24 NEWGATE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 25 NEWTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 26 NIBLEY SUB DISTRIBUTION-UNATTEN 46.00 24.90

 27 NORTH BENCH SUB DISTRIBUTION-UNATTEN 46.00 12.47

 28 NORTH FIELDS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 29 NORTH LOGAN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 30 NORTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 31 NORTH SALT LAKE SUB DISTRIBUTION-UNATTEN 46.00 13.20

 32 NORTHEAST SUB DISTRIBUTION-UNATTEN 46.00 12.50

 33 NORTHRIDGE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 34 OAKLAND AVE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 35 OAKLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 36 OLYMPUS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 37 OPHIR SUB DISTRIBUTION-UNATTEN 46.00 12.47

 38 ORANGE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 39 ORANGEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 40 OREM SUB DISTRIBUTION-UNATTEN 46.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 PACK CREEK RESERVOIR DISTRIBUTION-UNATTEN 46.00 12.47

 2 PANGUITCH SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 PARIETTE SUBSTATION DISTRIBUTION-UNATTEN 69.00 24.90

 4 PARK CITY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 5 PARKWAY SUB DISTRIBUTION-UNATTEN 138.00 12.47

 6 PARLEYS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 7 PELICAN POINT SUB DISTRIBUTION-UNATTEN 46.00 12.47

 8 PINE CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47

 9 PINE CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 10 PINNACLE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 11 PLAIN CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47

 12 PLEASANT GROVE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 13 PLEASANT VIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47

 14 PORTER ROCKWELL SUB DISTRIBUTION-UNATTEN 138.00 12.47

 15 PROMONTORY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 16 QUAIL CREEK SUB DISTRIBUTION-UNATTEN 34.50 12.47

 17 QUARRY SUB DISTRIBUTION-UNATTEN 138.00 12.47

 18 QUICHAPA SUB DISTRIBUTION-UNATTEN 34.50 12.47

 19 RAINS SUB DISTRIBUTION-UNATTEN 46.00 7.20

 20 RANDOLPH SUB DISTRIBUTION-UNATTEN 46.00 12.47

 21 RASMUSON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 RATTLESNAKE SUB DISTRIBUTION-UNATTEN 69.00 24.90

 23 RED MOUNTAIN SUB DISTRIBUTION-UNATTEN 69.00 34.50

 24 RED ROCK SUB DISTRIBUTION-UNATTEN 69.00 4.16

 25 REDWOOD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 26 RESEARCH PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 27 RICH SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 RICHFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 29 RICHMOND SUB DISTRIBUTION-UNATTEN 46.00 12.47

 30 RIDGELAND SUB DISTRIBUTION-UNATTEN 138.00 12.47

 31 RITER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 32 ROCK CANYON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 33 ROCKVILLE SUB DISTRIBUTION-UNATTEN 34.50 12.47

 34 ROCKY POINT DISTRIBUTION-UNATTEN 138.00 13.20

 35 ROSE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 36 ROYAL SUB DISTRIBUTION-UNATTEN 46.00 4.16

 37 SALINA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 38 SANDY SUB DISTRIBUTION-UNATTEN 138.00 12.47

 39 SARATOGA SUB DISTRIBUTION-UNATTEN 138.00 12.47

 40 SCIPIO SUB DISTRIBUTION-UNATTEN 46.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.15
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 SCOFIELD RESERVOIR SUB DISTRIBUTION-UNATTEN 46.00 7.20

 2 SCOFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 3 SECOND STREET SUB DISTRIBUTION-UNATTEN 46.00 12.47

 4 SEVEN MILE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 5 SHARON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 6 SHIVWITS SUB DISTRIBUTION-UNATTEN 34.50 4.16

 7 SHORELINE SUB DISTRIBUTION-UNATTEN 138.00 13.20

 8 SIXTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47

 9 SKULL VALLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 10 SNARR SUB DISTRIBUTION-UNATTEN 46.00 12.47

 11 SNOWVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 12 SNYDERVILLE SUB DISTRIBUTION-UNATTEN 138.00 12.47

 13 SOLDIER SUMMIT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 14 SOUTH JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47

 15 SOUTH MILFORD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 16 SOUTH MOUNTAIN SUB DISTRIBUTION-UNATTEN 138.00 12.47

 17 SOUTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47

 18 SOUTH PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 19 SOUTH WEBER SUB DISTRIBUTION-UNATTEN 138.00 12.47

 20 SOUTHEAST SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00

 21 SOUTHWEST SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 SPANISH VALLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 23 SPRINGDALE SUB DISTRIBUTION-UNATTEN 34.50 12.47

 24 ST. JOHNS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 25 STAIRS SUB DISTRIBUTION-UNATTEN 12.47 2.40

 26 STANSBURY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 27 SUMMIT CREEK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 28 SUMMIT PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 29 SUNRISE SUB DISTRIBUTION-UNATTEN 138.00 12.47

 30 SUPERIOR SUB DISTRIBUTION-UNATTEN 69.00 12.47

 31 SUTHERLAND SUB DISTRIBUTION-UNATTEN 46.00 12.47

 32 TAMARISK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 33 TAYLOR SUB DISTRIBUTION-UNATTEN 46.00 12.47

 34 THIEF CREEK SUB DISTRIBUTION-UNATTEN 138.00 24.90

 35 THIRD WEST SUB DISTRIBUTION-UNATTEN 46.00 12.47

 36 THIRTEENTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47

 37 THOMPSON SUB DISTRIBUTION-UNATTEN 46.00 4.16

 38 TOOELE DEPOT SUB DISTRIBUTION-UNATTEN 46.00 12.50

 39 TOQUERVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47 34.50

 40 TRI CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47

FERC FORM NO. 1 (ED. 12-96) Page 426.16
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 UINTAH SUB DISTRIBUTION-UNATTEN 46.00 12.47

 2 UNION SUB DISTRIBUTION-UNATTEN 46.00 12.47

 3 UNIVERSITY SUB DISTRIBUTION-UNATTEN 46.00 4.16

 4 VALLEY CENTER SUB DISTRIBUTION-UNATTEN 46.00 12.47

 5 VERMILLION SUB DISTRIBUTION-UNATTEN 46.00 12.47

 6 VERNAL SUB DISTRIBUTION-UNATTEN 69.00 12.47

 7 VEYO HYDRO DISTRIBUTION-UNATTEN 34.50 2.40

 8 VICKERS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 9 VINEYARD SUB DISTRIBUTION-UNATTEN 46.00 12.47

 10 WALLSBURG SUB DISTRIBUTION-UNATTEN 138.00 12.47

 11 WALNUT GROVE SUB DISTRIBUTION-UNATTEN 138.00 12.50

 12 WARREN SUB DISTRIBUTION-UNATTEN 138.00 12.47

 13 WASATCH STATE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 14 WASHAKIE SUB DISTRIBUTION-UNATTEN 138.00 4.16

 15 WELBY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 16 WELFARE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 17 WELLINGTON SUB DISTRIBUTION-UNATTEN 46.00 12.47

 18 WEST COMMERCIAL SUB DISTRIBUTION-UNATTEN 46.00 12.47

 19 WEST JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47

 20 WEST OGDEN SUB DISTRIBUTION-UNATTEN 138.00 12.47

 21 WEST ROY SUB DISTRIBUTION-UNATTEN 46.00 12.47

 22 WEST TEMPLE SUB DISTRIBUTION-UNATTEN 46.00 4.16

 23 WESTFIELD SUB DISTRIBUTION-UNATTEN 138.00 12.47

 24 WESTWATER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 25 WHITE MESA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 26 WHITE ROCK SUB DISTRIBUTION-UNATTEN 138.00 12.47

 27 WILLOWCREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47

 28 WILLOWRIDGE SUB DISTRIBUTION-UNATTEN 46.00 12.47

 29 WINCHESTER HILLS SUB DISTRIBUTION-UNATTEN 34.50 12.47

 30 WINKLEMAN SUB DISTRIBUTION-UNATTEN 46.00 7.20

 31 WOLF CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 32 WOOD CROSS SUB DISTRIBUTION-UNATTEN 46.00 12.47

 33 WOODRUFF SUB DISTRIBUTION-UNATTEN 46.00 12.47

 34 Total 20756.27 3726.81 184.97

 35 Number of Substations- 299

 36

 37 ANGEL SUB T/D-UNATTENDED 138.00 12.47 46.00

 38 BDO SUBSTATION T/D-UNATTENDED 138.00 12.47

 39 BUTLERVILLE SUB T/D-UNATTENDED 138.00 46.00 12.47

 40 COTTONWOOD SUB T/D-UNATTENDED 138.00 12.47 46.00

FERC FORM NO. 1 (ED. 12-96) Page 426.17
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 EMMA PARK SUBSTATION T/D-UNATTENDED 138.00 12.47

 2 HALE SUB T/D-UNATTENDED 138.00 46.00 12.47

 3 HIGHLAND SUB T/D-UNATTENDED 138.00 12.47 46.00

 4 JORDAN SUB T/D-UNATTENDED 138.00 46.00 12.47

 5 JUDGE SUB T/D-UNATTENDED 46.00 12.47

 6 MCCLELLAND SUB T/D-UNATTENDED 138.00 46.00 12.47

 7 OQUIRRH SUB T/D-UNATTENDED 345.00 46.00 138.00

 8 PARRISH SUB T/D-UNATTENDED 138.00 12.47 46.00

 9 PIONEER PLANT T/D-UNATTENDED 138.00 2.30 46.00

 10 RIVERDALE SUB T/D-UNATTENDED 138.00 46.00 12.47

 11 SEVIER SUB T/D-UNATTENDED 138.00 46.00 12.47

 12 SILVER CREEK SUB T/D-UNATTENDED 138.00 12.47 46.00

 13 SPHINX SUB T/D-UNATTENDED 46.00 12.47

 14 SYRACUSE SUB T/D-UNATTENDED 345.00 46.00 138.00

 15 TAYLORSVILLE SUB T/D-UNATTENDED 138.00 46.00 12.47

 16 TERMINAL SUB T/D-UNATTENDED 345.00 46.00 138.00

 17 TIMP SUB T/D-UNATTENDED 138.00 46.00 12.47

 18 TOOELE SUB T/D-UNATTENDED 138.00 46.00 12.47

 19 WEST VALLEY SUB T/D-UNATTENDED 138.00 12.47

 20 Total 3611.00 679.00 802.23

 21 Number of Substations- 23

 22

 23 EMERY SUB TRANSMISSION-ATTENDE 345.00 138.00 69.00

 24 GADSBY SUB TRANSMISSION-ATTENDE 138.00 46.00

 25 HUNTER PLANT TRANSMISSION-ATTENDE 345.00 23.00

 26 HUNTINGTON PLANT TRANSMISSION-ATTENDE 345.00 23.00

 27 90TH SOUTH SUB TRANSMISSION-UNATTEN 345.00 138.00

 28 ABAJO SUB TRANSMISSION-UNATTEN 138.00 69.00

 29 ASHLEY SUB TRANSMISSION-UNATTEN 138.00 46.00

 30 BARNEY SUB TRANSMISSION-UNATTEN 138.00 46.00

 31 BEN LOMOND SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00

 32 BLACKHAWK SUB TRANSMISSION-UNATTEN 138.00 69.00 46.00

 33 BOOKCLIFFS SUB TRANSMISSION-UNATTEN 69.00 46.00

 34 CAMERON SUB TRANSMISSION-UNATTEN 138.00 46.00

 35 CAMP WILLIAMS SUB TRANSMISSION-UNATTEN 345.00 138.00 12.47

 36 CARBON SUB TRANSMISSION-UNATTEN 138.00

 37 COLUMBIA SUB TRANSMISSION-UNATTEN 138.00 46.00

 38 CRANER FLAT SUB TRANSMISSION-UNATTEN 138.00 12.47

 39 CUTLER SUB TRANSMISSION-UNATTEN 138.00 46.00

 40 EL MONTE SUB TRANSMISSION-UNATTEN 138.00 46.00

FERC FORM NO. 1 (ED. 12-96) Page 426.18
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 GARKANE SUB TRANSMISSION-UNATTEN 69.00 46.00

 2 GREEN CANYON SUB TRANSMISSION-UNATTEN 138.00 46.00

 3 GRINDING SUB TRANSMISSION-UNATTEN 138.00 13.80

 4 HELPER SUB TRANSMISSION-UNATTEN 138.00 46.00

 5 HONEYVILLE SUB TRANSMISSION-UNATTEN 138.00 46.00

 6 HORSESHOE SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47

 7 HUNTINGTON SUB TRANSMISSION-UNATTEN 345.00 138.00

 8 JERUSALEM SUB TRANSMISSION-UNATTEN 138.00 46.00

 9 LAMPO SUB TRANSMISSION-UNATTEN 138.00 46.00

 10 MCFADDEN SUB TRANSMISSION-UNATTEN 138.00 46.00

 11 MIDDLETON SUB TRANSMISSION-UNATTEN 138.00 69.00 34.50

 12 MIDVALLEY SUB TRANSMISSION-UNATTEN 345.00 138.00

 13 MIDWAY CITY SUB TRANSMISSION-UNATTEN 138.00 46.00

 14 MINERAL PRODUCTS SUB TRANSMISSION-UNATTEN 69.00 46.00

 15 MOAB SUB TRANSMISSION-UNATTEN 138.00 69.00

 16 NEBO SUB TRANSMISSION-UNATTEN 138.00 46.00

 17 OLMSTED SUB TRANSMISSION-UNATTEN 46.00 2.40

 18 PAROWAN VALLEY SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50

 19 PAVANT SUB TRANSMISSION-UNATTEN 230.00 46.00

 20 PINTO SUB TRANSMISSION-UNATTEN 345.00 138.00 69.00

 21 RED BUTTE SUB TRANSMISSION-UNATTEN 230.00 138.00

 22 SAND COVE HYDRO TRANSMISSION-UNATTEN 34.50 2.40

 23 SIGURD SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00

 24 SMITHFIELD SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47

 25 SPANISH FORK SUB TRANSMISSION-UNATTEN 345.00 138.00 46.00

 26 ST GEORGE SUB TRANSMISSION-UNATTEN 138.00 16.50

 27 THREE PEAKS SUB TRANSMISSION-UNATTEN 345.00 138.00

 28 WEBER PLANT/SUB TRANSMISSION-UNATTEN 46.00 2.30

 29 WEST CEDAR SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50

 30 Total 8843.50 3315.87 646.91

 31 Number of Substations- 47

 32

 33 Washington

 34 ATTALIA SUB DISTRIBUTION-UNATTEN 69.00 12.47

 35 BOWMAN SUB DISTRIBUTION-UNATTEN 69.00 12.47

 36 CASCADE KRAFT SUB DISTRIBUTION-UNATTEN 69.00 12.47 4.16

 37 CLINTON SUB DISTRIBUTION-UNATTEN 115.00 12.47

 38 DAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47

 39 DODD ROAD SUB DISTRIBUTION-UNATTEN 69.00 20.80

 40 GRANDVIEW SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00

FERC FORM NO. 1 (ED. 12-96) Page 426.19
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 HOPLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47

 2 MILL CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 3 NACHES HYDRO DISTRIBUTION-UNATTEN 115.00 12.47

 4 NOB HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47

 5 NORTH PARK SUB DISTRIBUTION-UNATTEN 115.00 12.47

 6 ORCHARD SUB DISTRIBUTION-UNATTEN 115.00 12.47

 7 PACIFIC SUB DISTRIBUTION-UNATTEN 115.00 12.47

 8 POMEROY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 9 PROSPECT POINT SUB DISTRIBUTION-UNATTEN 69.00 12.47

 10 PUNKIN CENTER SUB DISTRIBUTION-UNATTEN 115.00 12.47

 11 RIVER ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47

 12 SELAH SUB DISTRIBUTION-UNATTEN 115.00 12.47

 13 SULPHUR CREEK SUB DISTRIBUTION-UNATTEN 115.00 12.47

 14 SUNNYSIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 15 TIETON SUB DISTRIBUTION-UNATTEN 115.00 12.47 34.50

 16 TOPPENISH SUB DISTRIBUTION-UNATTEN 115.00 12.47

 17 TOUCHET SUB DISTRIBUTION-UNATTEN 69.00 12.47

 18 VOELKER SUB DISTRIBUTION-UNATTEN 115.00 12.47

 19 WAITSBURG SUB DISTRIBUTION-UNATTEN 69.00 12.47

 20 WAPATO SUB DISTRIBUTION-UNATTEN 115.00 12.47

 21 WENAS SUB DISTRIBUTION-UNATTEN 115.00 12.47

 22 WHITE SWAN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 23 WILEY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 24 Total 2990.00 382.43 107.66

 25 Number of Substations- 30

 26

 27 CENTRAL SUB T/D-UNATTENDED 69.00 12.47

 28 UNION GAP SUB T/D-UNATTENDED 230.00 115.00 12.47

 29 Total 299.00 127.47 12.47

 30 Number of Substations- 2

 31

 32 CONDIT PLANT TRANSMISSION-ATTENDE 69.00 2.30

 33 MERWIN PLANT TRANSMISSION-ATTENDE 115.00 13.20

 34 YALE PLANT TRANSMISSION-ATTENDE 115.00 13.80

 35 OUTLOOK SUB TRANSMISSION-UNATTEN 230.00 115.00

 36 PASCO SUB TRANSMISSION-UNATTEN 115.00 69.00 7.20

 37 POMONA HEIGHTS SUB TRANSMISSION-UNATTEN 230.00 115.00

 38 WALLA WALLA 230KV SUB TRANSMISSION-UNATTEN 230.00 69.00

 39 WALLULA SUB TRANSMISSION-UNATTEN 230.00 69.00

 40 WINE COUNTRY SUB TRANSMISSION-UNATTEN 230.00 115.00

FERC FORM NO. 1 (ED. 12-96) Page 426.20
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 Total 1564.00 581.30 7.20

 2 Number of Substations- 9

 3

 4 Wyoming

 5 AIR BASE DISTRIBUTION-UNATTEN 12.47 2.40

 6 ANTELOPE MINE SUB DISTRIBUTION-UNATTEN 230.00 34.50

 7 ASTLE STREET DISTRIBUTION-UNATTEN 34.50 13.20

 8 BAILEY DOME SUB DISTRIBUTION-UNATTEN 57.00 12.47

 9 BAR X SUB DISTRIBUTION-UNATTEN 230.00 34.50

 10 BID MUDDY SUB DISTRIBUTION-UNATTEN 69.00 12.47

 11 BIG PINEY SUB DISTRIBUTION-UNATTEN 69.00 24.90

 12 BLACKS FORK SUB DISTRIBUTION-UNATTEN 230.00 34.50

 13 BRIDGER PUMP SUB DISTRIBUTION-UNATTEN 230.00 34.50 13.20

 14 BRYAN SUB DISTRIBUTION-UNATTEN 115.00 12.47

 15 BUFFALO TOWN SUB DISTRIBUTION-UNATTEN 20.80 4.16

 16 BYRON SUB DISTRIBUTION-UNATTEN 34.50 4.16

 17 CASSA SUB DISTRIBUTION-UNATTEN 57.00 20.80

 18 CENTER STREET SUB DISTRIBUTION-UNATTEN 115.00 4.16

 19 CHAPMAN SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47

 20 CHATHAM SUB DISTRIBUTION-UNATTEN 34.50 4.16

 21 CHUKAR SUB DISTRIBUTION-UNATTEN 12.47 4.16

 22 CHURCH AND DWIGHT SUB DISTRIBUTION-UNATTEN 34.50 0.48

 23 COKEVILLE SUB DISTRIBUTION-UNATTEN 46.00 24.90

 24 COLUMBIA-GENEVA SUB DISTRIBUTION-UNATTEN 230.00 13.80

 25 COMMUNITY PARK SUB DISTRIBUTION-UNATTEN 115.00 13.20

 26 CROOKS GAP SUB DISTRIBUTION-UNATTEN 34.50 12.47

 27 DEER CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 28 DJ COAL MINE SUB DISTRIBUTION-UNATTEN 69.00 34.50

 29 DOUGLAS SUB DISTRIBUTION-UNATTEN 57.00 2.30

 30 DRY FORK SUB DISTRIBUTION-UNATTEN 69.00 4.16

 31 ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 7.20

 32 ELK HORN SUB DISTRIBUTION-UNATTEN 115.00 12.50

 33 EMIGRANT SUB DISTRIBUTION-UNATTEN 115.00 12.47

 34 EVANS SUB DISTRIBUTION-UNATTEN 115.00 12.47

 35 EVANSTON SUB DISTRIBUTION-UNATTEN 138.00 12.47

 36 FARMERS UNION SUB DISTRIBUTION-UNATTEN 34.50 4.16

 37 FIREHOLE SUB DISTRIBUTION-UNATTEN 230.00 34.50

 38 FORT CASPER SUB DISTRIBUTION-UNATTEN 69.00 12.47

 39 FORT SANDERS SUB DISTRIBUTION-UNATTEN 115.00 13.20

 40 FRANNIE SUB DISTRIBUTION-UNATTEN 230.00 34.50

FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 FRONTIER SUB DISTRIBUTION-UNATTEN 69.00 4.16

 2 GARLAND SUB DISTRIBUTION-UNATTEN 230.00 34.50

 3 GLENDO SUB DISTRIBUTION-UNATTEN 57.00 4.16

 4 GRASS CREEK SUB DISTRIBUTION-UNATTEN 230.00 34.50

 5 GREAT DIVIDE SUB DISTRIBUTION-UNATTEN 115.00 34.50

 6 GREYBULL SUB DISTRIBUTION-UNATTEN 34.50 4.16

 7 HANNA SUB DISTRIBUTION-UNATTEN 34.50 12.47

 8 JACKALOPE SUB DISTRIBUTION-UNATTEN 115.00 12.47

 9 KEMMERER SUB DISTRIBUTION-UNATTEN 69.00 24.90

 10 KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.50 2.40

 11 KIRBY CREEK SUB DISTRIBUTION-UNATTEN 34.50 4.16

 12 LANDER SUB DISTRIBUTION-UNATTEN 34.50 12.47

 13 LARAMIE SUB DISTRIBUTION-UNATTEN 115.00 13.20

 14 LATHAM SUB DISTRIBUTION-UNATTEN 230.00 34.50

 15 LINCH SUB DISTRIBUTION-UNATTEN 69.00 13.80

 16 LITTLE MOUNTAIN SUB DISTRIBUTION-UNATTEN 230.00 34.50

 17 LOVELL SUB DISTRIBUTION-UNATTEN 34.50 4.16

 18 MILL IRON SUB DISTRIBUTION-UNATTEN 34.50 13.80

 19 MILLS SUB DISTRIBUTION-UNATTEN 12.47 4.16

 20 MURPHY DOME SUB DISTRIBUTION-UNATTEN 34.50 13.20

 21 NUGGETT SUB DISTRIBUTION-UNATTEN 69.00 7.20

 22 OPAL SUB DISTRIBUTION-UNATTEN 46.00 24.90

 23 ORIN SUB DISTRIBUTION-UNATTEN 57.00 12.47

 24 ORPHA SUB DISTRIBUTION-UNATTEN 57.00 7.20

 25 PARADISE SUB DISTRIBUTION-UNATTEN 69.00 25.00

 26 PARCO SUB DISTRIBUTION-UNATTEN 34.50 12.47

 27 PINEDALE SUB DISTRIBUTION-UNATTEN 69.00 24.90

 28 PITCHFORK SUB DISTRIBUTION-UNATTEN 69.00 24.90

 29 POINT OF ROCKS SUB DISTRIBUTION-UNATTEN 230.00 34.50

 30 POISON SPIDER SUB DISTRIBUTION-UNATTEN 69.00 2.40

 31 POLECAT SUB DISTRIBUTION-UNATTEN 34.50 12.47

 32 RAINBOW SUB DISTRIBUTION-UNATTEN 34.50 13.20

 33 RAVEN SUB DISTRIBUTION-UNATTEN 230.00 34.50

 34 RED BUTTE SUB DISTRIBUTION-UNATTEN 69.00 12.47

 35 REFINERY SUB DISTRIBUTION-UNATTEN 115.00 12.47

 36 SAGE HILL SUB DISTRIBUTION-UNATTEN 34.50 13.20

 37 SHOSHONI SUB DISTRIBUTION-UNATTEN 34.50 2.40

 38 SLATE CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47

 39 SOUTH CODY SUB DISTRIBUTION-UNATTEN 69.00 24.90

 40 SOUTH ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 4.16

FERC FORM NO. 1 (ED. 12-96) Page 426.22
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 SOUTH TRONA SUB DISTRIBUTION-UNATTEN 230.00 34.50

 2 SPRING CREEK SUB DISTRIBUTION-UNATTEN 115.00 13.20

 3 SVILAR SUB DISTRIBUTION-UNATTEN 34.50 4.16

 4 TEN MILE STEP DOWN SUB DISTRIBUTION-UNATTEN 34.50 12.50

 5 TEN MILE SUB DISTRIBUTION-UNATTEN 69.00 34.50

 6 THERMOPOLIS TOWN SUB DISTRIBUTION-UNATTEN 34.50 4.16

 7 THUNDER CREEK SUB DISTRIBUTION-UNATTEN 57.00 12.47

 8 VETERANS SUB DISTRIBUTION-UNATTEN 34.50 13.20

 9 WELCH SUB DISTRIBUTION-UNATTEN 57.00 2.40

 10 WERTZ-SINCLAIR SUB DISTRIBUTION-UNATTEN 57.00 4.16 12.50

 11 WEST ADAMS SUB DISTRIBUTION-UNATTEN 34.50 4.16

 12 WESTERN CLAY SUB DISTRIBUTION-UNATTEN 34.50 0.48

 13 WESTVACO SUB DISTRIBUTION-UNATTEN 230.00 34.50

 14 WORLAND TOWN SUB DISTRIBUTION-UNATTEN 34.50 4.16

 15 WYOPO SUB DISTRIBUTION-UNATTEN 230.00 34.50

 16 WYUTA SUB DISTRIBUTION-UNATTEN 46.00 12.47

 17 Total 8161.21 1404.07 25.70

 18 Number of Substations- 92

 19

 20 BUFFALO SUB T/D-UNATTENDED 230.00 20.80

 21 HILLTOP SUB T/D-UNATTENDED 115.00 34.50 20.80

 22 LABARGE SUB T/D-UNATTENDED 69.00 24.90

 23 RIVERTON 230 SUB T/D-UNATTENDED 230.00 12.47 34.50

 24 YELLOWCAKE SUB T/D-UNATTENDED 230.00 34.50

 25 Total 874.00 127.17 55.30

 26 Number of Substations- 5

 27

 28 DAVE JOHNSTON PLANT/SUB TRANSMISSION-ATTENDE 230.00 115.00 69.00

 29 JIM BRIDGER 345KV SUB TRANSMISSION-ATTENDE 345.00 230.00 34.50

 30 JIM BRIDGER UNITS 1-4 TRANSMISSION-ATTENDE 345.00 22.00

 31 NAUGHTON SUB TRANSMISSION-ATTENDE 230.00 69.00 138.00

 32 WYODAK 230KV SUB TRANSMISSION-ATTENDE 230.00 69.00

 33 WYODAK PLANT TRANSMISSION-ATTENDE 230.00 22.00

 34 BAIROIL SUB TRANSMISSION-UNATTEN 115.00 34.50 57.00

 35 CASPER SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00

 36 CHAPPELL CREEK SUB TRANSMISSION-UNATTEN 230.00 69.00

 37 CHIMNEY BUTTE SUB TRANSMISSION-UNATTEN 230.00 69.00

 38 FOOTE CREEK WIND FARM TRANSMISSION-UNATTEN 230.00 34.50

 39 GLENDO AUTO SUB TRANSMISSION-UNATTEN 69.00 57.00

 40 MANSFACE SUB TRANSMISSION-UNATTEN 230.00 34.50

FERC FORM NO. 1 (ED. 12-96) Page 426.23
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 MIDWEST SUB TRANSMISSION-UNATTEN 230.00 69.00 34.50

 2 MINERS SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50

 3 MUSTANG SUB TRANSMISSION-UNATTEN 230.00 115.00

 4 OREGON BASIN SUB TRANSMISSION-UNATTEN 230.00 34.50 69.00

 5 PLATTE SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50

 6 RAILROAD SUB TRANSMISSION-UNATTEN 230.00 138.00

 7 ROCK SPRINGS 230 SUB TRANSMISSION-UNATTEN 230.00 34.50

 8 SAGE SUB TRANSMISSION-UNATTEN 69.00 46.00

 9 THERMOPOLIS SUB TRANSMISSION-UNATTEN 230.00 115.00

 10 Total 4853.00 1722.50 540.00

 11 Number of Substations- 22

 12

 13 CALIFORNIA

 14 Distribution - 43

 15 T/D - 3

 16 Transmission - 9

 17

 18 IDAHO

 19 Distribution - 66

 20 T/D - 4

 21 Transmission - 18

 22

 23 MONTANA

 24 Transmission - 1

 25

 26 OREGON

 27 Distribution - 183

 28 T/D - 10

 29 Transmission - 42

 30

 31 UTAH

 32 Distribution - 299

 33 T/D - 23

 34 Transmission - 47

 35

 36 WASHINGTON

 37 Distribution - 30

 38 T/D - 2

 39 Transmission - 9

 40

FERC FORM NO. 1 (ED. 12-96) Page 426.24
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

Tertiary

(d)

Character of Substation

(e)

Secondary

VOLTAGE (In MVa)

1. Report below the information called for concerning substations of the respondent as of the end of the year.

2. Substations which serve only one industrial or street railway customer should not be listed below.

3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

 1 WYOMING

 2 Distribution - 92

 3 T/D - 5

 4 Transmission - 22

 5

 6 ALL STATES

 7 Distribution - 713

 8 T/D - 47

 9 Transmission - 148

 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

FERC FORM NO. 1 (ED. 12-96) Page 426.25
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 1

 25 1 2

 6 1 3

 1 3 4

 2 3 5

 4 3 6

 1 7

 8 3 8

 6 1 9

 9 1 10

 13 1 11

 1 1 12

 8 3 13

 4 3 14

 9 3 15

 13 1 16

 2 3 17

 4 1 18

 31 2 19

 6 1 20

 4 3 21

 6 1 22

 14 1 23

 16 4 24

 13 1 25

 6 6 26

 20 4 27

 2 3 28

 1 1 29

 2 3 30

 9 3 31

 2 3 32

 2 3 33

 18 3 34

 1 1 35

 6 3 36

 3 37

 2 3 38

 20 1 39

 6 6 40

FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 7 1 1

 25 1 2

 4 3 3

 4 3 4

 342 100 5

 6

 7

 31 4 8

 3 3 9

 95 2 10

 129 9 11

 12

 13

 5 3 14

 28 6 2 15

 375 2 16

 60 3 1 17

 2 3 18

 19 3 19

 150 2 20

 19 1 21

 38 3 22

 696 26 3 23

 24

 25

 26

 4 1 27

 14 1 28

 20 1 29

 6 1 30

 8 1 31

 4 1 32

 13 1 33

 11 1 34

 14 1 35

 20 1 36

 5 1 37

 30 1 1 38

 5 1 39

 4 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 21 4 1

 5 1 2

 13 1 3

 14 1 4

 14 1 5

 3 1 6

 6 1 7

 5 1 8

 14 1 9

 9 1 10

 3 1 11

 6 1 12

 9 1 13

 4 1 14

 20 1 15

 3 1 16

 22 1 17

 14 1 18

 3 1 19

 5 1 20

 3 1 21

 11 1 22

 20 1 23

 5 1 24

 8 1 25

 14 1 26

 20 1 27

 20 1 28

 13 1 29

 2 1 30

 20 1 31

 33 2 32

 9 1 33

 8 1 34

 7 1 35

 40 2 36

 20 1 37

 20 1 38

 20 1 39

 14 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 8 1 1

 5 1 2

 13 1 3

 13 1 4

 4 1 5

 4 1 6

 7 1 7

 7 1 8

 14 1 9

 20 1 10

 4 1 11

 20 1 12

 777 71 1 13

 14

 15

 71 4 1 16

 14 1 17

 189 4 18

 40 2 19

 314 11 1 20

 21

 22

 115 4 23

 75 2 1 24

 250 1 25

 25 3 26

 67 1 27

 67 1 28

 67 1 29

 25 3 30

 75 1 31

 763 8 1 32

 233 3 33

 6 2 34

 40 2 35

 30 1 36

 76 2 37

 168 3 38

 700 1 39

 533 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 3315 41 2 1

 2

 3

 4

 100 1 5

 100 1 6

 7

 8

 9

 5 1 10

 30 6 11

 25 1 12

 25 1 13

 5 1 14

 9 1 15

 8 3 1 16

 11 3 17

 25 1 18

 6 1 19

 40 2 20

 2 3 21

 32 2 22

 8 3 23

 3 1 24

 8 3 25

 25 1 26

 50 2 27

 13 1 28

 34 2 29

 40 2 30

 34 2 31

 20 1 32

 13 1 33

 9 3 34

 20 1 35

 45 2 36

 25 1 37

 5 3 38

 25 1 39

 80 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 45 2 1

 1 3 2

 20 1 3

 1 3 4

 9 2 5

 55 2 1 6

 20 1 7

 40 2 8

 5 1 9

 25 2 10

 20 1 11

 25 1 12

 13 1 13

 2 3 14

 25 1 15

 50 2 16

 75 3 17

 13 1 18

 50 2 19

 7 1 20

 13 1 21

 20 1 22

 45 2 23

 20 1 24

 19 2 25

 13 1 26

 25 1 27

 21 4 28

 5 3 29

 20 1 30

 8 3 31

 25 2 32

 5 1 33

 13 1 34

 11 3 35

 6 1 36

 20 1 37

 45 2 38

 1 4 39

 25 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 20 1 1

 8 3 2

 13 1 3

 6 3 4

 40 2 5

 45 2 6

 20 1 7

 75 3 8

 50 2 9

 40 2 10

 20 1 11

 13 1 12

 2 1 13

 20 1 14

 75 2 15

 13 1 16

 20 1 17

 20 1 18

 6 1 1 19

 25 2 20

 3 3 21

 40 2 22

 6 1 23

 50 2 24

 9 3 25

 13 3 26

 40 2 27

 105 3 28

 40 2 29

 9 1 30

 25 2 31

 25 1 32

 20 1 33

 20 1 34

 79 14 35

 45 2 36

 17 6 37

 1 38

 6 3 39

 2 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 100 4 1

 14 1 2

 9 1 3

 4 1 4

 9 1 5

 45 2 6

 8 1 7

 55 2 8

 45 2 9

 1 1 1 10

 40 2 11

 39 2 12

 46 7 1 13

 22 2 14

 6 1 15

 50 2 16

 11 3 17

 50 2 18

 2 3 19

 50 2 20

 14 1 21

 25 1 1 22

 25 2 23

 50 2 24

 9 3 25

 25 1 26

 9 1 27

 9 1 28

 45 2 29

 40 2 30

 70 3 31

 8 1 32

 40 2 33

 9 1 34

 2 3 35

 25 1 36

 19 2 37

 9 1 38

 20 1 39

 7 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.7
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 40 2 1

 55 2 2

 1 3

 25 1 4

 25 1 5

 42 2 6

 13 1 7

 50 2 8

 25 1 9

 1 1 10

 11 1 11

 13 3 12

 13 1 13

 25 2 14

 50 2 15

 25 1 16

 40 2 17

 22 4 18

 7 1 19

 13 3 20

 25 2 21

 3 3 22

 3 1 23

 50 2 24

 22 2 25

 23 9 26

 40 2 27

 60 3 28

 28 3 29

 23 3 30

 25 1 31

 37 2 32

 4526 360 6 33

 34

 35

 177 9 36

 65 2 37

 70 2 38

 23 3 39

 70 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.8
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 132 4 1

 187 8 2

 39 4 3

 400 4 4

 75 5 5

 1238 43 6

 7

 8

 17 3 9

 13 3 10

 89 2 1 11

 2 3 1 12

 40 4 13

 5 3 14

 40 6 1 15

 10 6 16

 50 9 17

 3 3 18

 75 1 19

 119 4 20

 60 1 21

 67 3 22

 50 1 23

 75 1 24

 344 6 25

 650 3 1 26

 3 1 27

 3 3 28

 7 3 29

 500 2 30

 458 4 31

 19 3 32

 29 2 33

 250 1 34

 33 1 35

 251 6 1 36

 733 10 37

 1300 6 1 38

 50 1 39

 114 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.9
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 150 1 1

 250 1 2

 8 3 1 3

 47 4 4

 50 1 5

 21 3 6

 13 3 7

 500 3 8

 100 2 9

 2 3 10

 6600 130 7 11

 12

 13

 14

 30 1 15

 30 1 16

 13 1 17

 30 1 18

 45 2 19

 11 1 20

 30 1 21

 1 1 22

 3 1 23

 50 1 24

 17 2 25

 2 1 26

 11 1 27

 2 3 28

 1 3 29

 9 1 30

 4 1 31

 14 1 32

 14 1 33

 9 1 34

 26 2 35

 6 1 36

 60 3 37

 11 3 38

 9 1 39

 13 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.10
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 1 1 1

 20 1 2

 3 1 3

 6 1 4

 30 1 5

 25 1 6

 40 2 7

 22 1 8

 9 1 9

 30 1 10

 25 1 11

 3 1 12

 4 1 13

 3 14

 60 2 15

 50 2 16

 4 1 17

 20 2 18

 30 1 19

 106 4 20

 1 3 21

 30 1 22

 3 1 23

 2 3 24

 30 1 25

 1 1 26

 22 1 27

 30 1 28

 42 1 29

 60 2 30

 55 2 31

 6 1 32

 48 3 33

 2 1 34

 4 1 35

 60 2 36

 2 1 37

 23 2 38

 60 2 39

 30 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.11
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 6 1 1

 60 2 2

 20 1 3

 19 2 4

 5 1 5

 3 1 6

 2 1 7

 3 3 8

 25 1 9

 14 1 10

 10 1 11

 3 1 12

 30 1 13

 1 2 14

 5 1 15

 6 1 16

 30 1 17

 4 1 18

 2 1 19

 2 1 20

 1 21

 22 1 22

 13 1 23

 28 2 1 24

 30 1 25

 30 1 26

 2 1 27

 50 2 28

 24 1 29

 5 2 30

 72 3 31

 1 1 32

 11 1 33

 60 2 34

 3 1 35

 3 3 36

 4 1 37

 30 1 38

 1 3 39

 25 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.12
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 50 2 1

 22 1 2

 4 1 3

 32 2 4

 22 1 5

 13 2 6

 1 1 7

 5 3 8

 2 1 9

 22 1 10

 13 2 11

 30 1 12

 30 1 13

 2 3 14

 3 1 15

 5 1 16

 7 1 17

 60 2 18

 7 1 19

 53 2 20

 6 1 21

 40 2 22

 2 1 23

 14 1 24

 20 1 25

 20 1 26

 4 1 27

 20 1 28

 1 29

 1 1 30

 20 1 31

 1 3 32

 4 1 33

 13 1 34

 30 1 35

 22 1 36

 2 1 37

 14 1 38

 20 1 39

 2 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.13
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 9 1 1

 6 1 2

 20 1 3

 42 2 4

 58 4 5

 5 1 6

 30 1 7

 25 1 8

 14 1 9

 1 10

 13 1 11

 2 1 12

 19 2 13

 13 1 14

 3 1 15

 3 1 16

 6 1 17

 25 1 18

 6 3 19

 5 1 20

 6 1 21

 6 1 22

 7 1 23

 20 1 24

 5 1 25

 14 1 26

 25 1 27

 2 1 28

 25 1 29

 22 1 30

 25 1 31

 45 2 32

 14 1 33

 24 2 34

 6 1 35

 22 1 36

 3 1 37

 20 1 38

 14 1 39

 48 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.14
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 4 1 1

 5 1 2

 4 3 3

 35 2 4

 50 2 5

 16 2 6

 6 1 7

 55 2 8

 2 1 9

 14 1 10

 22 1 11

 25 1 12

 14 1 13

 30 1 14

 2 1 15

 4 1 16

 60 2 17

 4 1 18

 15 1 19

 2 1 20

 1 3 21

 14 1 22

 13 1 23

 3 1 24

 45 2 25

 45 2 26

 5 1 27

 22 2 28

 11 1 29

 40 2 30

 20 1 31

 5 1 32

 4 1 33

 30 1 34

 24 3 35

 3 36

 11 1 37

 60 2 38

 30 1 39

 1 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.15
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 1 1 1

 1 3 2

 13 2 3

 5 3 4

 20 1 5

 6 1 6

 60 2 7

 20 1 8

 2 1 9

 40 2 10

 5 1 11

 60 2 12

 13 1 13

 30 1 14

 20 2 15

 60 2 16

 25 1 17

 30 1 18

 50 1 19

 50 2 20

 22 2 21

 6 1 22

 4 1 23

 4 1 24

 2 1 25

 20 1 26

 14 1 27

 7 1 28

 30 1 29

 8 1 30

 6 1 31

 20 1 32

 14 1 33

 14 1 34

 40 2 35

 24 2 36

 2 1 37

 25 1 38

 34 2 39

 30 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.16
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 39 2 1

 50 2 2

 48 4 3

 22 1 4

 3 1 5

 33 2 6

 2 3 7

 2 1 8

 25 1 9

 13 1 10

 30 1 11

 30 1 12

 2 3 13

 14 1 14

 22 1 15

 5 1 16

 4 1 17

 22 1 18

 28 1 19

 30 1 20

 25 1 21

 60 3 22

 20 1 23

 1 3 24

 14 1 25

 30 1 26

 1 1 27

 14 1 28

 4 1 29

 1 30

 6 1 31

 20 1 32

 2 1 33

 5620 419 1 34

 35

 36

 135 3 37

 30 1 38

 175 3 39

 289 7 40

FERC FORM NO. 1 (ED. 12-96) Page 427.17
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 8 1 1

 114 2 2

 97 2 3

 164 2 4

 22 1 5

 340 4 6

 135 3 7

 97 2 8

 51 7 9

 180 3 10

 34 4 11

 100 2 12

 3 4 3 13

 600 5 14

 358 4 15

 1108 6 2 16

 130 2 17

 158 3 18

 30 1 19

 4358 72 5 20

 21

 22

 783 13 1 23

 318 2 24

 1513 5 1 25

 981 4 26

 1538 6 1 27

 67 1 28

 133 2 29

 100 1 30

 1813 5 31

 100 2 32

 6 3 1 33

 25 3 34

 169 2 35

 8 1 36

 33 1 37

 40 2 38

 70 2 39

 313 3 40

FERC FORM NO. 1 (ED. 12-96) Page 427.18
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 33 1 1

 67 2 2

 225 3 3

 142 2 4

 35 1 5

 80 2 6

 270 4 7

 67 1 8

 75 1 9

 45 1 10

 141 4 11

 900 2 12

 67 1 13

 13 1 14

 67 1 15

 67 1 16

 15 1 17

 138 2 18

 133 2 19

 258 3 20

 400 1 21

 1 22

 1124 6 23

 63 2 24

 1017 5 25

 100 3 1 26

 450 1 27

 7 1 28

 131 2 29

 14140 116 5 30

 31

 32

 33

 25 1 34

 45 2 35

 117 6 36

 25 1 37

 23 2 38

 25 4 39

 56 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.19
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 50 2 1

 45 2 2

 20 1 3

 42 2 4

 45 2 5

 50 2 6

 28 3 7

 9 1 8

 40 2 9

 20 2 10

 51 4 11

 45 2 12

 25 1 13

 45 2 14

 29 2 15

 50 2 16

 6 1 17

 25 1 18

 9 1 19

 45 2 20

 25 2 21

 22 2 22

 45 2 23

 1087 61 24

 25

 26

 14 1 27

 348 5 28

 362 6 29

 30

 31

 13 6 1 32

 183 9 1 33

 144 3 1 34

 125 1 35

 39 9 36

 300 2 37

 300 2 38

 120 2 39

 250 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.20
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 1474 35 3 1

 2

 3

 4

 1 3 5

 25 1 6

 13 1 7

 2 1 8

 25 1 9

 7 1 10

 8 1 11

 150 2 12

 73 4 13

 25 1 14

 2 3 15

 2 3 16

 2 6 1 17

 13 1 18

 4 1 19

 3 20

 1 3 21

 3 2 22

 4 1 23

 45 2 24

 50 2 25

 5 3 26

 9 1 27

 13 1 28

 6 3 29

 9 1 30

 5 1 31

 25 1 32

 13 1 33

 9 1 34

 40 2 35

 2 3 36

 50 2 37

 25 1 38

 20 1 39

 50 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.21
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 6 1 1

 45 2 2

 3 4 3

 25 1 4

 20 1 5

 3 1 6

 6 1 7

 25 1 8

 10 1 9

 3 3 10

 2 3 11

 25 2 12

 50 2 13

 25 1 14

 13 1 15

 20 1 16

 4 3 17

 13 1 1 18

 1 3 19

 5 1 20

 1 21

 8 1 22

 2 3 23

 3 3 24

 30 1 25

 5 1 26

 8 1 27

 17 9 2 28

 25 1 29

 3 1 30

 2 3 31

 13 1 32

 200 2 33

 20 1 34

 45 2 35

 6 1 36

 2 3 37

 1 1 38

 14 3 1 39

 2 6 40

FERC FORM NO. 1 (ED. 12-96) Page 427.22
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 150 2 1

 25 1 2

 2 3 3

 5 1 4

 13 1 5

 5 1 6

 9 1 7

 25 2 8

 3 3 9

 2 6 10

 3 1 11

 1 1 12

 25 1 13

 5 1 14

 20 1 1 15

 1 16

 1739 173 6 17

 18

 19

 20 1 20

 45 2 1 21

 8 6 22

 50 3 23

 25 1 24

 148 13 1 25

 26

 27

 1358 17 28

 1084 22 29

 1122 2 30

 1232 15 1 31

 60 1 32

 503 3 1 33

 53 3 34

 517 6 35

 67 1 36

 75 1 37

 196 2 38

 15 2 39

 20 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.23
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 91 4 1

 58 4 1 2

 200 2 3

 65 2 4

 165 4 5

 400 1 6

 50 2 7

 22 1 8

 175 2 9

 7528 98 3 10

 11

 12

 13

 342 14

 129 15

 696 16

 17

 18

 777 19

 314 20

 3315 21

 22

 23

 100 24

 25

 26

 4526 27

 1238 28

 6600 29

 30

 31

 5620 32

 4358 33

 14140 34

 35

 36

 1087 37

 362 38

 1474 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 427.24
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

PacifiCorp X

04/18/2011

2010/Q4

Line

Number of Units No.

(f) (g) (h)

CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k)

Total Capacity

 (Continued)

Capacity of Substation

(In Service) (In MVa)

Number of

Transformers

In Service

Spare Type of Equipment

Number of

Transformers (In MVa)

(i) (j)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment 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.

 1

 1739 2

 148 3

 7528 4

 5

 6

 14091 7

 6549 8

 33853 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

FERC FORM NO. 1 (ED. 12-96) Page 427.25
Schedule Page: 426.9 Line No.: 26 Column: a

The Dixonville 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration (the "BPA").

Ownership of the substation is as follows: PacifiCorp 50.0% and the BPA 50.0%. Operation and maintenance costs are shared between

the two parties and responsibility is as follows: PacifiCorp 58.0% and the BPA 42.0%.

Schedule Page: 426.9 Line No.: 38 Column: a

The Meridian 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration (the "BPA"). Ownership

of the substation is as follows: PacifiCorp 50.0% and the BPA 50.0%. Operation and maintenance costs are shared between the two

parties and responsibility is as follows: PacifiCorp 58.0% and the BPA 42.0%.

Schedule Page: 426.23 Line No.: 28 Column: a

The Dave Johnston 230kV Substation is jointly owned by the respondent and Black Hills Power. Ownership of the substation is as

follows: PacifiCorp 85.0% and Black Hills Power 15.0%. Operation and maintenance costs are shared between the two parties and

responsibility is as follows: PacifiCorp 85.0% and Black Hills Power 15.0%.

Schedule Page: 426.23 Line No.: 29 Column: a

The Jim Bridger 345kV Substation is jointly owned by the respondent and Idaho Power Company. Ownership of the substation is as

follows: PacifiCorp 66.7% and Idaho Power Company 33.3%. Operation and maintenance costs are shared between the two parties and

responsibility is as follows: PacifiCorp 66.7% and Idaho Power Company 33.3%.

Schedule Page: 426.23 Line No.: 32 Column: a

The Wyodak 230kV Substation is jointly owned by the respondent and Black Hills Power. Ownership of the substation is as follows:

PacifiCorp 80.0% and Black Hills Power 20.0%. Operation and maintenance costs are shared between the two parties and

responsibility is as follows: PacifiCorp 80.0% and Black Hills Power 20.0%.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description of the Non-Power Good or Service

Name of

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

Assiciated/Affiliated

Company

Account

Charged or

Credited

Amount

Charged or Credited

1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.

2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to

an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not

attempt to include or aggregate amounts in a nonspecific category such as "general".

3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.

 1 Non-power Goods or Services Provided by Affiliated

 2 Coal purchases/ support services / materials and Bridger Coal Company 128,804,025

 3 supplies

 4

 5 Coal purchases Trapper Mining Inc. 151 12,420,218

 6

 7 MEHC management fee MEHC 11,622,757

 8 MEC 1,761,257

 9 MidAmerican Funding 930.2, 426.5, 107 1,433,272

 10 MHC, Inc. 930.2, 426.5 816,328

 11 CalEnergy Generation 930.2 5,211

 12 CE Electric UK Funding 930.2, 107 29,152

 13 Charges over cost cap - retained by MEHC MEHC 426.5 -6,667,977

 14

 15 Net management fee billings (sum of 7 - 13) MEHC see above 9,000,000

 16

 17

 18

 19

 20 Non-power Goods or Services Provided for Affiliate

 21 Administrative support services/ management fee/ Bridger Coal Company 146 3,542,671

 22 royalties

 23

 24

 25

 26 Labor and benefits services (primarily IT costs) MEHC 146 1,218,262

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 1 Non-power Goods or Services Provided by Affiliated

 2 Gas transportation services Kern River Gas 501, 547 3,308,627

FERC FORM NO. 1 (New) Page 429

FERC FORM NO. 1-F (New)
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description of the Non-Power Good or Service

Name of

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

Assiciated/Affiliated

Company

Account

Charged or

Credited

Amount

Charged or Credited

1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.

2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to

an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not

attempt to include or aggregate amounts in a nonspecific category such as "general".

3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.

 3

 4 Relocation services HomeServices 2,053,556

 5

 6 Captive insurance premiums expense MEHC Insurance Svcs. 924, 925 6,969,001

 7

 8 Rail services/ right-of-way fees BNSF Railway Company 151, 507, 567, 589 29,905,732

 9

 10

 11 Financial transactions related to energy hedging

 12 activity and banking services Wells Fargo & Company 28,815,677

 13

 14 Water treatment services at generating facilities Nalco Holding Company 3,225,464

 15

 16

 17

 18

 19

 20 Non-power Goods or Services Provided for Affiliate

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

 1 Non-power Goods or Services Provided by Affiliated

 2

 3

 4

FERC FORM NO. 1 (New) Page 429.1

FERC FORM NO. 1-F (New)
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES

PacifiCorp X

04/18/2011

2010/Q4

Line

 No. Description of the Non-Power Good or Service

Name of

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

Assiciated/Affiliated

Company

Account

Charged or

Credited

Amount

Charged or Credited

1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.

2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to

an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not

attempt to include or aggregate amounts in a nonspecific category such as "general".

3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20 Non-power Goods or Services Provided for Affiliate

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

 41

 42

FERC FORM NO. 1 (New) Page 429.2

FERC FORM NO. 1-F (New)
Schedule Page: 429 Line No.: 2 Column: 

Accounts charged for Bridger Coal Company: 232, 500, 501, 511, 553, 151.

Schedule Page: 429 Line No.: 2 Column: 

Non-power goods or services provided by Bridger Coal Company are as follows:

Coal purchases $ 128,741,571 

Support services/materials and supplies 62,454 

 $ 128,804,025 

Schedule Page: 429 Line No.: 7 Column: 

The amounts in column (d) were the amounts billed by MEHC and its affiliates to PacifiCorp on the consolidated bill through MEHC

under the Intercompany Administrative Services Agreement. The fee was capped at $9 million for the year ended December 31, 2010.

A portion of the services provided by MEHC and its affiliates were billed based on allocation factors, which are as follows: 

Labor and Assets: An equal weighting of each company's labor and assets expressed as a percentage of the whole ((labor % + assets

%) ÷ 2) determines the portion assigned to each company. Labor is 12 months ended through December of the prior year. Assets are

total assets at December 31 of the prior year. Five combinations of this allocator are used for allocating services that benefit different

companies within the holding company organization.

Legislative and Regulatory: used to allocate costs incurred by the holding company’s Legislative & Regulatory groups. The

Legislative & Regulatory groups work on a variety of legislative and regulatory subject matter for select group of companies within the

holding company organization. The Legislative and Regulatory allocation percentages are based on the Legislative & Regulatory

groups’ estimation of the time and resources that are being spent on these selected companies.

Plant: This allocator distributes costs of managing the corporate insurance function based on assets for each platform.

Schedule Page: 429 Line No.: 7 Column: 

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “MEHC” ON PAGE 429: Complete name is MidAmerican Energy

Holdings Company.

Schedule Page: 429 Line No.: 7 Column: 

Accounts charged for MEHC: 930.2, 513, 426.5, 107.

Schedule Page: 429 Line No.: 8 Column: 

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “MEC” ON PAGE 429: Complete name is MidAmerican Energy

Company.

Schedule Page: 429 Line No.: 8 Column: 

Accounts charged for MEC: 930.2, 501, 426.5, 146, 107, 143. 

Schedule Page: 429 Line No.: 11 Column: 

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “CALENERGY GENERATION” ON PAGE 429: Complete name is

CalEnergy Generation Operating Company.

Schedule Page: 429 Line No.: 21 Column: 

Non-power goods or services provided to Bridger Coal Company are as follows:

Administrative support services $ 2,344,729 

Non-MEHC management fee 1,074,000 

Royalties 123,942 

 $ 3,542,671 

The Bridger Coal Company management fee is intended to compensate PacifiCorp's subsidiary Pacific Minerals, Inc. for its full cost of

managing Bridger Coal Company, without profit. The fee is based on projected labor and other costs.

Schedule Page: 429 Line No.: 26 Column: 

A portion of the services provided to MEHC and its affiliates were billed based on the following allocation factor:

Labor and Assets: An equal weighting of each company's labor and assets expressed as a percentage of the whole ((labor % + assets

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.1
%) ÷ 2) determines the portion assigned to each company. Labor is 12 months ended through December of the prior year. Assets are

total assets at December 31 of the prior year. Five combinations of this allocator are used for allocating services that benefit different

companies within the holding company organization.

Schedule Page: 429.1 Line No.: 4 Column: 

THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF “HomeServices” ON PAGE 429: Complete name is HomeServices of

America, Inc.

Schedule Page: 429.1 Line No.: 4 Column: 

Accounts charged for HomeServices: 501, 506, 535, 539, 549, 557, 560, 561.2, 580, 581, 588, 590, 592, 593, 597, 902, 903, 908, 921,

935, and clearing accounts. 

Schedule Page: 429.1 Line No.: 6 Column: 

Refer to additional discussion regarding transactions with MEHC Insurance Services Ltd. in Note 17 of Notes to Financial Statements

within this FERC Form No. 1. 

Schedule Page: 429.1 Line No.: 8 Column: 

Non-power goods or services provided by BNSF Railway Company are as follows:

Rail services $ 29,856,898 

Right-of-way fees 48,834 

 $ 29,905,732 

Included in the rail services are amounts related to a jointly-owned plant that are paid indirectly to BNSF Railway Company.

Schedule Page: 429.1 Line No.: 12 Column: 

Accounts charged for Wells Fargo & Company: 501, 547, 548, 557, 588, 903, 921, 228.3, 419, 427.

Schedule Page: 429.1 Line No.: 14 Column: 

Accounts charged for Nalco Holding Company: 154, 502, 506, 511, 512, 513, 546, 548, 549, 570, 582.

Schedule Page: 429.1 Line No.: 16 Column: 

Excluded from this page are “convenience” payments made to vendors by one entity on behalf of, and charged to, other entities within

the MEHC group. Examples of such convenience payments include software license costs, industry association dues, insurance

premiums, leadership conference costs, etc. Such affiliate charges reflect the ability to obtain price discounts as a result of larger

purchasing power. Also excluded from this page are reimbursements by MEHC for payments made by PacifiCorp to its employees

under a long-term incentive plan (“LTIP”) maintained by MEHC. Amounts paid by PacifiCorp to fund the LTIP are included in the

MEHC management fee amount included on page 429 line 7. The convenience payments and the LTIP reimbursements do not

constitute “services” as required by this page. 

Schedule Page: 429.1 Line No.: 17 Column: 

PacifiCorp consolidates its wholly owned subsidiaries Centralia Mining Company, Energy West Mining Company, Glenrock Coal

Company, Interwest Mining Company and Pacific Minerals, Inc. Transactions with these entities have been excluded from the amounts

reported on this page. Refer to page 103, Corporations Controlled by Respondent in this Form No. 1 for more information regarding

the wholly owned subsidiaries that PacifiCorp consolidates.

Name of Respondent

PacifiCorp 

This Report is:

(1) X An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr)

04/18/2011

Year/Period of Report

2010/Q4

FOOTNOTE DATA

FERC FORM NO. 1 (ED. 12-87) Page 450.2
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

FERC FORM NO. 1 (ED. 12-95) Index 2
INDEX (continued)

Schedule Page No.

Interest

 charges, paid on long-term debt, advances, etc ............................................... 256-257

Investments

 nonutility property .............................................................................. 221

 subsidiary companies ......................................................................... 224-225

Investment tax credits, accumulated deferred ..................................................... 266-267

Law, excerpts applicable to this report form .......................................................... iv

List of schedules, this report form .................................................................. 2-4

Long-term debt ................................................................................... 256-257

Losses-Extraordinary property ........................................................................ 230

Materials and supplies ............................................................................... 227

Miscellaneous general expenses ....................................................................... 335

Notes

 to balance sheet ............................................................................. 122-123

 to statement of changes in financial position ................................................ 122-123

 to statement of income ....................................................................... 122-123

 to statement of retained earnings ............................................................ 122-123

Nonutility property .................................................................................. 221

Nuclear fuel materials ........................................................................... 202-203

Nuclear generating plant, statistics ............................................................. 402-403

Officers and officers' salaries ...................................................................... 104

Operating

 expenses-electric ............................................................................ 320-323

 expenses-electric (summary) ...................................................................... 323

Other

 paid-in capital .................................................................................. 253

 donations received from stockholders ............................................................. 253

 gains on resale or cancellation of reacquired

 capital stock .................................................................................... 253

 miscellaneous paid-in capital .................................................................... 253

 reduction in par or stated value of capital stock ................................................ 253

 regulatory assets ................................................................................ 232

 regulatory liabilities ........................................................................... 278

Peaks, monthly, and output ........................................................................... 401

Plant, Common utility

 accumulated provision for depreciation ........................................................... 356

 acquisition adjustments .......................................................................... 356

 allocated to utility departments ................................................................. 356

 completed construction not classified ............................................................ 356

 construction work in progress .................................................................... 356

 expenses ......................................................................................... 356

 held for future use .............................................................................. 356

 in service ....................................................................................... 356

 leased to others ................................................................................. 356

Plant data ...................................................................................336-337

 401-429

FERC FORM NO. 1 (ED. 12-95) Index 3
INDEX (continued)

Schedule Page No.

Plant - electric

 accumulated provision for depreciation ........................................................... 219

 construction work in progress .................................................................... 216

 held for future use .............................................................................. 214

 in service ................................................................................... 204-207

 leased to others ................................................................................. 213

Plant - utility and accumulated provisions for depreciation

 amortization and depletion (summary) ............................................................. 201

Pollution control facilities, accumulated deferred

 income taxes ..................................................................................... 234

Power Exchanges .................................................................................. 326-327

Premium and discount on long-term debt ............................................................... 256

Premium on capital stock ............................................................................. 251

Prepaid taxes .................................................................................... 262-263

Property - losses, extraordinary ..................................................................... 230

Pumped storage generating plant statistics ....................................................... 408-409

Purchased power (including power exchanges) ...................................................... 326-327

Reacquired capital stock ............................................................................. 250

Reacquired long-term debt ........................................................................ 256-257

Receivers' certificates .......................................................................... 256-257

Reconciliation of reported net income with taxable income

 from Federal income taxes ...................................................................... 261

Regulatory commission expenses deferred .............................................................. 233

Regulatory commission expenses for year .......................................................... 350-351

Research, development and demonstration activities ............................................... 352-353

Retained Earnings

 amortization reserve Federal ..................................................................... 119

 appropriated ................................................................................. 118-119

 statement of, for the year ................................................................... 118-119

 unappropriated ............................................................................... 118-119

Revenues - electric operating .................................................................... 300-301

Salaries and wages

 directors fees ................................................................................... 105

 distribution of .............................................................................. 354-355

 officers' ........................................................................................ 104

Sales of electricity by rate schedules ............................................................... 304

Sales - for resale ............................................................................... 310-311

Salvage - nuclear fuel ........................................................................... 202-203

Schedules, this report form .......................................................................... 2-4

Securities

 exchange registration ........................................................................ 250-251

Statement of Cash Flows .......................................................................... 120-121

Statement of income for the year ................................................................. 114-117

Statement of retained earnings for the year ...................................................... 118-119

Steam-electric generating plant statistics ....................................................... 402-403

Substations .......................................................................................... 426

Supplies - materials and ............................................................................. 227

FERC FORM NO. 1 (ED. 12-90) Index 4
INDEX (continued)

Schedule Page No.

Taxes

 accrued and prepaid ......................................................................... 262-263

 charged during year ......................................................................... 262-263

 on income, deferred and accumulated ............................................................. 234

 272-277

 reconciliation of net income with taxable income for ............................................ 261

Transformers, line - electric ....................................................................... 429

Transmission

 lines added during year ..................................................................... 424-425

 lines statistics ............................................................................ 422-423

 of electricity for others ................................................................... 328-330

 of electricity by others ........................................................................ 332

Unamortized

 debt discount ............................................................................... 256-257

 debt expense ................................................................................ 256-257

 premium on debt ............................................................................. 256-257

Unrecovered Plant and Regulatory Study Costs ........................................................ 230

FERC FORM NO. 1 (ED. 12-90) Index 5