### 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 End of 2010/Q4 PacifiCorp

### 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) Thefollowing 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.pdfand 

## 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 18thof 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 End of PacifiCorp 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 1Name 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 (c) (b) (a) 

### 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".

101 General Information 1 102 Control Over Respondent 2 103 Corporations Controlled by Respondent 3 104 Officers 4 105 Directors 5 106(a)(b) Information on Formula Rates 6 108-109 Important Changes During the Year 7 110-113 Comparative Balance Sheet 8 114-117 Statement of Income for the Year 9 118-119 Statement of Retained Earnings for the Year 10 120-121 Statement of Cash Flows 11 122-123 Notes to Financial Statements 12 122(a)(b) Statement of Accum Comp Income, Comp Income, and Hedging Activities 13 200-201 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14 N/A 202-203 Nuclear Fuel Materials 15 204-207 Electric Plant in Service 16 N/A 213 Electric Plant Leased to Others 17 214 Electric Plant Held for Future Use 18 216 Construction Work in Progress-Electric 19 219 Accumulated Provision for Depreciation of Electric Utility Plant 20 224-225 Investment of Subsidiary Companies 21 227 Materials and Supplies 22 228(ab)-229(ab) Allowances 23 N/A 230 Extraordinary Property Losses 24 230 Unrecovered Plant and Regulatory Study Costs 25 231 Transmission Service and Generation Interconnection Study Costs 26 232 Other Regulatory Assets 27 233 Miscellaneous Deferred Debits 28 234 Accumulated Deferred Income Taxes 29 250-251 Capital Stock 30 253 Other Paid-in Capital 31 254 Capital Stock Expense 32 256-257 Long-Term Debt 33 261 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34 262-263 Taxes Accrued, Prepaid and Charged During the Year 35 266-267 Accumulated Deferred Investment Tax Credits 36

FERC FORM NO. 1 (ED. 12-96) Page 2LIST 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

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

269 Other Deferred Credits 37 272-273 Accumulated Deferred Income Taxes-Accelerated Amortization Property 38 274-275 Accumulated Deferred Income Taxes-Other Property 39 276-277 Accumulated Deferred Income Taxes-Other 40 278 Other Regulatory Liabilities 41 300-301 Electric Operating Revenues 42 304 Sales of Electricity by Rate Schedules 43 310-311 Sales for Resale 44 320-323 Electric Operation and Maintenance Expenses 45 326-327 Purchased Power 46 328-330 Transmission of Electricity for Others 47 N/A 331 Transmission of Electricity by ISO/RTOs 48 332 Transmission of Electricity by Others 49 335 Miscellaneous General Expenses-Electric 50 336-337 Depreciation and Amortization of Electric Plant 51 350-351 Regulatory Commission Expenses 52 352-353 Research, Development and Demonstration Activities 53 354-355 Distribution of Salaries and Wages 54 N/A 356 Common Utility Plant and Expenses 55 N/A 397 Amounts included in ISO/RTO Settlement Statements 56 398 Purchase and Sale of Ancillary Services 57 400 Monthly Transmission System Peak Load 58 N/A 400a Monthly ISO/RTO Transmission System Peak Load 59 401 Electric Energy Account 60 401 Monthly Peaks and Output 61 402-403 Steam Electric Generating Plant Statistics 62 406-407 Hydroelectric Generating Plant Statistics 63 N/A 408-409 Pumped Storage Generating Plant Statistics 64 410-411 Generating Plant Statistics Pages 65 422-423 Transmission Line Statistics Pages 66

FERC FORM NO. 1 (ED. 12-96) Page 3LIST 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

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

424-425 Transmission Lines Added During the Year 67 426-427 Substations 68 429 Transactions with Associated (Affiliated) Companies 69 450 Footnote Data 70 

### 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) PAGE101

### 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)XAn 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.

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

Mining 100 1 Centralia Mining Company Mining 100 2 Energy West Mining Company Mining 100 3 Glenrock Coal Company Management Services 100 4 Interwest Mining Company Management Services 100 5 Pacific Minerals, Inc. Mining 66.67 6 Bridger Coal Company Environmental Services 100 7 PacifiCorp Environmental Remediation Company Management Services 100 8 PacifiCorp Investment Management, Inc. Mining 21.40 9 Trapper Mining Inc. Non-profit foundation 10 PacifiCorp 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)XAn 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 450.1Name 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 (c) (b) (a) 

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

Executive Officers as of December 31, 2010: 1 Chairman of the Board and Chief Executive Officer Gregory E. Abel 2 Senior Vice President and Chief Financial Officer 233,525 Douglas K. Stuver 3 President, Rocky Mountain Power 357,150 A. Richard Walje 4 President, Pacific Power 265,740 R. Patrick Reiten 5 President, PacifiCorp Energy 230,114 Micheal G. Dunn 6 7 Other Executive Officers in 2010: 8 President, PacifiCorp Energy 22,944 A. Robert Lasich 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

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)XAn 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 450.1Name 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 (b) (a) No. 

### 1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), 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.

PacifiCorp Board of Directors as of December 31, 2010: 1 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309 Gregory E. Abel (Chairman of the Board and CEO, PacifiCorp) 2 825 NE Multnomah, Suite 2000, Portland, Oregon 97232 R. Patrick Reiten (President, Pacific Power) 3 201 South Main, Suite 2300, Salt Lake City, Utah 84111 A. Richard Walje (President, Rocky Mountain Power) 4 302 South 36th Street, Omaha, Nebraska 68131 Douglas L. Anderson 5 825 NE Multnomah, Suite 2000, Portland, Oregon 97232 Brent E. Gale (Senior Vice President) 6 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309 Patrick J. Goodman 7 1407 West North Temple, Suite 320, Salt Lake City, Utah 84116 Micheal G. Dunn (President, PacifiCorp Energy) 8 201 South Main, Suite 2400, Salt Lake City, Utah 84111 Mark C. Moench (SVP and General Counsel, PacifiCorp) 9 825 NE Multnomah, Suite 2000, Portland, Oregon 97232 Natalie L. Hocken (VP and General Counsel, Pacific Power) 10 11 Other PacifiCorp Board of Directors in 2010: 12 1407 West North Temple, Suite 320, Salt Lake City, Utah 84116 A. Robert Lasich (President, PacifiCorp Energy) 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48

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)XAn 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 450.1Name 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 No 

### X 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

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

FERC FORM NO. 1 (NEW. 12-08) Page106Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. \ Filed Date Accession No. 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 No 

### X 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)?

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 (NEW. 12-08) Page106aName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp 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.

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

FERC FORM NO. 1 (NEW. 12-08) Page106b

### 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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"belowfor 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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

UTILITY PLANT 1 22,017,833,818 19,881,830,192 200-201 Utility Plant (101-106, 114) 2 1,000,790,049 1,799,367,394 200-201 Construction Work in Progress (107) 3 23,018,623,867 21,681,197,586 TOTAL Utility Plant (Enter Total of lines 2 and 3) 4 7,467,085,584 7,199,824,404 200-201 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5 15,551,538,283 14,481,373,182 Net Utility Plant (Enter Total of line 4 less 5) 6 0 0 202-203 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7 0 0 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8 0 0 Nuclear Fuel Assemblies in Reactor (120.3) 9 0 0 Spent Nuclear Fuel (120.4) 10 0 0 Nuclear Fuel Under Capital Leases (120.6) 11 0 0 202-203 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12 0 0 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13 15,551,538,283 14,481,373,182 Net Utility Plant (Enter Total of lines 6 and 13) 14 0 0 Utility Plant Adjustments (116) 15 0 0 Gas Stored Underground - Noncurrent (117) 16 OTHER PROPERTY AND INVESTMENTS 17 16,174,139 11,538,314 Nonutility Property (121) 18 1,214,176 1,421,418 (Less) Accum. Prov. for Depr. and Amort. (122) 19 69,928 11,220,813 Investments in Associated Companies (123) 20 213,443,234 184,718,167 224-225 Investment in Subsidiary Companies (123.1) 21 (For Cost of Account 123.1, See Footnote Page 224, line 42) 22 0 0 228-229 Noncurrent Portion of Allowances 23 84,517,252 84,336,862 Other Investments (124) 24 0 0 Sinking Funds (125) 25 0 0 Depreciation Fund (126) 26 0 0 Amortization Fund - Federal (127) 27 4,236,855 6,945,599 Other Special Funds (128) 28 0 0 Special Funds (Non Major Only) (129) 29 9,400,334 42,909,107 Long-Term Portion of Derivative Assets (175) 30 0 0 Long-Term Portion of Derivative Assets – Hedges (176) 31 326,627,566 340,247,444 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32 CURRENT AND ACCRUED ASSETS 33 0 0 Cash and Working Funds (Non-major Only) (130) 34 4,143,415 4,238,848 Cash (131) 35 603,868 610,443 Special Deposits (132-134) 36 1,720 1,920 Working Fund (135) 37 463,002 81,769,678 Temporary Cash Investments (136) 38 351,089 208,656 Notes Receivable (141) 39 352,691,649 361,520,728 Customer Accounts Receivable (142) 40 62,682,797 32,319,952 Other Accounts Receivable (143) 41 7,517,126 7,052,112 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42 0 4,748,292 Notes Receivable from Associated Companies (145) 43 16,630,240 14,254,320 Accounts Receivable from Assoc. Companies (146) 44 188,493,087 170,930,143 227 Fuel Stock (151) 45 0 0 227 Fuel Stock Expenses Undistributed (152) 46 0 0 227 Residuals (Elec) and Extracted Products (153) 47 186,406,158 178,147,022 227 Plant Materials and Operating Supplies (154) 48 0 0 227 Merchandise (155) 49 0 0 227 Other Materials and Supplies (156) 50 0 0 202-203/227 Nuclear Materials Held for Sale (157) 51 0 0 228-229 Allowances (158.1 and 158.2) 52



### FERC FORM NO. 1 (REV. 12-03) Page110

### 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)

0 0 (Less) Noncurrent Portion of Allowances 53 0 0 227 Stores Expense Undistributed (163) 54 0 0 Gas Stored Underground - Current (164.1) 55 0 0 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56 392,988,760 298,656,263 Prepayments (165) 57 0 0 Advances for Gas (166-167) 58 6,674 8,788 Interest and Dividends Receivable (171) 59 1,535,228 2,772,053 Rents Receivable (172) 60 205,559,000 213,989,000 Accrued Utility Revenues (173) 61 0 0 Miscellaneous Current and Accrued Assets (174) 62 123,801,642 151,143,601 Derivative Instrument Assets (175) 63 9,400,334 42,909,107 (Less) Long-Term Portion of Derivative Instrument Assets (175) 64 0 0 Derivative Instrument Assets - Hedges (176) 65 0 0 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66 1,519,440,869 1,465,358,488 Total Current and Accrued Assets (Lines 34 through 66) 67 DEFERRED DEBITS 68 33,300,472 35,978,910 Unamortized Debt Expenses (181) 69 0 0 230a Extraordinary Property Losses (182.1) 70 135,566 5,289,133 230b Unrecovered Plant and Regulatory Study Costs (182.2) 71 1,737,446,767 1,550,913,652 232 Other Regulatory Assets (182.3) 72 2,895,724 3,116,069 Prelim. Survey and Investigation Charges (Electric) (183) 73 0 0 Preliminary Natural Gas Survey and Investigation Charges 183.1) 74 0 0 Other Preliminary Survey and Investigation Charges (183.2) 75 0 0 Clearing Accounts (184) 76 90,676 89,891 Temporary Facilities (185) 77 86,483,361 67,302,539 233 Miscellaneous Deferred Debits (186) 78 0 0 Def. Losses from Disposition of Utility Plt. (187) 79 0 0 352-353 Research, Devel. and Demonstration Expend. (188) 80 11,446,745 13,778,067 Unamortized Loss on Reaquired Debt (189) 81 588,589,916 587,517,758 234 Accumulated Deferred Income Taxes (190) 82 0 0 Unrecovered Purchased Gas Costs (191) 83 2,460,389,227 2,263,986,019 Total Deferred Debits (lines 69 through 83) 84 19,857,995,945 18,550,965,133 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85



### FERC FORM NO. 1 (REV. 12-03) Page111

### 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)XAn 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

### Year/Period of Report Name of Respondent This Report is: (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)

PROPRIETARY CAPITAL 1 3,417,945,896 3,417,945,896 Common Stock Issued (201) 2 250-251 41,463,300 40,733,100 Preferred Stock Issued (204) 3 250-251 0 0 Capital Stock Subscribed (202, 205) 4 0 0 Stock Liability for Conversion (203, 206) 5 0 0 Premium on Capital Stock (207) 6 1,002,063,956 1,102,229,981 Other Paid-In Capital (208-211) 7 253 0 0 Installments Received on Capital Stock (212) 8 252 0 0 (Less) Discount on Capital Stock (213) 9 254 41,288,207 41,284,560 (Less) Capital Stock Expense (214) 10 254b 2,225,701,346 2,792,155,606 Retained Earnings (215, 215.1, 216) 11 118-119 8,330,470 6,232,713 Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119 0 0 (Less) Reaquired Capital Stock (217) 13 250-251 0 0 Noncorporate Proprietorship (Non-major only) (218) 14 -5,819,577 -6,961,899 Accumulated Other Comprehensive Income (219) 15 122(a)(b) 6,648,397,184 7,311,050,837 Total Proprietary Capital (lines 2 through 15) 16 LONG-TERM DEBT 17 6,372,343,000 6,357,741,000 Bonds (221) 18 256-257 0 0 (Less) Reaquired Bonds (222) 19 256-257 0 0 Advances from Associated Companies (223) 20 256-257 0 0 Other Long-Term Debt (224) 21 256-257 35,563 32,845 Unamortized Premium on Long-Term Debt (225) 22 15,413,483 14,381,234 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 23 6,356,965,080 6,343,392,611 Total Long-Term Debt (lines 18 through 23) 24 OTHER NONCURRENT LIABILITIES 25 57,295,450 55,883,528 Obligations Under Capital Leases - Noncurrent (227) 26 0 0 Accumulated Provision for Property Insurance (228.1) 27 7,487,871 8,499,000 Accumulated Provision for Injuries and Damages (228.2) 28 592,543,110 502,064,476 Accumulated Provision for Pensions and Benefits (228.3) 29 41,878,303 39,343,745 Accumulated Miscellaneous Operating Provisions (228.4) 30 0 0 Accumulated Provision for Rate Refunds (229) 31 409,727,110 399,481,536 Long-Term Portion of Derivative Instrument Liabilities 32 0 0 Long-Term Portion of Derivative Instrument Liabilities - Hedges 33 102,516,932 105,328,750 Asset Retirement Obligations (230) 34 1,211,448,776 1,110,601,035 Total Other Noncurrent Liabilities (lines 26 through 34) 35 CURRENT AND ACCRUED LIABILITIES 36 0 36,000,000 Notes Payable (231) 37 539,268,266 472,504,319 Accounts Payable (232) 38 0 0 Notes Payable to Associated Companies (233) 39 13,729,206 19,893,492 Accounts Payable to Associated Companies (234) 40 31,895,824 39,611,243 Customer Deposits (235) 41 46,747,021 48,804,714 Taxes Accrued (236) 42 262-263 111,568,228 115,234,368 Interest Accrued (237) 43 520,947 512,462 Dividends Declared (238) 44 0 0 Matured Long-Term Debt (239) 45



### FERC FORM NO. 1 (rev. 12-03) Page112

### Year/Period of Report Name of Respondent This Report is: (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 (continued) 

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

0 0 Matured Interest (240) 46 15,796,380 16,587,742 Tax Collections Payable (241) 47 63,197,166 64,738,616 Miscellaneous Current and Accrued Liabilities (242) 48 1,725,318 1,369,860 Obligations Under Capital Leases-Current (243) 49 494,721,339 483,234,721 Derivative Instrument Liabilities (244) 50 409,727,110 399,481,536 (Less) Long-Term Portion of Derivative Instrument Liabilities 51 0 0 Derivative Instrument Liabilities - Hedges (245) 52 0 0 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53 909,442,585 899,010,001 Total Current and Accrued Liabilities (lines 37 through 53) 54 DEFERRED CREDITS 55 20,946,236 18,492,298 Customer Advances for Construction (252) 56 45,888,892 41,949,428 Accumulated Deferred Investment Tax Credits (255) 57 266-267 0 0 Deferred Gains from Disposition of Utility Plant (256) 58 40,157,480 51,492,025 Other Deferred Credits (253) 59 269 64,164,255 59,611,213 Other Regulatory Liabilities (254) 60 278 0 0 Unamortized Gain on Reaquired Debt (257) 61 0 11,642,708 Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277 2,802,655,179 3,330,234,891 Accum. Deferred Income Taxes-Other Property (282) 63 450,899,466 680,518,898 Accum. Deferred Income Taxes-Other (283) 64 3,424,711,508 4,193,941,461 Total Deferred Credits (lines 56 through 64) 65 18,550,965,133 19,857,995,945 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66



### FERC FORM NO. 1 (rev. 12-03) Page113Name 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

(c) (b) (a) 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

UTILITY OPERATING INCOME 1 4,402,215,385 4,353,766,380 300-301 Operating Revenues (400) 2Operating Expenses 3 2,277,135,354 2,279,099,664 320-323 Operation Expenses (401) 4 414,960,789 394,816,343 320-323 Maintenance Expenses (402) 5 501,224,256 473,163,461 336-337 Depreciation Expense (403) 6 336-337 Depreciation Expense for Asset Retirement Costs (403.1) 7 34,838,293 32,391,772 336-337 Amort. & Depl. of Utility Plant (404-405) 8 5,518,393 5,479,353 336-337 Amort. of Utility Plant Acq. Adj. (406) 9 4,523,779 5,149,968 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10Amort. of Conversion Expenses (407) 11 -2,004,224 1,549,004 Regulatory Debits (407.3) 12(Less) Regulatory Credits (407.4) 13 136,550,272 123,877,487 262-263 Taxes Other Than Income Taxes (408.1) 14 -517,806,480 -472,156,577 262-263 Income Taxes - Federal (409.1) 15 -4,449,586 -2,026,201 262-263 - Other (409.1) 16 1,254,766,756 1,368,522,890 234, 272-277 Provision for Deferred Income Taxes (410.1) 17 551,088,560 688,511,583 234, 272-277 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 18 -1,874,204 -1,874,204 266 Investment Tax Credit Adj. - Net (411.4) 19(Less) Gains from Disp. of Utility Plant (411.6) 20Losses from Disp. of Utility Plant (411.7) 21 2,817,551 3,790,891 (Less) Gains from Disposition of Allowances (411.8) 22Losses from Disposition of Allowances (411.9) 23 96,470 Accretion Expense (411.10) 24 3,549,573,757 3,515,690,486 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25 852,641,628 838,075,894 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114Name 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 to Date (in dollars) (k) (j) (g) 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 115Name 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 (c) (b) (a) 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)

852,641,628 838,075,894 Net Utility Operating Income (Carried forward from page 114) 27Other Income and Deductions 28Other Income 29Nonutilty Operating Income 30 1,416,581 1,526,343 Revenues From Merchandising, Jobbing and Contract Work (415) 31 1,362,155 1,518,065 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32 247,917 241,243 Revenues From Nonutility Operations (417) 33 81,037 28,326 (Less) Expenses of Nonutility Operations (417.1) 34 91,251 74,959 Nonoperating Rental Income (418) 35 -2,097,757 1,811,740 119 Equity in Earnings of Subsidiary Companies (418.1) 36 5,077,391 20,556,977 Interest and Dividend Income (419) 37 79,298,238 63,955,322 Allowance for Other Funds Used During Construction (419.1) 38 27,081,235 32,225,273 Miscellaneous Nonoperating Income (421) 39 2,617,525 2,267,272 Gain on Disposition of Property (421.1) 40 112,289,189 121,112,738 TOTAL Other Income (Enter Total of lines 31 thru 40) 41 Other Income Deductions 42 46,470 82,456 Loss on Disposition of Property (421.2) 43 1,285,816 1,263,905 Miscellaneous Amortization (425) 44 2,676,885 2,997,500 Donations (426.1) 45 -4,971,828 -5,605,297 Life Insurance (426.2) 46 -418,323 400,132 Penalties (426.3) 47 2,284,308 1,519,511 Exp. for Certain Civic, Political & Related Activities (426.4) 48 29,828,972 34,666,110 Other Deductions (426.5) 49 30,732,300 35,324,317 TOTAL Other Income Deductions (Total of lines 43 thru 49) 50Taxes Applic. to Other Income and Deductions 51 367,905 576,313 262-263 Taxes Other Than Income Taxes (408.2) 52 28,723,272 29,005,691 262-263 Income Taxes-Federal (409.2) 53 3,903,016 3,941,391 262-263 Income Taxes-Other (409.2) 54 85,258,308 99,093,919 234, 272-277 Provision for Deferred Inc. Taxes (410.2) 55 85,411,869 99,416,511 234, 272-277 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 56Investment Tax Credit Adj.-Net (411.5) 57 2,065,260 2,065,260 (Less) Investment Tax Credits (420) 58 30,775,372 31,135,543 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59 50,781,517 54,652,878 Net Other Income and Deductions (Total of lines 41, 50, 59) 60Interest Charges 61 363,203,396 369,236,117 Interest on Long-Term Debt (427) 62 3,727,614 3,786,241 Amort. of Debt Disc. and Expense (428) 63 2,331,323 2,785,112 Amortization of Loss on Reaquired Debt (428.1) 64 2,718 2,718 (Less) Amort. of Premium on Debt-Credit (429) 65(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66Interest on Debt to Assoc. Companies (430) 67 12,367,152 10,264,106 Other Interest Expense (431) 68 44,618,458 35,186,532 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69 337,008,309 350,882,326 Net Interest Charges (Total of lines 62 thru 69) 70 566,414,836 541,846,446 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71 Extraordinary Items 72Extraordinary Income (434) 73(Less) Extraordinary Deductions (435) 74Net Extraordinary Items (Total of line 73 less line 74) 75 262-263 Income Taxes-Federal and Other (409.3) 76Extraordinary Items After Taxes (line 75 less line 76) 77 566,414,836 541,846,446 Net Income (Total of line 71 and 77) 78

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)XAn 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 450.1Name 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

(c) (b) (a) 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) 1,684,184,571 2,222,125,535 1 Balance-Beginning of Period 2Changes 3Adjustments to Retained Earnings (Account 439) 4 5 6 7 8 9TOTAL Credits to Retained Earnings (Acct. 439) 10 11 12 13 14 15TOTAL Debits to Retained Earnings (Acct. 439) 540,034,706 568,512,593 16Balance Transferred from Income (Account 433 less Account 418.1) 17Appropriations of Retained Earnings (Acct. 436) 18 19 20 21 22TOTAL Appropriations of Retained Earnings (Acct. 436) 23Dividends Declared-Preferred Stock (Account 437) ( 2,083,790) -2,058,333 238 24Preferred Stock, various series and rates 25 26 27 28 ( 2,083,790) -2,058,333 29TOTAL Dividends Declared-Preferred Stock (Acct. 437) 30Dividends Declared-Common Stock (Account 438) 31 32 33 34 35 36TOTAL Dividends Declared-Common Stock (Acct. 438) ( 9,952) 37Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 2,222,125,535 2,788,579,795 38Balance - End of Period (Total 1,9,15,16,22,29,36,37) APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 FERC FORM NO. 1/3-Q (REV. 02-04) Page 118Name 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

(c) (b) (a) 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 45TOTAL Appropriated Retained Earnings (Account 215) APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1) 3,575,811 3,575,811 46TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) 3,575,811 3,575,811 47TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 2,225,701,346 2,792,155,606 48TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly 6,508,778 8,330,470 49Balance-Beginning of Year (Debit or Credit) 1,811,740 -2,097,757 50Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 9,952 52Transfers to Unappropriated Retained Earnings (Account 216) 8,330,470 6,232,713 53Balance-End of Year (Total lines 49 thru 52)

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)XAn 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: 541,846,446 566,414,836 2Net Income (Line 78(c) on page 117) 3Noncash Charges (Credits) to Income: 492,861,350 517,014,250 4Depreciation and Depletion 45,834,002 44,162,057 5Amortization: 6 726,000 -1,892,323 7Unrealized (Gains)/Losses on Derivative Contracts 679,678,715 703,524,635 8Deferred Income Taxes (Net) -3,939,464 -3,939,464 9Investment Tax Credit Adjustment (Net) -7,140,528 -13,328,543 10Net (Increase) Decrease in Receivables -41,858,225 -25,822,080 11 Net (Increase) Decrease in Inventory 12Net (Increase) Decrease in Allowances Inventory -33,318,429 -130,489,533 13Net Increase (Decrease) in Payables and Accrued Expenses 12,441,383 8,890,615 14Net (Increase) Decrease in Other Regulatory Assets -6,970,542 -4,813,321 15Net Increase (Decrease) in Other Regulatory Liabilities 63,955,322 79,298,238 16(Less) Allowance for Other Funds Used During Construction 1,811,740 -2,097,757 17(Less) Undistributed Earnings from Subsidiary Companies -216,306,739 -90,231,534 18Amounts Due To/From Affiliates (Net) 57,400,001 -102,246,009 19Derivative Collateral (Net) 16,989,197 22,143,762 20Other Operating Activities: 21 1,472,476,105 1,412,186,867 22Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 23 24Cash Flows from Investment Activities: 25Construction and Acquisition of Plant (including land): -2,356,195,937 -1,686,214,575 26Gross Additions to Utility Plant (less nuclear fuel) 27Gross Additions to Nuclear Fuel 28Gross Additions to Common Utility Plant 29Gross Additions to Nonutility Plant -63,955,322 -79,298,238 30(Less) Allowance for Other Funds Used During Construction 31 Other (provide details in footnote): 32 33 -2,292,240,615 -1,606,916,337 34Cash Outflows for Plant (Total of lines 26 thru 33) 35 36Acquisition of Other Noncurrent Assets (d) 1,274,203 7,282,766 37Proceeds from Disposal of Noncurrent Assets (d) 38 -13,402,178 39Investments in and Advances to Assoc. and Subsidiary Companies 4,643,134 40Contributions and Advances from Assoc. and Subsidiary Companies 41 Disposition of Investments in (and Advances to) 42Associated and Subsidiary Companies 43 -269,354 44Purchase of Investment Securities (a) 458,430 45Proceeds from Sales of Investment Securities (a)

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) 46Loans Made or Purchased 47Collections on Loans 48 49Net (Increase) Decrease in Receivables 50Net (Increase ) Decrease in Inventory 51 Net (Increase) Decrease in Allowances Held for Speculation 52Net Increase (Decrease) in Payables and Accrued Expenses 3,540,757 2,401,475 53Other Investing Activities: 54 55 56Net Cash Provided by (Used in) Investing Activities -2,282,593,445 -1,610,634,274 57Total of lines 34 thru 55) 58 59Cash Flows from Financing Activities: 60Proceeds from Issuance of: 982,802,997 61 Long-Term Debt (b) 62Preferred Stock 63Common Stock 125,000,000 100,000,000 64Equity Contribution 65 35,999,320 66Net Increase in Short-Term Debt (c) 67Other (provide details in footnote): 68 69 1,107,802,997 135,999,320 70Cash Provided by Outside Sources (Total 61 thru 69) 71 72Payments for Retirement of: -138,454,000 -14,602,000 73Long-term Debt (b) -560,528 74Preferred Stock 75Common Stock 76Other (provide details in footnote): -5,811,642 -1,724,876 77Repayment of Capital Lease Obligations -84,991,027 78Net Decrease in Short-Term Debt (c) 79 -2,083,790 -2,066,818 80Dividends on Preferred Stock 81 Dividends on Common Stock 82Net Cash Provided by (Used in) Financing Activities 876,462,538 117,045,098 83(Total of lines 70 thru 81) 84 85Net Increase (Decrease) in Cash and Cash Equivalents 66,345,198 -81,402,309 86(Total of lines 22,57 and 83) 87 19,665,248 86,010,446 88Cash and Cash Equivalents at Beginning of Period 89 86,010,446 4,608,137 90Cash and Cash Equivalents at End of period

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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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 representPacifiCorp'sshare 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)XAn 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)XAn 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)XAn 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)XAn 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 ofPacifiCorp'scommodity 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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 summarizesPacifiCorp'savailability 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)XAn 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'slong-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)XAn 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)XAn 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)XAn 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 BenefitPlans 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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, forPacifiCorp'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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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'spreferred 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)XAn 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) CommonShareholder'sEquity 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)XAn 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)XAn 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)XAn 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 123.40Name 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 andLosses 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

130,769 ( 3,399,666) Total (lines 2 and 3) 4

( 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

( 1,142,322) Total (lines 7 and 8) 9

( 6,961,899) Balance of Account 219 at End of Current Quarter/Year 10

FERC FORM NO. 1 (NEW 06-02) Page 122aOther 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) ( 2,550,680) 1 191,182 2 ( 3,460,079) 3 541,846,446 538,577,549 ( 3,268,897) 4 ( 5,819,577) 5 ( 5,819,577) 6 7,825,262 7,825,262 7 ( 8,967,584) ( 7,825,262) 8 566,414,836 565,272,514 ( 1,142,322) 9 ( 6,961,899) 10

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)XAn 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 450.1Name 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. (b) (a) Classification Electric (c) FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Total Company for the Current Year/Quarter Ended Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.

Utility Plant 1 In Service 2 21,284,241,062 21,284,241,062 Plant in Service (Classified) 3 65,393,121 65,393,121 Property Under Capital Leases 4 -4,484,801 -4,484,801 Plant Purchased or Sold 5 495,830,779 495,830,779 Completed Construction not Classified 6Experimental Plant Unclassified 7 21,840,980,161 21,840,980,161 Total (3 thru 7) 8Leased to Others 9 17,678,149 17,678,149 Held for Future Use 10 1,000,790,049 1,000,790,049 Construction Work in Progress 11 159,175,508 159,175,508 Acquisition Adjustments 12 23,018,623,867 23,018,623,867 Total Utility Plant (8 thru 12) 13 7,467,085,584 7,467,085,584 Accum Prov for Depr, Amort, & Depl 14 15,551,538,283 15,551,538,283 Net Utility Plant (13 less 14) 15Detail of Accum Prov for Depr, Amort & Depl 16In Service: 17 6,893,664,705 6,893,664,705 Depreciation 18Amort & Depl of Producing Nat Gas Land/Land Right 19Amort of Underground Storage Land/Land Rights 20 471,575,613 471,575,613 Amort of Other Utility Plant 21 7,365,240,318 7,365,240,318 Total In Service (18 thru 21) 22Leased to Others 23Depreciation 24Amortization and Depletion 25Total Leased to Others (24 & 25) 26Held for Future Use 27Depreciation 28Amortization 29Total Held for Future Use (28 & 29) 30Abandonment of Leases (Natural Gas) 31 101,845,266 101,845,266 Amort of Plant Acquisition Adj 32 7,467,085,584 7,467,085,584 Total Accum Prov (equals 14) (22,26,30,31,32) 33

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 Depletion38,474,141 Total $6,893,664,705 Name of Respondent

PacifiCorp 

### This Report is: (1)XAn 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 450.1Name 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 (c) (b) (a) 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.

Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 1 Fabrication 2 Nuclear Materials 3Allowance for Funds Used during Construction 4 (Other Overhead Construction Costs, provide details in footnote) 5 SUBTOTAL (Total 2 thru 5) 6 Nuclear Fuel Materials and Assemblies 7 In Stock (120.2) 8 In Reactor (120.3) 9 SUBTOTAL (Total 8 & 9) 10 Spent Nuclear Fuel (120.4) 11 Nuclear Fuel Under Capital Leases (120.6) 12 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 13TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 14 Estimated net Salvage Value of Nuclear Materials in line 9 15 Estimated net Salvage Value of Nuclear Materials in line 11 16 Est Net Salvage Value of Nuclear Materials in Chemical Processing 17 Nuclear Materials held for Sale (157) 18 Uranium 19 Plutonium 20 Other (provide details in footnote): 21 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) 22

FERC FORM NO. 1 (ED. 12-89) Page 202Name 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

(f) (e) (d) Changes during Year End of Year Amortization Other Reductions (Explain in a footnote)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22

FERC FORM NO. 1 (ED. 12-89) Page203Name 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 (c) (b) (a) Beginning of Year 1. Report below the original cost of electric plant in service according to the prescribed accounts. 2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. 3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. 4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions 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. INTANGIBLE PLANT 1 (301) Organization 2 (302) Franchises and Consents 162,527,923 77,267,612 3 (303) Miscellaneous Intangible Plant 589,907,847 23,939,123 4TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 752,435,770 101,206,735 5 2. PRODUCTION PLANT 6 A. Steam Production Plant 7 (310) Land and Land Rights 95,879,653 20,488 8 (311) Structures and Improvements 838,579,575 4,433,606 9 (312) Boiler Plant Equipment 3,124,068,006 576,748,680 10 (313) Engines and Engine-Driven Generators 11 (314) Turbogenerator Units 832,870,176 80,225,196 12 (315) Accessory Electric Equipment 366,892,467 18,979,727 13 (316) Misc. Power Plant Equipment 29,208,805 863,529 14 (317) Asset Retirement Costs for Steam Production 37,319,815 5,965,060 15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 5,324,818,497 687,236,286 16 B. Nuclear Production Plant 17 (320) Land and Land Rights 18 (321) Structures and Improvements 19 (322) Reactor Plant Equipment 20 (323) Turbogenerator Units 21 (324) Accessory Electric Equipment 22 (325) Misc. Power Plant Equipment 23 (326) Asset Retirement Costs for Nuclear Production 24TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25 C. Hydraulic Production Plant 26 (330) Land and Land Rights 20,209,614 5,914,565 27 (331) Structures and Improvements 104,317,417 8,572,335 28 (332) Reservoirs, Dams, and Waterways 314,817,920 14,385,298 29 (333) Water Wheels, Turbines, and Generators 111,436,535 2,106,752 30 (334) Accessory Electric Equipment 59,040,854 759,180 31 (335) Misc. Power PLant Equipment 2,391,127 32 (336) Roads, Railroads, and Bridges 15,942,236 138,551 33 (337) Asset Retirement Costs for Hydraulic Production 34TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 628,155,703 31,876,681 35 D. Other Production Plant 36 (340) Land and Land Rights 23,516,708 5,394,604 37 (341) Structures and Improvements 155,449,405 439,916 38 (342) Fuel Holders, Products, and Accessories 10,811,674 39 (343) Prime Movers 2,276,086,094 240,919,747 40 (344) Generators 347,539,112 27,923 41 (345) Accessory Electric Equipment 230,222,062 4,326,760 42 (346) Misc. Power Plant Equipment 12,179,685 43 (347) Asset Retirement Costs for Other Production 4,031,634 1,078,163 44TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,059,836,374 252,187,113 45 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 9,012,810,574 971,300,080 46

Page 204 FERC FORM NO. 1 (REV. 12-05)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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Account Balance Additions (c) (b) (a) Beginning of Year

3. TRANSMISSION PLANT 47 (350) Land and Land Rights 101,061,038 78,701,268 48 (352) Structures and Improvements 86,366,332 18,215,228 49 (353) Station Equipment 1,306,947,373 290,415,773 50 (354) Towers and Fixtures 480,248,436 375,535,768 51 (355) Poles and Fixtures 583,430,919 102,011,621 52 (356) Overhead Conductors and Devices 762,583,203 164,583,952 53 (357) Underground Conduit 3,211,828 47,624 54 (358) Underground Conductors and Devices 7,529,724 -54,629 55 (359) Roads and Trails 11,535,068 63,635 56 (359.1) Asset Retirement Costs for Transmission Plant 57TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 3,342,913,921 1,029,520,240 58 4. DISTRIBUTION PLANT 59 (360) Land and Land Rights 52,407,949 1,229,245 60 (361) Structures and Improvements 66,526,605 42,850 61 (362) Station Equipment 788,914,257 48,583,269 62 (363) Storage Battery Equipment 1,457,804 63 (364) Poles, Towers, and Fixtures 909,346,119 39,382,964 64 (365) Overhead Conductors and Devices 633,551,900 18,432,598 65 (366) Underground Conduit 292,200,023 10,912,103 66 (367) Underground Conductors and Devices 701,110,916 19,423,783 67 (368) Line Transformers 1,062,949,128 42,087,257 68 (369) Services 559,763,102 22,803,407 69 (370) Meters 187,209,616 17,562,522 70 (371) Installations on Customer Premises 8,809,120 108,262 71 (372) Leased Property on Customer Premises 72 (373) Street Lighting and Signal Systems 62,391,252 1,852,948 73 (374) Asset Retirement Costs for Distribution Plant 1,937,045 74TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5,328,574,836 222,421,208 75 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76 (380) Land and Land Rights 77 (381) Structures and Improvements 78 (382) Computer Hardware 79 (383) Computer Software 80 (384) Communication Equipment 81 (385) Miscellaneous Regional Transmission and Market Operation Plant 82 (386) Asset Retirement Costs for Regional Transmission and Market Oper 83TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84 6. GENERAL PLANT 85 (389) Land and Land Rights 16,200,395 86 (390) Structures and Improvements 231,527,327 4,173,919 87 (391) Office Furniture and Equipment 81,338,734 10,030,590 88 (392) Transportation Equipment 100,146,208 1,690,843 89 (393) Stores Equipment 13,899,989 372,170 90 (394) Tools, Shop and Garage Equipment 62,717,636 997,536 91 (395) Laboratory Equipment 37,088,803 898,197 92 (396) Power Operated Equipment 131,425,381 8,328,313 93 (397) Communication Equipment 246,182,036 39,209,034 94 (398) Miscellaneous Equipment 6,816,010 276,095 95 SUBTOTAL (Enter Total of lines 86 thru 95) 927,342,519 65,976,697 96 (399) Other Tangible Property 278,447,958 23,409,773 97 (399.1) Asset Retirement Costs for General Plant 39,748 98 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,205,830,225 89,386,470 99 TOTAL (Accounts 101 and 106) 19,642,565,326 2,413,834,733 100 (102) Electric Plant Purchased (See Instr. 8) 3,003,416 6,533,307 101 (Less) (102) Electric Plant Sold (See Instr. 8) 4,484,801 102 (103) Experimental Plant Unclassified 103 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 19,645,568,742 2,415,883,239 104

Page 206 FERC FORM NO. 1 (REV. 12-05)(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 End of PacifiCorp 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 3 607,856,161 1,017,776 7,008,585 4 847,651,696 1,017,776 7,008,585 5 6 7 95,898,852 1,289 8 921,546,842 79,423,572 889,911 9 3,520,898,916 -115,588,486 64,329,284 10 11 896,985,415 1,248,076 17,358,033 12 415,967,515 31,588,682 1,493,361 13 33,234,020 3,400,178 238,492 14 42,346,157 -938,718 15 5,926,877,717 72,022 -938,718 84,310,370 16 17 18 19 20 21 22 23 24 25 26 26,123,587 592 27 113,026,083 797,518 661,187 28 326,583,937 -1,820,024 799,257 29 112,432,922 -334,380 775,985 30 60,200,807 871,703 470,930 31 2,360,733 -2,652 27,742 32 16,323,315 285,341 42,813 33 34 657,051,384 -202,494 2,778,506 35 36 28,911,312 37 155,973,793 84,472 38 10,811,674 39 2,513,737,706 -413,169 2,854,966 40 346,954,523 79,619 692,131 41 234,749,420 215,899 15,301 42 12,181,682 2,729 732 43 5,109,797 44 3,308,429,907 -30,450 3,563,130 45 9,892,359,008 -160,922 -938,718 90,652,006 46

Page 205 FERC FORM NO. 1 (REV. 12-05)(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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. (g) Adjustments (e) Retirements (d) ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

47 181,517,465 1,799,642 44,483 48 122,948,592 18,478,503 111,471 49 1,549,843,309 -14,044,880 33,474,957 50 863,436,957 8,112,938 460,185 51 686,565,486 3,829,570 2,706,624 52 912,469,174 -9,855,548 4,842,433 53 3,259,452 54 7,475,095 55 11,598,703 56 57 4,339,114,233 8,320,225 41,640,153 58 59 52,837,393 -798,528 1,273 60 74,675,982 8,686,881 580,354 61 817,421,421 -8,013,059 12,063,046 62 -64,739 1,393,065 63 942,088,822 -512 6,639,749 64 648,849,674 3,134,824 65 302,216,890 241,775 1,137,011 66 718,645,076 -241,263 1,648,360 67 1,097,798,842 141,227 7,378,770 68 581,777,749 788,760 69 179,453,205 25,318,933 70 8,801,076 116,306 71 72 60,795,839 -141,227 3,307,134 73 1,937,045 74 5,487,299,014 -189,445 63,507,585 75 76 77 78 79 80 81 82 83 84 85 16,200,395 86 235,540,153 1,238,043 1,399,136 87 77,219,598 -972,877 13,176,849 88 98,768,642 3,068,409 89 13,766,183 -184,387 321,589 90 61,822,342 -2,605 1,890,225 91 36,594,299 -7,331 1,385,370 92 132,526,576 7,227,118 93 259,841,810 1,456,743 27,006,003 94 6,906,051 11,230 197,284 95 939,186,049 1,538,816 55,671,983 96 274,422,093 -155,454 27,280,184 97 39,748 98 1,213,647,890 1,538,816 -155,454 82,952,167 99 21,780,071,841 10,526,450 -1,094,172 285,760,496 100 -9,536,723 101 4,484,801 102 103 21,775,587,040 989,727 -1,094,172 285,760,496 104

Page 207 FERC FORM NO. 1 (REV. 12-05)

### 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)XAn 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 450.1Name 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 (b) (a) (Designate associated companies with a double asterisk) Property Leased Commission 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) Page213

47 TOTALName 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 (c) (b) (a) 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.

Land and Rights: 1 2 1977 North Horn Mountain Coal Properties 953,014 2018-2025 3 2007 Barnes Butte Substation 746,268 2015 4 2007 Wild Horse Wind Plant 6,763,094 2020 5 2007 Twelve Mile Wind Plant 2,160,207 2021 6 2008 Jumbers Point Substation 1,173,276 2015 7 2009 Mountain Green Substation 284,996 2025 8 2009 Hoggard Substation 254,397 2025 9 2009 Oquirrh-Terminal 345 kV Transmission Line 396,020 2014 10 2010 Bend Service Center 3,507,838 2020 11 2010 Legacy Substation 722,119 2020 12 13Miscellaneous, each under $250,000: 716,920 14 15 16 17 18 19 20Other Property: 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

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)XAn 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 450.1Name 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 - (b) (a) Electric (Account 107) 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (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.

Intangible: 1 14,508,952 Harry Allen Sub Install Transformer 2 11,654,227 Energy Trading Systems 3 2,922,082 Mobile Radio Purch-Implement VHF Spectrum 4 2,590,806 SAP license and maintenance enhancements 5 6 Production: 7 97,852,693 Naughton U2 Flue Gas Desulfurization System 8 83,434,697 Dave Johnston U4 SO2 & PM Emission Control Upgrades 9 71,803,962 Naughton U1 Flue Gas Desulfurization System 10 69,766,970 Wyodak U1 SO2 & PM Emission Control Upgrades 11 35,753,200 North Umpqua River System Relicensing Implementation 12 32,332,081 Hunter U2 Clean Air - PM 13 22,684,809 Huntington U1 SO2 & PM Emission Control Upgrades 14 21,663,099 Lewis River System Relicensing Implementation 15 20,535,338 Hunter U1 SO2 & PM Emission Control Upgrades 16 19,658,370 Hunter U2 SO2 & PM Emission Control Upgrades 17 15,662,505 Blundell Proofing Well Integration 18 13,138,382 Hunter U2 Turbine Upgrade HP/IP/LP 19 11,818,025 Ashton Dam Seepage Control 20 9,861,092 Wyodak U1 Air Cooled Condenser Replacement 21 8,717,197 Jim Bridger U3 SO2 & PM Emission Control Upgrades 22 7,510,593 Hayden Coal Unloading Facility 23 7,404,728 Jim Bridger U1 Turbine Upgrade HP/IP/LP 24 4,055,129 Hunter U2 Main Controls Replacement 25 4,051,513 Generation Compliance Initiative Hardware 26 3,917,040 Hunter U3 Turbine Upgrade HP/IP/LP 27 3,797,498 Lake Side 2 Development 28 3,475,741 Jim Bridger U3 Turbine Upgrade HP/IP/LP 29 2,953,717 Huntington U2 Turbine Upgrade HP/IP/LP 30 2,551,903 Wyodak U1 OH Clean Air - NOX 31 2,422,289 Hunter U2 Economizer Replacement 32 2,306,337 Wyodak U1 Replacement of Secondary Superheater 33 2,594,462 Rogue River System Relicensing Implementation 34 2,116,993 Slide Creek Overhaul 35 1,853,869 Hunter U2 Low Temp SH Replacement 36 1,688,900 Craig U1 HP-IP Turbine Rotor Replacement 37 1,627,669 Hunter U2 RH Pendant Replacement 38 1,545,438 Klamath River System Interim Implementation Measures 39 1,526,445 Soda Unit 1 Generator Rewind 40 1,467,568 Huntington U2 Boiler Finishing SH Pendants Replacement 41 1,414,798 Craig U2 HP-IP Turbine Rotor Upgrade 42

FERC FORM NO. 1 (ED. 12-87) Page216

43 TOTAL 1,000,790,049Name 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 - (b) (a) Electric (Account 107) 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (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.

1,404,294 Huntington U1 Steam Inerting for Coal Mills 1 1,379,807 Currant Creek Block 2 Development 2 1,286,788 Jim Bridger U3 Reheater Outlet Terminal Tubes 11 3 1,135,970 Jim Bridger U4 Turbine Upgrade HP/IP/LP 4 1,000,671 Goodnoe Wind Blade Replacements 5 6 Transmission: 7 45,692,963 Gateway West 500kV Line 8 26,927,521 Mona-Oquirrh 345kV/500kV Line 9 21,446,742 Red Butte Sub SVC and Property Acquisition 10 17,019,304 Bridger Mona 500kV Line 11 16,355,518 Sigurd-Red Butte-Crystal 345kV Line 12 16,178,910 Malin Sub Series Capacitor Replacement 13 10,806,981 Populus-Terminal: Double Circuit 345 kV Line 14 6,265,829 Oquirrh New 345-138kV Substation 15 5,883,823 Dave Johnston to Casper 230kV No 1&2 Line Rebuild 16 5,366,035 California-Oregon Intertie Transfer Capability Increase 17 4,535,245 Oquirrh-Terminal 345kV Line 18 3,664,891 Chappel Creek 230kV Cimarex Energy 19 3,145,454 Vickers Sub Add 46kV Circuit Breakers 20 3,027,576 Tom McCall Industrial Park 115kV Project 21 3,017,130 Wyoming Transmission Clearance Project 22 2,977,830 Southwest WY Silver Creek Build 138kV Line 23 2,795,752 Wallula-McNary 230kV Line 24 2,637,961 St George-Red Butte 138kV Line 25 2,596,618 TOT 4A-4B Transmission Path Transfer Capacity 26 2,510,101 Line 3 Convert to 115kV 27 2,046,439 Line 37 Convert to 115kV Build Nickel Mt Sub 28 1,716,683 Idaho Transmission Clearance Project 29 1,650,483 West Point-New 138 kV Line & 40 MVA Sub 30 1,449,273 Vantage-Pomona Heights 230kV Line 31 1,394,346 Eastside Transmission Line Ratings Wave Traps 32 1,347,235 Two Elks Intercon at Tri County Switchyard 33 1,279,887 Cameron-Milford 138kV Transmission 34 1,118,268 Dave Johnston U3 GSU Replacement 35 1,087,466 Utah Transmission Clearance Project 36 1,071,035 Hemingway-Captain Jack 500kV Line 37 38 Distribution: 39 5,471,601 Skypark Build New 138-12.5kV Substation 40 2,937,847 Copper Hills New 138-12.5kV Sub 41 2,622,983 Nibley 138-12.5kV Sub 42

FERC FORM NO. 1 (ED. 12-87) Page216.1

43 TOTAL 1,000,790,049Name 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 - (b) (a) Electric (Account 107) 1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (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.

2,593,830 Saratoga Sub Add 2nd Trnsf Rebld Tran Jumper 1 2,430,483 City Creek Center (SLC) New 40 MW Dev for PRI 2 2,102,256 Bend Plant Sub Increase Capacity 3 1,043,448 Farmington Sub Add 2nd 138-12.5 kV Transfmr 4 5 General: 6 25,383,718 Mobile Radio Replacement Project 7 14,093,017 Deer Creek Mine-Reconstruct Longwall System 8 1,823,963 PCC/SCC Router Replacement TOM 9 10 90,424,957 Miscellaneous Projects each under $1,000,000 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 39 40 41 42

FERC FORM NO. 1 (ED. 12-87) Page216.2

43 TOTAL 1,000,790,049Name 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 (c) (b) (a) (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.

Balance Beginning of Year 1 6,663,897,531 6,663,897,531 Depreciation Provisions for Year, Charged to 2(403) Depreciation Expense 3 501,224,256 501,224,256 (403.1) Depreciation Expense for Asset Retirement Costs 4

(413) Exp. of Elec. Plt. Leas. to Others 5Transportation Expenses-Clearing 6Other Clearing Accounts 7Other Accounts (Specify, details in footnote): 8 27,690,769 27,690,769 9TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9) 10 528,915,025 528,915,025

Net Charges for Plant Retired: 11 Book Cost of Plant Retired 12 278,227,865 278,227,865 Cost of Removal 13 43,273,030 43,273,030 Salvage (Credit) 14 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

17Book Cost or Asset Retirement Costs Retired 18Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18) 19 6,893,664,705 6,893,664,705

Steam Production 20 Section B. Balances at End of Year According to Functional Classification 2,549,642,134 2,549,642,134 Nuclear Production 21 Hydraulic Production-Conventional 22 262,715,132 262,715,132 Hydraulic Production-Pumped Storage 23Other Production 24 388,889,683 388,889,683 Transmission 25 1,172,814,664 1,172,814,664 Distribution 26 2,072,617,011 2,072,617,011 Regional Transmission and Market Operation 27General 28 446,986,081 446,986,081 TOTAL (Enter Total of lines 20 thru 28) 29 6,893,664,705 6,893,664,705

Page 219 FERC FORM NO. 1 (REV. 12-05)

### 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 amortization1,099,537 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)XAn 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 450.1Name 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 (c) (b) (a) 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.

2/1/1974 BRIDGER COAL COMPANY 1 161,668,072 Partner Capital 2 161,668,072 SUBTOTAL 3 4 8/19/1994 PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 5 14,719,625 Capital Contributions 6 8,330,470 Undistributed Subsidiary Earnings 7 23,050,095 SUBTOTAL 8 9 4/15/1992 TRAPPER MINING INC. 10Members' Equity 11 SUBTOTAL 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) Page224

42Total Cost of Account 123.1 $ TOTAL 184,718,167 207,210,521Name 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 6,232,713 -2,097,757 7 20,952,338 -2,097,757 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)XAn 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 450.1Name 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
(c) (b) (a) 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.

170,930,143 Electric 188,493,087 1 Fuel Stock (Account 151) 2 Fuel Stock Expenses Undistributed (Account 152) 3 Residuals and Extracted Products (Account 153) 4 Plant Materials and Operating Supplies (Account 154) 69,236,794 Electric 71,053,270 5 Assigned to - Construction (Estimated) 6 Assigned to - Operations and Maintenance 87,614,292 Electric 93,357,638 7 Production Plant (Estimated) 838,582 Electric 718,031 8 Transmission Plant (Estimated) 16,134,398 Electric 16,656,313 9 Distribution Plant (Estimated) 10 Regional Transmission and Market Operation Plant (Estimated) 4,322,956 Electric 4,620,906 11 Assigned to - Other (provide details in footnote) 178,147,022 186,406,158 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 13 Merchandise (Account 155) 14 Other Materials and Supplies (Account 156) 15 Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util) 16 Stores Expense Undistributed (Account 163) 17 18 19 349,077,165 374,899,245 20 TOTAL Materials and Supplies (Per Balance Sheet)

Page227 FERC FORM NO. 1 (REV. 12-05)

### Schedule Page: 227 Line No.: 11 Column: b Mining M&S $ 4,170,119 General Plant M&S152,837 $ 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)XAn 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 450.1Name 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 (b) (a) (Account 158.1) No. Amt. (c) No. (d) Amt. (e) 

### 1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by 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

170,953.00 156,646.00 Balance-Beginning of Year 1 2 Acquired During Year: 3 Issued (Less Withheld Allow) 4 4,562.00 Returned by EPA 5 6 7 Purchases/Transfers: 8 2.00 Adjustment 9 10 11 12 13 14 2.00 Total 15 16 Relinquished During Year: 17 65,838.00 Charges to Account 509 18 Other: 19 20 Cost of Sales/Transfers: 21 80,000.00 See footnote for details 22 23 24 25 26 27 80,000.00 Total 28 29,679.00 156,646.00 Balance-End of Year 29 30 Sales: 31 Net Sales Proceeds(Assoc. Co.) 32 Net Sales Proceeds (Other) 33 Gains 34 Losses 35 Allowances Withheld (Acct 158.2) 2,259.00 2,259.00 Balance-Beginning of Year 36 Add: Withheld by EPA 37 Deduct: Returned by EPA 38 2,259.00 Cost of Sales 39 2,259.00 Balance-End of Year 40 41 Sales: 42 Net Sales Proceeds (Assoc. Co.) 43 Net Sales Proceeds (Other) 44 Gains 45 Losses 46

FERC FORM NO. 1 (ED. 12-95) Page228aName 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 4,035,430.00 156,646.00 156,647.00 4,676,322.00 2 3 4 156,645.00 156,645.00 5 4,562.00 6 7 8 9 2.00 10 11 12 13 14 15 2.00 16 17 18 65,838.00 19 20 21 22 80,000.00 23 24 25 26 27 28 80,000.00 29 4,192,075.00 156,646.00 156,647.00 4,691,693.00 30 31 32 33 34 35

36 110,921.00 2,259.00 2,259.00 119,957.00 37 4,528.00 4,528.00 38 39 2,269.00 4,528.00 40 113,180.00 2,259.00 2,259.00 119,957.00 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-95) Page229a

### 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)XAn 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 450.1Name 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 (b) (a) (Account 158.1) No. Amt. (c) No. (d) Amt. (e) 

### 1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by 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

Balance-Beginning of Year 1 2 Acquired During Year: 3 Issued (Less Withheld Allow) 4 Returned by EPA 5 6 7 Purchases/Transfers: 8 9 10 11 12 13 14 Total 15 16 Relinquished During Year: 17 Charges to Account 509 18 Other: 19 20 Cost of Sales/Transfers: 21 22 23 24 25 26 27 Total 28 Balance-End of Year 29 30 Sales: 31 Net Sales Proceeds(Assoc. Co.) 32 Net Sales Proceeds (Other) 33 Gains 34 Losses 35 Allowances Withheld (Acct 158.2) Balance-Beginning of Year 36 Add: Withheld by EPA 37 Deduct: Returned by EPA 38 Cost of Sales 39 Balance-End of Year 40 41 Sales: 42 Net Sales Proceeds (Assoc. Co.) 43 Net Sales Proceeds (Other) 44 Gains 45 Losses 46

FERC FORM NO. 1 (ED. 12-95) Page228bName 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) Page229bName 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. (c) (b) (a) (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 (f) (e) 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 TOTALName 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.

(c) (b) (a) (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
(f) (e) 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)] Unrecovered Plant: Trojan Nuclear 1,809,172 407, 131 1,673,606 135,566 21 Plant located near Portland, OR 22Date of Retirement: 12/31/1992 23Date of Commission Authorization: 2404/20/1993 25Amortization Period: 01/1993 26through 01/2011 27 28Unrecovered Plant: Powerdale 3,479,961 3,479,961 29Hydro Electric Plant 30Date of Retirement: 02/08/2007 31 Date of Commission Authorization: 3205/14/2007 33Amortization Period: 05/2007 34through 12/2010 35 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)XAn 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 450.1Name 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 (b) (a) 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

Transmission Studies 1 14,314 Aref 591168 5616000 14,314 4562000 2 12,687 Aref 592473 5616000 12,687 4562000 3 9,062 Aref 594665 5616000 9,062 4562000 4 12,325 Aref 599599 5616000 12,325 4562000 5 5,869 Aref 610299 5616000 5,869 4562000 6 8,833 Aref 618363 5616000 8,833 4562000 7 3,644 Aref 645170 5616000 3,644 4562000 8 1,618 Aref 654674 5616000 1,618 4562000 9 21,160 Aref 581025 5616000 10 ( 6,036) Accruals - Customer Studies 5616000 11 203 Aref 575662 1070000 12 203 Aref 575869 1070000 13 2,561 Aref 583608 1070000 14 2,529 Aref 583614 1070000 15 4,856 Aref 604216 1070000 16 3,171 Aref 604662 1070000 17 2,477 Aref 617716 1070000 18 8,402 Aref 618940 1070000 19 3,575 Aref 620282 1070000 20 Generation Studies 21 319 GIQ0093 5617000 319 4562000 22 136 GIQ0128 5617000 136 4562000 23 90 GIQ0169 5617000 90 4562000 24 90 GIQ0170 5617000 90 4562000 25 1,234 GIQ0187 5617000 1,234 4562000 26 16,126 GIQ0187, 188, 189 5617000 16,126 4562000 27 582 GIQ0188 5617000 582 4562000 28 76 GIQ0189 5617000 76 4562000 29 821 GIQ0193 5617000 821 4562000 30 303 GIQ0234 5617000 303 4562000 31 372 GIQ0243 5617000 372 4562000 32 1,571 GIQ0247 5617000 1,571 4562000 33 60 GIQ0248 5617000 60 4562000 34 2,924 GIQ0254 5617000 2,924 4562000 35 13,191 GIQ0255 5617000 13,191 4562000 36 467 GIQ0258 5617000 467 4562000 37 40,691 GIQ0260, 261, 262, 263 5617000 40,691 4562000 38 8,443 GIQ0268 5617000 8,443 4562000 39 10,739 GIQ0269 5617000 10,739 4562000 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231Name 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 (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 3,916 Aref 621679 1070000 2 9,244 Aref 624709 1070000 3 4,514 Aref 626275 1070000 4 2,293 Aref 630525 1070000 5 5,789 Aref 635532 1070000 6 1,651 Aref 637972 1070000 7 5,462 Aref 637974 1070000 8 4,233 Aref 637977 1070000 9 4,696 Aref 637979 1070000 10 28,760 Aref 648008 1070000 11 5,004 Aref 648013 1070000 12 13 14 15 16 17 18 19 20 Generation Studies 21 120 GIQ0274 5617000 120 4562000 22 36,841 GIQ0276 5617000 36,841 4562000 23 13,116 GIQ0277 5617000 13,116 4562000 24 1,052 GIQ0278 5617000 1,052 4562000 25 1,872 GIQ0279 5617000 1,872 4562000 26 1,069 GIQ0283 5617000 1,069 4562000 27 10,565 GIQ0287 5617000 10,565 4562000 28 435 GIQ0288 5617000 435 4562000 29 41,082 GIQ0289 5617000 41,082 4562000 30 40,083 GIQ0290 5617000 40,083 4562000 31 24,928 GIQ0291 5617000 24,928 4562000 32 16,089 GIQ0292 5617000 16,089 4562000 33 13,299 GIQ0293 5617000 13,299 4562000 34 18,348 GIQ0294 5617000 18,348 4562000 35 30,806 GIQ0295 5617000 30,806 4562000 36 3,163 GIQ0296 5617000 3,163 4562000 37 2,679 GIQ0297 5617000 2,679 4562000 38 6,959 GIQ0298 5617000 6,959 4562000 39 5,554 GIQ0299 5617000 5,554 4562000 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.1Name 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 (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 7,402 GIQ0300 5617000 7,402 4562000 22 4,699 GIQ0302 5617000 4,699 4562000 23 7,140 GIQ0303 5617000 7,140 4562000 24 6,078 GIQ0304 5617000 6,078 4562000 25 7,719 GIQ0305 5617000 7,719 4562000 26 30,724 GIQ0306 5617000 30,724 4562000 27 21,285 GIQ0307 5617000 21,285 4562000 28 634 GIQ0308 5617000 634 4562000 29 5,360 GIQ0309 5617000 5,360 4562000 30 13,263 GIQ0310 5617000 13,263 4562000 31 17,533 GIQ0311 5617000 17,533 4562000 32 2,816 GIQ0312 5617000 2,816 4562000 33 43,204 GIQ0313 5617000 43,204 4562000 34 11,734 GIQ0314 5617000 11,734 4562000 35 22,995 GIQ0315 5617000 22,995 4562000 36 23,177 GIQ0316 5617000 23,177 4562000 37 1,475 GIQ0317 5617000 1,475 4562000 38 2,041 GIQ0318 5617000 2,041 4562000 39 20,394 GIQ0319 5617000 20,394 4562000 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.2Name 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 (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 1,841 GIQ0320 5617000 1,841 4562000 22 4,206 GIQ0321 5617000 4,206 4562000 23 15,850 GIQ0322 5617000 15,850 4562000 24 53,682 GIQ0323 5617000 53,682 4562000 25 41,214 GIQ0324 5617000 41,214 4562000 26 1,977 GIQ0325 5617000 1,977 4562000 27 34,067 GIQ0326 5617000 34,067 4562000 28 3,078 GIQ0327 5617000 3,078 4562000 29 1,569 GIQ0328 5617000 1,569 4562000 30 2,910 GIQ0329 5617000 2,910 4562000 31 5,612 GIQ0330 5617000 5,612 4562000 32 1,143 GIQ0331 5617000 1,143 4562000 33 9,958 GIQ0332 5617000 9,958 4562000 34 6,844 GIQ0333 5617000 6,844 4562000 35 2,652 GIQ0334 5617000 2,652 4562000 36 8,666 GIQ0335 5617000 8,666 4562000 37 5,829 GIQ0337 5617000 5,829 4562000 38 622 GIQ0338 5617000 622 4562000 39 3,552 GIQ0339 5617000 3,552 4562000 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.3Name 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 (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 613 GIQ0340 5617000 613 4562000 22 18,959 GIQ0341 5617000 18,959 4562000 23 5,547 GIQ0342 5617000 5,547 4562000 24 9,380 GIQ0343 5617000 9,380 4562000 25 1,858 GIQ0344 5617000 1,858 4562000 26 2,506 GIQ0345 5617000 2,506 4562000 27 6,682 GIQ0346 5617000 6,682 4562000 28 4,852 GIQ0347 5617000 4,852 4562000 29 2,709 GIQ0348 5617000 2,709 4562000 30 10,870 GIQ0349 5617000 10,870 4562000 31 10,857 GIQ0350 5617000 10,857 4562000 32 12,468 GIQ0351 5617000 12,468 4562000 33 2,266 GIQ0352 5617000 2,266 4562000 34 182 GIQ0353 5617000 182 4562000 35 2,468 GIQ0354 5617000 2,468 4562000 36 846 GIQ0355 5617000 846 4562000 37 1,126 GIQ0356 5617000 1,126 4562000 38 1,100 GIQ0357 5617000 1,100 4562000 39 657 GIQ0358 5617000 657 4562000 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.4Name 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 (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) the Period

(continued)

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 2,104 GIQ0359 5617000 2,104 4562000 22 2,831 GIQ0360 5617000 2,831 4562000 23 549 GIQ0361 5617000 549 4562000 24 489 GIQ0362 5617000 489 4562000 25 65 GIQ0363 5617000 65 4562000 26 124 GIQ0364 5617000 124 4562000 27 46 GIQ0365 5617000 46 4562000 28 ( 15,847) Accruals - Customer Studies 5617000 29 9,875 GIQ0284 5617000 30 12,985 GIQ0270 5617000 31 8,497 GIQ0271 5617000 32 18,577 GIQ0267 1070000 33 41,071 GIQ0301 1070000 34 35 36 37 38 39 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231.5Name 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 (d) (c) (a) 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) ( 2,099,141) -3,193,591 1,959,697 908 865,247 DSM Regulatory Asset - CA 1 4,072,036 5,339,142 6,280,307 908 7,547,413 DSM Regulatory Asset - ID 2 28,520,678 2,284,513 74,035,776 908 47,799,611 DSM Regulatory Asset - UT 3 1,727,139 595,391 8,855,255 908, 431 7,723,507 DSM Regulatory Asset -WA 4 ( 2,468,965) -4,000,836 4,341,024 908, 431 2,809,153 DSM Regulatory Asset - WY 5 4,977,717 5,386,136 408,419 DSM Regulatory Assets- Accruals 6 1,396,569 253,983 1,214,280 142 71,694 Alternative Rate For Energy (CARE) - CA 7 2,269,573 2,289,365 930.2 19,792 Transition Plan - OR 8 2,969,259 1,714,502 920 4,683,761 2006 Transition Plan - OR (3) 9 318,524 318,524 920 2006 Transition Plan - WA (3) 10 610,195 610,195 920 2006 Transition Plan - ID (3) 11 222,772 222,772 2006 Transition Plan - CA 12 1,062,222 1,062,222 920 2006 Transition Plan - WY (3) 13 422,169,290 448,480,778 26,311,488 Deferred Income Taxes Electric 14 1,444,909 1,444,909 Deferral of Interest on Uncertain Tax Positions-UT 15 372,132 372,132 Deferral of Interest on Uncertain Tax Positions-WY 16 99,955 99,955 Tax Revenue Requirement Adjustment - WY 17 ( 68,360) 42,313 407.3, 431 110,673 Sch 781 Direct Access Shopping Incentive 18 112,218 112,218 930.2 Glenrock Mine Excluding Reclamation - UT (9) 19 175,363 176,578 254 1,215 Deferred Excess Net Power Costs - OR UE116 20 3,526,084 3,526,084 Deferred Excess Net Power Costs - OR 21 ( 2,604,371) 1,909,644 4,514,015 Deferred Excess Net Power Costs/ECAC - CA 22 9,970,836 10,030,176 555 59,340 Deferred Excess Net Power Costs - WY 2008 23 1,539,406 1,596,942 3,073,730 555 3,131,266 Deferred Excess Net Power Costs - WY 2009 24 14,492,513 14,492,513 Deferred Excess Net Power Costs - WY 2010 25 4,364,406 2,670,016 1,977,054 555 282,664 Deferred Excess Net Power Costs - WA Hydro (3) 26 2,615,813 487,229 2,361,551 555 232,967 Deferred Excess Net Power Costs - ID 2009 27 11,434,111 11,434,111 Deferred Excess Net Power Costs - ID 2010 28 1,035,589 1,035,589 Deferred Excess Net Power Costs - ID 2011 29 7,516,382 8,296,641 1,501,251 925 2,281,510 Environmental Costs (10) 30 ( 591,843) -650,117 163,356 925 105,082 Environmental Costs - WA (10) 31 3,441,141 9,370,862 5,929,721 Reg Asset - Environmental Costs 32 7,117,962 6,179,329 1,122,425 557 183,792 Cholla Plant Transaction Costs (26) 33 578,447 526,259 52,188 456 Washington Colstrip #3 (22) 34 367,301,591 487,295,264 119,993,673 Derivative Net Regulatory Asset 35 64,991,572 68,251,011 13,813,374 230 17,072,813 Asset Retirement Obligations Regulatory Difference 36 575,745,416 596,639,721 50,014,094 70,908,399 Pension/Other Postretirement 37 1,034,108 738,048 321,528 904 25,468 RTO Grid West N/R - OR (3) 38 92,022 92,022 904 RTO Grid West N/R - WY (3) 39 54,324 27,162 27,162 904 RTO Grid West N/R - ID (5) 40 ( 12,573) -16,501 3,928 557 Deferred Independent Evaluator Fee - UT 41 1,042,120 539,513 912,358 557 409,751 Deferred Independent Evaluator Fee - OR (1) 42 61,378 43,797 17,581 928 Deferred Intervenor Funding Grants - ID 43

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232

44 TOTAL 1,550,913,652 212,116,361 1,737,446,767 398,649,476Name 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 (d) (c) (a) 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) ( 175,032) 37,082 1,392 431 213,506 Deferred Intervenor Funding Grants - OR 1 2,081,580 2,685,242 603,662 BPA Idaho Balancing Account 2 5,196,941 629,955 6,485,375 1,918,389 Renewable Adjustment Clause (1) - OR 3 510,000 488,750 21,250 930.2 Goodnoe Hills Settlement - WY (24) 4 1,032,722 1,005,095 27,627 930.2 Lake Side Settlement - WY (38) 5 9,770,616 1,095,545 10,835,128 2,160,057 SB 408 Regulatory Asset - OR (1) 6 ( 22,043) -189,015 582,540 415,568 SB 408 Regulatory Asset - MCBIT 7 18,000,000 15,000,000 3,000,000 Chehalis Generating Facility Deferral - WA (6) 8 304,766 9,000 407.3 313,766 Powerdale Decommissioning - ID (10) 9 493,016 424,921 407.3 917,937 Powerdale Decommissioning - OR (1.5) 10 851,788 851,788 Powerdale Decommissioning - WA 11 34,392 153,725 407.3 188,117 Powerdale Decommissioning - WY (1) 12 52,198 52,198 Deferred Advertising Costs - WY 13 15,724,521 15,724,521 Major Plant Additions - UT 14 226,622 226,622 Solar Feed-In Tariff Deferral - OR 15 383,431 383,431 Tax Adj on Postretirement Benefits - CA 16 819,988 819,988 Tax Adj on Postretirement Benefits - ID 17 4,471,643 4,471,643 Tax Adj on Postretirement Benefits - OR 18 5,891,250 392,750 410.1, 283 6,284,000 Tax Adj on Postretirement Benefits - UT 19 1,126,592 1,126,592 Tax Adj on Postretirement Benefits - WA 20 2,121,315 2,121,315 Tax Adj on Postretirement Benefits - WY 21 1,230,000 1,230,000 Storm Damage Deferral - CA 22 249,097 435,826 501 684,923 Deferred Overburden Cost - ID 23 665,891 1,165,063 501 1,830,954 Deferred Overburden Cost - WY 24 7,485,673 7,399,943 85,730 254 Regulatory Assets - Reclassifications 25 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 1,550,913,652 212,116,361 1,737,446,767 398,649,476

### 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)XAn 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)XAn 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 450.2Name 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 (c) (b) (a) 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.

1,110,495 973,114 137,381 557 Joseph Settlement (20) 1 2 552,450 506,730 45,720 557 Lacomb Irrigation (24) 3 4 1,241,840 1,200,560 41,280 557 Bogus Creek (42) 5 6 Mead Phoenix Availability 7 14,134,520 13,756,760 377,760 565 & Trans Charge (50) 8 9 156,025 140,551 15,474 557 TGS Buyout (23) 10 11 4,564,178 4,392,484 171,694 557 Hermiston Swap (40) 12 13 994,128 1,105,396 2,100,584 2,211,852 151 Deferred Longwall Costs 14 15 2,573,900 4,476,900 593,680 2,496,680 142, 557 Point to Point Transmission 16 17 Deferred Coal Costs - Wyodak 18 4,357,363 4,022,182 335,181 151 Settlement (22) 19 20 Deferred Coal Costs - Arch 21 1,713,105 63,030 1,650,075 151 Settlement (3) 22 23 Deferred Coal Costs - Naughton 24 8,256,923 688,077 8,945,000 151 Settlement (7) 25 26 1,085,161 1,500,000 1,161 416,000 232 Deferred Colstrip Plant Costs 27 28 338,345 255,485 82,860 557 Jim Boyd Hydro Buyout (11) 29 30 1,507,772 1,051,143 456,629 427, 431 Credit Agreement Costs (5) 31 32 473,238 413,129 212,602 152,493 427 PCRB LOC/SBBPA Costs (5) 33 34 261,965 413,486 118,961 270,482 427 PCRB Mode Conversion Costs (10) 35 36 1,105,412 988,431 116,981 427 '94 Series Restruct. Costs (16) 37 38 2,956,980 2,956,980 Emission Reduction Credits 39 40 3,228,303 3,086,717 1,360,230 1,218,644 LGIA LT Transmission Prepaid 41 42 1,270,348 1,115,229 155,119 454 Lease Incentives (11) 43 44 LT Lease Commissions 45 739,981 649,659 90,322 931 Prepaids (10) 46

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 86,483,361Name 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 (c) (b) (a) 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.

9,593,309 9,133,961 791,362 332,014 232 BPA LT Transmission Prepaid 1 2 9,477,588 14,720,749 5,243,161 Lake Side Maint. Prepayment 3 4 2,587,071 5,777,606 3,190,535 Chehalis Maint. Prepayment 5 6 1,167,388 5,465,610 1,346,843 5,645,065 107 Currant Creek Maint. Prepayment 7 8 Other Deferred Debits with 9 111,674 60,546 51,128 various balances less than $100,000 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. 12-94) 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)XAn 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 450.1Name 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 (c) (b) (a) 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.

Electric 1 187,114,591 243,734,412 Employee Benefits 2 184,509,824 139,689,181 Derivative Contracts 3 25,903,274 40,091,582 Regulatory Liabilities 4 5 6 191,062,227 164,002,583 Other 7 588,589,916 587,517,758 TOTAL Electric (Enter Total of lines 2 thru 7) 8 Gas 9 10 11 12 13 14 Other 15 TOTAL Gas (Enter Total of lines 10 thru 15 16 Other (Specify) 17 588,589,916 587,517,758 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18 Notes

FERC FORM NO. 1 (ED. 12-88) Page234Name 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

(c) (b) (a) 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.

750,000,000 Common Stock (Account 201) 1 MidAmerican Energy Holdings Company 2indirectly owns all of the shares of 3PacifiCorp's outstanding common stock. 4Therefore, there is no public market for 5PacifiCorp's common stock. 6 7 750,000,000 TOTAL COMMON STOCK 8 9 10 Preferred Stock (Account 204): 11 110.00 100.00 126,533 5% Cumulative Preferred 12 13 14 3,500,000 Serial Preferred, Cumulative: 15 103.50 100.00 4.52% Series 16 100.00 7.00% Series 17 100.00 6.00% Series 18 100.00 100.00 5.00% Series 19 101.00 100.00 5.40% Series 20 103.50 100.00 4.72% Series 21 102.34 100.00 4.56% Series 22 16,000,000 No Par Serial Preferred 23 24 19,626,533 TOTAL PREFERRED STOCK 25 26 27 28 29 30 31 32 33Authorized and unissued Capital Stock 34 35 36 37 38 39 40 41 42

FERC FORM NO. 1 (ED. 12-91) Page 250AS 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 Shares Amount (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.

3,417,945,896 357,060,915 1 2 3 4 5 6 7 3,417,945,896 357,060,915 8 9 10 11 12,624,300 126,243 12 13 14 15 206,500 2,065 16 1,804,600 18,046 17 593,000 5,930 18 4,190,800 41,908 19 6,595,900 65,959 20 6,585,400 65,854 21 8,132,600 81,326 22 23 24 40,733,100 407,331 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)XAn 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 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line Item Amount (b) (a) OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)

No. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide 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.

Account 211 Miscellaneous Paid-in Capital 1 Additional Paid-in Capital 2 1,973,218 Share based payments 3 14,422,979 Tax benefit from stock option exercises 4 -3,575,760 Benefit plan separation 5 1,089,950,000 Capital contributions 6 136,208 Gain on sale of ScottishPower stock 7 -1,275,241 Qualified production activity tax deduction 8 432,552 Contribution of Intermountain Geothermal 9 166,025 Gain on repurchase of preferred stock 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

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)XAn 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 450.1Name 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 (b) (a) 

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

41,101,062 Common Stock 1 2 Preferred Stock: 3 98,049 5.00% 4 9,676 4.52% Serial 5 28,596 4.72% Serial 6 47,177 4.56% Serial 7 8 9 10 Refer to page 108, Important Changes During the Quarter/Year, Item 6. Financing Activities 11 and to page 123, Notes to Financial Statements, Note 14. Preferred Stock in this Form No. 1 12 for a discussion of PacifiCorp's repurchase of certain shares of its preferred stock. 13 14 15 16 17 18 19 20 21

FERC FORM NO. 1 (ED. 12-87) Page 254b

22 TOTAL 41,284,560Name 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
(c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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.

Bonds: (Account 221) 1 First Mortgage Bonds: 2 3 48,972,000 8.271% Series due October 1, 2010 4 4,422,000 7.978% Series due October 1, 2011 5 3,567,009 500,000,000 6.900% Series due November 15, 2011 6 1,735,000 7 D 19,772,000 8.493% Series due October 1, 2012 8 16,203,000 8.797% Series due October 1, 2013 9 1,422,659 200,000,000 5.450% Series due September 15, 2013 10 232,000 11 D 1,442,365 200,000,000 4.950% Series due August 15, 2014 12 728,000 13 D 28,218,000 8.734% Series due October 1, 2014 14 46,946,000 8.294% Series due October 1, 2015 15 18,750,000 8.635% Series due October 1, 2016 16 19,609,000 8.470% Series due October 1, 2017 17 3,067,221 500,000,000 5.650% Series due July 15, 2018 18 905,000 19 D 2,515,793 350,000,000 5.500% Series due January 15, 2019 20 2,292,500 21 D 2,874,150 300,000,000 7.700% Series due November 15, 2031 22 864,000 23 D 1,892,365 200,000,000 5.900% Series due August 15, 2034 24 722,000 25 D 2,912,055 300,000,000 5.25% Series due June 15, 2035 26 1,080,000 27 D 2,908,542 350,000,000 6.10% Series due August 1, 2036 28 1,141,000 29 D 589,216 600,000,000 5.75% Series due April 1, 2037 30 24,000 31 D 32

FERC FORM NO. 1 (ED. 12-96) Page 256

33 TOTAL 6,507,262,000 74,175,437Name 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
(c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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.

5,127,281 600,000,000 6.25% Series due October 15, 2037 1 750,000 2 D 2,290,333 300,000,000 6.35% Series due July 15, 2038 3 1,671,000 4 D 6,134,687 650,000,000 6.00% Series due January 15, 2039 5 6,175,000 6 D 75,327 8,000,000 9.15% Series C Medium-Term Notes due Aug. 9, 2011 7 175,398 25,000,000 8.95% Series C Medium-Term Notes due Sept. 1, 2011 8 132,118 20,000,000 8.95% Series C Medium-Term Notes due Sept. 1, 2011 9 188,318 20,000,000 8.92% Series C Medium-Term Notes due Sept. 1, 2011 10 23,040 3,000,000 8.29% Series C Medium-Term Notes due Dec. 30, 2011 11 7,649 1,000,000 8.26% Series C Medium-Term Notes due Jan. 10, 2012 12 13,297 2,000,000 8.28% Series C Medium-Term Notes due Jan. 10, 2012 13 22,946 3,000,000 8.25% Series C Medium-Term Notes due Feb. 1, 2012 14 75,827 10,000,000 8.13% Series E Medium-Term Notes due Jan. 22, 2013 15 115,202 15,000,000 8.53% Series C Medium-Term Notes due Dec. 16, 2021 16 38,400 5,000,000 8.375% Series C Medium-Term Notes due Dec. 31, 2021 17 33,243 5,000,000 8.26% Series C Medium-Term Notes due Jan. 7, 2022 18 30,594 4,000,000 8.27% Series C Medium-Term Notes due Jan. 10, 2022 19 131,471 15,000,000 8.05% Series E Medium-Term Notes due Sept. 1, 2022 20 70,118 8,000,000 8.07% Series E Medium-Term Notes due Sept. 9, 2022 21 438,238 50,000,000 8.12% Series E Medium-Term Notes due Sept. 9, 2022 22 105,177 12,000,000 8.11% Series E Medium-Term Notes due Sept. 9, 2022 23 87,648 10,000,000 8.05% Series E Medium-Term Notes due Sept. 14, 2022 24 208,198 26,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 25 200,190 25,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 26 37,914 5,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 27 30,331 4,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 28 -81,560 29 P 246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 30 100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 31 137,211 15,000,000 7.23% Series F Medium-Term Notes due Aug. 16, 2023 32

FERC FORM NO. 1 (ED. 12-96) Page 256.1

33 TOTAL 6,507,262,000 74,175,437Name 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
(c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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.

274,423 30,000,000 7.24% Series F Medium-Term Notes due Aug. 16, 2023 1 38,250 5,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 2 15,300 2,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 3 15,300 2,000,000 6.72% Series F Medium-Term Notes due Sept. 14, 2023 4 152,326 20,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 5 121,861 16,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 6 91,396 12,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 7 904,467 100,000,000 6.71% Series G Medium-Term Notes due Jan. 15, 2026 8 59,320,397 5,768,892,000 Subtotal - First Mortgage Bonds 9 10Pollution Control Obligations - Secured by Pledged First Mortgage Bonds: 11 12 874,159 40,655,000 Poll Ctrl Rev Refunding Bonds, Moffat County, CO, Series 1994 13 228,980 8,300,000 5-5/8% Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1993 14 197,125 15 D 1,624,793 46,500,000 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993A 16 625,551 16,400,000 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993B 17 389,500 18 D 510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 19 209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 20 3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 21 206,519 9,365,000 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 22 422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 23 155,970 17,000,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 24 122,887 15,000,000 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 25 105,000 26 D 771,836 45,000,000 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 27 304,824 8,500,000 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 28 132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 29 404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 30 10,560,809 400,470,000 Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 31 32

FERC FORM NO. 1 (ED. 12-96) Page 256.2

33 TOTAL 6,507,262,000 74,175,437Name 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
(c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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 Pollution Control Obligations - Unsecured 2 3 167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 4 151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 5 242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 6 84,822 11,500,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 7 660,750 70,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 8 872,505 45,000,000 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 9 422,443 50,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 10 380,198 45,000,000 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 11 351,905 41,200,000 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 12 225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 13 556,549 12,675,000 6.150% Environ. Imprvmnt Rev Bonds, Emery County, UT, Series 1996 14 178,464 15 D 16 4,294,231 337,900,000 Subtotal - Pollution Control Obligations - Unsecured 17 18 19 20 74,175,437 6,507,262,000 TOTAL ACCOUNT 221 21 22 23Reacquired Bonds: (Account 222) 24 25 26Advances from Associated Companies: (Account 223) 27 28 29 30Other Long-Term Debt: (Account 224) 31 32

FERC FORM NO. 1 (ED. 12-96) Page 256.3

33 TOTAL 6,507,262,000 74,175,437Name 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
(c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. 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.

TOTAL ACCOUNT 224 1 2 3Long-Term Debt Authorized but Unissued 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 256.4

33 TOTAL 6,507,262,000 74,175,437Name 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 3 294,903 10/01/2010 04/15/1992 10/01/2010 04/15/1992 4 412,000 55,667 10/01/2011 04/15/1992 10/01/2011 04/15/1992 5 500,000,000 34,500,000 11/15/2011 11/15/2001 11/15/2011 11/15/2001 6 7 3,590,000 406,050 10/01/2012 04/15/1992 10/01/2012 04/15/1992 8 4,247,000 452,320 10/01/2013 04/15/1992 10/01/2013 04/15/1992 9 200,000,000 10,900,000 09/15/2013 11/15/2001 09/15/2013 09/15/2003 10 11 200,000,000 9,900,000 08/15/2014 08/24/2004 08/15/2014 08/24/2004 12 13 9,301,000 935,367 10/01/2014 04/15/1992 10/01/2014 04/15/1992 14 17,918,000 1,660,480 10/01/2015 04/15/1992 10/01/2015 04/15/1992 15 8,318,000 784,835 10/01/2016 04/15/1992 10/01/2016 04/15/1992 16 9,585,000 873,913 10/01/2017 04/15/1992 10/01/2017 04/15/1992 17 500,000,000 28,250,000 07/15/2018 07/17/2008 07/15/2018 07/17/2008 18 19 350,000,000 19,250,000 01/15/2019 01/08/2009 01/15/2019 01/08/2009 20 21 300,000,000 23,100,000 11/15/2031 11/15/2001 11/15/2031 11/15/2001 22 23 200,000,000 11,800,000 08/15/2034 08/24/2004 08/15/2034 08/24/2004 24 25 300,000,000 15,750,000 06/15/2035 06/13/2005 06/15/2035 06/13/2005 26 27 350,000,000 21,350,000 08/01/2036 08/10/2006 08/01/2036 08/10/2006 28 29 600,000,000 34,500,000 04/01/2037 03/14/2007 04/01/2037 03/14/2007 30 31 32

FERC FORM NO. 1 (ED. 12-96) Page 257 33 6,357,741,000 363,203,396Name 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.

600,000,000 37,500,000 10/15/2037 10/03/2007 10/15/2037 10/03/2007 1 2 300,000,000 19,050,000 07/15/2038 07/17/2008 07/15/2038 07/17/2008 3 4 650,000,000 39,000,000 01/15/2039 01/08/2009 01/15/2039 01/08/2009 5 6 8,000,000 732,000 08/09/2011 08/09/1991 08/09/2011 08/09/1991 7 25,000,000 2,237,500 09/01/2011 08/16/1991 09/01/2011 08/16/1991 8 20,000,000 1,790,000 09/01/2011 08/16/1991 09/01/2011 08/16/1991 9 20,000,000 1,784,000 09/01/2011 08/16/1991 09/01/2011 08/16/1991 10 3,000,000 248,700 12/30/2011 12/31/1991 12/30/2011 12/31/1991 11 1,000,000 82,600 01/10/2012 01/09/1992 01/10/2012 01/09/1992 12 2,000,000 165,600 01/10/2012 01/10/1992 01/10/2012 01/10/1992 13 3,000,000 247,500 02/01/2012 01/15/1992 02/01/2012 01/15/1992 14 10,000,000 813,000 01/22/2013 01/20/1993 01/22/2013 01/20/1993 15 15,000,000 1,279,500 12/16/2021 12/16/1991 12/16/2021 12/16/1991 16 5,000,000 418,750 12/31/2021 12/31/1991 12/31/2021 12/31/1991 17 5,000,000 413,000 01/07/2022 01/08/1992 01/07/2022 01/08/1992 18 4,000,000 330,800 01/10/2022 01/09/1992 01/10/2022 01/09/1992 19 15,000,000 1,207,500 09/01/2022 09/18/1992 09/01/2022 09/18/1992 20 8,000,000 645,600 09/09/2022 09/09/1992 09/09/2022 09/09/1992 21 50,000,000 4,060,000 09/09/2022 09/11/1992 09/09/2022 09/11/1992 22 12,000,000 973,200 09/09/2022 09/11/1992 09/09/2022 09/11/1992 23 10,000,000 805,000 09/14/2022 09/14/1992 09/14/2022 09/14/1992 24 26,000,000 2,100,800 10/14/2022 10/15/1992 10/14/2022 10/15/1992 25 25,000,000 2,020,000 10/14/2022 10/15/1992 10/14/2022 10/15/1992 26 5,000,000 411,500 01/20/2023 01/20/1993 01/20/2023 01/20/1993 27 4,000,000 329,200 01/20/2023 01/29/1993 01/20/2023 01/29/1993 28 29 27,000,000 1,960,200 07/21/2023 07/22/1993 07/21/2023 07/22/1993 30 11,000,000 798,600 07/21/2023 07/22/1993 07/21/2023 07/22/1993 31 15,000,000 1,084,500 08/16/2023 08/16/1993 08/16/2023 08/16/1993 32

FERC FORM NO. 1 (ED. 12-96) Page 257.1 33 6,357,741,000 363,203,396Name 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.

30,000,000 2,172,000 08/16/2023 08/16/1993 08/16/2023 08/16/1993 1 5,000,000 337,500 09/14/2023 09/14/1993 09/14/2023 09/14/1993 2 2,000,000 135,000 09/14/2023 09/14/1993 09/14/2023 09/14/1993 3 2,000,000 134,400 09/14/2023 09/14/1993 09/14/2023 09/14/1993 4 20,000,000 1,350,000 10/26/2023 10/26/1993 10/26/2023 10/26/1993 5 16,000,000 1,080,000 10/26/2023 10/26/1993 10/26/2023 10/26/1993 6 12,000,000 810,000 10/26/2023 10/26/1993 10/26/2023 10/26/1993 7 100,000,000 6,710,000 01/15/2026 01/23/1996 01/15/2026 01/23/1996 8 5,619,371,000 349,981,485 9 10 11 12 40,655,000 353,792 05/01/2013 11/17/1994 05/01/2013 11/17/1994 13 8,300,000 476,835 11/01/2021 11/15/1993 11/01/2021 11/15/1993 14 15 46,500,000 2,683,050 11/01/2023 11/15/1993 11/01/2023 11/15/1993 16 16,400,000 942,180 11/01/2023 11/15/1993 11/01/2023 11/15/1993 17 18 21,260,000 168,760 11/01/2024 11/17/1994 11/01/2024 11/17/1994 19 8,190,000 73,010 11/01/2024 11/17/1994 11/01/2024 11/17/1994 20 121,940,000 1,005,483 11/01/2024 11/17/1994 11/01/2024 11/17/1994 21 9,365,000 74,924 11/01/2024 11/17/1994 11/01/2024 11/17/1994 22 15,060,000 137,933 11/01/2024 11/17/1994 11/01/2024 11/17/1994 23 17,000,000 680,352 01/01/2014 01/01/1988 01/01/2014 01/01/1988 24 15,000,000 600,357 12/01/2014 12/01/1984 12/01/2014 12/01/1984 25 26 45,000,000 953,494 01/01/2016 01/17/1991 01/01/2016 01/17/1991 27 8,500,000 359,450 12/01/2016 12/01/1986 12/01/2016 12/01/1986 28 5,300,000 224,251 11/01/2025 11/17/1995 11/01/2025 11/17/1995 29 22,000,000 953,747 11/01/2025 11/17/1995 11/01/2025 11/17/1995 30 400,470,000 9,687,618 31 32

FERC FORM NO. 1 (ED. 12-96) Page 257.2 33 6,357,741,000 363,203,396Name 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 9,335,000 109,784 12/01/2020 09/29/1992 12/01/2020 09/29/1992 4 6,305,000 74,393 12/01/2020 09/29/1992 12/01/2020 09/29/1992 5 22,485,000 263,488 12/01/2020 09/29/1992 12/01/2020 09/29/1992 6 11,500,000 89,883 01/01/2014 01/01/1988 01/01/2014 01/01/1988 7 70,000,000 535,882 07/01/2015 07/25/1990 07/01/2015 07/25/1990 8 45,000,000 365,100 07/01/2015 05/23/1991 07/01/2015 05/23/1991 9 50,000,000 437,603 01/01/2017 01/01/1988 01/01/2017 01/01/1988 10 45,000,000 356,956 01/01/2018 01/01/1988 01/01/2018 01/01/1988 11 41,200,000 323,737 01/01/2018 01/01/1988 01/01/2018 01/01/1988 12 24,400,000 197,954 11/01/2025 12/14/1995 11/01/2025 12/14/1995 13 12,675,000 779,513 09/01/2030 09/24/1996 09/01/2030 09/24/1996 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 33 6,357,741,000 363,203,396Name 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 33 6,357,741,000 363,203,396

### 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)XAn 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 450.1Name 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) (b) (a) Amount Line 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.

566,414,836 Net Income for the Year (Page 117) 1 2 3Taxable Income Not Reported on Books 4 5 6 7 186,118,747 Other 8Deductions Recorded on Books Not Deducted for Return 9 10 11 12 1,106,402,210 Other 13Income Recorded on Books Not Included in Return 14 15 16 17 154,071,658 Other 18Deductions on Return Not Charged Against Book Income 19 20 21 22 23 24 3,018,805,017 Other 25 6,881,135 State Tax Deductions 26 -1,307,059,747 Federal Tax Net Income 27Show Computation of Tax: 28 29 -457,470,911 Federal Income Tax at 35.00% 30 25,508,786 Provision to Return Adjustment 31 -1,467,224 Tax Reserve Changes 32 -55,464,174 Renewable Electricity Production Tax Credits 33 -72,211 Mining Rescue Training Credits 34 -71,195 Research & Experimentation Credits 35 -29,612 Foreign Tax Credit 36 -16,667 Fuel Tax Credit 37 38 39 40 -489,083,208 Federal Income Tax Accrual 41 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 Subsidiaries2,097,757 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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 450.12Name 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.

Federal: 1 -378,627,466 -489,083,208 243,804,243 15,057,106 Income 2 40,582,820 -208,383 40,451,265 654,362 FICA 3 391,381 -353 383,109 52,902 Unemployment 4 3,126,302 3,121,283 167,805 Excise Tax - Coal 5 -334,526,963 -208,736 -445,127,551 243,804,243 15,932,175 Subtotal 6 7State: 8 9Arizona: 10 2,142,135 2,363,138 960,566 Property 11 26,354 44,924 Income 12 2,142,135 2,389,492 44,924 960,566 Subtotal 13 14California: 15 2,259,708 2,259,708 Property 16 30,753 31,522 Unemployment 17 -105,096 148,513 364,355 Franchise-Income 18 181,784 179,485 5,581 Use 19 1,112,815 1,150,173 936,366 Local Franchise 20 3,479,964 3,769,401 364,355 941,947 Subtotal 21 22Colorado: 23 1,820,136 1,719,136 1,901,000 Property 24 -43,930 70 44,000 Income 25 1,776,206 1,719,206 44,000 1,901,000 Subtotal 26 27Idaho: 28 4,155,558 4,738,233 2,056,753 Property 29 -1,228,209 438,250 343,439 Income 30 28,158 26,822 15,012 KWh 31 94,680 95,862 733 Unemployment 32 146,895 160,036 837 Use 33 3,197,082 5,459,203 343,439 2,073,335 Subtotal 34 35Montana: 36 3,042,627 3,275,197 1,399,991 Property 37 67,710 50 -153,660 Corporate License-Income 38 1,030 1,030 Unemployment 39 238,722 269,226 33,362 Energy License 40

258,675,803

FERC FORM NO. 1 (ED. 12-96) Page 262 TOTAL 41 -286,256,396 -191,003,416 -209,999 46,747,021Name 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.

170,097 191,815 23,788 Wholesale Energy 1 3,520,186 3,737,318 -153,660 1,457,141 Subtotal 2 3New Mexico: 4 8,398 8,398 Property 5 50 50 Income 6 8,448 8,448 Subtotal 7 8Oregon: 9 21,470,885 20,348,226 9,620,711 Property 10 1,829,441 1,841,356 38,519 Unemployment 11 827 799 288 Wilsonville Payroll 12 -2,006,049 -1,761,300 922,587 Excise-Income 13 -3,149 -1,679 1,000 City of Portland-Income 14 1,445,179 722,590 357,444 Department of Energy 15 870,961 863,452 351,459 Tri-Met 16 1,872 1,872 Lane County 17 22,246,753 22,210,008 4,195,671 Franchise 18 45,856,720 44,225,324 10,544,298 4,943,381 Subtotal 19 20Utah: 21 52,281,027 52,353,573 398,350 Property 22 -11,503,320 -300,165 3,684,204 Income 23 252,986 203,542 52,150 Unemployment 24 804 804 Navajo Nation 25 648 648 Salt Lake Valley Law Enforc 26 4,731,443 4,958,116 314,915 Use 27 45,763,588 57,216,518 3,684,204 765,415 Subtotal 28 29Washington: 30 7,252,928 9,165,928 6,787,000 Property 31 125,303 128,956 2,611 Unemployment 32 34,870 33,252 4,998 Business & Occupation 33 10,447,279 9,832,285 1,675,000 Public Utility 34 2,324,198 1,990,456 449,559 Natural Gas Use Tax 35 385,391 394,687 38,923 Use 36 91,260 91,260 Franchise 37 63 63 Land Tax 38 20,661,292 21,636,887 8,958,091 Subtotal 39 40

258,675,803

FERC FORM NO. 1 (ED. 12-96) Page 262.1 TOTAL 41 -286,256,396 -191,003,416 -209,999 46,747,021Name 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.

Wyoming: 1 13,099,632 13,744,851 6,544,398 Property 2 544,675 -1,263 551,149 2,001 Unemployment 3 1,560,054 1,567,954 239,100 Franchise 4 1,462,238 1,490,853 111,294 Use 5 93,853 93,853 Annual Report 6 16,760,452 -1,263 17,448,660 6,896,793 Subtotal 7 8 903,287 1,899,175 State Other 9 10Miscellaneous: 11 15,079 15,079 Goshute Possessory 12 151,097 151,097 Sho-Ban Possessory 13 35,940 35,877 18,002 Navajo Possessory 14 27,349 27,349 Ute Possessory 15 63,720 63,720 Crow Possessory 16 64,289 64,289 Umatilla Possessory 17 357,474 1,260,698 1,917,177 Subtotal 18 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 TOTAL 41 -286,256,396 -191,003,416 -209,999 46,747,021Name 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 28,723,272 -517,806,480 352,792,763 13,589,884 2 40,451,265 -3,514 727,676 3 383,109 44,983 4 3,121,283 162,786 5 72,678,929 -517,806,480 352,789,249 14,525,329 6 7 8 9 10 2,363,138 1,181,569 11 41,300 -14,946 18,570 12 41,300 2,348,192 18,570 1,181,569 13 14 15 156,361 2,103,347 16 31,522 769 17 109,146 39,367 110,746 18 179,485 3,282 19 1,150,173 973,724 20 476,514 3,292,887 110,746 977,775 21 22 23 41,100 1,678,036 1,800,000 24 718 -648 25 41,818 1,677,388 1,800,000 26 27 28 1,598,337 3,139,896 2,639,428 29 241,162 197,088 -1,323,020 30 26,822 13,676 31 95,862 1,915 32 160,036 13,978 33 2,095,397 3,363,806 -1,323,020 2,668,997 34 35 36 3,275,197 1,632,561 37 27,037 -26,987 -86,000 38 1,030 39 269,226 63,866 40

FERC FORM NO. 1 (ED. 12-96) Page 263 41 355,776,477 -385,705,794 99,449,398 48,804,714Name 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.

191,815 45,506 1 28,067 3,709,251 -86,000 1,741,933 2 3 4 8,398 5 245 -195 6 245 8,203 7 8 9 518,055 19,830,171 10,743,370 10 1,841,356 50,434 11 799 260 12 1,794,590 -3,555,890 677,838 13 754 -2,433 -470 14 722,590 365,145 15 863,452 343,950 16 1,872 17 22,210,008 4,158,926 18 5,020,878 39,204,446 11,785,883 4,553,570 19 20 21 7,055,752 45,297,821 470,896 22 1,688,064 -1,988,229 -7,518,951 23 203,542 2,706 24 804 25 648 26 4,958,116 541,588 27 13,905,474 43,311,044 -7,518,951 1,015,190 28 29 30 243,390 8,922,538 8,700,000 31 128,956 6,264 32 1,921 31,331 3,380 33 9,832,285 1,060,006 34 1,990,456 115,817 35 394,687 48,219 36 91,260 37

63 38 2,759,410 18,877,477 9,933,686 39 40

FERC FORM NO. 1 (ED. 12-96) Page 263.1 41 355,776,477 -385,705,794 99,449,398 48,804,714Name 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.

1 359,364 13,385,487 7,189,617 2 551,149 9,738 3 1,567,954 247,000 4 1,490,853 139,909 5 93,853 6 2,401,366 15,047,294 7,586,264 7 8 903,287 2,802,462 9 10 11 15,079 12 151,097 13 35,877 17,939 14 27,349 15 63,720 16 64,289 17 1,260,698 2,820,401 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 41 355,776,477 -385,705,794 99,449,398 48,804,714

### 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., whichwas 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., whichwas 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 1,512589 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 40,402107 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 Construction1,596,994107 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)XAn 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 49,496589 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 5,208,543107 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 3,423589 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)XAn 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 11,439589 Total $ 359,364 Schedule Page: 262.2 Line No.: 3 Column: f Recognition of January 1, 2010 balance for Pacific Minerals, Inc., whichwas 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)XAn 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 450.3Name 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) (b) (a) 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.

Electric Utility 13% 24% 37% 410% 37,000,901 411.4 1,808,768 510% 7,294,222 420 1,624,452 6Idaho 712,457 411.4 65,436 7TOTAL 45,007,580 3,498,656 8Other (List separately and show 3%, 4%, 7%, 10% and TOTAL) 9

10 11 1210% 881,312 420 440,808 13 14Total Nonutility 881,312 440,808 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 266Balance at End (i) (h) 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) Page267

### 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)XAn 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 450.1Name 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 (c) (b) (a) 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 3,410,544 Working Capital Deposits 4,385,114 974,570 2 3 4,499,352 Reclamation Costs - Trapper Mine 4,736,622 237,270 4 5 534,826 Reclamation Costs - Deseret Mine 527,526 7,300 131 6 7 Reclamation Costs - Trail 8 1,090,948 Mountain Mine 1,087,498 3,450 131 9 10 9,791,441 Deferred Compensation Plan 9,806,399 2,192,142 2,177,184 232, 241,920 11 12 Western Coal Carriers Benefits 13 Obligation 9,124,000 9,403,264 279,264 232 14 15 1,893,375 Transmission Service Deposits 2,312,550 4,356,275 3,937,100 232, 235,456 16 17 557,783 MCI F.O.G. wire lease 558,451 3,350,705 3,350,037 454 18 19 3,300,076 Redding Contract (20) 2,750,080 549,996 456 20 21 705,302 Foote Creek Contract (15) 567,662 137,640 142 22 23 6,928,295 Environmental Liabilities 9,389,140 6,840,546 4,379,701 24 25 3,342,497 Unearned Joint Use Pole Contact 3,362,850 8,315,400 8,295,047 454 26 27 Deferred Revenue - 28 1,163,710 Hermiston Gas Settlement (5) 408,871 754,839 547, 555 29 30 1,550,000 Transmission Security Deposits 1,450,000 1,208,253 1,308,253 107, 142,232 31 32 Other deferred credits with 33 1,389,331 balances less than $500,000 1,025,262 364,069 various 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-94) Page 269 47 TOTAL 36,878,425 25,543,880 51,492,025 40,157,480

### 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)XAn 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 450.1Name 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.

1Accelerated Amortization (Account 281) 2Electric 3Defense Facilities 1,673,844 13,316,552 4Pollution Control Facilities 5Other (provide details in footnote): 6 7 1,673,844 13,316,552 8TOTAL Electric (Enter Total of lines 3 thru 7) 9Gas 10Defense Facilities 11 Pollution Control Facilities 12Other (provide details in footnote): 13 14 15TOTAL Gas (Enter Total of lines 10 thru 14) 16 1,673,844 13,316,552 17TOTAL (Acct 281) (Total of 8, 15 and 16) 18Classification of TOTAL 19Federal Income Tax 20State Income Tax 21 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page272 NOTESName 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 Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (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.

Account 282 1 Electric 2,801,783,463 1,074,973,139 400,329,543 2Gas 3 4TOTAL (Enter Total of lines 2 thru 4) 2,801,783,463 1,074,973,139 400,329,543 5Nonutility 871,716 6 7 8TOTAL Account 282 (Enter Total of lines 5 thru 2,802,655,179 1,074,973,139 400,329,543 9Classification of TOTAL 10Federal Income Tax 2,467,379,311 946,376,315 352,438,944 11 State Income Tax 335,275,868 128,596,824 47,890,599 12Local Income Tax 13

FERC FORM NO. 1 (ED. 12-96) Page 274 NOTESName 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 Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 3. Use footnotes as required.

1 190, 283 3,330,234,891 173,479,616190, 182.3 27,287,448 2 3 4 3,330,234,891 173,479,616 27,287,448 5 10,848 882,564 6 7 8 10,848 882,564 3,330,234,891 173,479,616 27,287,448 9 10 9,550 776,985 2,931,845,747 152,726,607 24,023,107 11 1,298 105,579 398,389,144 20,753,009 3,264,341 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)XAn 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 450.1Name 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.

Account 283 1
Electric 2 65,065,028 51,931,202 416,262,076 Regulatory Assets 3 4 5 6,070,503 2,227,685 34,637,390 Other Deferred Liabilities 6 7 8 71,135,531 54,158,887 450,899,466 TOTAL Electric (Total of lines 3 thru 8) 9Gas 10 11 12 13 14 15 16TOTAL Gas (Total of lines 11 thru 16) 17 18 71,135,531 54,158,887 450,899,466 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19Classification of TOTAL 20 62,625,734 47,679,971 396,958,249 Federal Income Tax 21 8,509,797 6,478,916 53,941,217 State Income Tax 22
Local Income Tax 23

FERC FORM NO. 1 (ED. 12-96) Page 276NOTESName 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 Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

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

1 2 649,677,709 217,159,853 10,898,320 56,437,118 16,149,192 3 4 5 30,841,189 372,360 190 190 325,743 6 7 8 680,518,898 217,532,213 10,898,320 56,437,118 16,474,935 9 10 11 12 13 14 15 16 17 18 680,518,898 217,532,213 10,898,320 56,437,118 16,474,935 19 20 599,108,781 191,509,282 9,594,577 49,685,662 14,504,072 21 81,410,117 26,022,931 1,303,743 6,751,456 1,970,863 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)XAn 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 450.1Name 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 Credits Account (d)

(c) (a) 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)20,359,322 1,013,976 19,345,346 Income Tax Regulatory Liability 190 1 876,629 2,426,440 1,549,811 Income Tax Reg. Liab. - WA Flow Through 2 459,170 851,328 73,549 465,707 Gain on Sale of Assets - OR 3 45,034 41,279 3,755 Gain on Sale of Assets - CA 421.1 4 109,564 109,564 Property Insurance Reserve 228.1,924 5 22,913,046 13,956,848 9,074,298 118,100 SMUD Revenue Imputation (11) 400,442 6 228,659 228,728 69 WA Rate Refund 142 7 413,856 4,165,060 203,362 3,954,566 Utah Home Energy Lifeline 142 8 903,021 1,482,441 579,420 BPA Washington Balancing Account 9 2,419,092 3,175,146 756,054 BPA Oregon Balancing Account 10 4,409,486 259,882 4,407,551 257,947 Asset Retirement Obligations Reg. Difference 230 11 ( 35,188) 967,554 206,049 1,208,791 Washington Low Income Program 142 12 211,435 176,623 192,624 157,812 Misc. Regulatory Liabilities - OR 182.3 13 378,243 1,077,654 626,935 1,326,346 Blue Sky - OR 456 14 40,285 159,322 48,434 167,471 Blue Sky - WA 456 15 67,399 119,651 18,498 70,750 Blue Sky - CA 456 16 734,895 2,475,501 920,706 2,661,312 Blue Sky - UT 456 17 28,623 83,459 2,422 57,258 Blue Sky - ID 456 18 76,129 220,683 54,985 199,539 Blue Sky - WY 456 19 822,596 19,538,442 2,338,991 21,054,837 OR Energy Conservation Charge 456 20 1,217,286 1,173,017 44,269 Deferred Arch Coal Settlement (3) 557 21 3,922,178 3,922,178 Renewable Energy Credit Sales Deferral - OR 22 3,594,057 3,594,057 Renewable Energy Credit Sales Deferral - WY 23 49,234 49,234 Tax Revenue Requirement Adj. - UT 24 7,485,673 85,730 7,399,943 Regulatory Liability - Reclassifications 182.3 25 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 42,151,259 46,704,301 59,611,213 64,164,255

### 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)XAn 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 450.1Name 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 (c) (b) (a) 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) Sales of Electricity 1 1,346,519,773 (440) Residential Sales 1,357,826,906 2 (442) Commercial and Industrial Sales 3 1,120,956,943 Small (or Comm.) (See Instr. 4) 1,146,322,741 4 976,991,304 Large (or Ind.) (See Instr. 4) 1,030,052,681 5 20,913,398 (444) Public Street and Highway Lighting 20,610,361 6 19,032,148 (445) Other Sales to Public Authorities 19,770,416 7 (446) Sales to Railroads and Railways 8 (448) Interdepartmental Sales 9 3,484,413,566 TOTAL Sales to Ultimate Consumers 3,574,583,105 10 643,321,157 (447) Sales for Resale 501,563,210 11 4,127,734,723 TOTAL Sales of Electricity 4,076,146,315 12 (Less) (449.1) Provision for Rate Refunds 13 4,127,734,723 TOTAL Revenues Net of Prov. for Refunds 4,076,146,315 14 Other Operating Revenues 15 7,318,368 (450) Forfeited Discounts 7,411,888 16 6,908,893 (451) Miscellaneous Service Revenues 5,919,271 17 12,154 (453) Sales of Water and Water Power 2,609 18 19,158,931 (454) Rent from Electric Property 19,559,096 19 (455) Interdepartmental Rents 20 128,935,328 (456) Other Electric Revenues 225,364,091 21 63,697,983 (456.1) Revenues from Transmission of Electricity of Others 67,812,115 22 (457.1) Regional Control Service Revenues 23 (457.2) Miscellaneous Revenues 24 25 226,031,657 TOTAL Other Operating Revenues 326,069,070 26 4,353,766,380 TOTAL Electric Operating Revenues 4,402,215,385 27

Page 300 FERC FORM NO. 1/3-Q (REV. 12-05)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 Previous Year (no Quarterly) Current Year (no Quarterly) AVG.NO. CUSTOMERS PER MONTH Year to Date Quarterly/Annual Amount Previous year (no Quarterly) (d) (e) (f) (g) 6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by 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 15,998,640 1,466,724 1,474,909 15,794,444 2 3 16,194,257 213,730 220,171 15,969,253 4 19,934,268 34,070 33,854 20,679,453 5 144,765 3,948 3,868 145,032 6 437,595 13 13 427,352 7 8 9 52,709,525 1,718,485 1,732,815 53,015,534 10 12,349,061 11,414,592 11 65,058,586 1,718,485 1,732,815 64,430,126 12 13 65,058,586 1,718,485 1,732,815 64,430,126 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)XAn 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)XAn 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 450.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp 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 (c) (b) 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 TOTALName 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 (b) (a) 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.

1RESIDENTIAL SALES 2CALIFORNIA 1 306CHCK000R-CA RES CHECK M -40 406LNX00109-REF/NREF ADV+ 266 29 9,172 0.1134 30,174 506NETMT135-CA RES NET 339 368 921 0.2146 72,752 606OALT015R-OUTD AR LGT SR 196,737 18,812 10,458 0.1118 21,997,535 706RESD000D-RES SRVC 109,576 9,459 11,584 0.1110 12,158,912 806RESDDL06-CA LOW INCOME 60 6 10,000 0.1083 6,498 906RESDDM9M-MULTI FAMILY 178 8 22,250 0.1072 19,082 1006RESD0DM9-MULTI FAMILY 866 15 57,733 0.0900 77,940 1106RESDDS8M-MULT FAM SBMET 626 15 41,733 0.0974 60,969 1206RESDDS8M-MULT FAM SBMET 1,259,052 13REVENUE ADJ. - DEFERRED NPC -1,024,881 14REV. ACCOUNTING ADJ. 44,729 15SMUD REVENUE IMPUTATIONS 96,864 7,463 12,979 0.1106 10,717,286 1606RESD00DN - CA RES SRVC - -2,551 0.1564 -399,000 17UNBILLED REVENUE 18IDAHO 1,192 1907LNX00010-MNTHLY 80%GUAR 1,520 2007LNX00035-ADV 80%MO GUAR 1,054 59 17,864 0.0801 84,442 2107NETMT135 - ID RESIDENTIAL 10 1 10,000 0.3704 3,704 2207OALCO007-CUST OWN LIGHT 106 136 779 0.4014 42,548 2307OALT07AR-SECURITY AR LG 423,071 42,306 10,000 0.0916 38,736,381 2407RESD0001-RES SRVC 6 2507RESD0001-RES SRVC 284,972 14,789 19,269 0.0741 21,122,790 2607RESD0036-RES SRVC-OPTIO -2 2707RESD0036-RES SRVC-OPTIO 1,640,993 28BPA BALANCING ACCOUNT 1 2907ZZMERGCR-MERGER CREDITS 3,000 30UNBILLED REV - UNCOLLECTIBLE 74,932 31SMUD REVENUE IMPUTATIONS -4,086 0.0489 -200,000 32UNBILLED REVENUE 33OREGON 1 3401CHCK000R-RES CHECK MTR 5,240,762 0.0456 239,182,779 3501COST0004 - 01RESD0004 -1 3601FXRENEWR - Fx Rnw Blue Sky 43,891 0.0445 1,951,428 3701HABIT004 - 01RESD0004 17,436 3801LNX00102-LINE EXT 80% G 42 3901LNX00105-CNTRCT $ MIN G 3,016 4001LNX00109-REF/NREF ADV +

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 TOTALName 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 (b) (a) 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.

938 404,935 101NETMT135-NET METERING -40,917 201NETMT135-NET METERING 7 1,707 301NMTOU135-TOU NET METR -172 401NMTOU135-TOU NET BPA 2,480 2,873 863 0.1584 392,792 501OALT014R-OUTD AR LGT RE -12,192 601OALT014R-OUTD AR LGT RE 20,792 0.0464 965,659 701PTOU0004 - 01RESD0004 202,590 0.0439 8,902,861 801RENEW004 - 01RESD0004 472,158 243,376,697 901RESD0004-RES SRVC -25,696,576 1001RESD0004-RES SRVC -18 1101RESD0013-3 PHASE RES SR 1,363 893,181 1201RESD004T - RES Time Option -97,264 1301RESD004T - RES Time Opt BPA 4 1401UPPL000R-BASE SCH FALL 19 3,194 1501VIR04136-OR RES VOL INCTV -344 1601VIR04136-OR RES VOL INCTV -774,369 17BPA BALANCING ACCOUNT 330,826 18OR GAIN ON SALE OF ASSET 717,937 19OR SB408 RECOVERY -2,139,500 20OR SB838 RECOVERY -24,768 21REV. ACCOUNTING ADJ. 560,635 22SMUD REVENUE IMPUTATIONS 12,000 23UNBILLED REV - UNCOLLECTIBLE -58,075 0.0687 -3,992,000 24UNBILLED REVENUE 25UTAH -2 2608BLSKY01R-BLUESKY ENERGY 1,265 2708CFR00001-MTH FACILITY S 1 2808CHCK000R-UT RES CHECK M 90,971 2908COOLKPRR-Utah Cool Keeper 3,120 3008LNX00001-MTHLY 80% GUAR 949 3108LNX00005- MNTHLY MIN GUAR 30,115 3208LNX00013-80% MTHLY MIN 605 3308LNX00016-80% annual gty 2,604 3408LNX00108-ANN COST MTHLY 12,092 11 1,099,273 0.0720 870,739 3508MHTP0025-MOBILE HOME & 4,538 571 7,947 0.0877 397,868 3608NETMT135 - Net Metering 2,803 3,084 909 0.2822 791,092 3708OALT007R-SECURITY AR LG 2 3 667 0.0625 125 3808PTLD000R-POST TOP LIGHT 6,292,269 670,049 9,391 0.0879 553,304,441 3908RESD0001-RES SRVC 3,069 352 8,719 0.0862 264,693 4008RESD0002-RES SRVC-OPTIO

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 TOTALName 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 (b) (a) 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.

257,586 31,622 8,146 0.0870 22,409,951 108RESD0003-LIFELINE PRGRM -4 208RESD0150-RES ALL E NOT5 4 308UPPL000R-BASE SCH FALL 5,572,698 4REV. ACCOUNTING ADJ. 3,386,349 5SMUD REVENUE IMPUTATIONS -19,000 6UNBILLED REV - UNCOLLECTIBLE -23,209 0.0671 -1,558,000 7UNBILLED REVENUE 8WASHINGTON 320 15 21,333 0.0816 26,121 902NETMT135 - WA RES NET MTR -1,417 1002NETMT135 - WA RES NET BPA 1,102 1,184 931 0.1424 156,939 1102OALTB15R-WA OUTD AR LGT -4,930 1202OALTB15R-OUTD AR LGT BPA 1,529,247 99,824 15,319 0.0764 116,774,628 1302RESD0016-WA RES SRVC -6,774,259 1402RESD0016-WA RES SRVC 63,121 3,977 15,872 0.0762 4,810,129 1502RESD0017-BILL ASSISTANCE -279,723 1602RESD0017-BILL ASSISTANCE 2,437 89 27,382 0.0838 204,156 1702RESD0018-WA 3 PHASE RES -10,829 1802RESD0018-WA 3 PHASE RES 516 22 23,455 0.0823 42,442 1902RESD018X-WA 3 PHASE RES -2,287 2002RESD018X-WA 3 PHASE RES 2 2102RFNDCENT - CENTRALIA RFND 2 2202ZZMERGCR-MERGER CREDITS -43 23ACQUISITION COMMIT-A&G CR -542,831 24BPA BALANCING ACCOUNT -3,928,254 25REV. ACCOUNTING ADJ. 158,816 26SMUD REVENUE IMPUTATIONS -1,320,000 27WA - CHEHALIS DEFERRAL -8,000 28UNBILLED REV - UNCOLLECTIBLE 24,434 0.0951 2,323,000 29UNBILLED REVENUE 30WYOMING -1 3105BLSKY01R-BLUE SKY ENERGY 152 3205LNX00102-LINE EXT 80% G 129 3305LNX00109-REF/NREF ADV + 910 67 13,582 0.0842 76,631 3405NETMT135-EXPERIMENTAL 930 1,092 852 0.1454 135,210 3505OALT015R-OUTD AR LGT SR 925,080 96,607 9,576 0.0837 77,385,266 3605RESD0002-WY RES SRVC 11 1 11,000 0.0850 935 3705RESD018X-RES 3 PHASE SR 16,692 38REV. ACCOUNTING ADJ. 83,234 39SMUD REVENUE IMPUTATIONS -11,000 40UNBILLED REV - UNCOLLECTIBLE

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 TOTALName 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 (b) (a) 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.

3,889 0.1167 454,000 1UNBILLED REVENUE 132,092 12,608 10,477 0.0836 11,040,106 205RESD0002-WY RES SRVC 78 92 848 0.3064 23,901 309OALT207R-SECURITY AR LG 205 10 20,500 0.0806 16,519 405NETMT135 - EXPERIMENTAL 2 509RES0002 -10 4 -2,500 0.0657 -657 609RESD0002 404 0.1262 51,000 7UNBILLED REVENUE -108,183 8LESS MULTIPLE BILLINGS 9 15,794,444 1,474,909 10,709 0.0860 1,357,826,906 10TOTAL RESIDENTIAL SALES 11 12COMMERCIAL SALES 13CALIFORNIA 1 1406CHCK000N-CA NRES CHECK 58,364 6,854 8,515 0.1354 7,902,097 1506GNSV0025-CA GEN SRVC 938 92 10,196 0.1512 141,832 1606GNSV025F-GEN SRVC-< 20 81,098 965 84,039 0.1108 8,985,799 1706GNSV0A32-GEN SRVC-20 KW 66,219 13 5,093,769 0.0700 4,638,318 1806LGSV048T-LRG GEN SERV 80,706 185 436,249 0.0911 7,355,985 1906LGSV0A36-LRG GEN SRVC-O 13,662 2006LNX00102-LINE EXT 80% G 4,591 2106LNX00105-CNTRCT $ MIN G 68,238 2206LNX00109-REF/NREF ADV + 28,779 2306LNX00300-80% MTHLY MIN GU 3,247 2406LNX00311-LINE EXT 80% GUAR 373 1 373,000 0.1016 37,912 2506NMT36135-CA GEN SVC NET 740 532 1,391 0.2166 160,277 2606OALT015N-OUTD AR LGT SR 204 38 5,368 0.1616 32,957 2706RCFL0042-AIRWAY & ATHLE 1 28 36 0.1250 125 2806WHS31025-COMM WTR HEATI 201 28 7,179 0.1150 23,108 2906WHSV0031-COMM WTR HEATI 33 1 33,000 0.1238 4,084 3006NMT25135-GN SVC NET<20K 296 2 148,000 0.1110 32,856 3106NMT32135-GN SVC NET>20K 915,488 32REVENUE ADJ. - DEFERRED NPC -663,108 33REV. ACCOUNTING ADJ. 33,005 34SMUD REVENUE IMPUTATIONS 5,305 3506LNX00110-REF/NREF ADV + -67 1.1045 -74,000 36UNBILLED REVENUE 37IDAHO 6,348 123 51,610 0.0689 437,576 3807CISH0019-COMM & IND SPA 191,906 947 202,646 0.0662 12,705,424 3907GNSV0006-GEN SRVC-LRG P 40,080 1 40,080,000 0.0465 1,865,169 4007GNSV0009-GEN SRVC-HI VO

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 TOTALName 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 (b) (a) 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.

129,527 6,299 20,563 0.0803 10,399,651 107GNSV0023-GEN SRVC-SML P 515 2 257,500 0.0570 29,333 207GNSV0035-GEN SRVCOPTION 30,126 203 148,404 0.0693 2,088,256 307GNSV006A-GEN SRVC-LRG P 19,091 1,348 14,162 0.0829 1,582,974 407GNSV023A-GEN SRVC-SML P 18 7 2,571 0.1473 2,652 507GNSV023F-GEN SRVC SML P 6,302 607LNX00010-MNTHLY 80%GUAR 334,092 707LNX00035-ADV 80%MO GUAR 68,273 807LNX00040-ADV+REFCHG+80% 239 182 1,313 0.3682 87,998 907OALT007N-SECURITY AR LG 12 14 857 0.3925 4,710 1007OALT07AN-SECURITY AR LG 3,069 1107LNX00312 - ID LINE EXT 50 4 12,500 0.0855 4,273 1207NMT23135-NET MTR-SM GEN 2,262 1307LNX00015-ANNUAL 80%GUAR 69,214 1407LNX00311-LINE EXT 80% GUAR 278 1507LNX00020 -MTHLY CONTRACT 6,214 1607LNX00300-80% MTHLY MIN GU 97,039 17BPA BALANCING ACCOUNT 45,218 18SMUD REVENUE IMPUTATIONS -23,780 0.0631 -1,500,000 19UNBILLED REVENUE 20OREGON 968,227 0.0456 44,159,121 2101COST0023-OR GEN SRV-COST 716,816 0.0421 30,152,501 2201COST0048 - 01LGSV0048 3,059 0.0484 147,959 2301COST023F-OR GEN SRV-COST 84,379 0.0472 3,985,038 2401COSTB023-OR GEN SRV-COST 1,043,038 0.0428 44,636,396 2501COSTL030-OR LG GEN SRV 1,913,017 0.0461 88,237,991 2601COSTS028-OR GEN SRV -COST 432 0.0354 15,272 2701COSTS030-OR GEN SRV -CBS -399,778 2801GNSB0023-BPA DISC<30kW 14,361 5,365,390 2901GNSB0023-OR GEN SRV -BPA -585,975 3001GNSB0028-OR GEN SRV -BPA 537 2,765,447 3101GNSB0028-OR GEN SRV -BPA 52 25,212 3201GNSB023T-OR GEN SRV-TOU -2,360 3301GNSB023T-OR GEN SRVC-TOU 57,229 40,514,698 3401GNSV0023-OR GEN SRV <30kW 8,971 42,000,539 3501GNSV0028-OR GEN SRV >30kW 9,360 801 11,685 0.1423 1,331,826 3601GNSV023F-OR GEN SRV -FLAT 42 1 42,000 0.0761 3,197 3701GNSV023M-OR GEN SRV -MANU 232 157,342 3801GNSV023T-OR GEN SRV-TOU 2,378 0.0462 109,892 3901HABT0023-OR HABITAT BLEND 209 0.0471 9,845 4001HABTB023-OR HABITAT BLEND

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 TOTALName 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 (b) (a) 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.

-221,985 101LGSB0030-GEN DEL SRV >200 27 797,643 201LGSB0030-GEN DEL SRV >200 635 19,041,024 301LGSV0030 - OR LRG GEN SRV, 97 8,520,124 401LGSV0048-1000KW AND OVR 65,247 1 65,247,000 0.0478 3,117,450 501LGSV048M-LRG GEN SRVC 1 4,918 601LNX00100-LINE EXT 60% GUAR 486,323 701LNX00102-LINE EXT 80% GUAR 3,994 801LNX00103-LINE EXT 80% GUAR 15,726 901LNX00105-CNTRCT $ MIN G 1,789,218 1001LNX00109-REF/NREF ADV + 8,502 1101LNX00110-REF/NREF ADV + 5,165 1201LNX00120-LINE EXT 60% GUAR 124,916 1301LNX00300-LINE EXT 80% GUAR 111,367 1401LNX00311-LINE EXT 80% GUAR 5,717 1501LNX00314-LINE EXT 60% GUAR 11,335 3 3,778,333 0.0849 961,860 1601LPRS047M-PART REQ SRVC 100 72,645 1701NMT23135 - OR NET MTR, GEN, -86 1801NMT23135 - OR NET MTR, GEN, 1,555 1,155 1,346 0.1640 255,017 1901OALT014N-OUTD AR LGT NR -7,588 2001OALT014N-OUTD AR LGT NR 5,812 3,061 1,899 0.1393 809,585 2101OALT015N-OUTD AR LGT NR 3,563 0.0458 163,149 2201PTOU0023, OR GEN SRV, TOU 534 0.0455 24,295 2301PTOUB023, OR GEN SRV, TOU 1,087 104 10,452 0.0934 101,517 2401RCFL0054-REC FIELD LGT 8,142 0.0465 378,344 2501RENW0023, OR RENW USAGE 479 0.0483 23,120 2601RENWB023 - OR RENEWABLE 2,037 0.0623 126,970 2701STDAY023 - OR DAY STD OFR, 7,103 0.0608 431,998 2801STDAY028 - OR DAY STD OFF, 4,350 0.0590 256,620 2901STDAY030 - OR STD DAY OFF, 3 45 3001VIR23136-OR VOLUME INCENTV 2 1,398 3101VIR28136-OR VOLUME INCENTV -1 3201ZZMERGCR-MERGER CREDITS -31,738 33BPA BALANCING ACCOUNT -14,577 3401LGSB0048 - LG GEN SVC > 1 49,026 3501LGSB0048 - LG GEN SVC > 41 204,692 3601NMT28135 - OR NET MTR, GEN, 10 246,217 3701NMT30135 - OR NET MTR, GEN, 458 1 458,000 0.0709 32,451 3801LGSV028M - OR LGSV, <1000 1,650 1 1,650,000 0.0566 93,399 3901GNSV030M - OR GEN SRV, 200 8 255,071 4001GNSV0728 - OR GEN SVC DIR

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 TOTALName 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 (b) (a) 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.

33 2,461,768 101GNSV0730 -OR GEN SVC DIR 2 542,541 201GNSV0748 LG GEN SVC DIR 297,113 3OR GAIN ON SALE OF ASSET 628,755 4OR SB408 RECOVERY -1,592,366 5OR SB 838 RECOVERY -20,866 6REV. ACCOUNTING ADJ. 496,288 7SMUD REVENUE IMPUTATIONS -63,458 0.0531 -3,371,000 8UNBILLED REVENUE 9UTAH 39,713 1008CFR00051-MTH FAC SRVCHG 2 1108CFR00052-ANN FAC SVCCHG 3,554 1208COOLKPRN - A/C DIRECT LOAD 4,771,840 10,914 437,222 0.0693 330,746,047 1308GNSV0006-GEN SRVC-DISTR 267,105 25 10,684,200 0.0481 12,837,629 1408GNSV0009-GEN SRVC-HI VO 1,251,393 72,903 17,165 0.0829 103,757,349 1508GNSV0023-GEN SRVC-DISTR 196,244 1,760 111,502 0.0950 18,643,401 1608GNSV006A-GEN SRVC-ENERG 9,130 21 434,762 0.0680 620,766 1708GNSV006B-GEN SRVC-DEM& 3,463 7 494,714 0.0589 204,018 1808GNSV006M-MNL DIST VOLTG 24,022 2 12,011,000 0.0516 1,239,923 1908GNSV009A-GEN SRVC HI VO 1,388 130 10,677 0.1158 160,765 2008GNSV023F-GEN SRVC FIXED 109 5 21,800 0.0814 8,869 2108GNSV023M-GNSV DIST VOLT 1 795 2208GNSV06AM-MNL ENERGY TOD 26,380 446 59,148 0.0654 1,726,284 2308GNSV06MN-GNSV DIST VOLT 545,339 2408LNX00002-MTHLY 80% GUAR 86,151 2508LNX00004-ANNUAL 80%GUAR 1,816 2608LNX00006-FIXD MTHLY MIN 12,167 2708LNX00008-ANNUALMIN GUAR 2,073,877 2808LNX00014-80% MIN MNTHLY 341,431 2908LNX00017-ADV/REF&80%ANN 34,209 3008LNX00158-ANNUALCOST MTH 124,444 3108LNX00300 - LINE EXT 80% PLUS 3,758 3208LNX00310 - IRR, 80% ANNUAL 10,579 3308LNX00312 UT IRG LINE EXT 10,298 19 542,000 0.0719 739,943 3408NMT06135 - UT NET MTR, GEN, 5,751 1 5,751,000 0.0584 335,791 3508NMT08135 -NET METERING 1,022 51 20,039 0.0840 85,836 3608NMT23135 - UT NET MTR, GEN, 19 1 19,000 0.1636 3,108 3708NMT6A135-NET METERING GEN 8,639 4,499 1,920 0.2296 1,983,135 3808OALT007N-SECURITY AR LG 1 61 3908POLE0075-POLES W/LIGHT 10,713 2 5,356,500 0.0647 692,801 4008PRSV031M-BKUP MNT&SUPPL

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 TOTALName 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 (b) (a) 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.

6 2 3,000 0.0757 454 108PTLD000N-POST TOP LIGHT 149 26 5,731 0.1010 15,045 208TOSS015F-TRAFFIC SIG NM 1,240 559 2,218 0.0936 116,009 308TOSS0015-TRAF & OTHER S 14,397 371 38,806 0.0701 1,008,800 408MONL0015-MTR OUTDONIGHT 5,787,624 5REV. ACCOUNTING ADJ. 3,895,349 6SMUD REVENUE IMPUTATIONS 210,085 708LNX00311 - LINE EXT 80% 952,000 150 6,346,667 0.0594 56,593,171 808GNSV0008 - UT GEN SVC TOU > 33,691 5 6,738,200 0.0639 2,152,344 908GNSV008M - UT GEN SVC TOU -5,703 -0.0573 327,000 10UNBILLED REVENUE 11WASHINGTON 40,251 3,179 12,662 0.0827 3,327,361 1202GNSB0024-WA GEN SRVC DO -177,594 1302GNSB0024-WA GEN SRVC DO 154 6 25,667 0.1043 16,065 1402GNSB024F-GEN SRVC DOM/F -4 1502GNSB024F-GEN SRVC DOM/F 351 100 3,510 0.3261 114,460 1602GNSB24FP-WA GEN SVC -1,558 1702GNSB24FP-WA GEN SVC 467,368 14,411 32,431 0.0758 35,405,704 1802GNSV0024-WA GEN SRVC 1,115 112 9,955 0.1120 124,826 1902GNSV024F-WA GEN SRVC-FL 82,828 98 845,184 0.0631 5,227,389 2002LGSB0036-LRG GEN SVC IRG -359,983 2102LGSB0036-LRG GENSVC IRG 680,624 819 831,043 0.0643 43,770,704 2202LGSV0036-WA LRG GEN SRV 143,366 26 5,514,077 0.0581 8,336,036 2302LGSV048T-LRG GEN SRVC 1 123,739 2402LNX00102-LINE EXT 80% G 6,553 2502LNX00103-LINE EXT 80% G 652 2602LNX00105-CNTRCT $ MIN G 390,446 2702LNX00109-REF/NREF ADV + 14,283 2802LNX00110-REF/NREF ADV + 669 2902LNX00112-YR INCURRED CH 3,070 3002LNX00300-LINE EXT 80% G 4,351 3102LNX00310 - IRG, 80% ANNUAL 26,159 3202LNX00311 - LINE EXT 80% 2,769 3302LNX00312 - WA IRG LINE EXT 1,650 856 1,928 0.1317 217,376 3402OALT015N-WA OUTD AR LGT 603 523 1,153 0.1410 85,036 3502OALTB15N-WA OUTD AR LGT -2,687 3602OALTB15N-WA OUTD AR LGT 278 29 9,586 0.0867 24,091 3702RCFL0054-WA REC FIELD L 175 3802RFNDCENT - CENTRALIA RFND -23 3902ZZMERGCR-MERGER CREDITS 73 0.0864 6,307 4002NMT24135, Net metering, WA

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 TOTALName 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 (b) (a) 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.

110 0.0944 10,388 102NMT36135-WA NET METER LRG -38 2ACQUISITION COMMIT-A&G CR -31,111 3BPA BALANCING ACCOUNT -3,090,281 4REV. ACCOUNTING ADJ. 140,164 5SMUD REVENUE IMPUTATIONS -1,020,000 6WA - CHEHALIS DEFERRAL -18,246 0.0506 -924,000 7UNBILLED REVENUE 8WYOMING 1 905CHCK000N-WY NRES 31,513 1,767 17,834 0.0710 2,237,603 1005GNS28025-GEN SVC 269 25 10,760 0.0687 18,481 1105GNSC0025 - WY SMALL 155,755 16,346 9,529 0.0836 13,027,409 1205GNSV0025-WY GEN SRVC 922,357 4,044 228,080 0.0723 66,652,138 1305GNSV0028-GEN SVC > 15 KW 974 190 5,126 0.1359 132,395 1405GNSV025F-GEN SRVC-FL RA 222,489 20 11,124,450 0.0563 12,532,839 1505LGSV0046-WY LRG GEN SRV 23,362 1 23,362,000 0.0564 1,317,396 1605LGSV046M-WY LRG GEN SERV 9,940 1 9,940,000 0.0625 621,563 1705LGSV048T-LRG GENSRV TIM 102 1805LNX00100-LINE EXT 60% G 565,208 1905LNX00102-LINE EXT 80% G 808 2005LNX00103-LINE EXT 80% 5,343 2105LNX00105-CNTRCT $ MIN G 612,454 2205LNX00109-REF/NREF ADV + 838 2305LNX00110-REF/NREF ADV+ 5,191 2405LNX00114-TEMP SVC 12MO> 12 1 12,000 0.0880 1,056 2505N2825135 - NET METERING 172 8 21,500 0.0688 11,827 2605NMT25135 - WY NET MTR, GEN, 1,283 7 183,286 0.0904 116,025 2705NMT28135-NET MTR SMALL 2,871 1,749 1,642 0.1463 420,027 2805OALT015N-OUTD AR LGT SR 664 50 13,280 0.0753 49,983 2905RCFL0054-WY REC FIELD L 191,062 3005LNX00300 - LINE EXT 80% 63,037 3105LNX00311 - LINE EXT 80% 20,691 32REV. ACCOUNTING ADJ. 116,998 33SMUD REVENUE IMPUTATIONS -2,016 0.1136 -229,000 34UNBILLED REVENUE 4,750 279 17,025 0.0721 342,254 3505GNS28025-GEN SVC 42 3 14,000 0.0654 2,746 3605GNSC0025 - WY SMALL 20,596 2,067 9,964 0.0825 1,699,429 3705GNSV0025 - WY GEN SRVC 115,540 550 210,073 0.0715 8,260,171 3805GNSV0028-GEN SVC > 15 KW 195 32 6,094 0.0992 19,337 3905GNSV025F-GEN SRVC-FL RA 1,865 1 1,865,000 0.0697 129,994 4005GNSV028M-GEN SVC>15 KW

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 TOTALName 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 (b) (a) 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.

5,167 105LNX00102-LINE EXT 80% G 167,539 205LNX00109-REF/NREF ADV + 257 305LNX00110-REF/NREF ADV + 481 405LNX00114-TEMP SVC -9 0.0907 -816 509GNSV0025-GEN SVC-SINGLE 24 1 24,000 0.0723 1,734 605NMT25135 - WY NET MTR, GEN, 165 1 165,000 0.0940 15,516 705NMT28135-NET MTR SMALL 278 139 2,000 0.2710 75,336 809OALT207N-SECURITY AR LG 21 3 7,000 0.0828 1,738 909MONL0213-WY MTR OUTDOOR -34,511 1005LNX00300 - LINE EXT 80% 6,662 1105LNX00311 - LINE EXT 80% -1,769 0.0594 -105,000 12UNBILLED REVENUE -28,068 13LESS MULTIPLE BILLINGS 14 15,969,253 220,171 72,531 0.0718 1,146,322,741 15TOTAL COMMERCIAL SALES 16 17INDUSTRIAL SALES 18CALIFORNIA 728 96 7,583 0.1388 101,075 1906GNSV0025-CA GEN SRVC 1,868 27 69,185 0.1239 231,485 2006GNSV0A32-GEN SRVC-20 KW 38,459 5 7,691,800 0.0692 2,661,481 2106LGSV048T-LRG GEN SERV 5,103 14 364,500 0.1017 519,076 2206LGSV0A36-LRG GEN SRVC-O 236 2306LNX00109-REF/NREF ADV + 173,488 24REVENUE ADJ.-DEFERRED NPPC -77,920 25REV. ACCOUNTING ADJ. 5,175 26SMUD REVENUE IMPUTATIONS 7 -1.5714 -11,000 27UNBILLED REVENUE 28IDAHO 2,217 2907CFR00001-MTH FACILITY S 132 3 44,000 0.0725 9,564 3007CISH0019-COMM & IND 91,682 112 818,589 0.0564 5,170,021 3107GNSV0006-GEN SRVC-LRG P 77,002 11 7,000,182 0.0476 3,665,442 3207GNSV0009-GEN SRVC-HI VO 10,709 353 30,337 0.0780 835,814 3307GNSV0023-GEN SRVC-SML P 1,192 1 1,192,000 0.0567 67,630 3407GNSV0035-GEN SRVCOPTION 4,651 31 150,032 0.0703 326,841 3507GNSV006A-GEN SRVC-LRG P 2,026 245 8,269 0.0924 187,140 3607GNSV023A-GEN SRVC-SML P 8 3 2,667 0.1319 1,055 3707GNSV023S-ID TRAFFIC 693 3807LNX00035-ADV 80%MO GUAR 1,996 3907LNX00108-ANN COST MTHLY 1,876 4007LNX00300 - 80% MONTHLY MIN

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 TOTALName 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 (b) (a) 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.

13 17 765 0.3823 4,970 107OALT007N-SECURITY AR LG 1 2 500 0.2840 284 207OALT07AN-SECURITY AR LG 1,381,900 1 1,381,900,000 0.0444 61,415,663 307SPCL0001 104,026 1 104,026,000 0.0425 4,418,677 407SPCL0002 14,963 5BPA BALANCING ACCOUNT 138,631 6SMUD REVENUE IMPUTATIONS -6,118 -0.0353 216,000 7UNBILLED REVENUE 8OREGON 20,565 0.0458 940,856 901COST0023, OR GEN SRV, COST 1,558,066 0.0413 64,298,860 1001COST0048 - 01LGSV0048 2 0.0560 112 1101COST023F - OR GEN SRV - 407 0.0466 18,984 1201COSTB023 - OR GEN SRV, 189,674 0.0430 8,158,845 1301COSTL030 - OR LRG GEN SRV, 92,687 0.0461 4,272,414 1401COSTS028, OR GEN SERV, -1,914 1501GNSB0023 - BPA DISC, < 30 65 27,173 1601GNSB0023, OR GEN SRV, BPA, -2,344 1701GNSB0028 - OR GEN SRVC, 5 15,778 1801GNSB0028, OR GEN SRV, BPA, 1,158 917,833 1901GNSV0023, OR GEN SRV, < 30 493 2,716,922 2001GNSV0028, OR GEN SRV > 30 2 2 1,000 0.3780 756 2101GNSV023F - OR GEN SRV - 40 1 40,000 0.2267 9,066 2201GNSV023M - OR GEN SRV, 4 2,763 2301GNSV023T, OR GEN SRV, TOU 1 4,386 2401GNSV0728 - OR GEN SVC DIR 3 544,025 2501GNSV0748 - OR GEN SVC DIR 11 0.0471 518 2601HABT0023, OR HABITAT 155 5,269,124 2701LGSV0030 - OR LRG GEN SRV, 106 15,192,976 2801LGSV0048-1000KW AND OVR 194,954 5 38,990,800 0.0500 9,744,333 2901LGSV048M-LRG GEN SRVC 1 18,092 3001LNX00102-LINE EXT 80% G 131 3101LNX00105-CNTRCT $ MIN 25,234 3201LNX00120 - Line Extension 60% G 10,293 3301LNX00300 - LINE EXT 80% 199,856 3 66,618,667 0.0474 9,466,247 3401LPRS047M-PART REQ 1 869 3501NMT23135 - OR NET MTR, GEN, 1 5,790 3601NMT28135 - OR NET MTR, GEN, 4 5 800 0.1600 640 3701OALT014N-OUTD AR LGT NR -22 3801OALT014N-OUTD AR LGT 320 143 2,238 0.1352 43,249 3901OALT015N-OUTD AR LGT 52 0.0462 2,403 4001PTOU0023, OR GEN SRV, TOU

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 TOTALName 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 (b) (a) 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.

164 0.0454 7,445 101RENW0023, OR RENW USAGE 1 0.0350 35 201RENWB023 - OR RENEWABLE -99 3BPA BALANCING ACCOUNT 21 0.0620 1,303 401STDAY023 - OR DAY STD OFR, 165 0.0644 10,629 501STDAY028 - OR DAY STD OFR, 205,340 6OR GAIN ON SALE OF ASSET 405,978 7OR SB 408 RECOVERY -857,468 8OR SB 838 RECOVERY -13,854 9REV. ACCOUNTING ADJ. 249,554 10SMUD REVENUE IMPUTATIONS -28,893 0.0355 -1,026,000 11UNBILLED REVENUE 12UTAH 14,047 1308CFR00051-MTH FAC SRVCHG 1,733 2 866,500 0.0814 141,072 1408EFOP0021-ELEC FURNACE O 1,199 3 399,667 0.1189 142,548 1508EFOP021M-ELEC FURNACE O 687,733 1,181 582,331 0.0738 50,759,257 1608GNSV0006-GEN SRVC-DISTR 2,643,518 111 23,815,477 0.0442 116,750,885 1708GNSV0009-GEN SRVC-HI VO 59,315 3,645 16,273 0.0843 4,998,451 1808GNSV0023-GEN SRVC-DISTR 53,164 244 217,885 0.1006 5,347,875 1908GNSV006A-GEN SRVC-ENERG 7,397 8 924,625 0.0708 523,850 2008GNSV006B-GEN 17,270 6 2,878,333 0.0674 1,164,639 2108GNSV009A-GEN SRVC HI VO 837,489 11 76,135,364 0.0416 34,846,273 2208GNSV009M-MANL HIGH 4 1 4,000 0.4730 1,892 2308GNSV023F-GEN SRVC FIXED 1,242 30 41,400 0.0750 93,158 2408GNSV06MN-GNSV DIST VOLT 2,072 1 2,072,000 0.1007 208,656 2508GNSV09AM-MAN TOD HIVOLT 28,800 2608LNX00002-MTHLY 80% GUAR 753,230 2708LNX00004-ANNUAL 80%GUAR 57,387 2808LNX00014-80% MIN 2,944 2908LNX00017-ADV/REF&80%ANN 2,126 3008LNX00311 - LINE EXT 80% 91,742 3108LNX00300 - LINE EXT 80% PLUS 5,424 3208LNX00310 - IRR, 80% ANNUAL 1,395 504 2,768 0.2100 292,894 3308OALT007N-SECURITY AR 26 10 2,600 0.0907 2,358 3408TOSS0015-TRAF & OTHER S 11 6 1,833 0.2564 2,820 3508MONL0015-MTR OUTDONIGHT 271 1 271,000 0.0803 21,751 3608NMT06135-UT NET MTR,GEN, 85 1 85,000 0.0652 5,542 3708NMT23135-UT NET MTR, GEN, 3,514 1 3,514,000 0.1469 516,205 3808PRSV031M-BKUP MNT&SUPP 472,728 1 472,728,000 0.0390 18,433,648 3908SPCL0001 861,461 1 861,461,000 0.0299 25,718,913 4008SPCL0002

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 TOTALName 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 (b) (a) 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.

721,792 1 721,792,000 0.0362 26,133,414 108SPCL0003 241,092 1 241,092,000 0.0391 9,435,337 208SPCL0005 3,576,966 3REV. ACCOUNTING ADJ. 3,923,014 4SMUD REVENUE IMPUTATIONS 348 2 174,000 0.1097 38,191 508GNSV06AM-MNL ENERGY TOD 918,970 115 7,991,043 0.0628 57,686,601 608GNSV0008 - UT GEN SVC TOU > 58,689 7 8,384,143 0.0618 3,626,179 708GNSV008M - UT GEN SVC TOU 37,497 0.0335 1,256,000 8UNBILLED REVENUE 9WASHINGTON 1,885 95 19,842 0.0851 160,423 1002GNSB0024-WA GEN SRVC -8,196 1102GNSB0024-WA GEN SRVC DO 7 1 7,000 0.3233 2,263 1202GNSB24FP-WA GEN SVC -31 1302GNSB24FP-WA GEN SVC 16,378 367 44,627 0.0772 1,264,050 1402GNSV0024-WA GEN SRVC 33 4 8,250 0.2086 6,885 1502GNSV024F-WA GEN 121,064 118 1,025,966 0.0655 7,930,744 1602LGSV0036-WA LRG GEN SRV 670,444 32 20,951,375 0.0513 34,417,221 1702LGSV048T-WA LRG GEN SRV 122 42 2,905 0.1238 15,098 1802OALT015N-WA OUTD AR LGT 30 17 1,765 0.1428 4,283 1902OALTB15N-WA OUTD AR LGT -135 2002OALTB15N-WA OUTD AR LGT 1,799 1 1,799,000 0.1430 257,200 2102PRSV47TM-LRG PART REQMT 4,093 29 141,138 0.1032 422,382 2202LGSB0036-LRG GEN SVC IRG -18,131 2302LGSB0036-LRG GENSVC IRG -29 24ACQUISITION COMMIT-A & G CR -2,046 25BPA BALANCING ACCOUNT -1,456,657 26REV. ACCOUNTING ADJ. 80,837 27SMUD REVENUE IMPUTATIONS -510,000 28WA - CHEHALIS DEFERRAL -14,562 0.0481 -700,000 29UNBILLED REVENUE 30WYOMING 7,459 179 41,670 0.0635 473,749 3105GNS28025-GEN SVC 14,734 1,033 14,263 0.0757 1,114,868 3205GNSV0025-WY GEN SRVC 264,730 504 525,258 0.0632 16,740,816 3305GNSV0028-GEN SRVC > 15 KW 21 5 4,200 0.1223 2,568 3405GNSV025F-GEN SRVC-FL RA 1,575,373 54 29,173,574 0.0531 83,641,666 3505LGSV0046-WY LRG GEN 119,548 2 59,774,000 0.0497 5,944,882 3605LGSV046M-WY LRG GEN 1,310,345 3 436,781,667 0.0415 54,432,211 3705LGSV048M-TOU>1000KW MAN 1,308,474 10 130,847,400 0.0426 55,771,163 3805LGSV048T-LRG GENSRV TIM 45,122 3905LNX00100-LINE EXT 60% G 228,759 4005LNX00102-LINE EXT 80% G

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 TOTALName 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 (b) (a) 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.

46,426 105LNX00105-CNTRCT $ MIN G 184,865 205LNX00109-REF/NREF ADV + 85 44 1,932 0.1345 11,429 305OALT015N-OUTD AR LGT SR 870,129 5 174,025,800 0.0508 44,191,804 405PRSV033M-PART SERV REQ 62,172 5REV. ACCOUNTING ADJ. 523,920 6SMUD REVENUE IMPUTATIONS 47,766 705LNX00300 - LINE EXT 80% 11,623 805LNX00311 - LINE EXT 80% 12,655 0.0627 794,000 9UNBILLED REVENUE 1,023 32 31,969 0.0694 71,018 1005GNS28025-WY GEN SVC 2,668 272 9,809 0.0843 224,869 1105GNSV0025-WY GEN SRVC 34,076 77 442,545 0.0662 2,255,888 1205GNSV0028-GEN SVC > 15 KW 4,937 4 1,234,250 0.0534 263,562 1305GNSV028M -GEN SVC > 15 KW 26,215 4 6,553,750 0.0644 1,687,664 1405LGSV0046-WY LRG GEN SRV 312,528 3 104,176,000 0.0420 13,131,323 1505LGSV048M-TOU>1000KW MAN 1,099,328 9 122,147,556 0.0433 47,549,355 1605LGSV048T-LRG GENSRV 6,096 1705LNX00102-LINE EXT 80% G 23 1805LNX00109-REF/NREF ADV 110,469 3 36,823,000 0.0458 5,060,947 1905PRSV033M-PART SERV REQ 5 3 1,667 0.2240 1,120 2009OALT207N-SECURITY AR -1,733 0.0092 -16,000 21UNBILLED REVENUE -1,131 22LESS MULTIPLE BILLINGS 23 19,445,864 10,788 1,802,546 0.0485 943,745,752 24TOTAL INDUSTRIAL SALES 25 26IRRIGATION SALES 27CALIFORNIA 60,763 1,360 44,679 0.1032 6,268,966 2806APSV0020-AG PMP SRVC 800 1 800,000 0.0901 72,053 2906LGSV048T-LRG GEN SERV 1,109 3006LNX00102-LINE EXT 80% G 5,526 3106LNX00103-LINE EXT 80% G 32,953 3206LNX00110-REF/NREF ADV + 2,261 3306LNX00312 - CA IRG LINE EXT 28,501 658 43,315 0.1100 3,135,630 3406USBR0020-KLAM IRG ONPRJ 327 3506LNX00109-REF/NREF ADV + 8 0.1250 1,000 36IRRIGATION UNBILLED -184,958 37REV. ACCOUNTING ADJ. 38IDAHO 432,645 3,253 132,999 0.0729 31,523,280 3907APSA010L - IRG & Pump Large -14 4007APSA010S - IRG & PUMP BPA

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 TOTALName 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 (b) (a) 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.

4,763 409 11,645 0.0911 433,869 107APSA010S - IRG & Pump Small 82,903 785 105,609 0.0742 6,147,887 207APSAL10X - IRG & PUMP - Large 1,840 219 8,402 0.0981 180,573 307APSAS10X - IRG & PUMP - Small 31,184 80 389,800 0.0653 2,037,751 407APSVCNLL-LRG LOAD CANAL 125 18 6,944 0.1059 13,233 507APSVCNLS-SML LOAD CANAL 2,982 607BPADEBIT-BPA ADJUST FEE 4,532 707LNX00015-ANNUAL 80%GUAR 211,106 807LNX00040-ADV+REFCHG+80% 1,097 907LNX00107-SUBD ADV & AIC 6,511 1007LNX00310 80% ANNUAL 31,387 1107LNX00312 - ID LINE EXT 3,357 47 71,426 0.0829 278,453 1207APSN010L - ID LG IRR & PUMP 320 20 16,000 0.0879 28,142 1307APSN010S - IRRIGATION, 4 2 2,000 0.2048 819 1407APSNS10X - IRRIGATION, -1,149,332 15IRRIGATION BPA BAL ACCT 87 0.0690 6,000 16UNBILLED REV - IRRIGATION 17OREGON 4,702 1,800,072 1801APSV0041-AG PMP SRVC BP -175,195 1901APSV0041-AG PMP SRVC BP 1,058 2,432,864 2001APSV041L-OR Pumping Serv -294,717 2101APSV041L-OR Pumping Serv -2,480 2201APSV041T - AGR PUMP SRV 58 25,685 2301APSV041T - AGR PUMP 256 85,403 2401APSV041X-AG PMP SRVC 63 224,729 2501APSV41XL-OR Pumping Serv no 28,605 2601BPADEBIT-BPA ADJUST FEE 108,450 0.0459 4,972,929 27 6,048 0.0414 250,337 2801COST0048 - 01LGSV0048 279 0.0463 12,913 2901COSTS028, OR GEN SERV, 2 9,124 3001GNSV0028, OR GEN SRV > 30 3 0.0470 141 3101HABIT041 - 01APSV0041 AG -28,365 3201LGSB0048 - LG GEN SVC > 1 77,312 3301LGSB0048 - LG GEN SVC > 15,846 3401LNX00103-LINE EXT 80% G 9,901 3501LNX00109-REF/NREF ADV + 155,647 3601LNX00110-REF/NREF ADV + 2,896 3701LNX00310-LINE EXTENSION 546 0.0415 22,668 3801PTOU0041 - 01APSV0041 AG 97 0.0462 4,480 3901RENEW041 - 01APSV0041 AG 181,173 4001SLX00005-KLAMATH FALLS

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 TOTALName 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 (b) (a) 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.

8,626 101SLX00013-K FALLS IRG MI 1,556 201SLX00014-K FALLS IRG MI 35 0.0618 2,162 301STDAY041 - Daily Standard Offer -57 401USBGV033-KLAMATH IRG TOU 43,991 640 68,736 0.0338 1,485,667 501USBOF033-KLAMATH BASIN -169,715 601USBOF033-KLAMATH BASIN 47,229 1,375 34,348 0.0311 1,468,399 701USBON033-KLAMATH BASIN -181,356 801USBON033-KLAMATH BASIN 2,008 10 200,800 0.0217 43,528 901USBGV033-IRG TOU W/O BPA 51,940 10IRRIGATION BPA BAL ACCT -118 0.0932 -11,000 11IRRIGATION UNBILLED 13,458 1201LNX00312 - OR IRG LINE EXT 6 1 6,000 0.0290 174 1301NMT33135 - OR NET MTR - -22 1401NMT33135 - NETMTR AG PMP 1 162 1501NMT41135 - NETMTR AG PMP 15,494 16OR GAIN ON SALE OF ASSET 11,597 17OR Irrigation - BPA adjustment 33,130 18OR SB408 RECOVERY -84,044 19OR SB 838 RECOVERY 1 20REV. ACCOUNTING ADJ. 21UTAH 191,267 2,662 71,851 0.0614 11,752,335 2208APSV0010-IRR & SOIL DRA 15,013 94 159,713 0.0587 880,706 2308APSV10NS- Irg Soil Drain Pump N 842 2408LNX00002-MTHLY 80% GUAR 9,123 2508LNX00004-ANNUAL 80%GUAR 1,998 2608LNX00014-80% MIN MNTHLY 153,527 2708LNX00017-ADV/REF&80%ANN 11,601 2808LNX00310 - IRR, 80% ANNUAL 9,728 2908LNX00312 UT IRG LINE EXT 15 1 15,000 0.0807 1,211 3008NMT10135-UT IRR_SOIL DRNG 138,166 31REV. ACCOUNTING ADJ. 90 0.0333 3,000 32UNBILLED REV - IRRIGATION 33WASHINGTON 128,040 4,580 27,956 0.0733 9,382,914 3402APSV0040-WA AG PMP SRVC -566,728 3502APSV0040-WA AG PMP SRVC 22,420 703 31,892 0.0727 1,631,029 3602APSV040X-WA AG PMP SRVC 12,958 3702BPADEBIT-BPA ADJUST FEE 805 3802LNX00102-LINE EXT 80% G 5,541 3902LNX00103-LINE EXT 80% G 30 4002LNX00105-CNTRCT $ MIN G

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 TOTALName 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 (b) (a) 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.

129,070 102LNX00110-REF/NREF ADV + 1,569 202LNX00310-IRG, 80% ANN MIN + 49 302LNX00311 - LINE EXT 80% 12,626 402LNX00312 - WA IRG LINE EXT 6 502ZZMERGCR-MERGER CREDITS -356,266 6REV. ACCOUNTING ADJ. -120,000 7WA - CHEHALIS DEFERRAL -2,706 8IRRIGATION BPA BAL ACCT 151 0.0662 10,000 9IRRIGATION UNBILLED 10WYOMING 17,447 633 27,562 0.0732 1,276,733 1105APS00040-AG PUMPING SVC 59,697 1205LNX00110-REF/NREF ADV + 8,519 1305LNX00103-LINE EXT 80% G 351 1405LNX00310 - WY IRG LINE EXT 377 1505LNX00312 - WY IRG LINE EXT -16 0.0625 -1,000 16IRRIGATION UNBILLED 28 1 28,000 0.0650 1,820 1705APS00040-AG PUMPING SVC 1,958 1805LNX00103-LINE EXT 80%G 14,667 1905LNX00110-REF/NREF ADV + 3,260 70 46,571 0.0754 245,862 2009APSV0210-IRR & SOIL DRA -697 21LESS MULTIPLE BILLINGS 22 1,233,589 23,066 53,481 0.0700 86,306,929 23TOTAL IRRIGATION SALES 24 25PUBLIC STREET & HWY LIGHTING 26CALIFORNIA 1,441 120 12,008 0.1221 175,930 2706CUSL053F-SPECIAL CUST O 242 23 10,522 0.1404 33,988 2806CUSL058F-CUST OWND STR 692 78 8,872 0.2475 171,246 2906HPSV0051-HI PRESSURE SO -8,830 30REV.ACCOUNTING ADJ. -34 0.1765 -6,000 31UNBILLED REVENUE 32IDAHO 152 25 6,080 0.0985 14,967 3307GNSV023S-ID TRAFFIC 100 29 3,448 0.4424 44,235 3407SLCO0011-STR LGT CO-OWN 247 17 14,529 0.1064 26,286 3507SLCU012E-ENGY STR 1,930 281 6,868 0.1891 364,957 3607SLCU012F-FULL MNT STR 192 16 12,000 0.1377 26,435 3707SLCU012P-PART MNT STR LGT -38 0.1579 -6,000 38UNBILLED REVENUE 39OREGON 943 60 15,717 0.1294 122,013 4001COSL0052-STR LGT SRVC C

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 TOTALName 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 (b) (a) 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.

815 70 11,643 0.0713 58,101 101CUSL0053-CUS-OWNED MTRD 8,441 166 50,849 0.0716 604,207 201CUSL053E-STR LGT SVC 261 21 12,429 0.1071 27,956 301CUSL053F-STR LGT SRVC C 17,751 699 25,395 0.2086 3,702,764 401HPSV0051-HI PRESSURE SO 1 31 501LEDSL055-OR LED PIOT 9,422 259 36,378 0.1283 1,208,653 601MVSL0050-MERC VAPSTR LG 4 4 1,000 0.1983 793 701OALT014N-OUTD AR LGT NR -18 801OALT014N-OUTD AR LGT NR 9 4 2,250 0.1661 1,495 901OALT015N-OUTD AR LGT NR 2,554 10OR GAIN ON SALE OF ASSET 5,014 11OR SB408 RECOVERY -8,905 12OR SB 838 RECOVERY 1 13REV. ACCOUNTING ADJ. -443 0.0813 -36,000 14UNBILLED REVENUE 15UTAH 54 1608CFR00012-STR LGTS (CONV 4,529 1708CFR00051-MTH FAC SRVCHG 79 1808CFR00062-STREET LIGHTS 13 10 1,300 0.2892 3,759 1908OALT007N-SECURITY AR LG 1,159 123 9,423 0.0760 88,101 2008TOSS015F-TRAFFIC SIG NM 20,490 969 21,146 0.2933 6,008,760 2108SLCO0011-STR LGT CO-OWN 2,911 1,504 1,936 0.0970 282,499 2208TOSS0015-TRAF & OTHER S 1,023 57 17,947 0.0795 81,307 2308MONL0015-MTR OUTDONIGHT 5,721 240 23,838 0.1230 703,896 2408SLCU012P-STR LGT CUST-O 2,706 121 22,364 0.1367 369,890 2508SLCU012F-STR LGT CUST-O 45,193 446 101,330 0.0657 2,967,340 2608SLCU012E-DECOR CUST-OWN 141 1 141,000 0.1225 17,277 2708THIK0077-STR LIGHT SPEC 276,332 28REV. ACCOUNTING ADJ. 1,152 0.0938 108,000 29UNBILLED REVENUE 30WASHINGTON 91 3102CFR00012-STR LGTS (CONV 406 19 21,368 0.1434 58,221 3202COSL0052-WA STR LGT SRV 3,589 105 34,181 0.0681 244,583 3302CUSL053F-WA STR LGT SRV 1,172 93 12,602 0.0672 78,805 3402CUSL053M-WA STR LGT SRV 3,216 152 21,158 0.1846 593,553 3502HPSV0051-WA HI PRESSURE 1,994 45 44,311 0.1187 236,627 3602MVSL0057-WA MERC VAPSTR -30,000 37WA - CHEHALIS DEFERRAL -23,544 38REV. ACCOUNTING ADJ. 648 0.1219 79,000 39UNBILLED REVENUE 40WYOMING

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 TOTALName 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 (b) (a) 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.

317 21 15,095 0.2004 63,540 105COSL0057-CO-OWND STR LG 74 11 6,727 0.0616 4,557 205CUSL058M-CUST OWND STR 1,083 31 34,935 0.0619 66,985 305CUSL0E58-WY CUST OWND 49 4 12,250 0.0760 3,724 405CUSL0M58-CUST OWNED 4,808 156 30,821 0.2056 988,331 505HPSV0051-HI PRESSURE SO 3,843 259 14,838 0.1248 479,615 605MVS00053-MERCURY VAPOR 400 7REV. ACCOUNTING ADJ. -160 0.1625 -26,000 8UNBILLED REVENUE 29 1 29,000 0.0758 2,197 909MONL0213-WY MTR OUTDOOR 1,335 49 27,245 0.2915 389,145 1009SLCO0211-STR LGT CO-OWN 72 9 8,000 0.1560 11,231 1109SLCUP212-STR LGT CUST-O 67 14 4,786 0.0389 2,604 1209TOSS0213-TRAF & OTHER S -146 0.3493 -51,000 13UNBILLED REVENUE -2,445 14LESS MULTIPLE BILLINGS 15 145,032 3,868 37,495 0.1421 20,610,361 16TOTAL PUBLIC STREET & HWY 17 18OTHER SALES TO PUBLIC AUTH 19UTAH 2,355 4 588,750 0.0652 153,647 2008GNSV0006-GEN SRVC-DISTR 29 3 9,667 0.0984 2,855 2108GNSV0023-GEN SRVC-DISTR 421,143 4 105,285,750 0.0461 19,402,446 2208GNSV009M-MANL HIGH VOLT 18 2 9,000 0.2482 4,468 2308OALT007N-SECURITY AR LG 3,807 0.0544 207,000 24UNBILLED REVENUE 25 427,352 13 32,873,231 0.0463 19,770,416 26TOTAL OTHER SALES TO PUBLIC 27 28FORFEITED DISCOUNTS 29CALIFORNIA 285,011 30Late Fees 31IDAHO 406,930 32Late Fees 33OREGON 2,666,385 34Late Fees 35UTAH 2,957,255 36Late Fees 37WASHINGTON 542,237 38Late Fees 39WYOMING 554,070 40Late Fees

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 TOTALName 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 (b) (a) 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 7,411,888 2TOTAL FORFEITED DISCOUNTS 3 4MISCELLANEOUS SERVICE REV 5CALIFORNIA 1,454 606CFR00003-MTH MAINTENANC 32,380 706CONN0300-CA RECONNECTIO 53,332 806FCBUYOUT 12,096 906RCHK0300-CA RET CHK CHR 1,050 1006TAMP0300-CA TAMP & UNAU 1,870 1106TEMP0300-CA TEMP SRVC C 288 1206XMTRTAMP-TAMPERING - 1,003 13Home Comfort -4,185 14Other 15IDAHO 1,682 1607CFR00001-MTH FAC SRVCHG 46,055 1707CONN0300-ID RECONNECTIO 37,980 1807RCHK0300-ID RET CHK CHR 1,275 1907TAMP0300 9,380 2007TEMP0014-TEMP SRVC CONN 121 2107XMTRTAMP-TAMPERING - 146 22Weatherization Loans ID 4,350 23Other 24OREGON 61,661 2501CFR00001-MTH FACILITY S 25,964 2601CFR00003-MTH MAINTENANC 22,439 2701CFR00004-EMRGNCY ST&BY 41,861 2801CFR00005-INTERMTNT 2,284 2901CFR00013-MTH MISC CHRG 5 3001CFR00014-YR MISC CHRG 316,525 3101CONN0300-RECONNECTION C 2,093 3201CONTSERV-OR 3RD PARTY 6,000 3301DPAC0300-DEMAND PULSE 90 3401ESSC0600 - ESS charges 260,885 3501FCBUYOUT-FAC CHG BUYOUT -34,997 3601LNX00109-REF/NREF ADV + 20 3701MTRVR300-METR VERIF FEE 5 38010RRA0300-OR RETAIL ACCESS 290,980 3901RCHK0300-RETURNED CHECK 12,975 4001TAMP0300-TAMP & UNAUTH

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 TOTALName 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 (b) (a) 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.

77,875 101TEMP0300-TEMP SRVC CHRG 12,654 201XMTRTAMP-TAMPERING - 21,358 3Other 4UTAH 148,885 508CFR00013-MTH MISC CHRG 107,746 608CFR00051-MTH FAC SRVCHG 424 708CFR00052-ANN FAC SVCCHG 11,272 808CFR00053-MTHLY MAINTFEE 2,408 908CFR00063-MTH MISC CHARG 6,660 1008CFR00064-ANN MISC CHARG 329,135 1108CONN0300-RECONN&DISCONN 285,840 1208CONTSERV-3RD PARTY O/S 186,556 1308FCBUYOUT-FAC CHG BUYOUT 6,760 1408NCON0300-UT FEE NRES RE 464,220 1508RCHK0300-UT RET CHK CHR 1,541,400 1608RCON0001-CONNECT FEE 18,000 1708TAMP0300-TAMPERING&UNAU 297,285 1808TEMP0014-TEMP SRVC CONN -11 1908UPPL000N-BASE SCH FALL 5,705 2008XMTRTAMP-TAMPERING - 430 21Energy Finanswer 12,000 23,631 22Energy Finanswer new Com -31,066 23Other 281,590 2408VISIT300 - UT Visit, Service Ca 25WASHINGTON 1,320 2602CFR00003-MTH MAINTENANC 5,879 2702CFR00004-EMRGNCY ST&BY 4,302 2802CFR00005-INTERMTNT SRVC 58,130 2902CONN0300-WA RECONNECTIO 22,397 3002FCBUYOUT - FAC CHG BUYOUT 57,660 3102RCHK0300-WA RET CHK CHR 4,650 3202TAMP0300-WA TAMP & UNAU 16,325 3302TEMP0300-WA TEMP SRVC C 2,571 3402XMTRTAMP-TAMPERING - 2,784 35Energy Finanswer new Com 3,148 36Home Comfort -7,674 37Other 38WYOMING 7,510 3905CFR00003-MTH MAINTENANC 18,891 4005CFR00004-EMRGNCY ST&BY

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 TOTALName 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 (b) (a) 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.

9,943 105CFR00005-INTERMTNT SRVC 3,186 205CFR00013-MTH MISC CHRG 63,560 305CONN0300-WY RECONNECTIO 294,099 405FCBUYOUT - FAC CHG BUYOUT 69,000 505RCHK0300-WY RET CHK CHR 120 605SERV0300-WY SRVC CALLS 1,650 705TAMP0300 27,430 805TEMP0300-WY TEMP SRVC C -2,985 9Other 170 1005XMTRTAMP-TAMPERING - 339 1109CFR00005-INTERMTNT SRVC 13,300 1205CONN0300-WY RECONNECTIO 215,167 1305FCBUYOUT - FAC CHG BUYOUT 11,670 1405RCHK0300-WY RET CHK CHR 150 1505TAMP0300 1,360 1605TEMP0300-WY TEMP SRVC C 27 1705XMTRTAMP-TAMPERING - 5,067 1809CFR00001-MTH FAC SRVCHG 301 19Energy Finanswer 12,000 20 5,919,271 21TOTAL MISC SERVICE REV 22 23SALES OF WATER AND WTR PWR 1,609 24UTAH 1,000 25WYOMING 2,609 26TOTAL WATER AND WATER PWR 27 28RENT FROM ELEC PROPERTIES 29CALIFORNIA 1,710 3006CFR00006-MTH RNTAL CHRG 17,693 31Rent Revenue - Subleases 531,229 32Joint use 33IDAHO 730 3407CFR00009-YR LSE CHRG-EQ 178 3507INVCHG00-INVEST MNT CHG 210 3607LOOP0014-MTH FEE PRE-AS 276 3707POLE0075-STEEL POLES US 34,369 3807XTRN0013-RNT/LSE L& PRO 66,682 39RENT REVENUE-HYDRO 900 40RENT REV-TRANSMISS

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 TOTALName 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 (b) (a) 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.

300 1RENT REV-DISTRIBUT 2,216 2Rent Revenue - Subleases 172,973 3Joint use 4OREGON 600,081 501CFR00006-MTH RNTAL CHRG 462,545 6RENTS - COMMON 25 7Rents - Non Common 3,350,038 8MCI FOGWIRE REVENUE 335,325 9Rent Revenue - Subleases 21,068 10RENT REVENUE-HYDRO 230,034 11RENT REV-TRANSMISS 50,979 12RENT REV-DISTRIBUT 42,260 13RENT REV-GEN(COMM) 4,492,037 14Joint use 15UTAH 33 1608CFR00056-MTH EQUIP RENT 729,329 1708CFR00058-MTH EQUIP LEAS 4,740 1808INVCHG0N-INVEST MNT CHG 283 1908INVCHG0R-INVEST MNT CHG 2,736 2008LOOP014N-TEMP SERV CONN 59,537 2108POLE0075-STEEL POLES US 56,388 2208XTRN0013-RNT/LSE L& PRO -20,446 23RENTS - COMMON 9,174 24Rents - Non Common 90,946 25RENT REVENUE-STEAM 86,704 26RENT REVENUE-HYDRO 840,373 27RENT REV-TRANSMISS 431,916 28RENT REV-DISTRIBUT 6,691 29RENT REV-GEN(COMM) 2,464,310 30Rent Revenue - Subleases 2,152,980 31Joint use 32WASHINGTON 2,104 3302CFR00001-MTH FACILITY S 29,871 3402CFR00006-MTH RNTAL CHRG 641,359 35RENT REVENUE-HYDRO 17,233 36RENT REV-DISTRIBUT 39,573 37RENT REV-GEN(COMM) 7,517 38RENT REV-TRANSMISS 45,245 39Rent Revenue - Subleases 999,785 40Joint use

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 TOTALName 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 (b) (a) 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.

1WYOMING 11,524 205CFR00001-MTH FACILITY S 2,482 305CFR00006-MTH RNTAL CHRG 66,695 4RENT REVENUE-STEAM 850 5RENT REV-TRANSMISS 7,814 6RENT REV-DISTRIBUT -6,947 7RENT REV-GEN(COMM) 15,912 8Rent Revenue - Subleases 309,340 9Joint use 62 1009LOOP0214-MTH FEE PRE-AS 17,403 1109POLE0075-STEEL POLES US 7,062 12RENT REVENUE-STEAM 14,660 13Joint use 14 19,559,096 15TOTAL RENT FROM ELEC PROP 16 7,281,432 17WIND BASED ANCILLARY SVC 5,339 18ELEC INC-OTHR -597,217 19OTHER ELEC ESTIMATE 93,760,900 20RENEWABLE ENERGY CREDIT 8,951,958 21NON-WHEELING SYSTEM 678,251 22Other Elec (exclud Wheel) 23CALIFORNIA 119,595 24ALL BLUE SKY RES 111 2507XTRN0011-SALE ORDERS 865,247 26DSM REV-CA SBC OFF 6,190 27Fish, Wildlife, Recr 28IDAHO 83,377 29ALL BLUE SKY RES 5,939,833 30DSM REV-ID SBC -71 31Other Elec (exclud Wheel) 32OREGON 1,110,611 33ALL BLUE SKY RES 67,699 34M&S INVENTORY REVENUE 281,550 353RD PARTY TRANS 18,762,568 36DSM REVENUE - OREGON ECC 1,564,645 37Other Elec (exclud Wheel) 236,371 38Other Elec DSR carry chrg 39UTAH 2,473,756 40ALL BLUE SKY RES

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 TOTALName 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 (b) (a) 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.

385,196 1M&S INVENTORY REVENUE 89,749 2ELEC INC-OTHR 1,735,998 3FLYASH SALES 150,755 43RD PARTY TRANS 62,981,154 5DSM REV-UT SBC OFFSET 2,280 6Fish, Wildlife, Recr -828 7other Elec (exclud Wheel) 8WASHINGTON 159,211 9ALL BLUE SKY RES 8,855,002 10DSM REVENUE - WA SBC 123 11Other Elec (exclud Wheel) 18,060 12Fish, Wildlife, Recr -52,188 13Wash Colstrip 3 14WYOMING 220,490 15ALL BLUE SKY RES 21,493 16M&S INVENTORY REVENUE 910,611 17FLYASH SALES 239,529 18WY Regulatory Recovery Fee 62,482 193RD PARTY TRANS 701,985 20DSM REVENUE - WY SBC - CAT 1 795,949 21DSM REVENUE - WY SBC - CAT 2 545,133 22DSM REVENUE - WY SBC - CAT 3 12,212 23FLYASH SALES 215,502 24DSM REVENUE - WY SBC - CAT 1 131,341 25DSM REVENUE - WY SBC - CAT 2 301,427 26DSM REVENUE - WY SBC - CAT 3 9 27Other Elec (exclud Wheel) 220,074,820 28TOTAL OTHER ELEC REVENUE 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)XAn 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 450.1Name 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

(c) (b) (a) 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 DemandMonthly 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.

Requirement Sales 1 Brigham City 17 19 19 T-12 RQ 2 Deaver, Town of 0.1 0.1 0.2 T-4 RQ 3 Helper City 11 1 T-6 RQ 4 Helper City Annex 0.6 0.6 0.7 T-6 RQ 5 Navajo Tribal Util Auth (Mexican Hat) 0.2 0.2 0.2 T-6 RQ 6 Navajo Tribal Util Auth (Red Mesa) 11 1 T-6 RQ 7 Portland General Electric Company NA NA NA 147 RQ 8 Price City 12 12 13 T-12 RQ 9 Accrual True-up NA NA NA NA RQ 10 11 Nonrequirement Sales 12 Anaheim, City of NA NA NA T-12 SF 13Arizona Public Service Company NA NA NA T-12 AD 14

FERC FORM NO. 1 (ED. 12-90) Page 310 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Arizona Public Service Company NA NA NA T-12 SF 1 Avista Corporation NA NA NA T-13 SF 2 Avista Corporation NA NA NA T-12 SF 3 BP Energy Company NA NA NA T-12 SF 4 Barclays Bank PLC NA NA NA T-12 AD 5 Barclays Bank PLC NA NA NA T-12 SF 6 Basin Electric Power Cooperative NA NA NA T-11 AD 7 Basin Electric Power Cooperative NA NA NA T-11 LF 8 Basin Electric Power Cooperative NA NA NA T-12 OS 9 Basin Electric Power Cooperative NA NA NA T-11 SF 10 Basin Electric Power Cooperative NA NA NA T-12 SF 11 Black Hills Power, Inc. 48 50 50 441 LF 12 Black Hills Power, Inc. NA NA NA T-12 OS 13 Black Hills Power, Inc. NA NA NA T-12 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.1 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Bonneville Power Administration NA NA NA 519 AD 1 Bonneville Power Administration NA NA NA T-11 AD 2 Bonneville Power Administration NA NA NA T-12 AD 3 Bonneville Power Administration NA NA NA 368 LF 4 Bonneville Power Administration NA NA NA T-11 LF 5 Bonneville Power Administration NA NA NA 519 LU 6 Bonneville Power Administration NA NA NA T-11 SF 7 Bonneville Power Administration NA NA NA T-13 SF 8 Bonneville Power Administration NA NA NA T-12 SF 9 British Columbia Transmission Corp. NA NA NA T-13 SF 10 California Independent System Operator NA NA NA T-12 AD 11 California Independent System Operator NA NA NA T-12 SF 12 Cargill Power Markets, LLC NA NA NA T-12 AD 13 Cargill Power Markets, LLC NA NA NA T-11 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.2 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Cargill Power Markets, LLC NA NA NA T-12 SF 1 Citigroup Energy, Inc. NA NA NA T-12 AD 2 Citigroup Energy, Inc. NA NA NA T-12 SF 3 City of Burbank NA NA NA T-12 SF 4 City of Redding NA NA NA T-12 SF 5 Clatskanie People's Utility District NA NA NA T-12 SF 6 Colorado Springs Utilities NA NA NA T-12 OS 7 Colorado Springs Utilities NA NA NA T-12 SF 8 ConocoPhillips Company NA NA NA T-12 SF 9 Constellation Energy Commodities Group NA NA NA T-11 SF 10 Constellation Energy Commodities Group NA NA NA T-11 SF 11 Constellation Energy Commodities Group NA NA NA T-12 SF 12 Credit Suisse Energy LLC NA NA NA T-12 AD 13 Credit Suisse Energy LLC NA NA NA T-12 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.3 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

DB Energy Trading LLC NA NA NA T-12 AD 1 DB Energy Trading LLC NA NA NA T-12 SF 2 Deseret Power Electric Cooperative NA NA NA T-11 SF 3 EDF Trading North America, LLC NA NA NA T-12 SF 4 El Paso Electric Company NA NA NA T-12 SF 5 Endure Energy, LLC NA NA NA T-12 SF 6 Eugene Water & Electric Board NA NA NA T-11 SF 7 Eugene Water & Electric Board NA NA NA T-12 SF 8 Gila River Power, L.P. NA NA NA T-12 AD 9 Gila River Power, L.P. NA NA NA T-11 SF 10 Gila River Power, L.P. NA NA NA T-12 SF 11 Glendale, City of NA NA NA T-12 SF 12 Hurricane, City of NA NA NA T-12 LF 13 Iberdrola Renewables, Inc. NA NA NA T-11 LF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.4 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Iberdrola Renewables, Inc. NA NA NA T-11 SF 1 Iberdrola Renewables, Inc. NA NA NA T-12 SF 2 Idaho Power Company NA NA NA T-11 LF 3 Idaho Power Company NA NA NA T-11 SF 4 Idaho Power Company NA NA NA T-13 SF 5 Idaho Power Company NA NA NA T-12 SF 6 Intermountain Renewable Power, LLC NA NA NA T-11 LF 7 Intermountain Renewable Power, LLC NA NA NA T-11 LF 8 J. Aron & Company NA NA NA T-12 SF 9 JP Morgan Ventures Energy Corporation NA NA NA T-12 AD 10 JP Morgan Ventures Energy Corporation NA NA NA T-11 SF 11 JP Morgan Ventures Energy Corporation NA NA NA T-12 SF 12 Los Angeles Dept. of Water & Power NA NA NA 301 LU 13 Los Angeles Dept. of Water & Power NA NA NA T-11 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.5 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Los Angeles Dept. of Water & Power NA NA NA T-12 SF 1 Macquarie Energy LLC NA NA NA T-11 SF 2 Macquarie Energy LLC NA NA NA T-12 SF 3 Metropolitan Water District of S. Cal. NA NA NA T-12 SF 4 Modesto Irrigation District NA NA NA T-12 SF 5 Morgan Stanley Capital Group, Inc. NA NA NA T-12 AD 6 Morgan Stanley Capital Group, Inc. NA NA NA T-11 SF 7 Morgan Stanley Capital Group, Inc. NA NA NA T-12 SF 8 Municipal Energy Agency of Nebraska NA NA NA T-11 SF 9 Municipal Energy Agency of Nebraska NA NA NA T-12 SF 10 Nevada Power Company NA NA NA T-12 IF 11 NextEra Energy Power Marketing, LLC NA NA NA T-11 AD 12 NextEra Energy Power Marketing, LLC NA NA NA T-11 LF 13 NextEra Energy Power Marketing, LLC NA NA NA T-11 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.6 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

NextEra Energy Power Marketing, LLC NA NA NA T-12 SF 1 NorthWestern Corporation NA NA NA T-13 SF 2 NorthWestern Corporation NA NA NA T-12 SF 3 Northern California Power Agency NA NA NA T-12 SF 4 Northpoint Energy Solutions Inc. NA NA NA T-12 SF 5 PPL EnergyPlus, LLC NA NA NA T-12 SF 6 PPL Montana, LLC NA NA NA T-11 SF 7 Pacific Gas & Electric Company NA NA NA T-12 IF 8 Pacific Gas & Electric Company NA NA NA T-12 SF 9 Pacific Northwest Generating Coop. NA NA NA T-12 SF 10 Pacific Summit Energy LLC NA NA NA T-12 SF 11 Portland General Electric Company NA NA NA T-11 SF 12 Portland General Electric Company NA NA NA T-12 SF 13 Portland General Electric Company NA NA NA T-13 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.7 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Powerex Corporation NA NA NA T-12 AD 1 Powerex Corporation NA NA NA T-11 LF 2 Powerex Corporation NA NA NA T-11 SF 3 Powerex Corporation NA NA NA T-12 SF 4 Public Service Company of Colorado NA NA NA 320 AD 5 Public Service Company of Colorado 59 65 71 320 LF 6 Public Service Company of Colorado NA NA NA T-11 SF 7 Public Service Company of Colorado NA NA NA T-12 SF 8 Public Service Company of New Mexico NA NA NA T-12 SF 9 PUD #1 of Snohomish County NA NA NA T-12 SF 10 PUD #2 of Grant County NA NA NA T-13 SF 11 PUD #2 of Grant County NA NA NA T-12 SF 12 Puget Sound Energy, Inc. NA NA NA T-13 SF 13 Puget Sound Energy, Inc. NA NA NA T-12 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.8 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Rainbow Energy Marketing Corporation NA NA NA T-11 SF 1 Rainbow Energy Marketing Corporation NA NA NA T-12 SF 2 Sacramento Municipal Utility District NA NA NA 250 AD 3 Sacramento Municipal Utility District NA NA NA 250 LF 4 Sacramento Municipal Utility District NA NA NA T-13 SF 5 Sacramento Municipal Utility District NA NA NA T-12 SF 6 Salt River Project NA NA NA T-12 IF 7 Salt River Project NA NA NA T-11 SF 8 Salt River Project NA NA NA T-12 SF 9 San Diego Gas & Electric Company NA NA NA T-12 AD 10 San Diego Gas & Electric Company NA NA NA T-12 IF 11 San Diego Gas & Electric Company NA NA NA T-12 SF 12 Santa Clara, City of NA NA NA T-12 SF 13 Seattle City Light NA NA NA T-11 LF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.9 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Seattle City Light NA NA NA T-11 SF 1 Seattle City Light NA NA NA T-13 SF 2 Seattle City Light NA NA NA T-12 SF 3 Sempra Energy Trading LLC NA NA NA T-12 AD 4 Sempra Energy Trading LLC NA NA NA T-12 SF 5 Sempra Generation NA NA NA T-12 SF 6 Shell Energy North America (US), L.P. NA NA NA T-12 AD 7 Shell Energy North America (US), L.P. NA NA NA T-12 OS 8 Shell Energy North America (US), L.P. NA NA NA T-11 SF 9 Shell Energy North America (US), L.P. NA NA NA T-12 SF 10 Sierra Pacific Power Company NA NA NA T-11 LF 11 Sierra Pacific Power Company NA NA NA T-11 SF 12 Sierra Pacific Power Company NA NA NA T-13 SF 13 Southern California Edison Company NA NA NA T-12 IF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.10 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Southern California Edison Company NA NA NA T-11 SF 1 Southern California Edison Company NA NA NA T-11 SF 2 Southern California Edison Company NA NA NA T-12 SF 3 Southwestern Public Service Company NA NA NA T-12 SF 4Tacoma Power NA NA NA T-13 SF 5 Tacoma Power NA NA NA T-12 SF 6 The Energy Authority NA NA NA T-11 SF 7The Energy Authority NA NA NA T-12 SF 8 TransAlta Energy Marketing Inc. NA NA NA T-12 IF 9 TransAlta Energy Marketing Inc. NA NA NA T-11 SF 10 TransAlta Energy Marketing Inc. NA NA NA T-12 SF 11 TransCanada Energy Sales Ltd. NA NA NA T-12 SF 12 Tri-State Gen. & Trans. NA NA NA T-11 SF 13Tri-State Gen. & Trans. 0.1 0.4 0.4 T-12 SF 14

FERC FORM NO. 1 (ED. 12-90) Page 310.11 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Tucson Electric Power Company NA NA NA T-12 SF 1 Turlock Irrigation District NA NA NA T-12 SF 2 UNS Electric, Inc. NA NA NA T-12 SF 3 Utah Associated Municipal Power Systems NA NA NA T-12 OS 4 Utah Associated Municipal Power Systems NA NA NA T-11 SF 5 Utah Associated Municipal Power Systems NA NA NA T-12 SF 6 Utah Municipal Power Agency 34 34 34 433 LF 7 Utah Municipal Power Agency NA NA NA T-3 SF 8 Western Area Power Administration NA NA NA T-11 AD 9 Western Area Power Administration NA NA NA T-11 LF 10 Western Area Power Administration NA NA NA T-11 SF 11 Western Area Power Administration NA NA NA T-12 SF 12 Test Generation NA NA NA NA AD 13 Bookout Sales NA NA NA NA AD 14

FERC FORM NO. 1 (ED. 12-90) Page 310.12 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name 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

(c) (b) (a) 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 DemandMonthly 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.

Trade Sales NA NA NA NA IF 1 Accrual True-up NA NA NA NA NA 2 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
0Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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 2,384,916 1,968,417 4,353,333 111,872 2 17,761 15,734 33,495 988 3 114,594 118,283 232,877 6,480 4 66,920 72,379 139,299 3,783 5 21,818 21,717 43,535 1,253 6 152,041 133,792 285,833 8,728 7 1,021,053 5,006 1,026,059 11,214 8 1,576,451 1,287,308 2,863,759 74,337 9 62,547 62,547 2,197 10 11 12 238,700 238,700 6,200 13 12,800 12,800 400 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

915,108 915,108 25,328 1 2,254 2,254 57 2 1,651,335 1,651,335 51,725 3 598,764 598,764 19,368 4 20,568 20,568 409 5 38,439,814 38,439,814 620,313 6 91,095 91,095 2,991 7 9,766 9,766 232 8 3,582 3,582 78 9 39,915 39,915 1,116 10 5,054,254 5,054,254 138,207 11 5,662,460 7,310,280 12,972,740 352,993 12 217,404 217,404 6,037 13 3,104,002 3,104,002 82,726 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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 1 216 216 5 2 120,206 120,206 3 61,133 61,133 1,850 4 90,898 90,898 2,571 5 2,614,039 2,614,039 35,570 6 25 25 1 7 336 336 8 8 2,826,672 2,826,672 81,992 9 549 549 21 10 112,274 112,274 170 11 12,480,046 12,480,046 408,091 12 44,817 44,817 2,022 13 196,574 196,574 6,754 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

42,447,033 42,447,033 1,116,467 1 14,111 14,111 166 2 48,006,404 48,006,404 933,729 3 682,800 682,800 19,800 4 553,579 553,579 15,043 5 2,712 2,712 72 6 2,960 2,960 160 7 6,478 6,478 335 8 2,005,952 2,005,952 56,256 9 17,987 17,987 512 10 2,064 2,064 55 11 3,434,253 3,434,253 95,659 12 20,012 20,012 151 13 2,888,900 2,888,900 43,400 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

136 136 17 1 35,081,629 35,081,629 596,590 2 1,305 1,305 39 3 14,962,652 14,962,652 423,350 4 513,122 513,122 12,407 5 294,285 294,285 7,380 6 4,707 4,707 140 7 357,676 357,676 10,995 8

-1 9 940 940 31 10 3,743,525 3,743,525 105,390 11 92,000 92,000 3,000 12 15,150 15,150 202 13 95,640 95,640 2,884 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

51,070 51,070 1,513 1 9,679,291 9,679,291 287,727 2 90,235 90,235 2,644 3 131,365 131,365 3,581 4 24,013 24,013 715 5 425,780 425,780 11,557 6 43,199 43,199 1,411 7 24,449 24,449 629 8 1,005,662 1,005,662 28,981 9 4,426 4,426 184 10 53,987 53,987 1,881 11 5,911,745 5,911,745 145,535 12 27,947,142 27,947,142 564,732 13 58,344 58,344 1,693 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

16,841,099 16,841,099 445,890 1 1,526 1,526 58 2 2,199,869 2,199,869 62,553 3 1,859,359 1,859,359 49,975 4 530,360 530,360 12,240 5 82,161 82,161 2,825 6 251,595 251,595 7,656 7 65,086,374 65,086,374 1,395,927 8 2,883 2,883 87 9 629,545 629,545 17,060 10 33,732,523 33,732,523 996,819 11 78 78 2 12 347,368 347,368 10,897 13 8,086 8,086 275 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

43,428 43,428 1,406 1 8,595 8,595 251 2 23,943 23,943 554 3 92,460 92,460 2,134 4 4,175 4,175 95 5 1,831,155 1,831,155 53,471 6 21,898 21,898 620 7 22,907,829 22,907,829 653,474 8 159,704 159,704 4,357 9 37,325 37,325 945 10 203,200 203,200 6,800 11 12,044 12,044 369 12 2,632,681 2,632,681 78,647 13 5,820 5,820 178 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

1,000 1,000 31 1 477,737 477,737 14,932 2 389,753 389,753 13,177 3 11,590,434 11,590,434 405,582 4 -772,626 -772,626 5 21,453,044 9,295,320 30,748,364 465,388 6 35,818 35,818 1,179 7 6,832,397 6,832,397 211,075 8 5,933,724 5,933,724 154,575 9 511,530 511,530 14,140 10 314 314 8 11 530,880 530,880 15,232 12 6,720 6,720 184 13 2,658,692 2,658,692 80,059 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

36,998 36,998 1,305 1 4,381,839 4,381,839 130,568 2 -146,668 -146,668 3 13,238,167 13,238,167 551,131 4 134 134 6 5 1,843,055 1,843,055 54,683 6 913 913 25 7 20,372 20,372 708 8 2,646,978 2,646,978 82,888 9 12,058 12,058 319 10 10,831,286 10,831,286 341,410 11 71,045 71,045 3,206 12 69,095 69,095 3,390 13 69,711 69,711 2,249 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

24 24 1 1 43 43 1 2 488,987 488,987 15,006 3 22,389 22,389 491 4 21,197,505 21,197,505 403,363 5 497,016 497,016 14,000 6 6,798 6,798 91 7 4,800 4,800 100 8 875 875 24 9 41,185,881 41,185,881 901,993 10 26,442 26,442 817 11 3,531 3,531 84 12 8,438 8,438 222 13 11,148,438 11,148,438 327,600 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

47,259 47,259 1,526 1 12,832 12,832 433 2 587,480 587,480 14,130 3 1,764,174 1,764,174 45,957 4 184 184 7 5 25,175 25,175 1,375 6 39 39 1 7 354,075 354,075 9,937 8 46,545,738 46,545,738 1,314,945 9 9,358 9,358 250 10 7,921,333 7,921,333 225,794 11 404 404 15 12 645 645 19 13 6,891,467 16,991 6,908,458 206,863 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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.

5,217,828 5,217,828 136,728 1 252,416 252,416 7,987 2 6,054,106 6,054,106 190,872 3 1,748,072 1,748,072 61,410 4 4,197 4,197 142 5 34,941 34,941 875 6 5,018,399 4,396,200 9,414,599 215,938 7 67,900 67,900 1,530 8 59,501 59,501 142 9 97,482 97,482 1,633 10 99,338 99,338 5,801 11 8,482,416 8,482,416 203,267 12 -556,235 -556,235 -41,215 13 -184,282,163 -184,282,163 -5,780,963 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 24,636,421Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as 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 1 150,119 150,119 7,286 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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: bWestern 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)XAn 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)XAn 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 450.7ELECTRIC 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

1. POWER PRODUCTION EXPENSES 1 A. Steam Power Generation 2 Operation 3 (500) Operation Supervision and Engineering 4 21,376,391 20,107,030 (501) Fuel 5 620,266,055 646,729,745 (502) Steam Expenses 6 35,509,089 38,472,021 (503) Steam from Other Sources 7 3,597,576 3,655,727 (Less) (504) Steam Transferred-Cr. 8 (505) Electric Expenses 9 3,904,528 4,285,137 (506) Miscellaneous Steam Power Expenses 10 43,559,253 48,042,874 (507) Rents 11 450,415 338,685 (509) Allowances 12 TOTAL Operation (Enter Total of Lines 4 thru 12) 13 728,663,307 761,631,219 Maintenance 14 (510) Maintenance Supervision and Engineering 15 5,970,114 6,462,258 (511) Maintenance of Structures 16 22,825,065 25,480,955 (512) Maintenance of Boiler Plant 17 94,433,581 112,922,881 (513) Maintenance of Electric Plant 18 33,727,522 38,934,338 (514) Maintenance of Miscellaneous Steam Plant 19 12,681,273 12,066,167 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 169,637,555 195,866,599 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 898,300,862 957,497,818 B. Nuclear Power Generation 22 Operation 23 (517) Operation Supervision and Engineering 24 (518) Fuel 25 (519) Coolants and Water 26 (520) Steam Expenses 27 (521) Steam from Other Sources 28 (Less) (522) Steam Transferred-Cr. 29 (523) Electric Expenses 30 (524) Miscellaneous Nuclear Power Expenses 31 (525) Rents 32 TOTAL Operation (Enter Total of lines 24 thru 32) 33 Maintenance 34 (528) Maintenance Supervision and Engineering 35 (529) Maintenance of Structures 36 (530) Maintenance of Reactor Plant Equipment 37 (531) Maintenance of Electric Plant 38 (532) Maintenance of Miscellaneous Nuclear Plant 39 TOTAL Maintenance (Enter Total of lines 35 thru 39) 40 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41 C. Hydraulic Power Generation 42 Operation 43 (535) Operation Supervision and Engineering 44 9,385,219 3,825,666 (536) Water for Power 45 290,209 212,409 (537) Hydraulic Expenses 46 3,518,610 3,449,509 (538) Electric Expenses 47 (539) Miscellaneous Hydraulic Power Generation Expenses 48 15,385,413 20,295,293 (540) Rents 49 183,444 117,398 TOTAL Operation (Enter Total of Lines 44 thru 49) 50 28,762,895 27,900,275 C. Hydraulic Power Generation (Continued) 51 Maintenance 52 (541) Mainentance Supervision and Engineering 53 84,358 469 (542) Maintenance of Structures 54 1,207,112 1,430,392 (543) Maintenance of Reservoirs, Dams, and Waterways 55 1,600,540 1,959,700 (544) Maintenance of Electric Plant 56 1,515,716 1,635,171 (545) Maintenance of Miscellaneous Hydraulic Plant 57 2,539,316 2,654,790 TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 6,947,042 7,680,522 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 35,709,937 35,580,797

FERC FORM NO. 1 (ED. 12-93) Page320ELECTRIC 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

D. Other Power Generation 60 Operation 61 (546) Operation Supervision and Engineering 62 316,964 358,628 (547) Fuel 63 461,743,015 432,620,733 (548) Generation Expenses 64 15,739,485 14,638,002 (549) Miscellaneous Other Power Generation Expenses 65 18,635,853 18,701,556 (550) Rents 66 1,861,264 3,558,679 TOTAL Operation (Enter Total of lines 62 thru 66) 67 498,296,581 469,877,598 Maintenance 68 (551) Maintenance Supervision and Engineering 69 (552) Maintenance of Structures 70 1,544,031 1,240,594 (553) Maintenance of Generating and Electric Plant 71 14,986,840 8,996,404 (554) Maintenance of Miscellaneous Other Power Generation Plant 72 1,321,906 2,196,699 TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 17,852,777 12,433,697 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 516,149,358 482,311,295 E. Other Power Supply Expenses 75 (555) Purchased Power 76 456,211,649 380,007,678 (556) System Control and Load Dispatching 77 1,514,461 877,454 (557) Other Expenses 78 49,819,215 63,870,496 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 507,545,325 444,755,628 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 1,957,705,482 1,920,145,538 2. TRANSMISSION EXPENSES 81 Operation 82 (560) Operation Supervision and Engineering 83 6,088,583 5,041,115 (561) Load Dispatching 84 650,305 (561.1) Load Dispatch-Reliability 85 (561.2) Load Dispatch-Monitor and Operate Transmission System 86 8,347,455 7,847,328 (561.3) Load Dispatch-Transmission Service and Scheduling 87 (561.4) Scheduling, System Control and Dispatch Services 88 (561.5) Reliability, Planning and Standards Development 89 816,883 (561.6) Transmission Service Studies 90 76,671 83,476 (561.7) Generation Interconnection Studies 91 899,582 938,904 (561.8) Reliability, Planning and Standards Development Services 92 (562) Station Expenses 93 1,506,478 2,124,825 (563) Overhead Lines Expenses 94 245,152 120,209 (564) Underground Lines Expenses 95 (565) Transmission of Electricity by Others 96 117,161,210 136,854,649 (566) Miscellaneous Transmission Expenses 97 2,393,112 4,257,862 (567) Rents 98 1,656,975 1,312,382 TOTAL Operation (Enter Total of lines 83 thru 98) 99 138,375,218 160,047,938 Maintenance 100 (568) Maintenance Supervision and Engineering 101 35,453 1,334,303 (569) Maintenance of Structures 102 788 395 (569.1) Maintenance of Computer Hardware 103 79,505 36,440 (569.2) Maintenance of Computer Software 104 974,621 1,065,683 (569.3) Maintenance of Communication Equipment 105 3,005,647 3,567,267 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 106 (570) Maintenance of Station Equipment 107 10,549,624 10,092,385 (571) Maintenance of Overhead Lines 108 19,620,066 19,173,510 (572) Maintenance of Underground Lines 109 51,599 36,881 (573) Maintenance of Miscellaneous Transmission Plant 110 182,001 273,467 TOTAL Maintenance (Total of lines 101 thru 110) 111 34,499,304 35,580,331 TOTAL Transmission Expenses (Total of lines 99 and 111) 112 172,874,522 195,628,269

FERC FORM NO. 1 (ED. 12-93) Page321ELECTRIC 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

3. REGIONAL MARKET EXPENSES 113 Operation 114 (575.1) Operation Supervision 115 (575.2) Day-Ahead and Real-Time Market Facilitation 116 (575.3) Transmission Rights Market Facilitation 117 (575.4) Capacity Market Facilitation 118 (575.5) Ancillary Services Market Facilitation 119 (575.6) Market Monitoring and Compliance 120 (575.7) Market Facilitation, Monitoring and Compliance Services 121 (575.8) Rents 122 Total Operation (Lines 115 thru 122) 123 Maintenance 124 (576.1) Maintenance of Structures and Improvements 125 (576.2) Maintenance of Computer Hardware 126 (576.3) Maintenance of Computer Software 127 (576.4) Maintenance of Communication Equipment 128 (576.5) Maintenance of Miscellaneous Market Operation Plant 129 Total Maintenance (Lines 125 thru 129) 130 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131 4. DISTRIBUTION EXPENSES 132 Operation 133 (580) Operation Supervision and Engineering 134 19,654,389 15,625,451 (581) Load Dispatching 135 13,439,746 13,735,481 (582) Station Expenses 136 3,879,687 3,812,831 (583) Overhead Line Expenses 137 5,794,824 5,762,152 (584) Underground Line Expenses 138 305 287 (585) Street Lighting and Signal System Expenses 139 207,152 209,265 (586) Meter Expenses 140 6,713,560 6,564,361 (587) Customer Installations Expenses 141 12,459,259 12,634,849 (588) Miscellaneous Expenses 142 7,441,400 5,887,263 (589) Rents 143 3,196,255 3,253,672 TOTAL Operation (Enter Total of lines 134 thru 143) 144 72,786,577 67,485,612 Maintenance 145 (590) Maintenance Supervision and Engineering 146 7,535,970 5,493,229 (591) Maintenance of Structures 147 2,015,990 1,828,870 (592) Maintenance of Station Equipment 148 12,800,357 12,622,071 (593) Maintenance of Overhead Lines 149 83,336,655 84,730,396 (594) Maintenance of Underground Lines 150 22,486,595 22,786,414 (595) Maintenance of Line Transformers 151 1,105,880 883,285 (596) Maintenance of Street Lighting and Signal Systems 152 4,217,687 4,084,559 (597) Maintenance of Meters 153 5,637,023 5,890,644 (598) Maintenance of Miscellaneous Distribution Plant 154 3,546,007 2,745,222 TOTAL Maintenance (Total of lines 146 thru 154) 155 142,682,164 141,064,690 TOTAL Distribution Expenses (Total of lines 144 and 155) 156 215,468,741 208,550,302 5. CUSTOMER ACCOUNTS EXPENSES 157 Operation 158 (901) Supervision 159 2,554,096 2,497,682 (902) Meter Reading Expenses 160 22,520,219 22,553,488 (903) Customer Records and Collection Expenses 161 56,280,326 54,938,892 (904) Uncollectible Accounts 162 12,175,795 12,590,656 (905) Miscellaneous Customer Accounts Expenses 163 254,571 169,927 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 93,785,007 92,750,645

FERC FORM NO. 1 (ED. 12-93) Page322ELECTRIC 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165 Operation 166 (907) Supervision 167 286,417 263,903 (908) Customer Assistance Expenses 168 66,102,006 124,155,800 (909) Informational and Instructional Expenses 169 4,924,267 4,435,033 (910) Miscellaneous Customer Service and Informational Expenses 170 150,054 90,169 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 71,462,744 128,944,905 7. SALES EXPENSES 172 Operation 173 (911) Supervision 174 (912) Demonstrating and Selling Expenses 175 (913) Advertising Expenses 176 (916) Miscellaneous Sales Expenses 177TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178 8. ADMINISTRATIVE AND GENERAL EXPENSES 179 Operation 180 (920) Administrative and General Salaries 181 72,874,820 66,458,826 (921) Office Supplies and Expenses 182 11,031,087 9,973,883 (Less) (922) Administrative Expenses Transferred-Credit 183 25,866,775 28,375,128 (923) Outside Services Employed 184 11,039,350 9,404,302 (924) Property Insurance 185 23,970,317 23,341,430 (925) Injuries and Damages 186 7,434,336 8,492,514 (926) Employee Pensions and Benefits 187 (927) Franchise Requirements 188 (928) Regulatory Commission Expenses 189 16,464,747 17,926,840 (929) (Less) Duplicate Charges-Cr. 190 3,420,842 6,130,867 (930.1) General Advertising Expenses 191 35,761 20,382 (930.2) Miscellaneous General Expenses 192 19,659,625 16,291,649 (931) Rents 193 6,199,584 6,337,703 TOTAL Operation (Enter Total of lines 181 thru 193) 194 139,422,010 123,741,534 Maintenance 195 (935) Maintenance of General Plant 196 23,197,501 22,334,950 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 162,619,511 146,076,484 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 2,673,916,007 2,692,096,143

FERC FORM NO. 1 (ED. 12-93) Page323

### 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)XAn 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 450.1Name 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

(c) (b) (a) 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 DemandMonthly 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.

Power Purchases 1 NA NA NA Albany, City of LU 2 NA NA NA Alberta Power Pool SF 3 NA NA NA Amy Ranch Hydro LU 4 NA NA NA Anaheim, City of SF 5 NA NA NA Arizona Public Service Company AD 6 NA NA NA Arizona Public Service Company OS 7 NA NA NA Arizona Public Service Company LF 8 NA NA NA Arizona Public Service Company SF 9 NA NA NA Avista Corporation SF 10 NA NA NA BNP Paribas Energy Trading GP SF 11 NA NA NA BP Corporation North America, Inc. SF 12 NA NA NA BP Energy Company SF 13 0.01 0.01 0.01 Ballard Hog Farms Inc. LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Barclays Bank PLC AD 1 NA NA NA Barclays Bank PLC AD 2 NA NA NA Barclays Bank PLC SF 3 NA NA NA Beaver City Corporation LF 4 NA NA NA Bell Mountain Hydro, LLC AD 5 NA NA NA Bell Mountain Hydro, LLC LU 6 NA NA NA Big Top, LLC LU 7 13.7 20.9 22.5 Biomass One, L.P. LU 8 NA NA NA Birch Creek Hydro LU 9 NA NA NA Black Hills Power, Inc. AD 10 NA NA NA Black Hills Power, Inc. LU 11 NA NA NA Black Hills Power, Inc. OS 12 NA NA NA Black Hills Power, Inc. SF 13 NA NA NA Black Hills Wyoming, Inc. SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.1 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Blanding City Corporation LF 1 461 575 575 Bonneville Power Administration LF 2 NA NA NA Bonneville Power Administration LF 3 NA NA NA Bonneville Power Administration OS 4 NA NA NA Bonneville Power Administration SF 5 NA NA NA British Columbia Transmission Corp. SF 6 NA NA NA Butter Creek Power, LLC LU 7 NA NA NA CDM Hydroelectric Company LU 8 NA NA NA California Independent System Operator AD 9 NA NA NA California Independent System Operator SF 10 NA NA NA Cameron A. Curtiss LU 11 NA NA NA Cargill Power Markets, LLC AD 12 NA NA NA Cargill Power Markets, LLC SF 13 2.7 3.7 3.6 Central Oregon Irrigation District LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.2 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Chevron U.S.A. Inc. LU 1 NA NA NA Citigroup Energy, Inc. AD 2 NA NA NA Citigroup Energy, Inc. SF 3 NA NA NA City of Burbank SF 4 NA NA NA City of Preston Idaho LU 5 NA NA NA City of Redding SF 6 1.5 1.7 1.1 City of Walla Walla LU 7 NA NA NA Clatskanie People's Utility District SF 8 NA NA NA Colorado River Commission of Nevada AD 9 NA NA NA Colorado River Commission of Nevada SF 10 NA NA NA Commercial Energy Management, Inc. LU 11 NA NA NA ConocoPhillips Company SF 12 NA NA NA Constellation Energy Commodities Group OS 13 NA NA NA Constellation Energy Commodities Group SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.3 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Cottonwood Hydro LLC IU 1 NA NA NA Credit Suisse Energy LLC AD 2 NA NA NA Credit Suisse Energy LLC SF 3 NA NA NA DB Energy Trading LLC AD 4 NA NA NA DB Energy Trading LLC SF 5 3.5 4.5 5.92 Deschutes Valley Water District LU 6 84 100 100 Deseret Power Electric Cooperative LF 7 NA NA NA Deseret Power Electric Cooperative OS 8 NA NA NA Deutsche Bank AG AD 9 NA NA NA Deutsche Bank AG SF 10 NA NA NA Douglas County Inc. IU 11 0.5 0.7 0.2 Douglas County Public Works LU 12 NA NA NA Draper Irrigation Company IU 13 NA NA NA Dry Creek LLC LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.4 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA EDF Trading North America, LLC SF 1 0.4 0.5 0.8 Eagle Point Irrigation District LU 2 NA NA NA El Paso Electric Company AD 3 NA NA NA El Paso Electric Company SF 4 NA NA NA Endure Energy, LLC SF 5 NA NA NA Eugene Water & Electric Board SF 6 NA NA NA Eurus Combine Hills I, LLC LU 7 NA NA NA Evergreen BioPower, LLC LU 8 NA NA NA ExxonMobile Production Company LU 9 1.6 3.7 3.5 Falls Creek H.P. Limited Partnership LU 10 2.9 3.6 3.92 Farmers Irrigation District LU 11 NA NA NA Fillmore City LF 12 NA NA NA Finley BioEnergy, LLC LU 13 NA NA NA Four Corners Windfarm, LLC LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.5 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Four Mile Canyon Windfarm, LLC LU 1 NA NA NA General Chemical Corporation OS 2 0.8 1 0.8 George DeRuyter & Sons Dairy LU 3 NA NA NA Georgetown Irrigation Company LU 4 NA NA NA Gila River Power, L.P. AD 5 NA NA NA Gila River Power, L.P. OS 6 NA NA NA Gila River Power, L.P. SF 7 NA NA NA Glendale, City of SF 8 NA NA NA Grand Valley Power LF 9 NA NA NA Grays Harbor Public Utility District SF 10 0.2 0.5 0.35 HDI Associates V, LP LU 11 NA NA NA Harold Foster & Robert Walker LU 12 NA NA NA Heber Light & Power Company LF 13 NA NA NA Hermiston Generating Company, L.P. AD 14

FERC FORM NO. 1 (ED. 12-90) Page 326.6 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

216 239 240 Hermiston Generating Company, L.P. LU 1 NA NA NA Hill Air Force Base AD 2 NA NA NA Hill Air Force Base LU 3 NA NA NA Hurricane, City of LF 4 NA NA NA Iberdrola Renewables, Inc. AD 5 NA NA NA Iberdrola Renewables, Inc. SF 6 NA NA NA Idaho Falls, City of AD 7 NA NA NA Idaho Falls, City of LU 8 NA NA NA Idaho Power Company SF 9 NA NA NA Intermountain Power Agency LU 10 NA NA NA J. Aron & Company SF 11 NA NA NA JP Morgan Ventures Energy Corporation AD 12 NA NA NA JP Morgan Ventures Energy Corporation SF 13 2.1 4.3 2.2 KEI (USA) Power Management Inc. LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.7 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Kennecott Utah Copper LLC LU 1 NA NA NA L&M Angus Ranch, LLC LU 2 NA NA NA Lacomb Irrigation District LU 3 NA NA NA Los Angeles Dept. of Water & Power IF 4 NA NA NA Los Angeles Dept. of Water & Power OS 5 NA NA NA Los Angeles Dept. of Water & Power SF 6 NA NA NA Lower Valley Energy, Inc. AD 7 NA NA NA Lower Valley Energy, Inc. IU 8 NA NA NA Loyd Fery LU 9 NA NA NA Macquarie Energy LLC SF 10 NA NA NA Marsh Valley Hydro & Electric Company LU 11 NA NA NA Metropolitan Water District of S. Cal. SF 12 NA NA NA Middle Fork Irrigation District LU 13 NA NA NA Mink Creek Hydro LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.8 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Modesto Irrigation District SF 1 NA NA NA Monsanto Company IU 2 NA NA NA Morgan City Corporation LF 3 NA NA NA Morgan Stanley Capital Group, Inc. AD 4 50 50 100 Morgan Stanley Capital Group, Inc. IF 5 NA NA NA Morgan Stanley Capital Group, Inc. SF 6 NA NA NA Mountain Wind Power II, LLC AD 7 NA NA NA Mountain Wind Power II, LLC LU 8 NA NA NA Mountain Wind Power, LLC LU 9 NA NA NA Municipal Energy Agency of Nebraska SF 10 NA NA NA Nephi City Corporation LF 11 NA NA NA Nevada Power Company SF 12 NA NA NA NextEra Energy Power Marketing, LLC SF 13 NA NA NA Nicholson Sunnybar Ranch AD 14

FERC FORM NO. 1 (ED. 12-90) Page 326.9 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Nicholson Sunnybar Ranch LU 1 NA NA NA NorthWestern Corporation SF 2 NA NA NA Northpoint Energy Solutions Inc. SF 3 NA NA NA Nucor Corporation IF 4 NA NA NA O.J. Power Company LU 5 0 0 0.01 Odell Creek Hydroelectric Investors LU 6 NA NA NA Oregon Environmental Industries, LLC LU 7 NA NA NA Oregon Institute of Technology LU 8 NA NA NA Oregon Trail Windfarm, LLC LU 9 NA NA NA PPL EnergyPlus, LLC SF 10 NA NA NA Pacific Canyon Windfarm, LLC LU 11 NA NA NA Pacific Gas & Electric Company SF 12 NA NA NA Pacific Northwest Generating Coop. SF 13 NA NA NA Pacific Summit Energy LLC SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.10 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Paul Luckey LU 1 NA NA NA Payson City Corporation LF 2 NA NA NA Platte River Power Authority SF 3 NA NA NA Portland General Electric Company AD 4 NA NA NA Portland General Electric Company LF 5 NA NA NA Portland General Electric Company OS 6 NA NA NA Portland General Electric Company SF 7 NA NA NA Powerex Corporation AD 8 NA NA NA Powerex Corporation SF 9 NA NA NA Provo City Corporation LF 10 NA NA NA Public Service Company of Colorado OS 11 NA NA NA Public Service Company of Colorado SF 12 NA NA NA Public Service Company of New Mexico SF 13 NA NA NA PUD #1 of Chelan County LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.11 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA PUD #1 of Chelan County SF 1 NA NA NA PUD #1 of Cowlitz County OS 2 NA NA NA PUD #1 of Douglas County AD 3 NA NA NA PUD #1 of Douglas County AD 4 NA NA NA PUD #1 of Douglas County LF 5 NA NA NA PUD #1 of Douglas County LU 6 NA NA NA PUD #1 of Douglas County SF 7 NA NA NA PUD #1 of Snohomish County SF 8 NA NA NA PUD #2 of Grant County AD 9 NA NA 14 PUD #2 of Grant County LF 10 NA NA NA PUD #2 of Grant County LU 11 NA NA NA PUD #2 of Grant County SF 12 NA NA NA PUD #1 of Lewis County AD 13 NA NA NA PUD #1 of Lewis County LF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.12 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Puget Sound Energy, Inc. SF 1 NA NA NA Rainbow Energy Marketing Corporation SF 2 NA NA NA Ralphs Ranch, Inc. AD 3 NA NA NA Ralphs Ranch, Inc. LU 4 NA NA NA Rock River 1, LLC LU 5 NA NA NA Rocky Mountain Generation Coop. SF 6 NA NA NA Roseburg Forest Products Co. LU 7 NA NA NA Roseburg Forest Products Co. OS 8 NA NA NA Rough & Ready Lumber Company LU 9 NA NA NA Roush Hydro Inc. LU 10 NA NA NA Sacramento Municipal Utility District AD 11 NA NA NA Sacramento Municipal Utility District LF 12 NA NA NA Sacramento Municipal Utility District SF 13 NA NA NA Salt River Project SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.13 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA San Diego Gas & Electric Company AD 1 NA NA NA San Diego Gas & Electric Company SF 2 NA NA NA Sand Ranch Windfarm, LLC LU 3 0.2 0.2 0.2 Santiam Water Control District LU 4 NA NA NA Seattle City Light SF 5 NA NA NA Sempra Energy Trading LLC AD 6 NA NA NA Sempra Energy Trading LLC SF 7 NA NA NA Sempra Generation SF 8 NA NA NA Shell Energy North America (US), L.P. AD 9 NA NA NA Shell Energy North America (US), L.P. SF 10 1 1.4 2.5 Shoshone Irrigation District LU 11 NA NA NA Sierra Pacific Power Company SF 12 NA NA NA Sierra Pacific Power Company SF 13 NA NA NA Sierra Pacific Power Company SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.14 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

9 13 10 Simplot Phosphates LLC LU 1 1.8 2.7 3.2 Slate Creek Hydro Company, Inc. LU 2 NA NA NA Southern California Edison Company OS 3 NA NA NA Southern California Edison Company SF 4 NA NA NA Southwestern Public Service Company SF 5 NA NA NA Spanish Fork City Corporation LF 6 NA NA NA Spanish Fork Wind Park 2, LLC LU 7 NA NA NA Springville City Corporation LF 8 NA NA NA Stahlbush Island Farms, Inc. IU 9 NA NA NA Strawberry Electric Service District LF 10 0.02 0.03 0.02 Sunderland Dairy Inc. LU 11 43 53 52 Sunnyside Cogeneration Associates LU 12 NA NA NA Swalley Irrigation District LU 13 NA NA NA Tacoma Power AD 14

FERC FORM NO. 1 (ED. 12-90) Page 326.15 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Tacoma Power SF 1 NA NA NA Tesoro Refining and Marketing Company LU 2 0.3 0.4 0.3 Thayn Hydro LLC LU 3 NA NA NA The Energy Authority SF 4 0.2 0.2 0.23 The Town of the City of Buffalo LU 5 NA NA NA Three Buttes Windpower, LLC LU 6 NA NA NA Threemile Canyon Wind I, LLC AD 7 NA NA NA Threemile Canyon Wind I, LLC LU 8 NA NA NA Top of The World Wind Energy LLC LU 9 NA NA NA TransAlta Energy Marketing Inc. IF 10 NA NA NA TransAlta Energy Marketing Inc. SF 11 NA NA NA TransCanada Energy Sales Ltd. SF 12 26 29 30 Tri-State Gen. & Trans. LF 13 NA NA NA Tri-State Gen. & Trans. SF 14

FERC FORM NO. 1 (ED. 12-90) Page 326.16 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Tucson Electric Power Company OS 1 NA NA NA Tucson Electric Power Company SF 2 NA NA NA Turlock Irrigation District SF 3 NA NA NA UNS Electric, Inc. SF 4 NA NA NA US Magnesium LLC IU 5 NA NA NA US Magnesium LLC LF 6 NA NA NA Utah Associated Municipal Power OS 7 NA NA NA Utah Associated Municipal Power SF 8 NA NA NA Utah Municipal Power Agency SF 9 NA NA NA Wadeland South LLC LU 10 NA NA NA Wagon Trail, LLC LU 11 NA NA NA Ward Butte Windfarm, LLC LU 12 NA NA NA Warm Springs Forest Products LU 13 NA NA NA Wasatch Integrated Waste Management LU 14

FERC FORM NO. 1 (ED. 12-90) Page 326.17 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Weber County, State of Utah LU 1 NA NA NA Western Area Power Administration AD 2 NA NA NA Western Area Power Administration SF 3 NA NA NA Western Area Power Administration SF 4 NA NA NA Western Area Power Administration SF 5 NA NA NA Whitney, A. C. AD 6 NA NA NA Wolverine Creek Energy LLC LU 7 NA NA NA Yakima-Tieton Irrigation District LU 8 NA NA NA Accrual/Net Power Cost Deferrals NA 9 NA NA NA Settlement/Reserves AD 10 NA NA NA Bookout Purchases AD 11 NA NA NA Trade Purchases AD 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 326.18 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

Power Exchanges 1 NA NA NA Arizona Public Service Company 306 EX 2 NA NA NA Avista Corporation 554 EX 3 NA NA NA Basin Electric Power Cooperative T-11 EX 4 NA NA NA Black Hills Power, Inc. 246 EX 5 NA NA NA Bonneville Power Administration 237 AD 6 NA NA NA Bonneville Power Administration -17 AD 7 NA NA NA Bonneville Power Administration 237 EX 8 NA NA NA Bonneville Power Administration 256 EX 9 NA NA NA Bonneville Power Administration 411 EX 10 NA NA NA Bonneville Power Administration 368 EX 11 NA NA NA Bonneville Power Administration 554 EX 12 NA NA NA Bonneville Power Administration -17 EX 13 NA NA NA Bonneville Power Administration T-11 EX 14

FERC FORM NO. 1 (ED. 12-90) Page 326.19 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA Bonneville Power Administration T-12 EX 1 NA NA NA Bonneville Power Administration T-12 EX 2 NA NA NA City of Redding 364 EX 3 NA NA NA City of St. George 280 EX 4 NA NA NA Colockum Transmission Company T-12 EX 5 NA NA NA Constellation Energy Commodities Group T-11 EX 6 NA NA NA Deseret Power Electric Cooperative 280 AD 7 NA NA NA Deseret Power Electric Cooperative 280 EX 8 NA NA NA Emerald People's Utility District 351 AD 9 NA NA NA Emerald People's Utility District 351 EX 10 NA NA NA Eugene Water & Electric Board T-12 EX 11 NA NA NA Iberdrola Renewables, Inc. T-11 EX 12 NA NA NA Idaho Power Company 380 EX 13 NA NA NA Intermountain Renewable Power, LLC T-11 EX 14

FERC FORM NO. 1 (ED. 12-90) Page 326.20 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA JP Morgan Ventures Energy Corporation T-11 EX 1 NA NA NA Los Angeles Dept. of Water & Power OV-1 AD 2 NA NA NA Los Angeles Dept. of Water & Power OV-1 EX 3 NA NA NA Milford Wind Corridor Phase I, LLC OV-1 AD 4 NA NA NA Milford Wind Corridor Phase I, LLC OV-1 EX 5 NA NA NA NextEra Energy Power Marketing, LLC T-11 EX 6 NA NA NA Noble Americas Energy Solutions LLC T-11 EX 7 NA NA NA Portland General Electric Company 554 EX 8 NA NA NA Powerex Corporation T-11 EX 9 NA NA NA Public Service Company of Colorado 319 EX 10 NA NA NA Public Service Company of Colorado 320 EX 11 NA NA NA Public Service Company of Colorado T-12 EX 12 NA NA NA PUD #1 of Chelan County 554 EX 13 NA NA NA PUD #1 of Chelan County 555 EX 14

FERC FORM NO. 1 (ED. 12-90) Page 326.21 

### TotalName 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

(c) (b) (a) 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 DemandMonthly 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.

NA NA NA PUD #1 of Cowlitz County 554 EX 1 NA NA NA Seattle City Light 554 EX 2 NA NA NA Seattle City Light T-11 EX 3 NA NA NA Southern California Edison Company T-11 EX 4 NA NA NA Tri-State Gen. & Trans. 319 AD 5 NA NA NA Tri-State Gen. & Trans. 319 EX 6 NA NA NA Tri-State Gen. & Trans. T-11 EX 7 NA NA NA Utah Associated Municipal Power T-11 AD 8 NA NA NA Utah Associated Municipal Power T-11 EX 9 NA NA NA Utah Municipal Power Agency T-11 EX 10 NA NA NA Warm Springs Power Enterprises T-11 EX 11 NA NA NA Western Area Power Administration LAS-4 AD 12 NA NA NA Western Area Power Administration LAS-4 EX 13 NA NA NA System Deviation NA 14

FERC FORM NO. 1 (ED. 12-90) Page 326.22 

### TotalName 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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 79,398 79,398 2 1,223 1,720 1,720 3

59 96,961 96,961 4 1,862 278 278 5

15 33,450 33,450 6 400 8,210 8,210 7 256 2,557,725 2,557,725 8 83,299 2,396,446 2,396,446 9 69,286 4,219,641 15,946 4,235,587 10 128,850 207,290 207,290 11

6,000 -37,170,962 -37,170,962 12 654,037 654,037 13 32,905 213 2,449 2,662 14

49

FERC FORM NO. 1 (ED. 12-90) Page 327 11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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 26,590 26,590 2 350 4,702,174 -68,131,914 -63,429,740 3 106,053 5,994 5,994 4

71 -15,139 -15,139 5 67,272 67,272 6 996 186,911 186,911 7 2,928 2,666,250 19,785,327 3,691,677 26,143,254 8 143,000 758,820 758,820 9 13,847 25,637 25,637 10 2,848,604 2,848,604 11 318 2,990 2,990 12 130 459,485 459,485 13 14,635 8,400 8,400 14

400

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

31,753 31,753 1 423 57,615,000 57,615,000 2 1,706,104 1,706,104 3

70,681 70,681 4 1,674 1,757,934 162,853 1,920,787 5 90,060 7,696 7,696 6

264 717,291 717,291 7 11,316 1,396,492 1,396,492 8 25,566 730,460 730,460 9 -16,617 17,865,500 17,865,500 10 529,098 3,008 3,008 11

69 141,722 141,722 12 1,805 25,047,500 402,724 25,450,224 13 637,442 400,660 2,134,677 2,535,337 14 22,660

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

2,076,638 21,959 2,098,597 1 38,584 3,425 3,425 2

91 7,356,095 -26,425,184 -19,069,089 3 249,311 974,450 974,450 4 22,800 77,193 77,193 5 1,579 22,425 22,425 6 1,014 138,741 1,653,967 1,792,708 7 12,135 45,110 45,110 8 1,445 7,088 7,088 9

94 13,588 13,588 10 154 85,375 85,375 11 1,627 3,736,216 3,736,216 12 123,362 237,718 237,718 13

4,581 9,491,237 -37,165 9,454,072 14 187,716

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

149,623 149,623 1 2,704 9,069 9,069 2

50 17,320 -1,559,739 -1,542,419 3 400 869 869 4 18 8,339,074 8,339,074 5 205,612 582,894 3,330,042 3,912,936 6 31,327 14,238,038 15,126,801 3,747,224 33,112,063 7 833,314 5,336 5,336 8 -3,391 -3,391 9 -2,633,858 -2,633,858 10 45,925 45,925 11 1,427 41,414 523,107 564,521 12 4,388 -1,378 -1,378 13 618,711 618,711 14 11,980

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

7,289,824 -432,543 6,857,281 1 172,839 44,501 363,935 408,436 2

3,248 40 40 3

1 950,250 58 950,308 4 25,486 358,550 358,550 5 11,600 550,261 550,261 6 18,796 3,671,564 3,671,564 7 104,663 2,328,875 2,328,875 8 42,924 31,711,273 31,711,273 9 652,410 225,624 1,823,788 2,049,412 10 17,303 338,031 2,589,659 2,927,690 11 24,385 19,680 19,680 12

182 1,758,942 1,758,942 13 27,071 1,469,252 1,469,252 14 23,146

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

1,390,126 1,390,126 1 21,849 38,485 38,485 2 2,583 13,360 410,812 424,172 3 6,698 113,503 113,503 4 2,112 63,592 63,592 5 671 8,250 8,250 6 150 2,134,549 2,134,549 7 53,877 42,200 42,200 8 1,200 23,873 23,873 9 132 62,160 62,160 10 4,320 37,268 250,129 287,397 11 2,282 29,827 29,827 12 843 511,075 511,075 13 6,037 -238,483 -238,483 14

1

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

35,316,527 59,644,334 326,730 95,287,591 1 1,592,856 6,533 6,533 2 678,405 678,405 3 14,185 149,378 149,378 4 1,992 4,366 4,366 5 14,588,523 -4,210,685 10,377,838 6 480,053 -31,788 -31,788 7 2,915,697 2,915,697 8 39,813 66,180 3,316 69,496 9 1,901 27,947,142 27,947,142 10 564,732 256,870 -2,236,873 -1,980,003 11

8,600 726 726 12

20 5,165,634 936,569 6,102,203 13 142,558 288,507 2,559,977 2,848,484 14 22,983

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

7,210,874 10,102,863 17,313,737 1 169,414 82,985 82,985 2

1,511 165,359 33,822 199,181 3 4,733 1,149,080 1,149,080 4 23,000 15,750 15,750 5 3,150 3,804,020 3,804,020 6 90,577 -687 -687 7

-12 291,324 291,324 8 5,175 15,020 15,020 9 232 3,502,713 123,376 3,626,089 10 116,134 250,058 250,058 11

4,555 1,445 1,445 12

41 1,267,429 1,267,429 13 23,610 423,842 423,842 14 8,036

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

47,600 47,600 1 1,200 17,705,685 17,705,685 2 2,902 2,902 3 25 101,468 101,468 4 2,837 3,057,000 10,682,513 13,739,513 5 245,575 52,870,919 -22,101,625 30,769,294 6 1,132,331 8,166 8,166 7 13,119,063 13,119,063 8 202,072 8,274,548 8,274,548 9 149,425 17,640 17,640 10

500 1,824 1,824 11 19 1,485,790 83,907 1,569,697 12 40,963 24,150 24,150 13

600 -2,475 -2,475 14 -38

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

100,426 100,426 1 1,852 19,994 19,994 2 588 12,200 12,200 3 400 4,885,800 4,885,800 4 35,249 35,249 5 708 439 4 443 6 1,123,946 1,123,946 7 20,978 5,902 5,902 8

322 1,399,186 1,399,186 9 22,057 1,573,131 1,573,131 10 52,235 1,035,088 1,035,088 11 16,242 46,000 46,000 12 1,600 264,080 264,080 13 10,075 398,797 398,797 14 12,348

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

29,309 29,309 1 253 764 764 2

7 77,767 77,767 3 2,776 -14,939 -14,939 4 141,000 141,000 5 12,001 1,200 1,200 6 1,691,178 24,481 1,715,659 7 53,247 1,255 1,255 8

31 5,866,328 166,508 6,032,836 9 150,257 25,400 25,400 10

301 885 885 11 26 752,474 752,474 12 20,720 2,489,686 137,681 2,627,367 13 73,104 3,964,408 3,964,408 14 306,009

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

802,570 5,445 808,015 1 43,360 -8,136 -8,136 2 -68,903 -68,903 3 -198,867 -198,867 4 758,612 758,612 5 34,958 2,958,681 2,958,681 6 198,970 1,056,220 1,560 1,057,780 7 33,391 2,018,714 2,018,714 8 79,896 -3,588,743 -3,588,743 9 94,138 5,791,025 318,779 6,203,942 10 87,600 12,896,650 7,780,156 20,676,806 11 981,806 956,570 6,840 963,410 12 32,107 -7,377 -7,377 13 -178 243,034 243,034 14 8,104

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

5,547,977 27,072 5,575,049 1 167,918 2,531,434 2,531,434 2 75,863 -2,214 -2,214 3

-18 4,426 4,426 4 37 4,903,494 4,903,494 5 138,204 159,221 159,221 6

5,815 9,626,855 9,626,855 7 168,638 14,362 14,362 8

11 550,664 550,664 9 8,463 15,257 15,257 10 236 43,800 43,800 11 3,748,456 3,748,456 12 213,709 799,882 2,157 802,039 13 21,930 3,938,386 127 3,938,513 14 98,968

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

11,387 11,387 1 357 397,974 397,974 2 9,509 1,265,980 1,265,980 3 19,888 13,632 144,445 158,077 4 1,521 3,277,977 10,245 3,288,222 5 119,532 348 348 6

81 13,453,560 -19,996,534 -6,542,974 7 273,914 525 525 8

15 3,028 3,028 9 90 10,665,574 -44,238,031 -33,572,457 10 291,446 163,673 391,435 555,108 11

9,713 2,336 2,336 12

72 9,154 9,154 13 152 382,995 382,995 14 9,725

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

444,600 3,501,940 3,946,540 1 82,452 212,588 1,516,653 1,729,241 2 15,289 62,200 62,200 3 2,600 1,246,943 1,246,943 4 37,921 66,883 66,883 5 1,996 2,776 2,776 6

24 2,442,876 2,442,876 7 46,929 7,333 7,333 8

60 243,120 243,120 9 3,660 4,921 4,921 10

58 1,503 3,479 4,982 11 109 9,681,949 13,803,144 23,485,093 12 377,727 144,327 144,327 13

2,225 1,239 1,239 14

21

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

702,195 4,332 706,527 1 20,896 1,974,079 1,974,079 2 47,654 67,772 188,643 256,415 3 2,525 1,040,588 1,040,588 4 37,082 30,348 155,069 185,417 5 1,753 19,117,682 379,646 19,497,328 6 299,989 153,684 153,684 7 1,338,382 1,338,382 8 20,689 12,172,889 12,172,889 9 188,825 44,909,806 -727,224 44,182,582 10 1,315,200 4,207,360 4,207,360 11 120,630 1,095,750 1,095,750 12 20,600 6,861,600 4,460,802 11,322,402 13 169,419 624,161 325,564 949,725 14 26,166

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

1,425 1,425 1 75 1,229,053 235 1,229,288 2 37,947 25,800 437 26,237 3

815 188,579 188,579 4 8,271 7,786,278 7,786,278 5 184,521 4,909,716 4,909,716 6 2,075,988 2,075,988 7 61,950 13,250 13,250 8

332 25,050 25,050 9 590 77 77 10 402,580 402,580 11 6,319 970,618 970,618 12 15,323 1,138 1,138 13

45 28,747 28,747 14 560

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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

149,019 149,019 1 3,298 2

87 543,719 543,719 3 18,457 121 121 4

4 505,597 505,597 5 14,122 -1 -1 6 8,944,609 8,944,609 7 162,305 351,212 351,212 8

5,773 -17,674,999 -17,674,999 9 1,516,071 1,516,071 10 -184,282,163 -184,282,163 11 -5,780,807 -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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

1 570,430 569,935 -910,873 -910,873 2

1,512 3 223 9,160 291,446 291,446 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 1,489,199 1,485,806 -170,000 -170,000 10 242,939 242,938 11 14,313 189,270 12 9,292,882 9,292,882 -35,921,147 -35,921,147 13 8,108 13,246 166,932 166,932 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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

91,824 126,893 1,390,386 1,390,386 1 -74,371 -74,371 2 119,121 116,660 -84,002 -84,002 3

38 6,164 6,164 4 268,153 5

583 1,239 25,430 25,430 6 -4,976 355 382,311 382,311 7 57,629 29,857 -1,286,349 -1,286,349 8 13 -324 -324 9 541 -13,538 -13,538 10 17,832 17,731 -7,138 -7,138 11 4,096 6,352 69,113 69,113 12 219,081 389,768 13 1,337 4,003 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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

1,949 2,408 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 95,145 121,108 743,856 743,856 6 2,576 31,487 875,110 875,110 7 138,959 140,017 8 1,277 526 -23,772 -23,772 9 8,745 10 873,663 875,971 3,600,000 3,600,000 11 71,273 71,480 -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 -408,270,490 380,007,678Name 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

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total 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.

252,784 213,594 1 297,971 300,994 -315,670 -315,670 2 5,478 7,210 30,845 30,845 3 12,193 16,851 133,132 133,132 4 19,219 19,219 5 8,745 48,050 48,050 6 2,973 3,028 8,810 8,810 7 -64 -24 230 230 8 68,167 118,752 1,755,000 1,755,000 9 4,272 45,631 1,509,447 1,509,447 10 6,571 1,991 -160,936 -160,936 11 -3,886 265 -256,850 -256,850 12 23,332 21,802 -209,558 -209,558 13 14 -27,973

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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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 450.11TRANSMISSION 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Payment By

(c) (b) (a) (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.

Arizona Public Service Company Arizona Public Service Company OS 1 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO 2 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 3 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO 4 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 5 Basin Electric Power Cooperative Western Area Power Administration NF 6 Barclay's Bank NF 7 Black Hills/Colorado Electric Utility Company NF 8 Black Hills/Colorado Electric Utility Company SFP 9 Black Hills, Inc. Montana-Dakota Utilities FNO 10 Black Hills, Inc. Montana-Dakota Utilities AD 11 Black Hills, Inc. NF 12 Black Hills, Inc. AD 13 Black Hills, Inc. SFP 14 Black Hills, Inc. Black Hills, Inc. LFP 15 Black Hills, Inc. Black Hills, Inc. AD 16 Bonneville Power Administration OS 17 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 18 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 19 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 20 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 21 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 22 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 23 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 24 Bonneville Power Administration Bonneville Power Administration Benton REA FNO 25 Bonneville Power Administration Bonneville Power Administration Benton REA AD 26 Bonneville Power Administration Bonneville Power Administration FNO 27 Bonneville Power Administration Bonneville Power Administration AD 28 Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP 29 Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration AD 30 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 31 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 32 Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 33 Bonneville Power Administration Bonneville Power Administration Yakama Power AD 34

FERC FORM NO. 1 (ED. 12-90) Page 328 TOTALTRANSMISSION 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Payment By

(c) (b) (a) (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.

Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 1 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 2 Bonneville Power Administration SFP 3 Bonneville Power Administration NF 4 Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO 5 Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD 6 Cargill Power Markets, LLC NF 7 Cargill Power Markets, LLC AD 8 Cargill Power Markets, LLC SFP 9 Citigroup NF 10 Constellation Energy Commodities Group NF 11 Constellation Energy Commodities Group AD 12 Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS 13 Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD 14 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. OS 15 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. AD 16 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. OS 17 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans. AD 18 Deseret Generation & Trans. Deseret Generation & Trans. SFP 19 Eagle Energy Partners NF 20 Endure Energy, LLC. AD 21 Enel Cove Fort, LLC Enel Cove Fort, LLC LFP 22 Eugene Water & Electric Board NF 23 Eugene Water & Electric Board AD 24 Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS 25 Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD 26 Foote Creek III, LLC Foote Creek III, LLC OS 27 Foote Creek III, LLC Foote Creek III, LLC AD 28 Gila River Power, L.P. NF 29 Iberdrola Renewables Inc. NF 30 Iberdrola Renewables Inc. AD 31 Iberdrola Renewables Inc. Iberdrola Renewables Inc. Iberdrola Renewables Inc. OS 32 Iberdrola Renewables Inc. Iberdrola Renewables Inc. Iberdrola Renewables Inc. AD 33 Iberdrola Renewables Inc. Iberdrola Renewables Inc. OS 34

FERC FORM NO. 1 (ED. 12-90) Page 328.1 TOTALTRANSMISSION 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Payment By

(c) (b) (a) (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.

Iberdrola Renewables Inc. Iberdrola Renewables Inc. AD 1 Iberdrola Renewables Inc. Exxon Mobile Nevada Power Company LFP 2 Iberdrola Renewables Inc. Exxon Mobile Nevada Power Company AD 3 Idaho Power Company Idaho Power Company Idaho Power Company OS 4 Idaho Power Company Nevada Power Company Idaho Power Company LFP 5 Idaho Power Company NF 6 Idaho Power Company SFP 7 Idaho Power Company OS 8 Idaho Power Company AD 9 Idaho Power Company OS 10 Idaho Power Company AD 11 JP Morgan Ventures Energy Corp. NF 12 JP Morgan Ventures Energy Corp. JP Morgan Ventures Energy Corp. OS 13 JP Morgan Ventures Energy Corp. AD 14 Los Angeles Dept of Water & Power NF 15 Macquarie Energy, LLC NF 16 Macquarie Energy, LLC AD 17 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS 18 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD 19 Morgan Stanley Capital Group, Inc. NF 20 Morgan Stanley Capital Group, Inc. AD 21 Morgan Stanley Capital Group, Inc. SFP 22 Municipal Energy Agency of Nebraska NF 23 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP 24 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD 25 NextEra Energy Resources, LLC NF 26 Pacific Gas & Electric Company OS 27 Pacific Gas & Electric Company OS 28 Pacific Gas & Electric Company NF 29 Powerex Corporation Bonneville Power Administration CAISO LFP 30 Powerex Corporation Bonneville Power Administration CAISO AD 31 Powerex Corporation NF 32 Powerex Corporation AD 33 Powerex Corporation SFP 34

FERC FORM NO. 1 (ED. 12-90) Page 328.2 TOTALTRANSMISSION 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Payment By

(c) (b) (a) (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.

PPL Energy Plus, LLC NF 1 PPL Energy Plus, LLC AD 2 PPL Energy Plus, LLC SFP 3 Public Svc. Co. of CO NF 4 Public Svc. Co. of CO AD 5 Public Svc. Co. of CO SFP 6 Rainbow Energy Marketing Corporation NF 7 Rainbow Energy Marketing Corporation AD 8 Rainbow Energy Marketing Corporation SFP 9 Raser Power Systems, Inc. Raser Power Systems, Inc. Raser Power Systems, Inc. LFP 10 Raser Power Systems, Inc. Raser Power Systems, Inc. Raser Power Systems, Inc. AD 11 Salt River Project NF 12 Seattle City & Light FPL Energy Vansycle, LLC Grant County PUD LFP 13 Seattle City & Light FPL Energy Vansycle, LLC Grant County PUD AD 14 Seattle City & Light NF 15 Sempra Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO 16 Sempra Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD 17 Shell Energy North America NF 18 Shell Energy North America AD 19 Sierra Pacific Power Company OS 20 Sierra Pacific Power Company NF 21 Sierra Pacific Power Company AD 22 Sierra Pacific Power Company AD 23 Southern California Edison SFP 24 Southern California Edison NF 25 Southern California Edison OS 26 State of South Dakota Western Area Power Administration Black Hills Power & Light Company LFP 27 State of South Dakota Western Area Power Administration Black Hills Power & Light Company AD 28 The Energy Authority NF 29 The Energy Authority AD 30 TransAlta Energy Marketing Corporation NF 31 TransAlta Energy Marketing Corporation AD 32 Tri-State Generation & Trans. Tri-State Generation & Trans. OS 33 Tri-State Generation & Trans. Tri-State Generation & Trans. AD 34

FERC FORM NO. 1 (ED. 12-90) Page 328.3 TOTALTRANSMISSION 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 End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Payment By

(c) (b) (a) (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.

Tri-State Generation & Trans. NF 1 Tri-State Generation & Trans. Tri-State Generation & Trans. FNO 2 United States Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 3 United States Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 4 United States Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 5 United States Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv. OS 6 United States Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv. AD 7 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power OS 8 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power AD 9 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power SFP 10 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 11 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 12 Warm Springs Power Enterprises Warm Springs Enterprises Portland General Electric Co OS 13 Warm Springs Power Enterprises Warm Springs Enterprises Portland General Electric Co AD 14 Western Area Power Administration Western Area Power Administration OS 15 Western Area Power Administration Western Area Power Administration AD 16 Western Area Power Administration Western Area Power Administration OS 17 Western Area Power Administration Western Area Power Administration AD 18 Western Area Power Administration Western Area Power Administration NF 19 Western Area Power Administration Western Area Power Administration AD 20 Western Area Power Administration Western Area Power Administration OS 21 Western Area Power Administration Western Area Power Administration AD 22 Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 23 Western Area Power Administration Western Area Power Administration Western Area Power Administration AD 24Accrual True-up 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 328.4 TOTALName 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 Yellowtail Sub 7V11-3,4 Sheridan Substation 2 4,331 4,331 2 Yellowtail Sub 7V11-3,4 Sheridan Substation 2 1,633 1,633 3 Yellowtail Sub 7V11 Sheridan Substation 11 7,416 7,416 4 Yellowtail Sub 7V11 Sheridan Substation 11 7,602 7,602 5 Various 7V11-8 Various 25,789 25,789 6 Various 7V11-8 Various 7 Various 7V11-8 Various 88 88 8 Various 7V11-7 Various 90 90 9 Various 7V11 Sheridan Substation 43 32,344 32,344 10 Various 7V11 Sheridan Substation 43 6,646 6,646 11 Various 7V11-8 Various 12,374 12,374 12 Various 7V11-8 Various 816 816 13 Various 7V11-7 Various 16,438 16,438 14 Various 7V11-7 Wyodak Substation 50 157,346 157,346 15 Various 7V11-7 Wyodak Substation 50 3,705 3,705 16 Midpoint Substation R.S. 369 Summer Lake Sub 17 Various R.S. 237 Various 189 1,102,930 1,102,930 18 Various R.S. 237 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 Bonneville Power Adm 7V11-3,4 Gazley Substation 3 23,150 23,150 23 Bonneville Power Adm 7V11-3 Gazley Substation 3 2,372 2,372 24 Bonneville Power Adm 7V11-3,4 Tieton Substation 2 4,666 4,666 25 Bonneville Power Adm 7V11-3,4 Tieton Substation 2 937 937 26 McNary Substation 7V11-3,4 Hinkle Substation 1 848 848 27 McNary Substation 7V11-3,4 Hinkle Substation 1 153 153 28 USBR Green Springs 7V11-7 Bonneville Power Adm 18 52,471 52,471 29 USBR Green Springs 7V11-7 Bonneville Power Adm 18 5,569 5,569 30 Malin Substation R.S. 368 Malin Substation 618,730 618,730 31 Malin Substation R.S. 368 Malin Substation 63,710 63,710 32 Bonneville Power Adm 7V11-3,4 White Swan/Toppenish 7 32,925 32,925 33 Bonneville Power Adm 7V11-3,4 White Swan/Toppenish 7 3,910 3,910 34

FERC FORM NO. 1 (ED. 12-90) Page 329 3,483 13,164,045 13,164,045Name 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.

Various R.S. 299 Various 160 1,416,059 1,416,059 1 Various R.S. 299 Various 160 208,173 208,173 2 Various 7V11-7 Various 24,791 24,791 3 Various 7V11-8 Various 4 Cardwell-Merwin 7V11-3,4 24 104,239 104,239 5 Cardwell-Merwin 7V11-3,4 24 16,619 16,619 6 Various 7V11-8 Various 149,117 149,117 7 Various 7V11-8 Various 7,432 7,432 8 Various 7V11-7 Various 11,430 11,430 9 Various 7V11-8 Various 10 Various 7V11-8, 9, 11 Various 9,670 9,670 11 Various 7V11-8 Various 4,330 4,330 12 Swift Unit No. 2 R.S. 234 Woodland Substation 13 Swift Unit No. 2 R.S. 234 Woodland Substation 14 Various R.S. 280 Various 105 438,585 438,585 15 Various R.S. 280 Various 105 204,213 204,213 16 Various R.S. 590 Various 17 Various R.S. 590 Various 18 Various 7V11-7 Various 864 864 19 Various 7V11-8 Various 20 Various 7V11-8 Various 21 Enel Cove Fort 7V11-7 Mona Substation 22 Various 7V11-8 Various 2,988 2,988 23 Various 7V11-8 Various 1,010 1,010 24 Targhee Substation R.S. 322 Goshen Substation 4,346 4,346 25 Targhee Substation R.S. 322 Goshen Substation 26 Foote Creek Sub S.A. 130 Various 27 Foote Creek Sub S.A. 130 Various 28 Various 7V11-8 Various 682 682 29 Various 7V11-8 Various 33,286 33,286 30 Various 7V11-8 Various 3,010 3,010 31 Wallula Substation 7V11-5,6,9,11 Wallula Substation 32 Wallula Substation 7V11-5,6,9 Wallula Substation 33 7V11-5,6,9,11 34

FERC FORM NO. 1 (ED. 12-90) Page 329.1 3,483 13,164,045 13,164,045Name 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 Trona Substation 7V11-7 Red Butte/Mona Sub 30 56,556 56,556 2 Trona Substation 7V11-7 Red Butte/Mona Sub 30 7,829 7,829 3 Goshen Substation R.S. 427 Goshen Substation 4 Red Butte Substation 7V11-7 Borah/Brady Sub 75 61,018 61,018 5 Various 7V11-8 Various 27,680 27,680 6 Various 7V11-7 Various 66,989 66,989 7 Antelope Substation R.S. 257 Antelope Substation 15,678 15,678 8 Antelope Substation R.S. 257 Antelope Substation 9 Jim Bridger Sub R.S. 203 Bridger Pump Station 10 Jim Bridger Sub R.S. 203 Bridger Pump Station 11 Various 7V11-8 Various 36,957 36,957 12 Various 7V11-5,6,9,11 Various 13 Various 7V11-8 Various 14 Various 7V11-8 Various 37,787 37,787 15 Various 7V11-8 Various 1,290 1,290 16 Various 7V11-8 Various 11 11 17 Duchesne R.S. 302 Duchesne 3 17,434 17,434 18 Duchesne R.S. 302 Duchesne 3 1,541 1,541 19 Various 7V11-8 Various 159,217 159,217 20 Various 7V11-8 Various 12,873 12,873 21 Various 7V11-7 Various 2,647 2,647 22 Various 7V11-8 Various 1,935 1,935 23 Wallula Substation 7V11-5,6,9,11 Wala-MID-C Path 80 255,567 255,567 24 Wallula Substation 7V11-5,6,9,11 Wala-MID-C Path 80 13,863 13,863 25 Various 7V11-8 Various 26 R.S. 607 27 Sigurd-Glen Canyon R.S. 298 Pinto-Four Corners 28 Various 7V11-8 Various 9 9 29 Bonneville Power Adm 7V11-7 Weed Jct. Substation 80 290,447 290,447 30 Bonneville Power Adm 7V11-7 Weed Jct. Substation 80 18,922 18,922 31 Various 7V11-5,6,8 Various 365,059 365,059 32 Various 7V11-5,6,8 Various 9,217 9,217 33 Various 7V11-7 Various 948 948 34

FERC FORM NO. 1 (ED. 12-90) Page 329.2 3,483 13,164,045 13,164,045Name 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.

Various 7V11-8 Various 9,586 9,586 1 Various 7V11-8 Various 1,066 1,066 2 Various 7V11-7 Various 3,688 3,688 3 Various 7V11-8 Various 8,685 8,685 4 Various 7V11-8 Various 32 32 5 Various 7V11-7 Various 17,628 17,628 6 Various 7V11-8 Various 11,260 11,260 7 Various 7V11-8 Various 419 419 8 Various 7V11-7 Various 17,866 17,866 9 South Milford Sub 7V11-5,6,7,9 Mona Substation 11 45,680 45,680 10 South Milford Sub 7V11-5,6,7,9 Mona Substation 11 3,892 3,892 11 Various 7V11-8 Various 15,803 15,803 12 Wallula Substation 7V11-5,6,7,9 Wala-MID-C Path 25 46,496 46,496 13 Wallula Substation 7V11-5,6,7,9 Wala-MID-C Path 25 1,883 1,883 14 Various 7V11-8 Various 17 17 15 Bonneville Power Adm 7V11-3,4 Various 15 116,828 116,828 16 Bonneville Power Adm 7V11-3,4 Various 15 6,627 6,627 17 Various 7V11-8 Various 530 530 18 Various 7V11-8 Various 448 448 19 Sigurd Sub R.S. 674 20 Various 7V11-8 Various 1,891 1,891 21 Various 7V11-8 Various 947 947 22 Various 7V11-7 Various 1,000 1,000 23 Various 7V11-5,6,7 Various 5,845 5,845 24 Various 7V11-8,9,11 Various 16,199 16,199 25 Sigurd-Glen Canyon R.S. 298 Pinto-Four Corners 26 Yellowtail Sub 7V11-7 Wyodak Substation 4 16,864 16,864 27 Yellowtail Sub 7V11-7 Wyodak Substation 4 1,505 1,505 28 Various 7V11-8 Various 25 25 29 Various 7V11-8 Various 11 11 30 Various 7V11-8 Various 5,406 5,406 31 Various 7V11-8 Various 1,749 1,749 32 Various R.S. 123 Various 31 144,112 144,112 33 Various R.S. 123 Various 31 17,166 17,166 34

FERC FORM NO. 1 (ED. 12-90) Page 329.3 3,483 13,164,045 13,164,045Name 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.

Various 7V11-8 Various 436 436 1 DJ Substation 7V11-3,4 Thermopolis Sub 18 17,613 17,613 2 Walla Walla Sub 7V11-3 Burbank Pumps 1 2,195 2,195 3 Walla Walla Sub 7V11-3 Burbank Pumps 1 4 Redmond Substation R.S. 67 Crooked River Pumps 4 7,347 7,347 5 Various R.S. 286 Various 24,196 24,196 6 Various R.S. 286 Various 1,415 1,415 7 Various R.S. 297 Various 338 2,898,693 2,898,693 8 Various R.S. 297 Various 338 292,993 292,993 9 Various 7V11-8 Various 3,174 3,174 10 Various R.S. 637 Various 101 557,192 557,192 11 Various R.S. 637 Various 101 52,250 52,250 12 Pelton Reregulating R.S. 591 Round Butte Sub 80,634 80,634 13 Pelton Reregulating R.S. 591 Round Butte Sub 7,355 7,355 14 Various R.S. 262 Various 330 1,479,333 1,479,333 15 Various R.S. 262 Various 330 156,206 156,206 16 Various R.S. 263 Various 83,483 83,483 17 Various R.S. 263 Various 8,520 8,520 18 Various 7V11-8 Various 129,311 129,311 19 Various 7V11-8 Various 13,208 13,208 20 Dave Johnston Sub R.S. 664 Various 166,992 166,992 21 Dave Johnston Sub R.S. 664 Various 11,912 11,912 22 Wyoming Distribution 7V11 Wyoming Distribution 1 10,374 10,374 23 Wyoming Distribution 7V11 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 13,164,045Name 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. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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 33,026 23,488 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 4,232,267 67,947 18 384,761 384,761 19 340,200 340,200 20 208,184 208,184 21 26,023 26,023 22 45,398 187,174 141,776 23 16,230 16,230 24 19,043 19,790 747 25 2,513 2,513 26 9,566 9,708 142 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 85,621 115,461 29,840 33 25,535 25,535 34

FERC FORM NO. 1 (ED. 12-90) Page 330 27,323,230 67,812,115 31,498,786 8,990,099Name 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. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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 1,912,432 1,024,573 1 176,622 176,622 2 1,401 1,401 3 6 6 4 291,796 314,429 22,633 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 91,062 37,138 53,924 11 32,018 17,465 14,553 12 75,239 75,239 13 36,813 36,813 14 1,561,042 1,588,290 27,248 15 608,352 789,019 180,667 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 67,812,115 31,498,786 8,990,099Name 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. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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 1 486,000 668,250 182,250 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 2,508,682 961,687 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 2,514,136 19,603 2,494,533 32 58,574 58,574 33 8,325 8,325 34

FERC FORM NO. 1 (ED. 12-90) Page 330.2 27,323,230 67,812,115 31,498,786 8,990,099Name 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. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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 9 245,025 278,663 33,638 10 25,221 25,221 11 113,303 113,303 12 718,875 762,466 43,591 13 50,625 50,625 14 1,460 1,460 15 177,344 251,271 73,927 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 36,337 5,350 30,987 24 900,489 801,708 98,781 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 67,812,115 31,498,786 8,990,099Name 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. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from 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 70,962 12,057 2 4,106 13,509 9,403 3 -23,159 -23,159 4 12,433 12,433 5 24,196 24,196 6 1,415 1,415 7 7,085,533 7,743,416 657,883 8 660,917 660,917 9 18,414 18,414 10 1,991,594 2,089,989 98,395 11 181,181 181,181 12 109,725 109,725 13 9,975 9,975 14 2,057,249 2,607,249 550,000 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 56,945 38,212 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 67,812,115 31,498,786 8,990,099

### 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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 andWestern Area Power Administrationfor 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 andWestern Area Power Administrationfor 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)XAn 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)XAn 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 450.22Name 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 (b) (a) (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

Page331

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 (d) (c) (a) 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) OS Arizona Public Service 1 LFP 1,093,316 1,093,316 370,348 370,348 Arizona Public Service 2 NF 80,392 80,392 20,773 20,773 Arizona Public Service 3 OS 9,942 3,745 6,197 Arizona Public Service 4 SFP 71,146 71,146 18,763 18,763 Arizona Public Service 5 FNS 16,638 16,638 1,769 1,769 Ashland, City of 6 FNS 217,930 217,930 50,243 48,575 Avista Corporation 7 NF 73,464 73,464 12,732 12,732 Avista Corporation 8 LFP 71,485 71,485 Basin Elect. Power Coop 9 OS 181,813 181,813 Big Horn Rural Electric 10 OS Bonneville Power Admin. 11 AD 26,121 9,121 17,000 9,021 9,021 Bonneville Power Admin. 12 FNS 6,555,934 6,555,934 Bonneville Power Admin. 13 LFP 56,487,763 3,010,860 53,476,903 5,394,463 5,394,463 Bonneville Power Admin. 14 NF 1,341,217 1,341,217 309,750 309,750 Bonneville Power Admin. 15 OS 32,536,797 1,557,921 165,008 30,813,868 5,226,006 5,049,853 Bonneville Power Admin. 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649 TOTALName 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 (d) (c) (a) 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) SFP 208,244 208,244 52,522 52,522 Bonneville Power Admin. 1 AD 26,960 30,716 -3,756 CA Ind. Sys. Operator 2 OS 1,829,210 1,829,210 CA Ind. Sys. Operator 3 SFP 2,867,483 2,867,483 533,427 533,427 CA Ind. Sys. Operator 4 AD 13,415 13,415 1,808 1,808 Deseret Pwr Elect. Coop 5 LFP 3,391,570 3,391,570 168,010 168,010 Deseret Pwr Elect. Coop 6 NF 1,327,332 1,327,332 183,089 183,089 Deseret Pwr Elect. Coop 7 AD 113 113 150 150 El Paso Elect. Co. 8 NF 181 181 200 200 El Paso Elect. Co. 9 OS 63,922 63,922 Flathead Elect. Coop. 10 OS 175,965 175,965 Hermiston Generating Co 11 OS Idaho Power Company 12 AD 514,482 697,502 -183,020 Idaho Power Company 13 FNS 6,994 6,994 Idaho Power Company 14 LFP 6,121,548 6,121,548 3,257,310 3,206,147 Idaho Power Company 15 NF 1,050,762 1,050,762 365,715 311,953 Idaho Power Company 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649 TOTALName 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 (d) (c) (a) 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) OS 10,767,019 10,767,019 Idaho Power Company 1 SFP 2,180 2,180 1,032 1,032 Idaho Power Company 2 FNS 182,791 182,791 Moon Lake Elect. Assoc. 3 AD 434 434 41 41 Morgan City Corporation 4 NF 200,194 200,194 60,588 60,588 Nevada Power Company 5 OS 69,299 69,299 Nevada Power Company 6 SFP 214,659 214,659 79,037 79,037 Nevada Power Company 7 NF 391,630 391,630 94,852 94,374 NorthWestern Corp. 8 OS 26,991 26,991 NorthWestern Corp. 9 SFP 118,134 118,134 27,233 27,233 NorthWestern Corp. 10 LFP 966,000 966,000 173,713 173,713 Platte River Power 11 OS 15,333 15,333 Platte River Power 12 NF 1,759 1,759 1,617 1,617 Portland Gen. Electrric 13 OS 908 908 Portland Gen. Electric 14 SFP -1,025,820 -1,025,820 Portland Gen. Electric 15 SFP -1,894,500 -1,894,500 Powerex Corporation 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649 TOTALName 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 (d) (c) (a) 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) LFP 901,862 901,862 177,879 169,116 Public Service Co of CO 1 NF 4,524 4,524 855 855 Public Service Co of CO 2 LFP 591,311 591,311 116,760 116,760 Public Service Co of NM 3 OS 21,148 21,148 Public Service Co of NM 4 NF 499 499 160 160 Salt River Project 5 NF 41,504 41,504 6,480 6,480 Sierra Pacific Power Co 6 OS 5,986 5,986 Sierra Pacific Power Co 7 OLF 9,523 9,523 Surprise Valley Electr. 8 LFP 901,862 901,862 212,197 203,428 Tri-State Gen & Transm 9 NF 563,215 563,215 249,472 249,472 Tri-State Gen & Transm 10 OS 222,304 222,304 Tri-State Gen & Transm 11 NF 1,093 1,093 218 218 Tucson Electric Power 12 OS 127 127 Tucson Electric Power 13 AD -109,300 -1,500 -107,800 -1,512 -1,512 Utah Assoc Muni Pwr Sys 14 NF 445 445 89 89 Utah Assoc Muni Pwr Sys 15 LFP -2,310,796 -2,310,796 Westport Field Srv LLC 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649 TOTALName 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 (d) (c) (a) 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) OS Western Area Power Adm. 1 AD -7,331 -819 -6,512 -311 -311 Western Area Power Adm. 2 FNS 4,812,992 4,812,992 Western Area Power Adm. 3 LFP 2,220,000 2,220,000 414,790 414,790 Western Area Power Adm. 4 NF 594,452 594,452 234,189 234,189 Western Area Power Adm. 5 OS 423,870 423,870 Western Area Power Adm. 6 SFP 80,650 80,650 45,948 45,948 Western Area Power Adm. 7 1,485,559 1,485,559 Accrual True-up 8 9 10 11 12 13 14 15 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4 17,570,670 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649 TOTAL

### 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 BigHorn 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)XAn 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 isEl 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 isHermiston 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)XAn 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)XAn 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 isWestern 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)XAn 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 450.4Name 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 (b) (a) No. 1,329,375 Industry Association Dues 1 Nuclear Power Research Expenses 2 Other Experimental and General Research Expenses 3 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5 6 Community & Economic Development and 7 Corporate Memberships and Subscriptions 8 10,000 Bend 2030 9 5,000 CCD Business Development Corp 10 91,481 Economic Development Corp of Utah 11 7,500 Idaho Economic Development Association 12 10,000 Governor's Utah Economic Summit 13 10,000 Oregon Economic Development Association 14 8,000 Port Of Columbia 15 10,000 State of Utah 16 5,500 Uintah County Economic Development 17 5,000 Utah Center For Rural Life 18 57,072 Utah Sports Commission 19 5,000 Wyoming Business Council 20 5,000 Americas' SAP User Group 21 28,000 Associated Oregon Industries 22 25,000 Four County Economic Development Corp 23 9,000 Intermountain Electrical Association 24 418,088 Northern Tier Transmission Group 25 11,000 Oregon Business Association 26 33,228 Oregon Business Council 27 5,000 Oregon Solar Energy Industries Association 28 5,000 Oregon Sports Authority Foundation 29 69,069 Pacific Northwest Utilities Conference 30 39,400 Portland Business Alliance 31 18,000 Rocky Mountain Electrical League 32 30,255 Salt Lake Area Chamber of Commerce 33 10,000 The Climate Registry 34 20,000 Utah Foundation 35 6,000 Utah Manufacturers Association 36 20,000 Utah Taxpayers Association 37 16,408 Watson & Renner 38 28,511 West Association 39 3,786,077 Western Electricity Coordinating Council 40 42,004 Western Energy Institute 41 5,000 Wyoming Business Alliance 42 9,523 Wyoming Taxpayers Association 43 7,500 Yakima County Development 44 153,729 Other 45

16,291,649

FERC FORM NO. 1 (ED. 12-94) Page 335

46 TOTALName 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 (b) (a) No. 6 16,240 Directors Fees - Regional Advisory Boards 7 8 General: 9 7,470,918 MidAmerican Energy Holdings Company Management Fee 10 -689 Other 11 12 Regulatory Asset Amortization: 13 112,218 Glenrock Mine Excluding Reclamation - UT 14 21,250 Goodnoe Hills Settlement - WY 15 2,289,365 Transition Plan - OR 16 27,627 Lake Side Settlement - WY 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

16,291,649

FERC FORM NO. 1 (ED. 12-94) Page 335.1

46 TOTALName 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 (d) (b) (a) 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)
31,747,938 31,747,938 1Intangible Plant 129,276,321 129,276,321 2Steam Production Plant 3Nuclear Production Plant 16,005,731 15,836,545 169,186 4Hydraulic Production Plant-Conventional 5Hydraulic Production Plant-Pumped Storage 107,805,700 107,805,700 6Other Production Plant 71,678,696 71,678,696 7Transmission Plant 142,300,998 142,300,998 8Distribution Plant 9Regional Transmission and Market Operation 37,247,165 34,325,996 2,921,169 10General Plant 11Common Plant-Electric 536,062,549 501,224,256 34,838,293 12TOTAL

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 ChargesName 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. (c) (b) (a) (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)

WIND GENERATION 12Dunlap Ranch I 13 24.87 -1.00 4.06 341.00 WY 366 14 24.87 -1.00 4.06 343.00 WY 232,074 15 16DISTRIBUTION PLANT 17 50.00 -90.00 3.80 37.94 R1.5 364.00 CA 51,952 18 65.00 -55.00 2.35 51.70 S-.5 365.00 CA 32,245 19 50.00 -30.00 2.55 34.58 R5 366.00 CA 15,315 20 45.00 1.07 29.50 S6 367.00 CA 16,737 21 50.00 -52.00 3.36 32.34 R5 368.00 CA 46,821 22 55.00 -5.00 1.56 44.37 R1 369.10 CA 8,371 23 60.00 -5.00 1.50 48.69 R4 369.20 CA 14,239 24 26.00 4.30 13.24 R2.5 370.00 CA 3,911 25 25.00 -30.00 4.08 13.85 L0 371.00 CA 271 26 35.00 -35.00 3.58 16.36 R3 373.00 CA 662 27 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)XAn 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 450.1Name 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

(c) (b) (a) 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.

Public Service Commission of Utah: 1 Annual Fee 3,648,134 3,648,134 2Rate Case 1,343,711 1,343,711 3 4Public Utility Commission of Oregon: 5Annual Fee 2,145,364 2,145,364 6Rate Case 1,261,788 1,261,788 7 8Public Service Commission of Wyoming: 9Annual Fee 1,210,427 1,210,427 10Rate Case 1,000,801 1,000,801 11 12Washington Utilities and Transportation 13Commission: 14Annual Fee 576,475 576,475 15Rate Case 646,375 646,375 16 17Idaho Public Utilities Commission: 18Annual Fee 353,980 353,980 19Rate Case 826,933 826,933 20Other State Regulatory Expenses 17,580 17,580 21 22Public Utilities Commission of California: 23Annual Fee 952 952 24Rate Case 851,318 851,318 25 26Rate Cases - All States 16,890 16,890 27 28Federal Energy Regulatory Commission: 29Annual Fee 1,917,327 1,917,327 30Annual Land Use Fee 596,587 596,587 31 Transmission Rate Case 762,536 762,536 32FERC Other Regulatory 704,704 704,704 33 34Other Regulatory 44,958 44,958 35 36 61,378 Deferred Regulatory Commission Expense 37 38 39 40 41 42 43 44 45

FERC FORM NO. 1 (ED. 12-96) Page 350 46TOTAL 10,449,246 7,477,594 17,926,840 61,378Name 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. (j) (i) (f) (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 2 3,648,134 928 Electric 3 1,343,711 928 4 5 Electric 6 2,145,364 928 Electric 7 1,261,788 928 8 9 Electric 10 1,210,427 928 Electric 11 1,000,801 928 12 13 14 Electric 15 576,475 928 Electric 16 646,375 928 17 18 Electric 19 353,980 928 Electric 20 826,933 928 Electric 21 17,580 928 22 23 Electric 24 952 928 Electric 25 851,318 928 26 Electric 27 16,890 928 28 29 Electric 30 1,917,327 928 Electric 31 596,587 928 Electric 32 762,536 928 Electric 33 704,704 928 34 Electric 35 44,958 928 36 80,879 17,580 928 37,081 37 38 39 40 41 42 43 44 45

FERC FORM NO. 1 (ED. 12-96) Page 351 46 17,926,840 37,081 17,580 80,879Name 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 (b) (a) Classification 1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(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

B. Electric R, D & D Performed Externally 1 Electric Power Research Institute (1) Research Support 2 - Membership dues 3 - Seismic studies of substation equipment program 4 - Toxic release inventory reporting for power plants program 5 - Utility gasification program 6 National Electric Testing, Research & Applications Center (4) Research Support 7 - Membership dues 8 - Participation 9 Solar Electric Power Association (4) Research Support 10 - Membership dues 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 352Name 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 3 547,651 930.2 547,651 4 20,000 560 20,000 5 12,000 557 12,000 6 5,000 557 5,000 7 8 23,750 930.2 23,750 4,501 9 580 4,501 10 11 7,000 930.2 7,000 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)XAn 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 450.1Name 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 (c) (b) (a) 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.

Electric 1 Operation 2 87,442,511 Production 3 10,172,322 Transmission 4 Regional Market 5 41,229,347 Distribution 6 41,273,457 Customer Accounts 7 5,288,051 Customer Service and Informational 8 Sales 9 37,750,552 Administrative and General 10 223,156,240 TOTAL Operation (Enter Total of lines 3 thru 10) 11 Maintenance 12 46,048,473 Production 13 11,251,850 Transmission 14 Regional Market 15 69,824,793 Distribution 16 1,869,579 Administrative and General 17 128,994,695 TOTAL Maintenance (Total of lines 13 thru 17) 18 Total Operation and Maintenance 19 133,490,984 Production (Enter Total of lines 3 and 13) 20 21,424,172 Transmission (Enter Total of lines 4 and 14) 21 Regional Market (Enter Total of Lines 5 and 15) 22 111,054,140 Distribution (Enter Total of lines 6 and 16) 23 41,273,457 Customer Accounts (Transcribe from line 7) 24 5,288,051 Customer Service and Informational (Transcribe from line 8) 25 Sales (Transcribe from line 9) 26 39,620,131 Administrative and General (Enter Total of lines 10 and 17) 27 352,150,935 352,150,935 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28 Gas 29 Operation 30 Production-Manufactured Gas 31 Production-Nat. Gas (Including Expl. and Dev.) 32 Other Gas Supply 33 Storage, LNG Terminaling and Processing 34 Transmission 35 Distribution 36 Customer Accounts 37 Customer Service and Informational 38 Sales 39 Administrative and General 40 TOTAL Operation (Enter Total of lines 31 thru 40) 41 Maintenance 42 Production-Manufactured Gas 43 Production-Natural Gas (Including Exploration and Development) 44 Other Gas Supply 45 Storage, LNG Terminaling and Processing 46 Transmission 47

FERC FORM NO. 1 (ED. 12-88) Page 354Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Classification (c) (b) (a) Direct Payroll Allocation of Total (d) Distribution Payroll charged for Clearing Accounts DISTRIBUTION OF SALARIES AND WAGES (Continued)

Distribution 48 Administrative and General 49 TOTAL Maint. (Enter Total of lines 43 thru 49) 50 Total Operation and Maintenance 51 Production-Manufactured Gas (Enter Total of lines 31 and 43) 52 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53 Other Gas Supply (Enter Total of lines 33 and 45) 54 Storage, LNG Terminaling and Processing (Total of lines 31 thru 55 Transmission (Lines 35 and 47) 56 Distribution (Lines 36 and 48) 57 Customer Accounts (Line 37) 58 Customer Service and Informational (Line 38) 59 Sales (Line 39) 60 Administrative and General (Lines 40 and 49) 61 TOTAL Operation and Maint. (Total of lines 52 thru 61) 62 Other Utility Departments 63 Operation and Maintenance 64 352,150,935 352,150,935 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65 Utility Plant 66 Construction (By Utility Departments) 67 147,587,388 147,587,388 Electric Plant 68 Gas Plant 69 Other (provide details in footnote): 70 147,587,388 147,587,388 TOTAL Construction (Total of lines 68 thru 70) 71 Plant Removal (By Utility Departments) 72 9,659,614 9,659,614 Electric Plant 73 Gas Plant 74 Other (provide details in footnote): 75 9,659,614 9,659,614 TOTAL Plant Removal (Total of lines 73 thru 75) 76 Other Accounts (Specify, provide details in footnote): 77 27,117,060 27,117,060 Fuel Stock 78 429,366 429,366 Miscellaneous Other Income Deductions 79 689,699 689,699 Miscellaneous Nonoperating/Nonutility 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 28,236,125 28,236,125 TOTAL Other Accounts 95 537,634,062 537,634,062 TOTAL SALARIES AND WAGES 96

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 356Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Description of Item(s) Balance at End of (c) (b) (a) Balance at End of AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

Quarter 1 Quarter 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 Energy 1Net Purchases (Account 555) 2Net Sales (Account 447) 3Transmission Rights 4Ancillary Services 5Other Items (list separately) 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 397 46 TOTALName 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

144,444 Scheduling, System Control and Dispatch 1Reactive Supply and Voltage 2 9,857,432 MWh 58,287,704 9,242,739 MWh 57,766,387 Regulation and Frequency Response 3 -4,614,914 MWh -145,195 Energy Imbalance 4 25,129,384 MWh 68,807,239 23,896,498 MWh 65,622,051 Operating Reserve - Spinning 5 25,007,148 MWh 68,479,528 23,896,498 MWh 65,622,051 Operating Reserve - Supplement 6 -4,219 Other 7 55,519,275 195,429,276 57,035,735 189,010,489 Total (Lines 1 thru 7) 8

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)XAn 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 450.1Name 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

(c) (b) (a) 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

1,050 1,668 5,276 118 8,152 1800 7 16,264 January 1 629 1,588 5,276 101 8,002 800 22 15,596 February 2 1,346 1,530 5,276 88 7,574 1900 9 15,814 March 3 3,025 4,786 15,828 307 23,728 47,674 Total for Quarter 1 4 744 1,489 5,276 85 7,248 800 1 14,842 April 5 828 1,424 5,276 88 7,092 800 6 14,708 May 6 549 1,817 6,111 84 8,824 1700 28 17,385 June 7 2,121 4,730 16,663 257 23,164 46,935 Total for Quarter 2 8 1,075 1,863 5,654 88 9,398 1600 27 18,078 July 9 1,246 1,919 5,654 98 9,382 1600 17 18,299 August 10 1,246 1,686 5,635 74 8,168 1700 3 16,809 September 11 3,567 5,468 16,943 260 26,948 53,186 Total for Quarter 3 12 1,244 1,543 5,667 69 7,426 1600 1 15,949 October 13 1,515 1,587 4,800 121 8,592 1800 23 16,615 November 14 842 1,603 4,800 110 8,402 1800 29 15,757 December 15 3,601 4,733 15,267 300 24,420 48,321 Total for Quarter 4 16

12,314 19,717 64,701 1,124 98,260 196,116 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)XAn 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)XAn 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 450.2Name 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

(c) (b) (a) 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

January 1 February 2March 3Total for Quarter 1 4April 5May 6June 7Total for Quarter 2 8July 9August 10September 11Total for Quarter 3 12October 13November 14December 15Total for Quarter 4 16Total Year to Date/Year 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400aName 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.

SOURCES OF ENERGY 1Generation (Excluding Station Use): 2 44,918,646

Steam 3Nuclear 4 3,748,308

Hydro-Conventional 5 -2,784

Hydro-Pumped Storage 6 8,975,021

Other 7Less Energy for Pumping 8 57,639,191

Net Generation (Enter Total of lines 3 through 8) 9

11,417,025

Purchases 10Power Exchanges: 11 14,493,755 Received 12 14,289,088 Delivered 13 204,667 Net Exchanges (Line 12 minus line 13) 14Transmission For Other (Wheeling) 15 13,164,045 Received 16 13,164,045 Delivered 17Net Transmission for Other (Line 16 minus line 17) 18

-300,756 Transmission By Others Losses 19 68,960,127 TOTAL (Enter Total of lines 9, 10, 14, 18 and 19) 20 DISPOSITION OF ENERGY 21 53,015,534 Sales to Ultimate Consumers (Including Interdepartmental Sales) 22

220,852 Requirements Sales for Resale (See instruction 4, page 311.) 23

11,193,740 Non-Requirements Sales for Resale (See instruction 4, page 311.) 24

Energy Furnished Without Charge 25 142,578 Energy Used by the Company (Electric Dept Only, Excluding Station Use) 26

4,387,423 Total Energy Losses 27 68,960,127 TOTAL (Enter Total of Lines 22 Through 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 (c) (b) (a) 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) January 29 7 8,152 1,076,008 1800 PST 6,184,473 February 30 22 8,002 878,419 0800 PST 5,381,058 March 31 9 7,574 985,758 1900 PST 5,638,659 April 32 6 7,264 1,034,439 0900 PDT 5,371,748 May 33 6 7,092 1,091,408 0800 PDT 5,510,114 June 34 28 8,824 800,018 1700 PDT 5,488,340 July 35 27 9,398 759,612 1600 PDT 6,264,414 August 36 16 9,418 783,730 1600 PDT 6,053,365 September 37 3 8,168 866,699 1700 PDT 5,428,087 October 38 1 7,426 898,230 1600 PDT 5,498,485 November 39 23 8,592 924,018 1800 PST 5,777,818 December 40 29 8,402 1,095,401 1800 PST 6,363,566

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)XAn 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 450.1Cholla Carbon Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Item (b) (a) (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.

Steam Steam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Full Outdoor Outdoor Boiler 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1981 1954 3Year Originally Constructed 1981 1957 4Year Last Unit was Installed 414.00 188.60 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 397 175 6Net Peak Demand on Plant - MW (60 minutes) 7834 8750 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 395 172 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 69 11 Average Number of Employees 2621160000 1296004000 12Net Generation, Exclusive of Plant Use - KWh 2468743 956546 13Cost of Plant: Land and Land Rights 58700214 15099265 14Structures and Improvements 459194385 103140699 15Equipment Costs 39000 6587976 16Asset Retirement Costs 520402342 125784486 17Total Cost 1257.0105 666.9379 18Cost per KW of Installed Capacity (line 17/5) Including 1808025 45596 19Production Expenses: Oper, Supv, & Engr 51488605 20657109 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 6994684 1489090 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 1199979 2113830 25Electric Expenses 1936373 4334676 26Misc Steam (or Nuclear) Power Expenses 440 0 27Rents 0 0 28Allowances 1881910 0 29Maintenance Supervision and Engineering 411499 416124 30Maintenance of Structures 7201452 2448463 31 Maintenance of Boiler (or reactor) Plant 783588 1020130 32Maintenance of Electric Plant 2811384 266812 33Maintenance of Misc Steam (or Nuclear) Plant 76517939 32791830 34Total Production Expenses 0.0292 0.0253 35Expenses per Net KWh Coal Oil Composite Coal Oil Composite 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons Barrels Tons Barrels 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 595236 1978 0 1461977 3855 0 38Quantity (Units) of Fuel Burned 11941 138000 0 9321 130414 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 33.592 103.502 0.000 32.778 93.395 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 34.360 103.502 0.000 34.972 93.395 0.000 41 Average Cost of Fuel per Unit Burned 1.439 17.858 1.452 1.876 17.051 1.888 42Average Cost of Fuel Burned per Million BTU 0.016 0.000 0.016 0.020 0.000 0.020 43Average Cost of Fuel Burned per KWh Net Gen 10968.605 8.845 10977.450 10397.977 8.056 10406.033 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402Hunter Unit No. 1 Hayden Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Item (b) (a) (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.

Steam Steam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Outdoor Boiler Outdoor Boiler 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1978 1965 3Year Originally Constructed 1978 1976 4Year Last Unit was Installed 457.70 81.40 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 429 79 6Net Peak Demand on Plant - MW (60 minutes) 7027 8760 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 418 78 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 2572955000 658624000 12Net Generation, Exclusive of Plant Use - KWh 9688975 379735 13Cost of Plant: Land and Land Rights 63087853 6012420 14Structures and Improvements 270326440 62566079 15Equipment Costs 948199 532363 16Asset Retirement Costs 344051467 69490597 17Total Cost 751.6965 853.6928 18Cost per KW of Installed Capacity (line 17/5) Including 0 230757 19Production Expenses: Oper, Supv, & Engr 35497583 12449623 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 2817013 983622 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 266648 25Electric Expenses 1630831 508004 26Misc Steam (or Nuclear) Power Expenses 3850 0 27Rents 0 0 28Allowances 0 300437 29Maintenance Supervision and Engineering 2681686 255415 30Maintenance of Structures 11140805 915621 31 Maintenance of Boiler (or reactor) Plant 4518436 358309 32Maintenance of Electric Plant 165029 332185 33Maintenance of Misc Steam (or Nuclear) Plant 58455233 16600621 34Total Production Expenses 0.0227 0.0252 35Expenses per Net KWh Coal Oil Composite Coal Oil Composite 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons Barrels Tons Barrels 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 307335 254 0 1210133 8614 0 38Quantity (Units) of Fuel Burned 11542 137377 0 11272 138000 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 38.449 104.561 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 40.342 104.561 0.000 28.601 0.000 0.000 41 Average Cost of Fuel per Unit Burned 1.748 18.119 1.755 1.269 17.759 1.299 42Average Cost of Fuel Burned per Million BTU 0.019 0.000 0.019 0.013 0.000 0.013 43Average Cost of Fuel Burned per KWh Net Gen 10771.255 2.225 10773.480 10603.331 19.405 10622.736 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.1Jim Bridger Huntington Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Item (b) (a) (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.

Steam Steam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Semi-Outdoor Outdoor Boiler 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1974 1974 3Year Originally Constructed 1979 1977 4Year Last Unit was Installed 1545.10 996.00 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 1426 893 6Net Peak Demand on Plant - MW (60 minutes) 8754 8567 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 1412 911 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 335 163 11 Average Number of Employees 9833000000 6107379000 12Net Generation, Exclusive of Plant Use - KWh 1161925 2386782 13Cost of Plant: Land and Land Rights 139527507 115210321 14Structures and Improvements 890582328 689981960 15Equipment Costs 4557783 2342186 16Asset Retirement Costs 1035829543 809921249 17Total Cost 670.3964 813.1739 18Cost per KW of Installed Capacity (line 17/5) Including 16396216 25706 19Production Expenses: Oper, Supv, & Engr 171454601 86524665 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 4209728 8276929 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 5958 0 25Electric Expenses -12919410 10696874 26Misc Steam (or Nuclear) Power Expenses 263196 3311 27Rents 0 0 28Allowances 539711 1346600 29Maintenance Supervision and Engineering 8534063 2296785 30Maintenance of Structures 23962462 13486036 31 Maintenance of Boiler (or reactor) Plant 7817940 4313740 32Maintenance of Electric Plant 2669801 1237313 33Maintenance of Misc Steam (or Nuclear) Plant 222934266 128207959 34Total Production Expenses 0.0227 0.0210 35Expenses per Net KWh Coal Oil Composite Coal Oil Composite 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons Barrels Tons Barrels 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 2687375 12209 0 5450917 17766 0 38Quantity (Units) of Fuel Burned 11923 138000 0 9227 138000 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 32.847 105.056 0.000 32.259 93.298 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 31.719 105.056 0.000 31.150 93.298 0.000 41 Average Cost of Fuel per Unit Burned 1.330 18.126 1.349 1.688 16.097 1.703 42Average Cost of Fuel Burned per Million BTU 0.014 0.000 0.014 0.017 0.000 0.017 43Average Cost of Fuel Burned per KWh Net Gen 10492.431 11.587 10504.018 10229.994 10.472 10240.466 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.2Hermiston Little Mountain Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Item (b) (a) (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.

Combined Cycle Gas Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Outdoor Outdoor Boiler 2Type of Constr (Conventional, Outdoor, Boiler, etc) 1996 1972 3Year Originally Constructed 1996 1972 4Year Last Unit was Installed 279.60 16.00 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 244 16 6Net Peak Demand on Plant - MW (60 minutes) 8160 8150 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 237 14 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 6 11 Average Number of Employees 1595689000 100773000 12Net Generation, Exclusive of Plant Use - KWh 842245 635 13Cost of Plant: Land and Land Rights 12844996 337028 14Structures and Improvements 156205792 5219987 15Equipment Costs 214373 0 16Asset Retirement Costs 170107406 5557650 17Total Cost 608.3956 347.3531 18Cost per KW of Installed Capacity (line 17/5) Including 0 0 19Production Expenses: Oper, Supv, & Engr 58376865 13355445 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 6473512 971137 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 177184 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 64850377 14503766 34Total Production Expenses 0.0406 0.1439 35Expenses per Net KWh Gas Gas 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 1822511 0 0 11617259 0 0 38Quantity (Units) of Fuel Burned 1044 0 0 1015 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 7.328 0.000 0.000 5.025 0.000 0.000 40Avg 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 7.018 0.000 0.000 4.948 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.133 0.000 0.000 0.037 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 18884.155 0.000 0.000 7393.052 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.3Currant Creek Gadsby Gas Peakers Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PacifiCorp X 04/18/2011 2010/Q4

Line No. Item (b) (a) (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.

Combined Cycle Gas Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Outdoor Outdoor 2Type of Constr (Conventional, Outdoor, Boiler, etc) 2005 2002 3Year Originally Constructed 2006 2002 4Year Last Unit was Installed 566.90 181.10 5Total Installed Cap (Max Gen Name Plate Ratings-MW) 567 124 6Net Peak Demand on Plant - MW (60 minutes) 8480 8760 7Plant Hours Connected to Load 0 0 8Net Continuous Plant Capability (Megawatts) 550 120 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 19 0 11 Average Number of Employees 2536660000 255281000 12Net Generation, Exclusive of Plant Use - KWh 3403277 0 13Cost of Plant: Land and Land Rights 43827265 4241952 14Structures and Improvements 307413223 74726370 15Equipment Costs 134848 0 16Asset Retirement Costs 354778613 78968322 17Total Cost 625.8222 436.0482 18Cost per KW of Installed Capacity (line 17/5) Including 79852 0 19Production Expenses: Oper, Supv, & Engr 131063441 21345038 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 2617822 1314264 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 874 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 500930 184471 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 1246435 2593345 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 135509354 25437118 34Total Production Expenses 0.0534 0.0996 35Expenses per Net KWh Gas Gas 36Fuel: Kind (Coal, Gas, Oil, or Nuclear) MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 2903816 0 0 17850615 0 0 38Quantity (Units) of Fuel Burned 1044 0 0 1059 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 7.351 0.000 0.000 7.342 0.000 0.000 40Avg 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 7.040 0.000 0.000 6.931 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.084 0.000 0.000 0.052 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 11877.508 0.000 0.000 7454.884 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.49. 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.

Dave Johnston Craig Colstrip 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 Semi-Outdoor Conventional Outdoor Boiler 2 1959 1984 1979 3 1972 1986 1980 4 816.80 155.60 172.10 5 739 156 166 6 8760 8759 8738 7 0 0 0 8 762 148 165 9 0 0 0 10 179 0 0 11 4699767000 1192652000 1280372000 12 10449793 1355853 137086 13 136781636 58269930 36555498 14 720141128 158023784 131117558 15 11315101 39236 35149 16 878687658 217688803 167845291 17 1075.7684 1399.0283 975.2777 18 571600 23305 359605 19 45364783 12505908 20249991 20 0 0 0 21 31079 916378 1483108 22 0 0 0 23 0 0 0 24 0 30744 640260 25 17884777 2096039 1332605 26 37178 11536 984 27 0 0 0 28 0 244102 632833 29 3141444 337249 465703 30 15993970 2011204 4374004 31 10163144 221939 1340513 32 1078857 357053 905893 33 94266832 18755457 31785499 34 0.0201 0.0157 0.0248 35 Coal Oil Composite Coal Oil Composite Coal Oil Composite 36 Tons Barrels Tons Barrels Tons Barrels 37 734650 968 0 3309283 41961 0 652589 116 0 38 8432 140000 0 7956 138000 0 9968 133693 0 39 14.581 92.012 0.000 12.786 99.452 0.000 29.993 121.915 0.000 40 16.902 92.012 0.000 12.447 99.452 0.000 30.910 121.915 0.000 41 1.002 15.649 1.009 0.782 17.159 0.858 1.550 21.714 1.556 42 0.010 0.000 0.010 0.009 0.001 0.010 0.016 0.000 0.016 43 10387.667 4.774 10392.441 11204.623 51.749 11256.372 10161.294 0.511 10161.805 44

FERC FORM NO. 1 (REV. 12-03) Page4039. 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 - Total Plant Hunter Unit No. 3 Hunter Unit 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 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 1978 1980 1983 3 1983 1980 1983 4 1247.80 294.50 495.60 5 1132 259 470 6 8741 7845 8321 7 0 0 0 8 1137 259 460 9 0 0 0 10 212 0 0 11 7536395000 1667003000 3296437000 12 29653351 9688975 10275401 13 206170324 51968521 91113950 14 837138123 157360861 409450822 15 2844597 948199 948199 16 1075806395 219966556 511788372 17 862.1625 746.9153 1032.6642 18 0 0 0 19 103724019 24501492 43724944 20 0 0 0 21 8432244 2809276 2805955 22 0 0 0 23 0 0 0 24 0 0 0 25 2085072 -2612326 3066567 26 11550 3850 3850 27 0 0 0 28 0 0 0 29 7230537 2408766 2140085 30 25572721 5719032 8712884 31 8053505 1407896 2127173 32 745458 264114 316315 33 155855106 34502100 62897773 34 0.0207 0.0207 0.0191 35 Coal Oil Composite Coal Oil Composite Coal Oil Composite 36 Tons Barrels Tons Barrels Tons Barrels 37 830460 5116 0 3531269 23580 0 1490676 9850 0 38 11397 138000 0 11262 138000 0 11179 138000 0 39 0.000 0.000 0.000 29.640 103.202 0.000 0.000 0.000 0.000 40 28.875 0.000 0.000 28.684 103.202 0.000 28.645 0.000 0.000 41 1.267 17.612 1.292 1.273 17.806 1.302 1.281 17.947 1.310 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 10554.063 18.134 10572.197 10110.225 17.319 10127.544 44

FERC FORM NO. 1 (REV. 12-03) Page403.19. 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.
Gadsby Steam Plant Wyodak Naughton 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 Outdoor Boiler Conventional 2 1951 1963 1978 3 1955 1971 1978 4 251.60 707.20 289.70 5 194 708 278 6 1661 8760 8025 7 0 0 0 8 231 700 268 9 0 0 0 10 35 140 59 11 104123000 5339603000 2047508000 12 1252090 4290826 210526 13 15053899 69837827 50594075 14 63130224 370503279 281199857 15 587008 11639026 490453 16 80023221 456270958 332494911 17 318.0573 645.1795 1147.7215 18 97491 192179 299719 19 12131762 91410507 18768172 20 0 0 0 21 18 5648415 0 22 0 0 0 23 0 0 0 24 0 27718 0 25 3681887 10584401 4081592 26 0 1203 3041 27 0 0 0 28 0 1511638 5028 29 209753 1441379 515248 30 1788302 7944104 7060084 31 955412 1500466 1683796 32 124725 1182830 289616 33 18989350 121444840 32706296 34 0.1824 0.0227 0.0160 35 Coal Gas Composite Gas Coal Oil Composite 36 Tons MCF MCF 0 0 Tons Barrels 37 2817478 247058 0 1569575 0 0 1537341 6245 0 38 9858 1029 0 1049 0 0 7776 138000 0 39 32.477 7.083 0.000 7.729 0.000 0.000 11.858 98.961 0.000 40 31.823 7.083 0.000 7.729 0.000 0.000 11.806 98.961 0.000 41 1.614 6.886 1.638 7.369 0.000 0.000 0.759 17.074 0.784 42 0.017 0.000 0.017 0.117 0.000 0.000 0.009 0.000 0.009 43 10403.644 47.592 10451.236 15811.771 0.000 0.000 11676.499 17.677 11694.176 44

FERC FORM NO. 1 (REV. 12-03) Page403.29. 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.

Chehalis Camas Co-Gen Blundell 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 Steam - Geothermal Steam 1 Outdoor Indoor Outdoor Boiler 2 2003 1984 1996 3 2003 2007 1996 4 593.30 38.10 61.50 5 516 36 28 6 3651 8607 7000 7 0 0 0 8 520 34 22 9 0 0 0 10 17 22 0 11 1288256000 247359000 94061000 12 1973791 41195596 0 13 23249210 7906027 5733734 14 317858946 68805675 28716806 15 689117 1336278 0 16 343771064 119243576 34450540 17 579.4220 3129.7527 560.1714 18 191030 56831 0 19 79197671 0 0 20 0 0 0 21 0 6726 0 22 0 3655727 0 23 0 0 0 24 2392798 0 7 25 0 1739984 0 26 34243 6246 0 27 0 0 0 28 0 0 0 29 3045 225755 0 30 0 164458 0 31 1285471 721856 505521 32 0 64240 0 33 83104258 6641823 505528 34 0.0645 0.0269 0.0054 35 Gas 36 MCF 37 00 0 9348871 0 0 0 0 0 38 00 0 1035 0 0 0 0 0 39 0.000 0.000 0.000 8.471 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 8.471 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 8.183 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.061 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 7512.959 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.39. 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 0.00 591.30 0.00 5 0 581 0 6 0 7569 0 7 0 0 0 8 0 558 0 9 0 0 0 10 0 21 0 11 0 2537046000 0 12 0 17296760 0 13 0 27697517 0 14 0 306449096 0 15 0 0 0 16 0 351443373 0 17 0.0000 594.3571 0.0000 18 0 87746 0 19 0 129282273 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 2935756 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 552149 0 30 0 0 0 31 0 1952086 0 32 0 0 0 33 0 134810010 0 34 0.0000 0.0531 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) Page403.4

### 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)XAn 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)XAn 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 450.22082 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. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

Kind of Plant (Run-of-River or Storage)

1 Storage Run-of-River Plant Construction type (Conventional or Outdoor) 2 Conventional Conventional Year Originally Constructed 3 1918 1925 Year Last Unit was Installed 4 1922 1925 Total installed cap (Gen name plate Rating in MW) 5 20.00 27.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 22 27 Plant Hours Connect to Load 7 8,445 8,442 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 28 34 (b) Under the Most Adverse Oper Conditions 10 28 34 Average Number of Employees 11 1 2 Net Generation, Exclusive of Plant Use - Kwh 12 67,544,000 88,801,000 Cost of Plant 13Land and Land Rights 14 180,375 20,914 Structures and Improvements 15 1,605,323 2,227,581 Reservoirs, Dams, and Waterways 16 2,645,475 2,954,724 Equipment Costs 17 5,157,577 10,376,116 Roads, Railroads, and Bridges 18 105,442 479,588 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 9,694,192 16,058,923 Cost per KW of Installed Capacity (line 20 / 5) 21 484.7096 594.7749 Production Expenses 22Operation Supervision and Engineering 23 56,118 34,346 Water for Power 24 0 0 Hydraulic Expenses 25 731 987 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 810,982 1,069,662 Rents 28 296 400 Maintenance Supervision and Engineering 29 23 31 Maintenance of Structures 30 6,721 17,305 Maintenance of Reservoirs, Dams, and Waterways 31 107,335 26,905 Maintenance of Electric Plant 32 34,707 18,463 Maintenance of Misc Hydraulic Plant 33 31,315 27,038 Total Production Expenses (total 23 thru 33) 34 1,048,228 1,195,137 Expenses per net KWh 35 0.0155 0.0135

FERC FORM NO. 1 (REV. 12-03) Page40620 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. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

Kind of Plant (Run-of-River or Storage)

1 Run-of River Storage Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional Year Originally Constructed 3 1952 1908 Year Last Unit was Installed 4 1952 1923 Total installed cap (Gen name plate Rating in MW) 5 11.00 33.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 10 30 Plant Hours Connect to Load 7 5,825 7,468 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 10 33 (b) Under the Most Adverse Oper Conditions 10 10 33 Average Number of Employees 11 1 3 Net Generation, Exclusive of Plant Use - Kwh 12 37,477,000 63,490,000 Cost of Plant 13Land and Land Rights 14 0 62,169 Structures and Improvements 15 914,418 1,667,210 Reservoirs, Dams, and Waterways 16 12,176,260 9,208,496 Equipment Costs 17 1,791,282 4,271,582 Roads, Railroads, and Bridges 18 533,015 94,793 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 15,414,975 15,304,250 Cost per KW of Installed Capacity (line 20 / 5) 21 1,401.3614 463.7652 Production Expenses 22Operation Supervision and Engineering 23 -12,286 -335,332 Water for Power 24 5,832 0 Hydraulic Expenses 25 43,753 49,460 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 298,775 1,678,486 Rents 28 247 257 Maintenance Supervision and Engineering 29 13 0 Maintenance of Structures 30 29,386 31,126 Maintenance of Reservoirs, Dams, and Waterways 31 43,522 299,114 Maintenance of Electric Plant 32 31,376 72,032 Maintenance of Misc Hydraulic Plant 33 32,252 117,051 Total Production Expenses (total 23 thru 33) 34 472,870 1,912,194 Expenses per net KWh 35 0.0126 0.0301

FERC FORM NO. 1 (REV. 12-03) Page406.1935 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. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

Kind of Plant (Run-of-River or Storage)

1 Run-of River Storage (Re-Reg) Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional Year Originally Constructed 3 1956 1931 Year Last Unit was Installed 4 1956 1958 Total installed cap (Gen name plate Rating in MW) 5 33.00 136.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 34 151 Plant Hours Connect to Load 7 8,404 8,670 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 34 151 (b) Under the Most Adverse Oper Conditions 10 34 151 Average Number of Employees 11 1 2 Net Generation, Exclusive of Plant Use - Kwh 12 138,473,000 559,382,000 Cost of Plant 13Land and Land Rights 14 0 1,951,411 Structures and Improvements 15 3,268,622 41,087,704 Reservoirs, Dams, and Waterways 16 22,631,929 9,971,566 Equipment Costs 17 11,742,273 16,513,797 Roads, Railroads, and Bridges 18 1,879,245 2,156,440 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 39,522,069 71,680,918 Cost per KW of Installed Capacity (line 20 / 5) 21 1,197.6385 527.0656 Production Expenses 22Operation Supervision and Engineering 23 -43,247 970,245 Water for Power 24 20,414 20,085 Hydraulic Expenses 25 153,136 587,098 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 720,144 1,132,153 Rents 28 864 24,077 Maintenance Supervision and Engineering 29 44 0 Maintenance of Structures 30 76,756 18,363 Maintenance of Reservoirs, Dams, and Waterways 31 63,925 80,444 Maintenance of Electric Plant 32 17,557 89,947 Maintenance of Misc Hydraulic Plant 33 110,475 257,490 Total Production Expenses (total 23 thru 33) 34 1,120,068 3,179,902 Expenses per net KWh 35 0.0081 0.0057

FERC FORM NO. 1 (REV. 12-03) Page406.220 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. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

Kind of Plant (Run-of-River or Storage)

1 Run-of-River Storage Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional Year Originally Constructed 3 1951 1924 Year Last Unit was Installed 4 1951 1924 Total installed cap (Gen name plate Rating in MW) 5 18.00 14.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 16 9 Plant Hours Connect to Load 7 8,689 6,085 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 18 14 (b) Under the Most Adverse Oper Conditions 10 18 14 Average Number of Employees 11 1 2 Net Generation, Exclusive of Plant Use - Kwh 12 79,059,000 13,592,000 Cost of Plant 13Land and Land Rights 14 0 511,083 Structures and Improvements 15 1,802,822 672,316 Reservoirs, Dams, and Waterways 16 5,671,411 6,938,925 Equipment Costs 17 1,365,045 2,203,018 Roads, Railroads, and Bridges 18 16,778 0 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 8,856,056 10,325,342 Cost per KW of Installed Capacity (line 20 / 5) 21 492.0031 737.5244 Production Expenses 22Operation Supervision and Engineering 23 -30,085 -134,734 Water for Power 24 9,544 0 Hydraulic Expenses 25 71,596 20,983 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 384,354 558,071 Rents 28 404 109 Maintenance Supervision and Engineering 29 21 0 Maintenance of Structures 30 39,094 7,959 Maintenance of Reservoirs, Dams, and Waterways 31 31,844 -5,189 Maintenance of Electric Plant 32 9,878 27,677 Maintenance of Misc Hydraulic Plant 33 52,146 43,766 Total Production Expenses (total 23 thru 33) 34 568,796 518,642 Expenses per net KWh 35 0.0072 0.0382

FERC FORM NO. 1 (REV. 12-03) Page406.30 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. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts 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.

Kind of Plant (Run-of-River or Storage)

1 Run-of-River Plant Construction type (Conventional or Outdoor) 2 Conventional Year Originally Constructed 3 1904 Year Last Unit was Installed 4 1922 Total installed cap (Gen name plate Rating in MW) 5 10.30 0.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 9 0 Plant Hours Connect to Load 7 8,740 0 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 10 0 (b) Under the Most Adverse Oper Conditions 10 10 0 Average Number of Employees 11 4 0 Net Generation, Exclusive of Plant Use - Kwh 12 18,451,000 0 Cost of Plant 13Land and Land Rights 14 0 0 Structures and Improvements 15 368,652 0 Reservoirs, Dams, and Waterways 16 529,217 0 Equipment Costs 17 31,914 0 Roads, Railroads, and Bridges 18 12,641 0 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 942,424 0 Cost per KW of Installed Capacity (line 20 / 5) 21 91.4975 0.0000 Production Expenses 22Operation Supervision and Engineering 23 -15,403 0 Water for Power 24 0 0 Hydraulic Expenses 25 13,521 0 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 279,741 0 Rents 28 0 0 Maintenance Supervision and Engineering 29 0 0 Maintenance of Structures 30 2,626 0 Maintenance of Reservoirs, Dams, and Waterways 31 2,524 0 Maintenance of Electric Plant 32 3,235 0 Maintenance of Misc Hydraulic Plant 33 131,459 0 Total Production Expenses (total 23 thru 33) 34 417,703 0 Expenses per net KWh 35 0.0226 0.0000

FERC FORM NO. 1 (REV. 12-03) Page406.41927 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. (e) (d) (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 Storage Run-of-River 1 Outdoor Conventional Outdoor 2 1953 1927 1953 3 1953 1927 1953 4 26.00 30.00 15.00 5 17 23 9 6 7,982 6,001 8,570 7 8 31 29 18 9 31 29 18 10 1 3 1 11 29,705,000 48,987,000 31,476,000 12 13 0 3,505,129 0 14 1,632,875 3,969,184 1,222,452 15 14,757,082 7,485,343 4,547,301 16 1,624,689 14,550,291 1,188,143 17 250,151 572,059 52,034 18 0 0 0 19 18,264,797 30,082,006 7,009,930 20 702.4922 1,002.7335 467.3287 21 22 -7,877 -28,846 -10,077 23 13,786 0 7,953 24 103,417 39,382 59,664 25 0 0 0 26 518,109 759,667 300,090 27 584 0 337 28 30 0 17 29 46,455 3,663 47,860 30 57,255 40,533 25,264 31 130,785 8,822 22,337 32 74,692 217,199 45,805 33 937,236 1,040,420 499,250 34 0.0316 0.0212 0.0159 35

FERC FORM NO. 1 (REV. 12-03) Page4072082 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. (e) (d) (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 1958 1955 1962 3 1958 1955 1962 4 97.98 31.99 18.00 5 83 30 18 6 5,336 8,239 8,458 7 8 83 32 19 9 83 32 19 10 2 1 1 11 193,133,000 111,394,000 96,256,000 12 13 26,277 0 341,706 14 2,873,701 2,114,257 4,614,730 15 14,155,361 15,131,501 13,091,301 16 14,890,342 5,896,348 2,404,786 17 886,710 475,419 1,076,116 18 0 0 0 19 32,832,391 23,617,525 21,528,639 20 335.0928 738.2784 1,196.0355 21 22 298,124 -46,461 367,234 23 0 16,962 0 24 3,581 127,243 658 25 0 0 0 26 657,449 654,914 769,556 27 298 718 267 28 112 37 18 29 15,644 84,758 639,872 30 32,677 80,793 52,214 31 31,089 139,175 67,152 32 70,419 158,417 18,025 33 1,109,393 1,216,556 1,914,996 34 0.0057 0.0109 0.0199 35

FERC FORM NO. 1 (REV. 12-03) Page407.11927 Toketee Prospect No. 22630 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. (e) (d) (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 Run-of River Storage 1 Conventional Conventional Conventional 2 1915 1928 1949 3 1920 1928 1950 4 30.00 32.00 42.50 5 25 36 43 6 8,752 8,420 8,298 7 8 28 36 45 9 28 36 45 10 2 1 1 11 28,335,000 225,108,000 188,950,000 12 13 36,698 105,168 0 14 1,406,986 2,946,404 2,210,324 15 6,475,575 25,003,207 10,706,970 16 5,155,281 3,599,742 3,270,264 17 503,332 305,071 264,441 18 0 0 0 19 13,577,872 31,959,592 16,451,999 20 452.5957 998.7373 387.1059 21 22 -314,475 212,037 -60,431 23 0 20,803 22,535 24 44,963 2,826 169,047 25 0 0 0 26 983,833 685,121 725,356 27 233 2,706 954 28 0 37 49 29 18,692 46,539 68,552 30 0 129,919 79,036 31 71,597 20,553 129,613 32 118,567 50,833 121,953 33 923,410 1,171,374 1,256,664 34 0.0326 0.0052 0.0067 35

FERC FORM NO. 1 (REV. 12-03) Page407.21927 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. (e) (d) (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 (Re-Reg) 1 Conventional Conventional Outdoor 2 1958 1953 1952 3 1958 1953 1952 4 240.00 134.00 11.00 5 255 164 12 6 6,235 6,339 8,670 7 8 264 164 12 9 263 164 12 10 2 2 1 11 733,951,000 629,932,000 51,896,000 12 13 7,813,808 8,349,393 0 14 11,153,113 7,183,730 1,165,632 15 41,214,434 27,489,478 13,609,199 16 16,263,319 14,830,132 2,177,660 17 1,012,079 1,426,051 56,124 18 0 0 0 19 77,456,753 59,278,784 17,008,615 20 322.7365 442.3790 1,546.2377 21 22 1,586,601 886,981 -13,260 23 35,443 19,789 5,832 24 1,217,225 578,464 43,753 25 0 0 0 26 1,614,719 968,747 301,704 27 42,488 23,723 247 28 0 0 13 29 51,505 31,812 20,983 30 52,380 84,804 23,370 31 262,701 46,449 25,941 32 438,865 249,043 31,564 33 5,301,927 2,889,812 440,147 34 0.0072 0.0046 0.0085 35

FERC FORM NO. 1 (REV. 12-03) Page407.30 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. (e) (d) (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) Page407.4

### 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)XAn 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)XAn 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)XAn 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)XAn 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)XAn 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 450.5FERC 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) 2Year Originally Constructed 3Year Last Unit was Installed 4Total installed cap (Gen name plate Rating in MW) 5Net Peak Demaind on Plant-Megawatts (60 minutes) 6Plant Hours Connect to Load While Generating 7Net Plant Capability (in megawatts) 8Average Number of Employees 9Generation, Exclusive of Plant Use - Kwh 10Energy Used for Pumping 11 Net Output for Load (line 9 - line 10) - Kwh 12Cost of Plant 13Land and Land Rights 14Structures and Improvements 15Reservoirs, Dams, and Waterways 16Water Wheels, Turbines, and Generators 17Accessory Electric Equipment 18Miscellaneous Powerplant Equipment 19Roads, Railroads, and Bridges 20Asset Retirement Costs 21 Total cost (total 13 thru 20) 22Cost per KW of installed cap (line 21 / 4) 23Production Expenses 24Operation Supervision and Engineering 25Water for Power 26Pumped Storage Expenses 27Electric Expenses 28Misc Pumped Storage Power generation Expenses 29Rents 30Maintenance Supervision and Engineering 31 Maintenance of Structures 32Maintenance of Reservoirs, Dams, and Waterways 33Maintenance of Electric Plant 34Maintenance of Misc Pumped Storage Plant 35Production Exp Before Pumping Exp (24 thru 34) 36Pumping Expenses 37Total Production Exp (total 35 and 36) 38Expenses per KWh (line 37 / 9)

FERC FORM NO. 1 (REV. 12-03) Page408FERC 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: (e) (c) 6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. 7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 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 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

FERC FORM NO. 1 (REV. 12-03) Page409Name 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

(c) (b) (a) 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.

Hydroelectric : Licensed Proj. No. 1 6.85 4.9 22,728,000 8,910,187 1917 Ashton 2381 2 1.11 1.0 2,439,000 1,314,472 1913 Bend 3 4.15 4.6 32,262,000 7,207,761 1910 Big Fork 2652 4 1.00 1913 Cline Falls 5 13.70 15.0 95,220,000 6,935,270 1913 Condit 2342 6 2.81 2.8 17,206,000 1,795,497 1957 Eagle Point 7 3.20 3.0 4,399,000 1,991,695 1924 East Side 2082 8 2.20 2.0 11,086,000 1,365,095 1903 Fall Creek 2082 9 0.16 0.1 646,000 597,630 1922 Fountain Green 10 2.00 1.2 6,403,000 5,237,598 1896 Granite 11 0.75 0.5 1,527,000 672,853 1917 Gunlock 12 1.73 1.3 3,232,000 2,802,615 1983 Last Chance 13 0.72 0.7 2,275,000 416,673 1910 Paris 14 5.00 4.0 15,484,000 10,807,561 1897 Pioneer 2722 15 6.00 122,396 1923 Powerdale 2659 16 3.76 4.6 22,455,000 1,731,817 1912 Prospect No. 1 2630 17 7.20 7.7 35,330,000 7,001,153 1932 Prospect No. 3 2337 18 1.00 0.9 3,917,000 1,596,217 1944 Prospect No. 4 2630 19 0.80 0.5 1,542,000 933,993 1926 Sand Cove 20 1.18 0.9 3,079,000 992,623 1910 Snake Creek 21 1.00 1.2 5,587,000 1,607,647 1895 Stairs 597 22 0.50 1,337,279 1915 St. Anthony 2381 23 0.50 0.3 1,130,000 875,122 1920 Veyo 24 0.74 0.6 1,440,000 1,194,486 1986 Viva Naughton 25 1.10 1.0 7,925,000 2,833,031 1921 Wallowa Falls 308 26 3.85 2.0 15,316,000 2,848,017 1911 Weber 1744 27 0.60 0.6 288,000 468,574 1908 West Side 2082 28 7,500,010 Keno Regulating Dam 2082 29 3,847,005 Upper Klamath Lake 2082 30 15,446,611 North Umpqua 1927 31 32 Pumping Plant: 33 -4.50 -3.0 -2,784,000 19,198,557 1917 Lifton 34 35 Wind: 36 111.00 111.0 102,429,000 238,882,767 2010 Dunlap Ranch I 37 32.62 32.6 93,145,000 37,037,356 1999 Foote Creek 38 99.00 103.0 287,941,000 199,905,929 2008 Glenrock 39 39.00 38.0 99,967,000 87,185,602 2009 Glenrock III 40 99.00 99.0 252,669,000 201,242,950 2009 Rolling Hills 41 94.00 95.0 212,268,000 180,512,024 2008 Goodnoe Hills 42 100.50 102.0 223,558,000 174,536,399 2006 Leaning Juniper 1 43 140.40 137.0 330,943,000 237,368,036 2007 Marengo 44 70.20 68.0 165,475,000 128,127,213 2008 Marengo II 45 99.00 102.0 324,123,000 199,246,447 2008 Seven Mile Hill 46

FERC FORM NO. 1 (REV. 12-03) Page 410Name 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

(c) (b) (a) 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.

19.50 19.0 67,722,000 41,819,719 2008 Seven Mile Hill II 1 99.00 98.0 257,349,000 219,300,133 2009 High Plains 2 28.50 29.7 77,366,000 56,796,654 2009 McFadden Ridge I 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 (REV. 12-03) Page 410.1Name 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. (i) (h) (g) (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 45,664 1,300,757 2 Water 583,930 17,542 1,184,209 3 Water 148,628 47,580 1,736,810 4 Water 357,653 2,459 5 Water 4,817 63,030 506,224 6 Water 382,803 26,623 638,967 7 Water 266,477 5,827 622,405 8 Water 309,345 70,875 620,498 9 Water 142,943 7,685 3,735,188 10 Water 32,978 42,754 2,618,799 11 Water 130,753 26,682 897,137 12 Water 42,609 30,259 1,620,009 13 Water 126,034 39,669 578,713 14 Water 58,114 113,444 2,161,512 15 Water 393,203 7,778 20,399 16 Water 74,593 26,648 460,590 17 Water 171,988 299,515 972,382 18 Water 398,584 21,065 1,596,217 19 Water 73,051 18,605 1,167,491 20 Water 43,449 23,818 841,206 21 Water 108,396 40,962 1,607,647 22 Water 117,470 2,453 2,674,558 23 Water 26,946 160,866 1,750,244 24 Water 47,377 52,594 1,614,170 25 Water 42,492 40,600 2,575,483 26 Water 25,876 48,364 739,745 27 Water 239,831 18,192 780,957 28 Water 44,142 3,605 29 14,745 27,325 30 318,425 31 32 33 73,794 -4,266,346 34 Water 312,143 35 36 1,996 2,152,097 37 Wind 583,645 1,135,419 38 Wind 1,919,055 316,402 2,019,252 39 Wind 1,494,484 120,223 2,235,528 40 Wind 365,258 305,182 2,032,757 41 Wind 1,043,021 487,584 1,920,341 42 Wind 2,142,887 45,278 1,736,681 43 Wind 2,526,331 49,266 1,690,656 44 Wind 5,295,498 24,633 1,825,174 45 Wind 1,386,749 168,426 2,012,590 46 Wind 1,877,605

FERC FORM NO. 1 (REV. 12-03) Page 411Name 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. (i) (h) (g) (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

34,025 2,144,601 1 Wind 353,524 1,471,333 2,215,153 2 Wind 914,989 408,712 1,992,865 3 Wind 254,778 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 (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)XAn 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)XAn 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)XAn 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 450.3Name 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.

(c) (b) (a) (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.

Steel Tower 500.00 500.00 47.00 1 1 MALIN , OR PG&E ROUND MTN , CA Steel Tower 500.00 500.00 26.00 1 2KLAMATH CO-GEN , OR CAPTAIN JACK , OR Steel Tower 500.00 500.00 58.00 1 3MERIDIAN , OR KLAMATH CO-GEN , OR Steel Tower 500.00 500.00 58.00 1 4ALVEY , OR DIXONVILLE 500 , OR Steel Tower 500.00 500.00 74.00 1 5DIXONVILLE , OR MERIDIAN , OR Steel Tower 500.00 500.00 7.00 1 6CAPTAIN JACK , OR MALIN , OR Steel Tower 500.00 500.00 447.00 1 7MIDPOINT , OR MALIN , OR Steel Tower 500.00 500.00 1.00 1 8COLSTRIP 4, MT Switchyard, MT Steel Tower 500.00 500.00 112.00 1 9COLSTRIP, MT BROADVIEW A, MT Steel Tower 500.00 500.00 116.00 1 10COLSTRIP, MT BROADVIEW B, MT Steel Tower 500.00 500.00 133.00 1 11 BROADVIEW, MT TOWNSEND A, MT Steel Tower 500.00 500.00 133.00 1 12BROADVIEW, MT TOWNSEND B, MT 13500 kV costs and expenses 14 1,212.00 12 15Subtotal 500kV 16 Wood - H 345.00 345.00 138.00 1 17BEN LOMOND , UT BORAH , ID Steel SP 345.00 345.00 70.00 1 18BEN LOMOND , UT CAMP WILLIAMS , UT 345.00 345.00 47.00 1 19BEN LOMOND , UT TERMINAL , UT Steel Tower 345.00 345.00 121.00 1 20EMERY , UT CAMP WILLIAMS , UT Wood - H 345.00 345.00 47.00 1 21CAMP WILLIAMS , UT MONA #3 , UT Steel SP 345.00 345.00 11.00 1 22NINETY SOUTH , UT CAMP WILLIAMS #1, UT Wood - H 345.00 345.00 47.00 1 23CAMP WILLIAMS , UT MONA #1 , UT Steel Tower 345.00 345.00 47.00 1 24CAMP WILLIAMS , UT MONA #2 , UT 345.00 345.00 35.00 1 25SPANISH FORK , UT CAMP WILLIAMS , UT Steel SP 345.00 345.00 26.00 1 26TERMINAL , UT CAMP WILLIAMS #2,UT 345.00 345.00 23.00 1 27TERMINAL , UT CAMP WILLIAMS , UT Wood - H 345.00 345.00 20.00 1 28EMERY , UT HUNTINGTON , UT Steel - H 345.00 345.00 74.00 1 29EMERY , UT SIGURD #1 , UT Steel - H 345.00 345.00 75.00 1 30EMERY , UT SIGURD #2 , UT Wood - H 345.00 345.00 101.00 1 31 FOUR CORNERS , NM PINTO , UT Wood - H 345.00 345.00 41.00 1 32GOSHEN , ID KINPORT , ID Wood - H 345.00 345.00 159.00 1 33HUNTINGTON , UT PINTO , UT Wood - H 345.00 345.00 78.00 1 34HUNTINGTON , UT SPANISH FORK , UT Steel SP 345.00 345.00 16.00 1 35TERMINAL , UT NINETY SOUTH , UT

FERC FORM NO. 1 (ED. 12-87) Page 422

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Steel Tower 345.00 345.00 69.00 1 1 MONA , UT SIGURD #1 , UT 345.00 345.00 69.00 1 2MONA , UT SIGURD #2 , UT Wood - H 345.00 345.00 190.00 1 3SIGURD , UT UT / NV BORDER , UT Steel Tower 345.00 345.00 240.00 1 4JIM BRIDGER , WY BORAH , ID Steel Tower 345.00 345.00 234.00 1 5JIM BRIDGER , WY KINPORT , ID Steel Tower 345.00 345.00 60.00 1 6MONA , UT HUNTINGTON , UT Steel SP 345.00 345.00 1.00 1 7CURRENT CREEK , UT MONA , UT Wood - H 345.00 345.00 42.00 5.00 1 8CAMP WILLIAMS , UT MONA #4 , UT Steel SP 345.00 345.00 47.00 1 9BEN LOMOND, UT TERMINAL, UT 345.00 345.00 47.00 1 10BEN LOMOND, UT TERMINAL, UT 345.00 345.00 82.00 1 11 BEN LOMOND,UT POPULUS, ID Steel SP 345.00 345.00 86.00 1 12BEN LOMOND, UT POPULUS, ID Steel SP 345.00 345.00 11.00 1 1390TH SOUTH, UT CAMP WILLIAMS #4, UT 345.00 345.00 11.00 1 1490TH SOUTH, UT CAMP WILLIAMS #3, UT 15345 kV costs and expenses 16 383.00 1,987.00 33 17Subtotal 345kV 18 Wood - H 230.00 230.00 76.00 1 19ANTELOPE , ID ANACONDA , ID Wood - H 230.00 230.00 20.00 1 20ANTELOPE , ID LOST RIVER , ID Wood - H 230.00 230.00 88.00 1 21 BEN LOMOND , UT NAUGHTON #1 , WY Wood - H 230.00 230.00 88.00 1 22BEN LOMOND , UT NAUGHTON #2 , WY Wood - H 230.00 230.00 19.00 1 23BIRCH CREEK , UT RAILROAD , WY Wood - H 230.00 230.00 66.00 1 24TREASURETON , ID BRADY , ID Wood - H 230.00 230.00 159.00 1 25GLEN CANYON , AZ SIGURD , UT Wood - H 230.00 230.00 98.00 1 26GONDER (ELY) , UT PAVANT , UT Wood - H 230.00 230.00 80.00 1 27NAUGHTON , WY TREASURETON , ID Wood - H 230.00 230.00 94.00 1 28PAROWAN VALLEY , UT SIGURD , UT Wood - H 230.00 230.00 26.00 1 29PAROWAN VALLEY , UT WEST CEDAR , UT Wood - H 230.00 230.00 43.00 1 30PAVANT , UT SIGURD , UT Wood - H 230.00 230.00 1.00 1 31ATLANTIC CITY, WY COLUMBIA GENEVA, WY Wood - H 230.00 230.00 4.00 1 32PALISADES SS , WY BLUE RIM , WY Wood - H 230.00 230.00 107.00 1 33BUFFALO , WY CASPER , WY Wood - H 230.00 230.00 43.00 1 34GOOSE CREEK , WY BUFFALO , WY Wood - H 230.00 230.00 69.00 1 35WYODAK , WY BUFFALO , WY

FERC FORM NO. 1 (ED. 12-87) Page 422.1

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Wood - H 230.00 230.00 229.00 1 1JIM BRIDGER , WY DAVE JOHNSTON , WY Wood - H 230.00 230.00 35.00 1 2ROCK SPRINGS , WY JIM BRIDGER , WY Wood - H 230.00 230.00 149.00 1 3JIM BRIDGER , WY SPENCE , WY Wood - H 230.00 230.00 1.00 1 4BRIDGER PUMP, WY MANS FACE, WY Wood - H 230.00 230.00 33.00 1 5CASPER , WY DAVE JOHNSTON , WY Wood - H 230.00 230.00 110.00 1 6CASPER , WY RIVERTON , WY Wood - H 230.00 230.00 31.00 1 7DAVE JOHNSTON , WY SPENCE , WY Wood - H 230.00 230.00 70.00 1 8DAVE JOHNSTON , WY WYODAK , WY Wood - H 230.00 230.00 13.00 1 9MONUMENT , WY SHUTE CREEK , WY Wood - H 230.00 230.00 49.00 1 10FIREHOLE , WY MONUMENT , WY Wood - H 230.00 230.00 55.00 1 11 ROCK SPRINGS , WY FLAMING GORGE , UT Wood - H 230.00 230.00 59.00 1 12YELLOWTAIL , MT GOOSE CREEK , WY Wood - H 230.00 230.00 30.00 1 13NAUGHTON , WY MONUMENT , WY Wood - H 230.00 230.00 41.00 1 14ROCK SPRINGS , WY MONUMENT , WY Wood - H 230.00 230.00 118.00 1 15RIVERTON , WY ROCK SPRINGS , WY Wood - H 230.00 230.00 51.00 1 16RIVERTON , WY THERMOPOLIS , WY Wood - H 230.00 230.00 176.00 1 17THERMOPOLIS , WY YELLOWTAIL , MT Wood - H 230.00 230.00 30.00 1 18CHAPPEL CREEK , WY CRAVEN CREEK , WY Wood - H 230.00 230.00 16.00 1 19CRAVEN CREEK , WY NAUGHTON , WY Wood - H 230.00 230.00 32.00 1 20CHAPPEL CREEK , WY JONAH GAS , WY Steel-SP 230.00 230.00 6.00 14.00 1 21CHAPPEL CREEK , WY CHIMNEY BUTTE, WY Wood - H 230.00 230.00 39.00 1 22MINERS , WY FOOTE CREEK , WY Wood - H 230.00 230.00 27.00 1 23POINT OF ROCKS , WY ROCK SPRINGS , WY Wood - H 230.00 230.00 20.00 1 24MONUMENT , WY CRAVEN CREEK , WY Wood - H 230.00 230.00 13.00 1 25WINDSTAR, WY GLENROCK WIND, WY Wood - H 230.00 230.00 63.00 1 26YAMSAY , OR KLAMATH FALLS , OR Wood - H 230.00 230.00 35.00 1 27KLAMATH FALLS , OR MALIN , OR Wood - H 230.00 230.00 76.00 1 28LONE PINE , OR KLAMATH FALLS , OR 230.00 230.00 5.00 1 29LONE PINE , OR MERIDIAN , OR Wood - H 230.00 230.00 62.00 1 30GRANTS PASS , OR DIXONVILLE LINE 72, OR Wood - H 230.00 230.00 17.00 1 31 DIXONVILLE , OR RESTON BPA , OR Wood - H 230.00 230.00 9.00 1 32TAP TO HANNA , OR HANNA BPA , OR Wood - H 230.00 230.00 1.00 1 33DIXONVILLE 500 , OR DIXONVILLE 230 , OR Wood - H 230.00 230.00 35.00 1 34MERIDIAN , OR GRANTS PASS , OR Steel SP 230.00 230.00 5.00 1 35MERIDIAN , OR LONE PINE , OR

FERC FORM NO. 1 (ED. 12-87) Page 422.2

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Wood - H 230.00 230.00 12.00 1 1 FAIRVIEW BPA , OR ISTHMUS , OR Steel Tow 230.00 230.00 6.00 1 2TROUTDALE BPA , OR PGE GRESHAM , OR 230.00 230.00 6.00 1 3TROUTDALE BPA , OR LINNEMAN , OR Wood - H 230.00 230.00 2.00 1 4SWIFT No. 1 , WA SWIFT No. 2 , WA Wood - H 230.00 230.00 23.00 1 5SWIFT No. 2 , WA WOODLAND BPA SS , WA Wood - H 230.00 230.00 26.00 1 6FRY , OR BETHEL , OR Wood - H 230.00 230.00 45.00 1 7FRY , OR ALVEY , OR Wood - H 230.00 230.00 59.00 1 8ALVEY , OR DIXONVILLE , OR Wood - H 230.00 230.00 78.00 1 9HURRICANE , OR WALLA WALLA , WA Wood - H 230.00 230.00 56.00 1 10MCNARY BPA , WA WALLA WALLA , WA Wood - H 230.00 230.00 45.00 1 11WALLA WALLA , WA AVISTA LEWISTON , WA Wood - H 230.00 230.00 33.00 1 12WALLA WALLA , WA WANAPUM , WA Wood - H 230.00 230.00 8.00 1 13TALBOT , WA MARENGO , WA Wood - H 230.00 230.00 39.00 1 14UNION GAP , WA MIDWAY BPA , WA Wood - H 230.00 230.00 37.00 1 15WANAPUM , WA POMONA , WA Wood - H 230.00 230.00 8.00 1 16POMONA , WA UNION GAP , WA 17230 kV costs and expenses 18 17.00 3,302.00 68 19Subtotal 230kV 20 Wood - H 161.00 161.00 90.00 1 21 ID / MT BORDER , ID GOSHEN , ID Wood - H 161.00 161.00 45.00 1 22ANTELOPE , ID GOSHEN , ID Wood SP 161.00 161.00 9.00 1 23BONNEVILLE , ID EAGLEROCK , ID Wood SP 161.00 161.00 3.00 1 24EAGLEROCK , ID SUGARMILL , ID Wood - H 161.00 161.00 57.00 1 25GOSHEN , ID GRACE , ID Wood - H 161.00 161.00 31.00 1 26GOSHEN , ID RIGBY , ID Wood SP 161.00 161.00 17.00 1 27GOSHEN , ID SUGARMILL , ID Wood SP 161.00 161.00 17.00 1 28SUGARMILL , ID RIGBY , ID Wood - H 161.00 161.00 12.00 1 29EAGLEROCK , ID GOSHEN , ID Wood - H 161.00 161.00 46.00 1 30YELLOWTAIL , MT RIMROCK , MT Wood SP 161.00 161.00 18.00 1 31 RIGBY , ID JEFFERSON , ID 32161 kV costs and expenses 33 90.00 255.00 11 34Subtotal 161 kV 35

FERC FORM NO. 1 (ED. 12-87) Page 422.3

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Wood - H 138.00 138.00 86.00 1 1WHEELON , ID AMERICAN FALLS , ID Wood - SP 138.00 138.00 21.00 1 2OQUIRRH , UT TOOELE , UT Wood - H 138.00 138.00 5.00 1 3OQUIRRH , UT KCC BARNEY , UT Wood - H 138.00 138.00 22.00 1 4ANSCHTZ CO-GEN, WY RAILROAD , WY Wood - H 138.00 138.00 1.00 1 5ANTELOPE , ID SCOVILLE #1 , ID Wood - H 138.00 138.00 1.00 1 6ANTELOPE , ID SCOVILLE #2 , ID Wood - H 138.00 138.00 92.00 1 7ASHLEY , UT CARBON , UT Wood - H 138.00 138.00 12.00 1 8ASHLEY , UT VERNAL , UT Wood - H 138.00 138.00 4.00 1 9BEKER INDUST , ID THREEMILE KNOLL , ID Wood - H 138.00 138.00 14.00 1 10BEN LOMOND , UT BRIGHAM CITY , UT Wood - H 138.00 138.00 14.00 1 11 BEN LOMOND , UT EL MONTE , UT Wood - H 138.00 138.00 13.00 1 12BEN LOMOND , UT EL MONTE , UT 138.00 138.00 22.00 1 13BEN LOMOND , UT HONEYVILLE , UT 138.00 138.00 23.00 1 14BEN LOMOND , UT CLINTON , UT Wood - SP 138.00 138.00 28.00 1 15BEN LOMOND , UT ANGEL , UT Wood - SP 138.00 138.00 14.00 1 16BEN LOMOND , UT W ZIRCONIUM , UT Steel Tower 138.00 138.00 42.00 1 17BEN LOMOND , UT WHEELON , UT Wood - H 138.00 138.00 24.00 1 18BRIGHAM CITY , UT WHEELON , UT Wood - H 138.00 138.00 35.00 1 19CAMERON , UT PAROWAN , UT Wood - H 138.00 138.00 64.00 1 20CAMERON , UT SIGURD , UT Wood - H 138.00 138.00 2.00 1 21CARBON , UT HELPER , UT Wood - H 138.00 138.00 2.00 1 22CARBON , UT HELPER , UT Steel Tower 138.00 138.00 54.00 1 23CARBON , UT SPANISH FORK , UT 138.00 138.00 52.00 1 24CARBON , UT SPANISH FORK , UT Wood - H 138.00 138.00 17.00 1 25THREEMILE KNOLL , ID GRACE #1 , ID Wood - H 138.00 138.00 17.00 1 26THREEMILE KNOLL , ID GRACE #2 , ID Wood - H 138.00 138.00 2.00 1 27THREEMILE KNOLL , ID MONSANTO 1 , ID Wood - SP 138.00 138.00 2.00 1 28THREEMILE KNOLL , ID MONSANTO 2 , ID Wood - SP 138.00 138.00 5.00 1 29PAINTER , WY CLEAR CREEK , WY Wood - H 138.00 138.00 7.00 1 30COLUMBIA , WY MOUNDS SWRK , UT Wood - SP 138.00 138.00 6.00 1 31COTTONWOOD , UT MCCLELLAND , UT Wood - SP 138.00 138.00 5.00 1 32COTTONWOOD , UT HAMMER , UT Wood - SP 138.00 138.00 29.00 1 33COTTONWOOD , UT SILVER CREEK , UT Wood - SP 138.00 138.00 1.00 1 34CUTLER , UT WHEELON , UT Wood - H 138.00 138.00 20.00 1 35ENTERPRISE , UT MIDDLETON , UT

FERC FORM NO. 1 (ED. 12-87) Page 422.4

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Wood - H 138.00 138.00 33.00 1 1WEST CEDAR , UT ENTERPRISE VALLEY, UT Wood - SP 138.00 138.00 3.00 1 2EVANSTON, WY RAILROAD, WY Wood - SP 138.00 138.00 25.00 1 3FRANKLIN , UT SMITHFIELD , UT Wood - SP 138.00 138.00 10.00 1 4FRANKLIN , ID TREASURETON , ID Wood - SP 138.00 138.00 5.00 1 5JORDAN , UT MCCLELLAND , UT Wood - SP 138.00 138.00 6.00 1 6GADSBY , UT TERMINAL , UT Wood - SP 138.00 138.00 6.00 1 7JORDAN , UT TERMINAL , UT Steel - SP 138.00 138.00 4.00 1 8TIMP , UT HALE , UT Steel - SP 138.00 138.00 14.00 1 9TRI-CITY , UT AMERICAN FORK , UT Wood - SP 138.00 138.00 44.00 1 10ABAJO , UT PINTO , UT Wood - H 138.00 138.00 19.00 1 11ONEIDA , ID GRACE , ID Steel Tower 138.00 138.00 25.00 1 12TREASURETON , ID GRACE 103 , ID 138.00 138.00 25.00 1 13TREASURETON , ID GRACE 104 , ID Wood - H 138.00 138.00 37.00 1 14NEBO , UT DRY CREEK , UT Wood - H 138.00 138.00 42.00 1 15WESTFIELD, UT HIGHLAND, UT Wood - SP 138.00 138.00 23.00 1 16TIMP , UT SPANISH FORK , UT Wood - H 138.00 138.00 7.00 1 17HALE , UT TANNER , UT Wood - H 138.00 138.00 29.00 1 18MOUNDS SWRK , UT HELPER , UT 138.00 138.00 14.00 1 19HONEYVILLE , UT WHEELON , UT Wood - H 138.00 138.00 7.00 1 20HUNTINGTON , UT MCFADDEN , UT 138.00 138.00 9.00 1 21TERMINAL , UT KENNECOTT , UT Wood - H 138.00 138.00 30.00 1 22KILN , UT NEBO , UT Wood - SP 138.00 138.00 6.00 1 23MCCLELLAND , UT MIDVALLEY , UT Wood - H 138.00 138.00 83.00 1 24MOUNDS SWRK , UT MOAB , UT Wood - H 138.00 138.00 68.00 1 25MOAB , UT PINTO , UT Wood - H 138.00 138.00 35.00 1 26NAUGHTON , WY NGPL , WY Wood - H 138.00 138.00 45.00 1 27NAUGHTON , WY PAINTER , WY Wood - H 138.00 138.00 12.00 1 28NGPL , WY TAP TO STR 204 , WY Wood - H 138.00 138.00 1.00 1 29NGPL, WY WHITNEY, WY Wood - SP 138.00 138.00 10.00 1 30NINETY SOUTH , UT OQUIRRH , UT Wood - SP 138.00 138.00 7.00 1 31TAYLORSVILLE , UT NINETY SOUTH , UT Wood - H 138.00 138.00 13.00 1 32MID VALLEY , UT NINETY SOUTH , UT Wood - H 138.00 138.00 10.00 1 33NUCOR STEEL , UT WHEELON , UT Wood - H 138.00 138.00 23.00 1 34ONEIDA , ID OVID , ID Wood - H 138.00 138.00 6.00 1 35TREASURETON , ID ONEIDA , ID

FERC FORM NO. 1 (ED. 12-87) Page 422.5

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Wood - H 138.00 138.00 7.00 1 1 PAINTER , WY RAILROAD , WY Wood - H 138.00 138.00 21.00 1 2PAROWAN , UT WEST CEDAR , UT 138.00 138.00 13.00 1 3TAP TO ANGEL SOUTH, UTTAP TO PARRISH , UT Steel SP 138.00 138.00 16.00 1 4PARRISH , UT TERMINAL , UT 138.00 138.00 14.00 1 5PARRISH , UT TERMINAL , UT Wood - H 138.00 138.00 19.00 1 6RAILROAD , WY WHITNEY , WY Steel Tower 230.00 138.00 25.00 1 7BEN LOMOND , UT SYRACUSE , UT Wood - H 138.00 138.00 56.00 1 8TERMINAL , UT ROWLEY , UT Wood - SP 138.00 138.00 19.00 1 9GREEN CANYON , UT WHEELON , UT Wood - H 138.00 138.00 10.00 1 10SPANISH FORK , UT TANNER , UT 138.00 138.00 13.00 1 11TAP TO ANGEL NORTH, UT TAP TO PARRISH , UT Wood - H 138.00 138.00 7.00 1 12TERMINAL , UT MIDVALLEY , UT Steel - SP 138.00 138.00 7.00 1 13TERMINAL , UT CENT / MIDVALLEY, UT Wood - H 138.00 138.00 35.00 1 14TERMINAL , UT TOOELE , UT Steel Tower 138.00 138.00 29.00 1 15WHEELON #103 , UT TREASURETON , ID 138.00 138.00 29.00 1 16WHEELON #104 , UT TREASURETON , ID Wood - H 138.00 138.00 29.00 1 17WHEELON #105 , UT TREASURETON , ID Wood - H 138.00 138.00 1.00 1 18KCC BARNEY , UT KCCGRIND , UT Wood - H 138.00 138.00 14.00 1 19TERMINAL , UT LAKE PARK , UT Wood - H 138.00 138.00 8.00 1 20OQUIRRH , UT KCC BINGHAM , UT Wood - SP 138.00 138.00 20.00 1 21WEST CEDAR , UT THREE PEAKS, UT Wood - H 138.00 138.00 18.00 1 22HALE , UT SPANISH FORK , UT Wood - SP 138.00 138.00 5.00 1 23MID VALLEY , UT TAYLORSVILLE , UT Steel - SP 138.00 138.00 14.00 1 24PARRISH , UT TERMINAL , UT Wood-H 138.00 138.00 2.00 1 25COLUMBIA, UT SUNNYSIDE, UT Wood - H 138.00 138.00 26.00 1 26JERUSALM , UT NEBO , UT Wood - H 138.00 138.00 19.00 1 27HALE , UT MIDWAY , UT U/G 138.00 138.00 4.00 1 28DIMPLE DELL , UT DUMAS , UT Wood - H 138.00 138.00 25.00 1 29HONEYVILLE , UT LAMPO , UT Wood - SP 138.00 138.00 1.00 1 30GADSBY , UT JORDAN , UT Wood - SP 138.00 138.00 5.00 1 31 MID VALLEY , UT COTTONWOOD , UT Steel - SP 138.00 138.00 1.00 1 32NINETY SOUTH , UT SANDY , UT 138.00 138.00 9.00 1 33MICRON , UT CAMP WILLIAMS , UT Wood - H 138.00 138.00 11.00 1 34MCFADDEN , UT BLACKHAWK , UT Wood - SP 138.00 138.00 8.00 1 35NINETY SOUTH , UT QUARRY SUBSTATION, UT

FERC FORM NO. 1 (ED. 12-87) Page 422.6

36 TOTAL 16,015.00 767.00 250Name 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.

(c) (b) (a) (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.

Steel - SP 138.00 138.00 4.00 1 1 EL MONTE , UT STR 30B , UT Steel - SP 138.00 138.00 1.00 1 2EL MONTE , UT PIONEER , UT Steel - SP 138.00 138.00 1.00 1 3SYRACUSE , UT CLEARFIELD SOUTH, UT Steel - SP 138.00 138.00 5.00 1 4MID VALLEY , UT COTTONWOOD , UT 138.00 138.00 2.00 1 5HAMMER , UT BUTLERVILLE , UT Steel - SP 138.00 138.00 9.00 1 6BUTLERVILLE , UT NINETY SOUTH , UT Wood - SP 138.00 138.00 2.00 1 7KEARNS , UT TAYLORSVILLE , UT Steel - SP 138.00 138.00 10.00 1 8SILVER CREEK SUB, UT JORDANELLE SUB , UT Wood - SP 138.00 138.00 2.00 1 9KEARNS , UT WEST VALLEY , UT Steel - SP 138.00 138.00 21.00 1 10RIVERDALE , UT 105 TAP , UT Steel - SP 138.00 138.00 21.00 1 11OQUIRRH , UT SUNRISE / TRI-CITY, UT 138.00 138.00 23.00 1 12OQUIRRH , UT BANGERTER / TRI-CITY, UT 138.00 138.00 5.00 1 13DYNAMO , UT TRI-CITY #2 , UT 138.00 138.00 4.00 1 14TIMP #2 , UT DYNAMO , UT Wood - H 138.00 138.00 1.00 1 15MIDDLETON , UT ST. GEORGE , UT Steel - SP 138.00 138.00 16.00 1 16BRIDGERLAND , UT GREEN CANYON , UT Steel Tower 230.00 138.00 12.00 1 17SYRACUSE , UT PARRISH, UT Wood - H 138.00 138.00 8.00 1 18BONANZA , UT CHAPITA , UT Steel - SP 345.00 138.00 20.00 1 19CENTRAL, UT SAINT GEORGE #1, UT Steel - SP 345.00 138.00 20.00 1 20CENTRAL, UT SAINT GEORGE #2, UT Steel-SP 138.00 138.00 1.00 1 21 EBAY TAP, UT OQUIRRH, UT 22138 kV costs and expenses 23 277.00 1,945.00 126 24Subtotal 138 kV 25 26 1,613.00 27All 115 kV Lines 2,978.00 28All 69 kV Lines 113.00 29All 57 kV Lines 2,610.00 30All 46 kV Lines 31 32 33 34 35

FERC FORM NO. 1 (ED. 12-87) Page 422.7

36 TOTAL 16,015.00 767.00 250Name 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 Maintenance Rents Total Land Construction and 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 12 283,428,901 269,650,316 13,778,585 1,401,074 39,666 1,361,408 13 14 283,428,901 269,650,316 13,778,585 1,401,074 39,666 1,361,408 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 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 1,088,645,025 985,497,683 103,147,342 2,903,667 321,060 2,514,264 68,343 15 16 1,088,645,025 985,497,683 103,147,342 2,903,667 321,060 2,514,264 68,343 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 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 16 345,145,201 332,924,488 12,220,713 4,920,540 360,603 4,553,238 6,699 17 18 345,145,201 332,924,488 12,220,713 4,920,540 360,603 4,553,238 6,699 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 17,138,262 16,514,772 623,490 358,024 4,139 353,885 32 33 17,138,262 16,514,772 623,490 358,024 4,139 353,885 34 35

FERC FORM NO. 1 (ED. 12-87) Page 423.3 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335Name 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 Maintenance Rents Total Land Construction and 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 21 299,890,106 282,541,903 17,348,203 2,008,899 144,824 1,839,250 24,825 22 23 299,890,106 282,541,903 17,348,203 2,008,899 144,824 1,839,250 24,825 24 25 26 155,380,512 151,293,779 4,086,733 3,761,699 233,226 3,526,193 2,280 27 237,066,005 230,690,274 6,375,731 2,873,003 161,990 2,702,093 8,920 28 9,724,488 9,679,030 45,458 47,069 3,516 43,553 29 212,656,921 204,595,922 8,060,999 2,328,360 39,592 2,279,626 9,142 30 31 32 33 34 35

FERC FORM NO. 1 (ED. 12-87) Page 423.7 36 165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,335

### 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)XAn 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)XAn 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 450.2Name 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. (c) (b) (a) (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

9.00 Steel - SP 2 2 1TERMINAL, UT BEN LOMOND, UT 46.60 9.00 Steel - SP 2 2 2BEN LOMOND, UT POPULUS, ID 85.70 9.00 Steel - SP 2 2 3NINETY SOUTH, UT CAMP WILLIAMS, UT 10.80 8.00 Steel - SP 2 2 4CENTRAL, UT ST. GEORGE, UT 20.10 12.00 Wood - SP 1 1 5STR 169, UT THREE PEAKS, UT 6.40 8.00 Wood - H 1 1 6SHIRLEY BASIN, WY DUNLAP WIND, WY 9.00 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 TOTALTotal 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. (k) (j) (h) (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
Vertical 27' ACSR 2-1272 29,549,964 160,647,099 118,199,855 12,897,280 345 1 Vertical 27' ACSR 2-1272 74,131,831 423,239,851 296,527,325 52,580,695 345 2 Vertical 27' ACSR 2-1557.4 5,199,460 26,383,494 20,797,840 386,194 345 3 Vertical 27' ACSR 2-1272 3,718,900 19,260,071 14,875,600 665,571 138 4 Vertical 12' ACSR 795 1,314,424 4,234,172 2,789,303 130,445 138 5 Horizon 20' ACSR 1272 1,739,258 5,843,929 3,738,719 365,952 230 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

115,653,837 456,928,642

FERC FORM NO. 1 (REV. 12-03) Page 425 44 67,026,137 639,608,616

### 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)XAn 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 450.1Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

California 1 BELMONT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 BIG SPRINGS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 3 CANBY #2 2.40 69.00 DISTRIBUTION-UNATTEN 4 CASTELLA SUB 2.40 69.00 DISTRIBUTION-UNATTEN 5 CLEAR LAKE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 6 DOG CREEK SUB 2.40 69.00 DISTRIBUTION-UNATTEN 7 DORRIS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 8 FORT JONES SUB 12.47 69.00 DISTRIBUTION-UNATTEN 9 GASQUET SUB 12.47 115.00 DISTRIBUTION-UNATTEN 10 GREENHORN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 11 HAMBURG SUB 2.40 69.00 DISTRIBUTION-UNATTEN 12 HAPPY CAMP SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 HORNBROOK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 14 INTERNATIONAL PAPER SUB 2.40 69.00 DISTRIBUTION-UNATTEN 15 LAKE EARL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 16 LITTLE SHASTA SUB 7.20 69.00 DISTRIBUTION-UNATTEN 17 LUCERNE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 18 MACDOEL SUB 20.80 69.00 DISTRIBUTION-UNATTEN 19 MCCLOUD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 20 MILLER REDWOOD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 21 MONTAGUE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 22 MORRISON CREEK SUB 12.50 69.00 DISTRIBUTION-UNATTEN 23 MOUNT SHASTA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 24 NEWELL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 NORTH DUNSMUIR SUB 12.47 69.00 DISTRIBUTION-UNATTEN 26 NORTHCREST SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 NUTGLADE SUB 2.40 69.00 DISTRIBUTION-UNATTEN 28 PATRICKS CREEK SUB 7.20 115.00 DISTRIBUTION-UNATTEN 29 PEREZ SUB 12.47 69.00 DISTRIBUTION-UNATTEN 30 REDWOOD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 31 SCOTT BAR SUB 12.47 69.00 DISTRIBUTION-UNATTEN 32 SEIAD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 33 SHASTINA SUB 20.80 69.00 DISTRIBUTION-UNATTEN 34 SHOTGUN CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 35 SMITH RIVER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 36 SNOW BRUSH SUB 7.20 69.00 DISTRIBUTION-UNATTEN 37 SOUTH DUNSMUIR SUB 4.16 69.00 DISTRIBUTION-UNATTEN 38 TULELAKE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 39 TUNNEL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

WALKER BRYAN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 1 WEED SUB 12.47 115.00 DISTRIBUTION-UNATTEN 2 YUBA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 3YUROK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 4Total 468.36 3105.00 5 Number of Substations- 43 6 7ALTURAS SUB 12.47 115.00 69.00 T/D-UNATTENDED 8 FALL CREEK HYDRO/SUB 2.30 69.00 T/D-UNATTENDED 9 YREKA SUB 12.47 115.00 69.00 T/D-UNATTENDED 10 Total 27.24 299.00 138.00 11 Number of Substations- 3 12 13AGER SUB 69.00 115.00 TRANSMISSION-ATTENDE 14 COPCO #1 HYDRO PLANT 2.30 69.00 TRANSMISSION-ATTENDE 15 COPCO #2 230 SUB 115.00 230.00 TRANSMISSION-ATTENDE 16 COPCO #2 HYDRO PLANT 6.60 69.00 TRANSMISSION-ATTENDE 17 COPCO #2 SUB 69.00 115.00 TRANSMISSION-ATTENDE 18 CRAG VIEW SUB 69.00 115.00 TRANSMISSION-UNATTEN 19 DEL NORTE SUB 69.00 115.00 TRANSMISSION-UNATTEN 20 IRON GATE HYDRO PLANT 6.60 69.00 TRANSMISSION-UNATTEN 21 WEED JUNCTION SUB 69.00 115.00 TRANSMISSION-UNATTEN 22 Total 475.50 1012.00 23 Number of Substations- 9 24 25 Idaho 26 ALEXANDER 12.47 46.00 DISTRIBUTION-UNATTEN 27AMMON 12.47 69.00 DISTRIBUTION-UNATTEN 28 ANDERSON 12.47 69.00 DISTRIBUTION-UNATTEN 29 ARCO 12.47 69.00 DISTRIBUTION-UNATTEN 30 ARIMO 12.47 46.00 DISTRIBUTION-UNATTEN 31 BANCROFT SUB 12.47 46.00 DISTRIBUTION-UNATTEN 32 BELSON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 33 BERENICE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 34 CAMAS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 35 CANYON CREEK SUB 24.90 69.00 DISTRIBUTION-UNATTEN 36 CHESTERFIELD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 37 CINDER BUTTE SUB 12.47 161.00 DISTRIBUTION-UNATTEN 38 CLEMENTS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 39 CLIFTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.1Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

COVE SUB 6.60 46.00 DISTRIBUTION-UNATTEN 1 DOWNEY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 2 DUBOIS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 3 EASTMONT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 4 EGIN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 5 EIGHT MILE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 6 GEORGETOWN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 7 GRACE CITY SUBSTATION 12.47 46.00 DISTRIBUTION-UNATTEN 8 HAMER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 9 HAYES SUB 12.47 69.00 DISTRIBUTION-UNATTEN 10 HENRY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 11 HOLBROOD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 12 HOOPES SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 HORSLEY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 14 IDAHO FALLS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 15 INDIAN CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 16 JEFFCO SUB 24.90 69.00 DISTRIBUTION-UNATTEN 17 KETTLE SUB 24.90 69.00 DISTRIBUTION-UNATTEN 18 LAVA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 19 LUND SUB 12.47 46.00 DISTRIBUTION-UNATTEN 20 MCCAMMON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 MENAN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 22 MERRILL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 23 MILLER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 24 MONTPELIER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 MOODY SUB 24.90 69.00 DISTRIBUTION-UNATTEN 26 NEWDALE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 OSGOOD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 28 PRESTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 29 RAYMOND SUB 12.47 69.00 DISTRIBUTION-UNATTEN 30 RENO SUB 12.47 69.00 DISTRIBUTION-UNATTEN 31 REXBURG SUB 12.47 69.00 DISTRIBUTION-UNATTEN 32 RIRIE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 33 ROBERTS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 34 RUDY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 35 SAND CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 36 SANDUNE SUB 24.90 69.00 DISTRIBUTION-UNATTEN 37 SHELLEY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 38 SMITH SUB 12.47 69.00 DISTRIBUTION-UNATTEN 39 SOUTH FORK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.2Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

SPUD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 1 ST. CHARLES SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 SUGAR CITY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 3 SUNNYDELL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 4TANNER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 5 TARGHEE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 6 THORNTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 7 UCON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 8 WATKINS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 9 WEBSTER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 10 WESTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 11 WINDSPER SUB 24.90 69.00 DISTRIBUTION-UNATTEN 12 Total 891.73 4163.00 13 Number of Substations- 66 14 15 MALAD SUB 46.00 138.00 12.47 T/D-UNATTENDED 16 MUD LAKE SUB 12.47 69.00 T/D-UNATTENDED 17 RIGBY SUB 12.47 161.00 69.00 T/D-UNATTENDED 18 SAINT ANTHONY SUB 46.00 69.00 12.47 T/D-UNATTENDED 19 Total 116.94 437.00 93.94 20 Number of Substations- 4 21 22 GRACE HYDRO 46.00 138.00 6.60 TRANSMISSION-ATTENDE 23AMPS SUB 69.00 230.00 TRANSMISSION-UNATTEN 24ANTELOPE SUB 161.00 230.00 TRANSMISSION-UNATTEN 25 ASHTON PLANT 2.40 46.00 TRANSMISSION-UNATTEN 26 BIG GRASSY SUB 69.00 161.00 TRANSMISSION-UNATTEN 27 BONNEVILLE SUB 69.00 161.00 TRANSMISSION-UNATTEN 28 CONDA SUB 46.00 138.00 TRANSMISSION-UNATTEN 29 FISH CREEK SUB 46.00 161.00 TRANSMISSION-UNATTEN 30 FRANKLIN SUB 46.00 138.00 TRANSMISSION-UNATTEN 31 GOSHEN SUB 161.00 345.00 46.00 TRANSMISSION-UNATTEN 32 JEFFERSON SUB 69.00 161.00 TRANSMISSION-UNATTEN 33 LIFTON HYDRO 2.30 69.00 TRANSMISSION-UNATTEN 34 ONEIDA SUB 25.00 138.00 TRANSMISSION-UNATTEN 35 OVID SUB 69.00 138.00 TRANSMISSION-UNATTEN 36 SCOVILLE SUB 69.00 138.00 TRANSMISSION-UNATTEN 37 SUGARMILL SUB 46.00 161.00 69.00 TRANSMISSION-UNATTEN 38 THREEMILE KNOLL SUB 138.00 345.00 46.00 TRANSMISSION-UNATTEN 39 TREASURETON SUB 138.00 230.00 TRANSMISSION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.3Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

Total 1271.70 3128.00 167.60 1 Number of Substations- 18 2 3 MONTANA 4YELLOWTAIL SUB 161.00 230.00 TRANSMISSION-UNATTEN 5 Total 161.00 230.00 6 Number of Substations- 1 7 8 Oregon 9 26TH STREET 4.16 20.80 DISTRIBUTION-UNATTEN 10 35TH STREET 2.40 20.80 DISTRIBUTION-UNATTEN 11 AGNESS AVE 12.47 115.00 DISTRIBUTION-UNATTEN 12 ALDERWOOD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13ARLINGTON 12.47 69.00 DISTRIBUTION-UNATTEN 14ATHENA 12.47 69.00 DISTRIBUTION-UNATTEN 15 BANDON TIE SUB 12.47 20.80 DISTRIBUTION-UNATTEN 16 BEACON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 17 BEALL LANE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 18 BEATTY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 19 BELKNAP SUB 12.47 69.00 DISTRIBUTION-UNATTEN 20 BLALOCK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 21 BLOSS SUB 12.47 115.00 DISTRIBUTION-UNATTEN 22 BLY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 23 BOISE CASCADE SUB 11.00 69.00 DISTRIBUTION-UNATTEN 24 BONANZA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 BOND STREET SUB 12.50 69.00 DISTRIBUTION-UNATTEN 26 BROOKHURST SUB 12.47 115.00 DISTRIBUTION-UNATTEN 27 BROWNSVILLE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 28 BRYANT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 29 BUCHANAN SUB 20.80 115.00 DISTRIBUTION-UNATTEN 30 BUCKAROO SUB 12.47 69.00 DISTRIBUTION-UNATTEN 31 CAMPBELL SUB 12.47 115.00 DISTRIBUTION-UNATTEN 32 CANNON BEACH SUB 12.47 115.00 DISTRIBUTION-UNATTEN 33 CARNES SUB 12.47 69.00 DISTRIBUTION-UNATTEN 34 CASEBEER SUB 20.80 69.00 DISTRIBUTION-UNATTEN 35 CAVEMAN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 36 CHERRY LANE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 37 CHILOQUIN MARKET SUB 12.47 69.00 DISTRIBUTION-UNATTEN 38 CHINA HAT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 39 CIRCLE BLVD SUB 20.80 115.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.4Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

CLEVELAND AVE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 1 CLINE FALLS HYDRO 2.40 12.47 DISTRIBUTION-UNATTEN 2 CLOAKE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 3 COBURG SUB 20.80 69.00 DISTRIBUTION-UNATTEN 4 COLISEUM SUB 4.16 20.80 DISTRIBUTION-UNATTEN 5 COLUMBIA SUB 12.47 115.00 57.00 DISTRIBUTION-UNATTEN 6 COOS RIVER SUB 20.80 115.00 DISTRIBUTION-UNATTEN 7 COQUILLE SUB 20.80 115.00 DISTRIBUTION-UNATTEN 8 CREEK SUB 34.50 69.00 DISTRIBUTION-UNATTEN 9 CROOKED RIVER RANCH SUB 20.80 69.00 DISTRIBUTION-UNATTEN 10 CROWFOOT SUB 12.47 115.00 DISTRIBUTION-UNATTEN 11 CULLY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 12 CULVER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 CUTLER CITY SUB 4.16 20.80 DISTRIBUTION-UNATTEN 14 DAIRY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 15 DALLAS SUB 20.80 115.00 DISTRIBUTION-UNATTEN 16 DALREED SUB 34.50 230.00 DISTRIBUTION-UNATTEN 17 DESCHUTES SUB 12.47 69.00 DISTRIBUTION-UNATTEN 18 DEVILS LAKE SUB 20.80 115.00 DISTRIBUTION-UNATTEN 19 DIXON SUB 4.16 115.00 DISTRIBUTION-UNATTEN 20 DODGE BRIDGE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 21 DOWELL SUB 12.47 115.00 DISTRIBUTION-UNATTEN 22 EASY VALLEY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 23 EMPIRE SUB 20.80 115.00 DISTRIBUTION-UNATTEN 24 ENTERPRISE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 FERN HILL SUB 12.47 115.00 DISTRIBUTION-UNATTEN 26 FIELDER CREEK SUB 20.80 115.00 DISTRIBUTION-UNATTEN 27 FOOTHILLS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 28 FRALEY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 29 GARDEN VALLEY SUB 20.80 69.00 DISTRIBUTION-UNATTEN 30 GAZLEY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 31 GLENDALE SUB 12.47 230.00 DISTRIBUTION-UNATTEN 32 GLENEDEN SUB 4.16 20.80 DISTRIBUTION-UNATTEN 33 GLIDE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 34 GOLD HILL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 35 GORDON HOLLOW SUB 12.47 69.00 DISTRIBUTION-UNATTEN 36 GOSHEN SUB (OR) 20.80 115.00 DISTRIBUTION-UNATTEN 37 GRANT STREET SUB 20.80 115.00 DISTRIBUTION-UNATTEN 38 GRASS VALLEY SUB 4.16 20.80 DISTRIBUTION-UNATTEN 39 GREEN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.5Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

GRIFFIN CREEK SUB 12.47 115.00 DISTRIBUTION-UNATTEN 1 HAMAKER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 HARRISBURG SUB 20.80 69.00 DISTRIBUTION-UNATTEN 3 HENLEY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 4 HERMISTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 5 HILLVIEW SUB 20.80 115.00 DISTRIBUTION-UNATTEN 6 HINKLE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 7 HOLLADAY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 8 HOLLYWOOD SUB 12.47 115.00 DISTRIBUTION-UNATTEN 9 HOOD RIVER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 10 HORNET SUB 12.47 69.00 DISTRIBUTION-UNATTEN 11 HUNTERS CIRCLE TEMP SUB 12.47 69.00 DISTRIBUTION-UNATTEN 12 ILLAHEE FLATS SUB 12.47 115.00 DISTRIBUTION-UNATTEN 13 INDEPENDENCE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 14 JACKSONVILLE SUB 12.47 115.00 69.00 DISTRIBUTION-UNATTEN 15 JEFFERSON SUB 20.80 69.00 DISTRIBUTION-UNATTEN 16 JEROME PRAIRIE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 17 JORDAN POINT SUB 12.47 115.00 DISTRIBUTION-UNATTEN 18 JOSEPH SUB 12.47 20.80 DISTRIBUTION-UNATTEN 19 JUNCTION CITY SUB 20.80 69.00 DISTRIBUTION-UNATTEN 20 KENWOOD SUB 12.47 69.00 DISTRIBUTION-UNATTEN 21 KILLINGSWORTH SUB 12.47 69.00 DISTRIBUTION-UNATTEN 22 KNAPPA SVENSEN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 23 LAKEPORT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 24 LAKEVIEW SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 LANCASTER SUB 20.80 69.00 DISTRIBUTION-UNATTEN 26 LEBANON SUB 20.80 115.00 DISTRIBUTION-UNATTEN 27 LINCOLN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 28 LOCKHART SUB 20.80 115.00 DISTRIBUTION-UNATTEN 29 LYONS SUB 20.80 69.00 DISTRIBUTION-UNATTEN 30 MADRAS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 31 MALLORY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 32 MARYS RIVER SUB 20.80 115.00 DISTRIBUTION-UNATTEN 33 MEDCO SUB 12.47 115.00 DISTRIBUTION-UNATTEN 34 MEDFORD 12.47 69.00 DISTRIBUTION-UNATTEN 35 MERLIN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 36 MERRILL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 37 MINAM SUB 12.47 69.00 DISTRIBUTION-UNATTEN 38 MODOC SUB 12.47 69.00 DISTRIBUTION-UNATTEN 39 MORO SUB 2.40 20.80 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.6Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

MURDER CREEK SUB 20.80 115.00 DISTRIBUTION-UNATTEN 1 MYRTLE CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 MYRTLE POINT SUB 20.80 115.00 DISTRIBUTION-UNATTEN 3 NELSCOTT SUB 4.16 20.80 DISTRIBUTION-UNATTEN 4 NEW O'BRIEN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 5 OAK KNOLL SUB 12.47 115.00 DISTRIBUTION-UNATTEN 6 OAKLAND SUB 12.47 115.00 DISTRIBUTION-UNATTEN 7 OREMET SUB 12.47 115.00 DISTRIBUTION-UNATTEN 8 OVERPASS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 9 PALLETTE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 10 PARK STREET SUB 12.47 115.00 DISTRIBUTION-UNATTEN 11 PARKROSE SUB 12.47 57.00 DISTRIBUTION-UNATTEN 12 PENDLETON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 PILOT ROCK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 14 POWELL BUTTE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 15 PRINEVILLE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 16 PROVOLT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 17 QUEEN AVE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 18 RED BLANKET SUB 4.16 69.00 DISTRIBUTION-UNATTEN 19 REDMOND SUB 12.47 115.00 DISTRIBUTION-UNATTEN 20 RIDDLE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 21 RIDDLE VENEER SUB 12.47 115.00 DISTRIBUTION-UNATTEN 22 ROGUE RIVER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 23 ROSEBURG SUB 20.80 115.00 DISTRIBUTION-UNATTEN 24 ROSS AVE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 ROXY ANN SUB 12.50 115.00 DISTRIBUTION-UNATTEN 26 RUCH SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 RUNNING Y SUB 20.80 69.00 DISTRIBUTION-UNATTEN 28 RUSSELLVILLE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 29 SAGE ROAD SUB 12.47 115.00 DISTRIBUTION-UNATTEN 30 SCENIC SUB 12.47 115.00 69.00 DISTRIBUTION-UNATTEN 31 SCIO SUB 12.47 69.00 DISTRIBUTION-UNATTEN 32 SEASIDE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 33 SELMA SUB 12.47 115.00 DISTRIBUTION-UNATTEN 34 SHASTA WAY SUB 4.16 12.47 DISTRIBUTION-UNATTEN 35 SHEVLIN PARK SUB 12.50 69.00 DISTRIBUTION-UNATTEN 36 SIMTAG BOOSTER PUMP 4.16 34.50 DISTRIBUTION-UNATTEN 37 SOUTH DUNES SUB 12.47 115.00 DISTRIBUTION-UNATTEN 38 SOUTHGATE SUB 20.80 69.00 DISTRIBUTION-UNATTEN 39 SPRAGUE RIVER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.7Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

STATE STREET SUB 20.80 115.00 DISTRIBUTION-UNATTEN 1 STAYTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 STEAMBOAT SUB 7.20 115.00 DISTRIBUTION-UNATTEN 3 STEVENS ROAD SUB 20.80 115.00 DISTRIBUTION-UNATTEN 4 SUTHERLIN SUB 12.00 115.00 DISTRIBUTION-UNATTEN 5 SWEET HOME SUB 20.80 115.00 DISTRIBUTION-UNATTEN 6 TAKELMA SUB 20.80 115.00 DISTRIBUTION-UNATTEN 7TALENT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 8 TEXUM SUB 12.47 69.00 DISTRIBUTION-UNATTEN 9 TILLER SUB 12.47 115.00 DISTRIBUTION-UNATTEN 10 TOLO SUB 12.47 69.00 DISTRIBUTION-UNATTEN 11 TURKEY HILL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 12 UMAPINE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 UMATILLA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 14 VERNON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 15 VILAS SUB 12.47 115.00 DISTRIBUTION-UNATTEN 16 VILLAGE GREEN SUB 20.80 115.00 DISTRIBUTION-UNATTEN 17 VINE STREET SUB 20.80 69.00 DISTRIBUTION-UNATTEN 18 WALLOWA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 19 WARM SPRINGS SUB 20.80 69.00 DISTRIBUTION-UNATTEN 20 WARRENTON SUB 12.47 115.00 DISTRIBUTION-UNATTEN 21 WASCO SUB 4.16 20.80 DISTRIBUTION-UNATTEN 22 WECOMA BEACH SUB 4.16 20.80 DISTRIBUTION-UNATTEN 23 WESTERN KRAFT SUB 12.47 115.00 DISTRIBUTION-UNATTEN 24 WESTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 WESTSIDE HYDRO/SUB 12.47 69.00 DISTRIBUTION-UNATTEN 26 WEYERHAUSER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 WHITE CITY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 28 WILLOW COVE SUB 4.16 34.50 DISTRIBUTION-UNATTEN 29 WINSTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 30 YEW AVENUE SUB 12.50 115.00 DISTRIBUTION-UNATTEN 31 YOUNGS BAY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 32 Total 2522.27 15580.54 195.00 33 Number of Substations- 183 34 35 ALBINA SUB 12.47 115.00 69.00 T/D-UNATTENDED 36 APPLEGATE SUB 69.00 115.00 12.47 T/D-UNATTENDED 37ASHLAND MTN AVE SUB 69.00 115.00 12.47 T/D-UNATTENDED 38 BEND PLANT 4.16 69.00 12.47 T/D-UNATTENDED 39 CAVE JUNCTION SUB 12.47 115.00 69.00 T/D-UNATTENDED 40

FERC FORM NO. 1 (ED. 12-96) Page 426.8Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

HAZELWOOD SUB 69.00 115.00 12.47 T/D-UNATTENDED 1 KNOTT SUB 12.47 115.00 57.00 T/D-UNATTENDED 2 MILE HI SUB 69.00 115.00 12.47 T/D-UNATTENDED 3 PILOT BUTTE SUB 69.00 230.00 12.47 T/D-UNATTENDED 4 WINCHESTER SUB 12.47 115.00 69.00 T/D-UNATTENDED 5 Total 399.04 1219.00 338.82 6 Number of Substations- 10 7 8 CLEARWATER #1 HYDRO PLANT 6.90 138.00 TRANSMISSION-ATTENDE 9 FISH CREEK HYDRO 6.90 115.00 TRANSMISSION-ATTENDE 10 JC BOYLE HYDRO 11.00 230.00 TRANSMISSION-ATTENDE 11 LEMOLO #1 HYDRO 12.50 11.30 TRANSMISSION-ATTENDE 12 LEMOLO #2 HYDRO 12.00 115.00 TRANSMISSION-ATTENDE 13 PROSPECT 1 HYDRO 2.30 69.00 TRANSMISSION-ATTENDE 14 PROSPECT 2 HYDRO 6.60 69.00 TRANSMISSION-ATTENDE 15 PROSPECT 3 HYDRO 12.47 69.00 TRANSMISSION-ATTENDE 16 TOKETEE HYDRO 6.90 115.00 TRANSMISSION-ATTENDE 17 BEND PLANT 2.40 4.16 TRANSMISSION-UNATTEN 18 CALAPOOYA SUB 69.00 230.00 TRANSMISSION-UNATTEN 19 CHILOQUIN SUB 115.00 230.00 69.00 TRANSMISSION-UNATTEN 20 COLD SPRINGS SUB 69.00 230.00 TRANSMISSION-UNATTEN 21 COVE SUB 69.00 230.00 TRANSMISSION-UNATTEN 22 DAYS CREEK SUB 69.00 115.00 TRANSMISSION-UNATTEN 23 DIAMOND HILL SUB 69.00 230.00 TRANSMISSION-UNATTEN 24 DIXONVILLE 115/230 SUB 115.00 230.00 69.00 TRANSMISSION-UNATTEN 25 DIXONVILLE 500 SUB 230.00 500.00 TRANSMISSION-UNATTEN 26 EAGLE POINT HYDRO 2.40 115.00 TRANSMISSION-UNATTEN 27 EAST SIDE HYDRO 12.47 46.00 TRANSMISSION-UNATTEN 28 FISH HOLE SUB 69.00 115.00 TRANSMISSION-UNATTEN 29 FRY SUB 115.00 230.00 TRANSMISSION-UNATTEN 30 GRANTS PASS SUB 115.00 230.00 69.00 TRANSMISSION-UNATTEN 31 GREEN SPRINGS PLANT/SUB 69.00 115.00 TRANSMISSION-UNATTEN 32 HURRICANE SUB 69.00 230.00 2.40 TRANSMISSION-UNATTEN 33 ISTHMUS SUB 115.00 230.00 TRANSMISSION-UNATTEN 34 KENNEDY SUB 57.00 69.00 TRANSMISSION-UNATTEN 35 KLAMATH FALLS SUB 69.00 230.00 TRANSMISSION-UNATTEN 36 LONE PINE SUB 115.00 230.00 69.00 TRANSMISSION-UNATTEN 37 MERIDIAN SUB 230.00 500.00 TRANSMISSION-UNATTEN 38 MONPAC SUB 69.00 115.00 TRANSMISSION-UNATTEN 39 NICKEL MOUNTAIN 115.00 230.00 TRANSMISSION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.9Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

PARRISH GAP SUB 69.00 230.00 12.47 TRANSMISSION-UNATTEN 1 PONDEROSA SUB 115.00 230.00 TRANSMISSION-UNATTEN 2 POWERDALE PLANT 7.20 69.00 TRANSMISSION-UNATTEN 3 PROSPECT CENTRAL SUB 69.00 115.00 TRANSMISSION-UNATTEN 4 ROBERTS CREEK SUB 69.00 115.00 TRANSMISSION-UNATTEN 5 SLIDE CREEK HYDRO 7.00 115.00 TRANSMISSION-UNATTEN 6 SODA SPRINGS HYDRO 7.00 115.00 TRANSMISSION-UNATTEN 7TROUTDALE SUB 115.00 230.00 69.00 TRANSMISSION-UNATTEN 8 TUCKER SUB 69.00 115.00 TRANSMISSION-UNATTEN 9 WALLOWA FALLS HYDRO 20.80 TRANSMISSION-UNATTEN 10 Total 2634.04 6970.26 359.87 11 Number of Substations- 42 12 13 Utah 14 106TH SOUTH SUB 12.50 138.00 DISTRIBUTION-UNATTEN 15 118TH SOUTH SUB 12.47 138.00 DISTRIBUTION-UNATTEN 16 23RD ST SUB 12.47 46.00 DISTRIBUTION-UNATTEN 17 70TH SOUTH SUB 12.47 138.00 DISTRIBUTION-UNATTEN 18 ALTAVIEW SUB 12.47 46.00 DISTRIBUTION-UNATTEN 19 AMALGA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 20 AMERICAN FORK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 21 ARAGONITE 7.20 46.00 DISTRIBUTION-UNATTEN 22 AURORA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 23 BANGERTER SUB 12.47 138.00 DISTRIBUTION-UNATTEN 24 BEAR RIVER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 25 BENJAMIN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 26 BINGHAM SUB 12.47 46.00 DISTRIBUTION-UNATTEN 27 BLUE CREEK 12.47 46.00 DISTRIBUTION-UNATTEN 28 BLUFF SUB 12.47 69.00 DISTRIBUTION-UNATTEN 29 BLUFFDALE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 30 BOTHWELL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 31 BOX ELDER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 32 BRIAN HEAD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 33 BRICKYARD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 34 BRIGHTON SUB 24.90 46.00 DISTRIBUTION-UNATTEN 35 BROOKLAWN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 36 BRUNSWICK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 37 BURTON SUB 12.47 34.50 DISTRIBUTION-UNATTEN 38 BUSH SUB 12.47 46.00 DISTRIBUTION-UNATTEN 39 CANNON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.10Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

CANYONLANDS SUB 12.47 69.00 DISTRIBUTION-UNATTEN 1 CAPITOL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 2 CARBIDE SUB 7.20 46.00 DISTRIBUTION-UNATTEN 3 CARBONVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 4 CARLISLE SUB 12.50 138.00 DISTRIBUTION-UNATTEN 5 CASTO SUBSTATION 12.47 46.00 DISTRIBUTION-UNATTEN 6 CENTENNIAL SUB 12.47 138.00 DISTRIBUTION-UNATTEN 7 CENTERVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 8 CENTRAL SUB 12.47 43.80 DISTRIBUTION-UNATTEN 9 CHAPEL HILL SUB 12.47 138.00 DISTRIBUTION-UNATTEN 10 CHERRYWOOD SUB 12.47 138.00 DISTRIBUTION-UNATTEN 11 CIRCLEVILLE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 12 CLEAR CREEK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 13 CLEAR LAKE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 14 CLEARFIELD SOUTH SUB 12.47 138.00 DISTRIBUTION-UNATTEN 15 CLINTON SUB 12.47 138.00 DISTRIBUTION-UNATTEN 16 CLIVE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 17 COALVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 18 COLD WATER CANYON SUB 12.47 138.00 DISTRIBUTION-UNATTEN 19 COLEMAN SUB 69.00 138.00 12.47 DISTRIBUTION-UNATTEN 20 COLTON WELL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 COMMERCE SUB 12.50 138.00 DISTRIBUTION-UNATTEN 22 CORINNE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 23 COVE FORT SUB 12.47 46.00 DISTRIBUTION-UNATTEN 24 COZYDALE SUB 12.50 138.00 DISTRIBUTION-UNATTEN 25 CRESCENT JUNCTION SUB 7.20 46.00 DISTRIBUTION-UNATTEN 26 CROSS HOLLOW SUB 12.47 138.00 DISTRIBUTION-UNATTEN 27 CUDAHY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 28 DAMMERON VALLEY SUB 12.47 34.50 DISTRIBUTION-UNATTEN 29 DECADE SUB 12.50 138.00 DISTRIBUTION-UNATTEN 30 DECKER LAKE SUB 12.47 138.00 DISTRIBUTION-UNATTEN 31 DELLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 32 DELTA SUB 69.00 46.00 DISTRIBUTION-UNATTEN 33 DESERET SUB 4.16 46.00 DISTRIBUTION-UNATTEN 34 DEWEYVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 35 DIMPLE DELL SUB 12.47 138.00 DISTRIBUTION-UNATTEN 36 DIXIE DEER SUB 12.47 34.50 DISTRIBUTION-UNATTEN 37 DRAPER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 38 DUMAS SUB 12.47 138.00 DISTRIBUTION-UNATTEN 39 EAST BENCH SUB 12.47 138.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.11Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

EAST HYRUM SUB 12.47 46.00 DISTRIBUTION-UNATTEN 1 EAST LAYTON SUB 12.47 138.00 DISTRIBUTION-UNATTEN 2 EAST MILLCREEK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 3 EDEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 4 ELBERTA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 5 ELK MEADOWS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 6 ELSINORE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 7 EMERY CITY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 8 EMIGRATION SUB 12.47 46.00 DISTRIBUTION-UNATTEN 9 ENOCH SUB 12.47 138.00 DISTRIBUTION-UNATTEN 10 ENTERPRISE VALLEY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 11 EUREKA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 12 FARMINGTON SUB 12.47 138.00 DISTRIBUTION-UNATTEN 13 FAYETTE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 14 FERRON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 15 FIELDING SUB 12.00 46.00 DISTRIBUTION-UNATTEN 16 FIFTH WEST SUB 12.47 138.00 DISTRIBUTION-UNATTEN 17 FLUX SUB 12.47 46.00 DISTRIBUTION-UNATTEN 18 FOOL CREEK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 19 FOUNTAIN GREEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 20 FREEDOM SUBSTATION 7.20 46.00 DISTRIBUTION-UNATTEN 21 FRUIT HEIGHTS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 22 GARDEN CITY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 23 GATEWAY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 24 GOLD RUSH SUB 12.50 138.00 DISTRIBUTION-UNATTEN 25 GORDON AVENUE SUB 12.50 138.00 DISTRIBUTION-UNATTEN 26 GOSHEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 27 GRANGER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 28 GRANTSVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 29 GREEN RIVER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 30 GROW SUB 12.47 138.00 46.00 DISTRIBUTION-UNATTEN 31 GUNLOCK HYDRO 2.30 34.50 DISTRIBUTION-UNATTEN 32 GUNNISON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 33 HAMMER SUB 12.47 138.00 DISTRIBUTION-UNATTEN 34 HAVASU SUB 12.47 69.00 DISTRIBUTION-UNATTEN 35 HELPER CITY SUB 4.16 46.00 DISTRIBUTION-UNATTEN 36 HENEFER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 37 HERRIMAN SUB 12.47 138.00 DISTRIBUTION-UNATTEN 38 HIAWATHA SUB 4.16 46.00 DISTRIBUTION-UNATTEN 39 HIGHLAND DIST SUB 12.47 46.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.12Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

HOGGARD SUB 12.47 138.00 DISTRIBUTION-UNATTEN 1 HOGLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 2 HOLDEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 3 HOLLADAY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 4 HUNTER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 5 HUNTINGTON CITY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 6 IRON MOUNTAIN SUB 7.20 34.50 DISTRIBUTION-UNATTEN 7 IRON SPRINGS SUB 12.47 34.50 DISTRIBUTION-UNATTEN 8 IRONTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 9 IVINS SUB 12.47 34.50 DISTRIBUTION-UNATTEN 10 JORDAN NARROWS SUB 2.40 46.00 DISTRIBUTION-UNATTEN 11 JORDAN PARK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 12 JORDANELLE SUB 12.47 138.00 DISTRIBUTION-UNATTEN 13 JUAB SUB 12.47 46.00 DISTRIBUTION-UNATTEN 14 JUNCTION SUB 12.47 69.00 DISTRIBUTION-UNATTEN 15 KAIBAB SUB 12.47 69.00 DISTRIBUTION-UNATTEN 16 KAMAS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 17 KEARNS SUB 12.47 138.00 DISTRIBUTION-UNATTEN 18 KENSINGTON SUB 4.16 46.00 DISTRIBUTION-UNATTEN 19 LAKE PARK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 20 LARK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 LAYTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 22 LEGRANDE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 23 LEWISTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 24 LINCOLN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 25 LINDON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 26 LISBON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 LITTLE MOUNTAIN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 28 LOAFER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 29 LOGAN CANYON SUB 7.20 46.00 DISTRIBUTION-UNATTEN 30 LONE TREE SUB 12.47 34.50 DISTRIBUTION-UNATTEN 31 LOWER BEAVER SUB 6.60 46.00 DISTRIBUTION-UNATTEN 32 LYNNDYL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 33 MAESER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 34 MAGNA SUB 12.47 138.00 DISTRIBUTION-UNATTEN 35 MANILA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 36 MANTUA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 37 MAPLETON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 38 MARRIOTT SUB 12.47 46.00 DISTRIBUTION-UNATTEN 39 MARYSVALE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.13Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

MATHIS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 1 MCCORNICK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 2 MCKAY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 3 MEADOWBROOK SUB 12.47 138.00 46.00 DISTRIBUTION-UNATTEN 4 MEDICAL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 5 MELLING SUB 4.16 34.50 DISTRIBUTION-UNATTEN 6 MIDLAND SUB 12.47 138.00 DISTRIBUTION-UNATTEN 7 MIDVALE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 8 MILFORD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 9 MILFORD TV SUB 13.20 46.00 DISTRIBUTION-UNATTEN 10 MILLVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 11 MINERSVILLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 12 MOAB CITY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 MONTEZUMA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 14 MOORE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 15 MORGAN SUB 4.16 46.00 DISTRIBUTION-UNATTEN 16 MORONI SUB 12.47 46.00 DISTRIBUTION-UNATTEN 17 MORTON COURT SUB 12.47 138.00 DISTRIBUTION-UNATTEN 18 MOSS JUNCTION SUB 12.47 46.00 DISTRIBUTION-UNATTEN 19 MOUNTAIN DELL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 20 MOUNTAIN GREEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 MYTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 22 NEW HARMONY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 23 NEWGATE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 24 NEWTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 25 NIBLEY SUB 24.90 46.00 DISTRIBUTION-UNATTEN 26 NORTH BENCH SUB 12.47 46.00 DISTRIBUTION-UNATTEN 27 NORTH FIELDS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 28 NORTH LOGAN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 29 NORTH OGDEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 30 NORTH SALT LAKE SUB 13.20 46.00 DISTRIBUTION-UNATTEN 31 NORTHEAST SUB 12.50 46.00 DISTRIBUTION-UNATTEN 32 NORTHRIDGE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 33 OAKLAND AVE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 34 OAKLEY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 35 OLYMPUS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 36 OPHIR SUB 12.47 46.00 DISTRIBUTION-UNATTEN 37 ORANGE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 38 ORANGEVILLE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 39 OREM SUB 12.47 46.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.14Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

PACK CREEK RESERVOIR 12.47 46.00 DISTRIBUTION-UNATTEN 1 PANGUITCH SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 PARIETTE SUBSTATION 24.90 69.00 DISTRIBUTION-UNATTEN 3 PARK CITY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 4 PARKWAY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 5 PARLEYS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 6 PELICAN POINT SUB 12.47 46.00 DISTRIBUTION-UNATTEN 7 PINE CANYON SUB 12.47 138.00 DISTRIBUTION-UNATTEN 8 PINE CREEK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 9 PINNACLE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 10 PLAIN CITY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 11 PLEASANT GROVE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 12 PLEASANT VIEW SUB 12.47 46.00 DISTRIBUTION-UNATTEN 13 PORTER ROCKWELL SUB 12.47 138.00 DISTRIBUTION-UNATTEN 14 PROMONTORY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 15 QUAIL CREEK SUB 12.47 34.50 DISTRIBUTION-UNATTEN 16 QUARRY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 17 QUICHAPA SUB 12.47 34.50 DISTRIBUTION-UNATTEN 18 RAINS SUB 7.20 46.00 DISTRIBUTION-UNATTEN 19 RANDOLPH SUB 12.47 46.00 DISTRIBUTION-UNATTEN 20 RASMUSON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 RATTLESNAKE SUB 24.90 69.00 DISTRIBUTION-UNATTEN 22 RED MOUNTAIN SUB 34.50 69.00 DISTRIBUTION-UNATTEN 23 RED ROCK SUB 4.16 69.00 DISTRIBUTION-UNATTEN 24 REDWOOD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 25 RESEARCH PARK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 26 RICH SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 RICHFIELD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 28 RICHMOND SUB 12.47 46.00 DISTRIBUTION-UNATTEN 29 RIDGELAND SUB 12.47 138.00 DISTRIBUTION-UNATTEN 30 RITER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 31 ROCK CANYON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 32 ROCKVILLE SUB 12.47 34.50 DISTRIBUTION-UNATTEN 33 ROCKY POINT 13.20 138.00 DISTRIBUTION-UNATTEN 34 ROSE PARK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 35 ROYAL SUB 4.16 46.00 DISTRIBUTION-UNATTEN 36 SALINA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 37 SANDY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 38 SARATOGA SUB 12.47 138.00 DISTRIBUTION-UNATTEN 39 SCIPIO SUB 12.47 46.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.15Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

SCOFIELD RESERVOIR SUB 7.20 46.00 DISTRIBUTION-UNATTEN 1 SCOFIELD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 2 SECOND STREET SUB 12.47 46.00 DISTRIBUTION-UNATTEN 3 SEVEN MILE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 4 SHARON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 5 SHIVWITS SUB 4.16 34.50 DISTRIBUTION-UNATTEN 6 SHORELINE SUB 13.20 138.00 DISTRIBUTION-UNATTEN 7 SIXTH SOUTH SUB 12.47 46.00 DISTRIBUTION-UNATTEN 8 SKULL VALLEY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 9 SNARR SUB 12.47 46.00 DISTRIBUTION-UNATTEN 10 SNOWVILLE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 11 SNYDERVILLE SUB 12.47 138.00 DISTRIBUTION-UNATTEN 12 SOLDIER SUMMIT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 13 SOUTH JORDAN SUB 12.47 138.00 DISTRIBUTION-UNATTEN 14 SOUTH MILFORD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 15 SOUTH MOUNTAIN SUB 12.47 138.00 DISTRIBUTION-UNATTEN 16 SOUTH OGDEN SUB 12.47 46.00 DISTRIBUTION-UNATTEN 17 SOUTH PARK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 18 SOUTH WEBER SUB 12.47 138.00 DISTRIBUTION-UNATTEN 19 SOUTHEAST SUB 12.47 138.00 46.00 DISTRIBUTION-UNATTEN 20 SOUTHWEST SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 SPANISH VALLEY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 22 SPRINGDALE SUB 12.47 34.50 DISTRIBUTION-UNATTEN 23 ST. JOHNS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 24 STAIRS SUB 2.40 12.47 DISTRIBUTION-UNATTEN 25 STANSBURY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 26 SUMMIT CREEK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 27 SUMMIT PARK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 28 SUNRISE SUB 12.47 138.00 DISTRIBUTION-UNATTEN 29 SUPERIOR SUB 12.47 69.00 DISTRIBUTION-UNATTEN 30 SUTHERLAND SUB 12.47 46.00 DISTRIBUTION-UNATTEN 31 TAMARISK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 32 TAYLOR SUB 12.47 46.00 DISTRIBUTION-UNATTEN 33THIEF CREEK SUB 24.90 138.00 DISTRIBUTION-UNATTEN 34THIRD WEST SUB 12.47 46.00 DISTRIBUTION-UNATTEN 35 THIRTEENTH SOUTH SUB 12.47 46.00 DISTRIBUTION-UNATTEN 36 THOMPSON SUB 4.16 46.00 DISTRIBUTION-UNATTEN 37TOOELE DEPOT SUB 12.50 46.00 DISTRIBUTION-UNATTEN 38 TOQUERVILLE SUB 12.47 69.00 34.50 DISTRIBUTION-UNATTEN 39 TRI CITY SUB 12.47 138.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.16Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

UINTAH SUB 12.47 46.00 DISTRIBUTION-UNATTEN 1 UNION SUB 12.47 46.00 DISTRIBUTION-UNATTEN 2 UNIVERSITY SUB 4.16 46.00 DISTRIBUTION-UNATTEN 3 VALLEY CENTER SUB 12.47 46.00 DISTRIBUTION-UNATTEN 4 VERMILLION SUB 12.47 46.00 DISTRIBUTION-UNATTEN 5 VERNAL SUB 12.47 69.00 DISTRIBUTION-UNATTEN 6 VEYO HYDRO 2.40 34.50 DISTRIBUTION-UNATTEN 7 VICKERS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 8 VINEYARD SUB 12.47 46.00 DISTRIBUTION-UNATTEN 9 WALLSBURG SUB 12.47 138.00 DISTRIBUTION-UNATTEN 10 WALNUT GROVE SUB 12.50 138.00 DISTRIBUTION-UNATTEN 11 WARREN SUB 12.47 138.00 DISTRIBUTION-UNATTEN 12 WASATCH STATE PARK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 13 WASHAKIE SUB 4.16 138.00 DISTRIBUTION-UNATTEN 14 WELBY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 15 WELFARE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 16 WELLINGTON SUB 12.47 46.00 DISTRIBUTION-UNATTEN 17 WEST COMMERCIAL SUB 12.47 46.00 DISTRIBUTION-UNATTEN 18 WEST JORDAN SUB 12.47 138.00 DISTRIBUTION-UNATTEN 19 WEST OGDEN SUB 12.47 138.00 DISTRIBUTION-UNATTEN 20 WEST ROY SUB 12.47 46.00 DISTRIBUTION-UNATTEN 21 WEST TEMPLE SUB 4.16 46.00 DISTRIBUTION-UNATTEN 22 WESTFIELD SUB 12.47 138.00 DISTRIBUTION-UNATTEN 23 WESTWATER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 24 WHITE MESA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 25 WHITE ROCK SUB 12.47 138.00 DISTRIBUTION-UNATTEN 26 WILLOWCREEK SUB 12.47 46.00 DISTRIBUTION-UNATTEN 27 WILLOWRIDGE SUB 12.47 46.00 DISTRIBUTION-UNATTEN 28 WINCHESTER HILLS SUB 12.47 34.50 DISTRIBUTION-UNATTEN 29 WINKLEMAN SUB 7.20 46.00 DISTRIBUTION-UNATTEN 30 WOLF CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 31 WOOD CROSS SUB 12.47 46.00 DISTRIBUTION-UNATTEN 32 WOODRUFF SUB 12.47 46.00 DISTRIBUTION-UNATTEN 33Total 3726.81 20756.27 184.97 34 Number of Substations- 299 35 36 ANGEL SUB 12.47 138.00 46.00 T/D-UNATTENDED 37 BDO SUBSTATION 12.47 138.00 T/D-UNATTENDED 38 BUTLERVILLE SUB 46.00 138.00 12.47 T/D-UNATTENDED 39 COTTONWOOD SUB 12.47 138.00 46.00 T/D-UNATTENDED 40

FERC FORM NO. 1 (ED. 12-96) Page 426.17Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

EMMA PARK SUBSTATION 12.47 138.00 T/D-UNATTENDED 1 HALE SUB 46.00 138.00 12.47 T/D-UNATTENDED 2 HIGHLAND SUB 12.47 138.00 46.00 T/D-UNATTENDED 3 JORDAN SUB 46.00 138.00 12.47 T/D-UNATTENDED 4 JUDGE SUB 12.47 46.00 T/D-UNATTENDED 5 MCCLELLAND SUB 46.00 138.00 12.47 T/D-UNATTENDED 6 OQUIRRH SUB 46.00 345.00 138.00 T/D-UNATTENDED 7 PARRISH SUB 12.47 138.00 46.00 T/D-UNATTENDED 8 PIONEER PLANT 2.30 138.00 46.00 T/D-UNATTENDED 9 RIVERDALE SUB 46.00 138.00 12.47 T/D-UNATTENDED 10 SEVIER SUB 46.00 138.00 12.47 T/D-UNATTENDED 11 SILVER CREEK SUB 12.47 138.00 46.00 T/D-UNATTENDED 12 SPHINX SUB 12.47 46.00 T/D-UNATTENDED 13 SYRACUSE SUB 46.00 345.00 138.00 T/D-UNATTENDED 14TAYLORSVILLE SUB 46.00 138.00 12.47 T/D-UNATTENDED 15 TERMINAL SUB 46.00 345.00 138.00 T/D-UNATTENDED 16 TIMP SUB 46.00 138.00 12.47 T/D-UNATTENDED 17TOOELE SUB 46.00 138.00 12.47 T/D-UNATTENDED 18 WEST VALLEY SUB 12.47 138.00 T/D-UNATTENDED 19 Total 679.00 3611.00 802.23 20 Number of Substations- 23 21 22 EMERY SUB 138.00 345.00 69.00 TRANSMISSION-ATTENDE 23 GADSBY SUB 46.00 138.00 TRANSMISSION-ATTENDE 24 HUNTER PLANT 23.00 345.00 TRANSMISSION-ATTENDE 25 HUNTINGTON PLANT 23.00 345.00 TRANSMISSION-ATTENDE 26 90TH SOUTH SUB 138.00 345.00 TRANSMISSION-UNATTEN 27ABAJO SUB 69.00 138.00 TRANSMISSION-UNATTEN 28 ASHLEY SUB 46.00 138.00 TRANSMISSION-UNATTEN 29 BARNEY SUB 46.00 138.00 TRANSMISSION-UNATTEN 30 BEN LOMOND SUB 230.00 345.00 138.00 TRANSMISSION-UNATTEN 31 BLACKHAWK SUB 69.00 138.00 46.00 TRANSMISSION-UNATTEN 32 BOOKCLIFFS SUB 46.00 69.00 TRANSMISSION-UNATTEN 33 CAMERON SUB 46.00 138.00 TRANSMISSION-UNATTEN 34 CAMP WILLIAMS SUB 138.00 345.00 12.47 TRANSMISSION-UNATTEN 35 CARBON SUB 138.00 TRANSMISSION-UNATTEN 36 COLUMBIA SUB 46.00 138.00 TRANSMISSION-UNATTEN 37 CRANER FLAT SUB 12.47 138.00 TRANSMISSION-UNATTEN 38 CUTLER SUB 46.00 138.00 TRANSMISSION-UNATTEN 39 EL MONTE SUB 46.00 138.00 TRANSMISSION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.18Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

GARKANE SUB 46.00 69.00 TRANSMISSION-UNATTEN 1 GREEN CANYON SUB 46.00 138.00 TRANSMISSION-UNATTEN 2 GRINDING SUB 13.80 138.00 TRANSMISSION-UNATTEN 3 HELPER SUB 46.00 138.00 TRANSMISSION-UNATTEN 4 HONEYVILLE SUB 46.00 138.00 TRANSMISSION-UNATTEN 5 HORSESHOE SUB 46.00 138.00 12.47 TRANSMISSION-UNATTEN 6 HUNTINGTON SUB 138.00 345.00 TRANSMISSION-UNATTEN 7 JERUSALEM SUB 46.00 138.00 TRANSMISSION-UNATTEN 8 LAMPO SUB 46.00 138.00 TRANSMISSION-UNATTEN 9 MCFADDEN SUB 46.00 138.00 TRANSMISSION-UNATTEN 10 MIDDLETON SUB 69.00 138.00 34.50 TRANSMISSION-UNATTEN 11 MIDVALLEY SUB 138.00 345.00 TRANSMISSION-UNATTEN 12 MIDWAY CITY SUB 46.00 138.00 TRANSMISSION-UNATTEN 13 MINERAL PRODUCTS SUB 46.00 69.00 TRANSMISSION-UNATTEN 14 MOAB SUB 69.00 138.00 TRANSMISSION-UNATTEN 15 NEBO SUB 46.00 138.00 TRANSMISSION-UNATTEN 16 OLMSTED SUB 2.40 46.00 TRANSMISSION-UNATTEN 17 PAROWAN VALLEY SUB 138.00 230.00 34.50 TRANSMISSION-UNATTEN 18 PAVANT SUB 46.00 230.00 TRANSMISSION-UNATTEN 19 PINTO SUB 138.00 345.00 69.00 TRANSMISSION-UNATTEN 20 RED BUTTE SUB 138.00 230.00 TRANSMISSION-UNATTEN 21 SAND COVE HYDRO 2.40 34.50 TRANSMISSION-UNATTEN 22 SIGURD SUB 230.00 345.00 138.00 TRANSMISSION-UNATTEN 23 SMITHFIELD SUB 46.00 138.00 12.47 TRANSMISSION-UNATTEN 24 SPANISH FORK SUB 138.00 345.00 46.00 TRANSMISSION-UNATTEN 25 ST GEORGE SUB 16.50 138.00 TRANSMISSION-UNATTEN 26 THREE PEAKS SUB 138.00 345.00 TRANSMISSION-UNATTEN 27 WEBER PLANT/SUB 2.30 46.00 TRANSMISSION-UNATTEN 28 WEST CEDAR SUB 138.00 230.00 34.50 TRANSMISSION-UNATTEN 29 Total 3315.87 8843.50 646.91 30 Number of Substations- 47 31 32 Washington 33ATTALIA SUB 12.47 69.00 DISTRIBUTION-UNATTEN 34 BOWMAN SUB 12.47 69.00 DISTRIBUTION-UNATTEN 35 CASCADE KRAFT SUB 12.47 69.00 4.16 DISTRIBUTION-UNATTEN 36 CLINTON SUB 12.47 115.00 DISTRIBUTION-UNATTEN 37 DAYTON SUB 12.47 69.00 DISTRIBUTION-UNATTEN 38 DODD ROAD SUB 20.80 69.00 DISTRIBUTION-UNATTEN 39 GRANDVIEW SUB 12.47 115.00 69.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.19Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

HOPLAND SUB 12.47 115.00 DISTRIBUTION-UNATTEN 1 MILL CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 2 NACHES HYDRO 12.47 115.00 DISTRIBUTION-UNATTEN 3 NOB HILL SUB 12.47 115.00 DISTRIBUTION-UNATTEN 4 NORTH PARK SUB 12.47 115.00 DISTRIBUTION-UNATTEN 5 ORCHARD SUB 12.47 115.00 DISTRIBUTION-UNATTEN 6 PACIFIC SUB 12.47 115.00 DISTRIBUTION-UNATTEN 7 POMEROY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 8 PROSPECT POINT SUB 12.47 69.00 DISTRIBUTION-UNATTEN 9 PUNKIN CENTER SUB 12.47 115.00 DISTRIBUTION-UNATTEN 10 RIVER ROAD SUB 12.47 115.00 DISTRIBUTION-UNATTEN 11 SELAH SUB 12.47 115.00 DISTRIBUTION-UNATTEN 12 SULPHUR CREEK SUB 12.47 115.00 DISTRIBUTION-UNATTEN 13 SUNNYSIDE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 14TIETON SUB 12.47 115.00 34.50 DISTRIBUTION-UNATTEN 15 TOPPENISH SUB 12.47 115.00 DISTRIBUTION-UNATTEN 16 TOUCHET SUB 12.47 69.00 DISTRIBUTION-UNATTEN 17 VOELKER SUB 12.47 115.00 DISTRIBUTION-UNATTEN 18 WAITSBURG SUB 12.47 69.00 DISTRIBUTION-UNATTEN 19 WAPATO SUB 12.47 115.00 DISTRIBUTION-UNATTEN 20 WENAS SUB 12.47 115.00 DISTRIBUTION-UNATTEN 21 WHITE SWAN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 22 WILEY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 23Total 382.43 2990.00 107.66 24 Number of Substations- 30 25 26 CENTRAL SUB 12.47 69.00 T/D-UNATTENDED 27 UNION GAP SUB 115.00 230.00 12.47 T/D-UNATTENDED 28 Total 127.47 299.00 12.47 29 Number of Substations- 2 30 31 CONDIT PLANT 2.30 69.00 TRANSMISSION-ATTENDE 32 MERWIN PLANT 13.20 115.00 TRANSMISSION-ATTENDE 33YALE PLANT 13.80 115.00 TRANSMISSION-ATTENDE 34 OUTLOOK SUB 115.00 230.00 TRANSMISSION-UNATTEN 35 PASCO SUB 69.00 115.00 7.20 TRANSMISSION-UNATTEN 36 POMONA HEIGHTS SUB 115.00 230.00 TRANSMISSION-UNATTEN 37 WALLA WALLA 230KV SUB 69.00 230.00 TRANSMISSION-UNATTEN 38 WALLULA SUB 69.00 230.00 TRANSMISSION-UNATTEN 39 WINE COUNTRY SUB 115.00 230.00 TRANSMISSION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.20Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

Total 581.30 1564.00 7.20 1 Number of Substations- 9 2 3 Wyoming 4AIR BASE 2.40 12.47 DISTRIBUTION-UNATTEN 5 ANTELOPE MINE SUB 34.50 230.00 DISTRIBUTION-UNATTEN 6 ASTLE STREET 13.20 34.50 DISTRIBUTION-UNATTEN 7 BAILEY DOME SUB 12.47 57.00 DISTRIBUTION-UNATTEN 8 BAR X SUB 34.50 230.00 DISTRIBUTION-UNATTEN 9 BID MUDDY SUB 12.47 69.00 DISTRIBUTION-UNATTEN 10 BIG PINEY SUB 24.90 69.00 DISTRIBUTION-UNATTEN 11 BLACKS FORK SUB 34.50 230.00 DISTRIBUTION-UNATTEN 12 BRIDGER PUMP SUB 34.50 230.00 13.20 DISTRIBUTION-UNATTEN 13 BRYAN SUB 12.47 115.00 DISTRIBUTION-UNATTEN 14 BUFFALO TOWN SUB 4.16 20.80 DISTRIBUTION-UNATTEN 15 BYRON SUB 4.16 34.50 DISTRIBUTION-UNATTEN 16 CASSA SUB 20.80 57.00 DISTRIBUTION-UNATTEN 17 CENTER STREET SUB 4.16 115.00 DISTRIBUTION-UNATTEN 18 CHAPMAN SUBSTATION 12.47 46.00 DISTRIBUTION-UNATTEN 19 CHATHAM SUB 4.16 34.50 DISTRIBUTION-UNATTEN 20 CHUKAR SUB 4.16 12.47 DISTRIBUTION-UNATTEN 21 CHURCH AND DWIGHT SUB 0.48 34.50 DISTRIBUTION-UNATTEN 22 COKEVILLE SUB 24.90 46.00 DISTRIBUTION-UNATTEN 23 COLUMBIA-GENEVA SUB 13.80 230.00 DISTRIBUTION-UNATTEN 24 COMMUNITY PARK SUB 13.20 115.00 DISTRIBUTION-UNATTEN 25 CROOKS GAP SUB 12.47 34.50 DISTRIBUTION-UNATTEN 26 DEER CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 27 DJ COAL MINE SUB 34.50 69.00 DISTRIBUTION-UNATTEN 28 DOUGLAS SUB 2.30 57.00 DISTRIBUTION-UNATTEN 29 DRY FORK SUB 4.16 69.00 DISTRIBUTION-UNATTEN 30 ELK BASIN SUB 7.20 34.50 DISTRIBUTION-UNATTEN 31 ELK HORN SUB 12.50 115.00 DISTRIBUTION-UNATTEN 32 EMIGRANT SUB 12.47 115.00 DISTRIBUTION-UNATTEN 33 EVANS SUB 12.47 115.00 DISTRIBUTION-UNATTEN 34 EVANSTON SUB 12.47 138.00 DISTRIBUTION-UNATTEN 35 FARMERS UNION SUB 4.16 34.50 DISTRIBUTION-UNATTEN 36 FIREHOLE SUB 34.50 230.00 DISTRIBUTION-UNATTEN 37 FORT CASPER SUB 12.47 69.00 DISTRIBUTION-UNATTEN 38 FORT SANDERS SUB 13.20 115.00 DISTRIBUTION-UNATTEN 39 FRANNIE SUB 34.50 230.00 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.21Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

FRONTIER SUB 4.16 69.00 DISTRIBUTION-UNATTEN 1 GARLAND SUB 34.50 230.00 DISTRIBUTION-UNATTEN 2 GLENDO SUB 4.16 57.00 DISTRIBUTION-UNATTEN 3 GRASS CREEK SUB 34.50 230.00 DISTRIBUTION-UNATTEN 4 GREAT DIVIDE SUB 34.50 115.00 DISTRIBUTION-UNATTEN 5 GREYBULL SUB 4.16 34.50 DISTRIBUTION-UNATTEN 6 HANNA SUB 12.47 34.50 DISTRIBUTION-UNATTEN 7 JACKALOPE SUB 12.47 115.00 DISTRIBUTION-UNATTEN 8 KEMMERER SUB 24.90 69.00 DISTRIBUTION-UNATTEN 9 KIRBY CREEK PUMPING STATION 2.40 34.50 DISTRIBUTION-UNATTEN 10 KIRBY CREEK SUB 4.16 34.50 DISTRIBUTION-UNATTEN 11 LANDER SUB 12.47 34.50 DISTRIBUTION-UNATTEN 12 LARAMIE SUB 13.20 115.00 DISTRIBUTION-UNATTEN 13 LATHAM SUB 34.50 230.00 DISTRIBUTION-UNATTEN 14 LINCH SUB 13.80 69.00 DISTRIBUTION-UNATTEN 15 LITTLE MOUNTAIN SUB 34.50 230.00 DISTRIBUTION-UNATTEN 16 LOVELL SUB 4.16 34.50 DISTRIBUTION-UNATTEN 17 MILL IRON SUB 13.80 34.50 DISTRIBUTION-UNATTEN 18 MILLS SUB 4.16 12.47 DISTRIBUTION-UNATTEN 19 MURPHY DOME SUB 13.20 34.50 DISTRIBUTION-UNATTEN 20 NUGGETT SUB 7.20 69.00 DISTRIBUTION-UNATTEN 21 OPAL SUB 24.90 46.00 DISTRIBUTION-UNATTEN 22 ORIN SUB 12.47 57.00 DISTRIBUTION-UNATTEN 23 ORPHA SUB 7.20 57.00 DISTRIBUTION-UNATTEN 24 PARADISE SUB 25.00 69.00 DISTRIBUTION-UNATTEN 25 PARCO SUB 12.47 34.50 DISTRIBUTION-UNATTEN 26 PINEDALE SUB 24.90 69.00 DISTRIBUTION-UNATTEN 27 PITCHFORK SUB 24.90 69.00 DISTRIBUTION-UNATTEN 28 POINT OF ROCKS SUB 34.50 230.00 DISTRIBUTION-UNATTEN 29 POISON SPIDER SUB 2.40 69.00 DISTRIBUTION-UNATTEN 30 POLECAT SUB 12.47 34.50 DISTRIBUTION-UNATTEN 31 RAINBOW SUB 13.20 34.50 DISTRIBUTION-UNATTEN 32 RAVEN SUB 34.50 230.00 DISTRIBUTION-UNATTEN 33 RED BUTTE SUB 12.47 69.00 DISTRIBUTION-UNATTEN 34 REFINERY SUB 12.47 115.00 DISTRIBUTION-UNATTEN 35 SAGE HILL SUB 13.20 34.50 DISTRIBUTION-UNATTEN 36 SHOSHONI SUB 2.40 34.50 DISTRIBUTION-UNATTEN 37 SLATE CREEK SUB 12.47 69.00 DISTRIBUTION-UNATTEN 38 SOUTH CODY SUB 24.90 69.00 DISTRIBUTION-UNATTEN 39 SOUTH ELK BASIN SUB 4.16 34.50 DISTRIBUTION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.22Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

SOUTH TRONA SUB 34.50 230.00 DISTRIBUTION-UNATTEN 1 SPRING CREEK SUB 13.20 115.00 DISTRIBUTION-UNATTEN 2 SVILAR SUB 4.16 34.50 DISTRIBUTION-UNATTEN 3TEN MILE STEP DOWN SUB 12.50 34.50 DISTRIBUTION-UNATTEN 4TEN MILE SUB 34.50 69.00 DISTRIBUTION-UNATTEN 5 THERMOPOLIS TOWN SUB 4.16 34.50 DISTRIBUTION-UNATTEN 6 THUNDER CREEK SUB 12.47 57.00 DISTRIBUTION-UNATTEN 7 VETERANS SUB 13.20 34.50 DISTRIBUTION-UNATTEN 8 WELCH SUB 2.40 57.00 DISTRIBUTION-UNATTEN 9 WERTZ-SINCLAIR SUB 4.16 57.00 12.50 DISTRIBUTION-UNATTEN 10 WEST ADAMS SUB 4.16 34.50 DISTRIBUTION-UNATTEN 11 WESTERN CLAY SUB 0.48 34.50 DISTRIBUTION-UNATTEN 12 WESTVACO SUB 34.50 230.00 DISTRIBUTION-UNATTEN 13 WORLAND TOWN SUB 4.16 34.50 DISTRIBUTION-UNATTEN 14 WYOPO SUB 34.50 230.00 DISTRIBUTION-UNATTEN 15 WYUTA SUB 12.47 46.00 DISTRIBUTION-UNATTEN 16 Total 1404.07 8161.21 25.70 17 Number of Substations- 92 18 19 BUFFALO SUB 20.80 230.00 T/D-UNATTENDED 20 HILLTOP SUB 34.50 115.00 20.80 T/D-UNATTENDED 21 LABARGE SUB 24.90 69.00 T/D-UNATTENDED 22 RIVERTON 230 SUB 12.47 230.00 34.50 T/D-UNATTENDED 23YELLOWCAKE SUB 34.50 230.00 T/D-UNATTENDED 24Total 127.17 874.00 55.30 25 Number of Substations- 5 26 27 DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00 TRANSMISSION-ATTENDE 28 JIM BRIDGER 345KV SUB 230.00 345.00 34.50 TRANSMISSION-ATTENDE 29 JIM BRIDGER UNITS 1-4 22.00 345.00 TRANSMISSION-ATTENDE 30 NAUGHTON SUB 69.00 230.00 138.00 TRANSMISSION-ATTENDE 31 WYODAK 230KV SUB 69.00 230.00 TRANSMISSION-ATTENDE 32 WYODAK PLANT 22.00 230.00 TRANSMISSION-ATTENDE 33 BAIROIL SUB 34.50 115.00 57.00 TRANSMISSION-UNATTEN 34 CASPER SUB 115.00 230.00 69.00 TRANSMISSION-UNATTEN 35 CHAPPELL CREEK SUB 69.00 230.00 TRANSMISSION-UNATTEN 36 CHIMNEY BUTTE SUB 69.00 230.00 TRANSMISSION-UNATTEN 37 FOOTE CREEK WIND FARM 34.50 230.00 TRANSMISSION-UNATTEN 38 GLENDO AUTO SUB 57.00 69.00 TRANSMISSION-UNATTEN 39 MANSFACE SUB 34.50 230.00 TRANSMISSION-UNATTEN 40

FERC FORM NO. 1 (ED. 12-96) Page 426.23Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

MIDWEST SUB 69.00 230.00 34.50 TRANSMISSION-UNATTEN 1 MINERS SUB 115.00 230.00 34.50 TRANSMISSION-UNATTEN 2 MUSTANG SUB 115.00 230.00 TRANSMISSION-UNATTEN 3 OREGON BASIN SUB 34.50 230.00 69.00 TRANSMISSION-UNATTEN 4 PLATTE SUB 115.00 230.00 34.50 TRANSMISSION-UNATTEN 5 RAILROAD SUB 138.00 230.00 TRANSMISSION-UNATTEN 6 ROCK SPRINGS 230 SUB 34.50 230.00 TRANSMISSION-UNATTEN 7 SAGE SUB 46.00 69.00 TRANSMISSION-UNATTEN 8 THERMOPOLIS SUB 115.00 230.00 TRANSMISSION-UNATTEN 9 Total 1722.50 4853.00 540.00 10 Number of Substations- 22 11 12 CALIFORNIA 13 Distribution - 43 14T/D - 3 15 Transmission - 9 16 17 IDAHO 18 Distribution - 66 19 T/D - 4 20 Transmission - 18 21 22 MONTANA 23Transmission - 1 24 25 OREGON 26 Distribution - 183 27T/D - 10 28 Transmission - 42 29 30 UTAH 31 Distribution - 299 32 T/D - 23 33Transmission - 47 34 35 WASHINGTON 36 Distribution - 30 37T/D - 2 38 Transmission - 9 39 40

FERC FORM NO. 1 (ED. 12-96) Page 426.24Name 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 (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped 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).

WYOMING 1 Distribution - 92 2 T/D - 5 3Transmission - 22 4 5 ALL STATES 6 Distribution - 713 7T/D - 47 8 Transmission - 148 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 426.25Name 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. Number of Units (g) (f) (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 427Name 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. Number of Units (g) (f) (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 427.1Name 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. Number of Units (g) (f) (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 427.2Name 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. Number of Units (g) (f) (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 427.3Name 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. Number of Units (g) (f) (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 427.4Name 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. Number of Units (g) (f) (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 427.5Name 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. Number of Units (g) (f) (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 427.6Name 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. Number of Units (g) (f) (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 427.7Name 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. Number of Units (g) (f) (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 427.8Name 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. Number of Units (g) (f) (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 427.9Name 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. Number of Units (g) (f) (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 427.10Name 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. Number of Units (g) (f) (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 427.11Name 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. Number of Units (g) (f) (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 427.12Name 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. Number of Units (g) (f) (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 427.13Name 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. Number of Units (g) (f) (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 427.14Name 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. Number of Units (g) (f) (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 427.15Name 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. Number of Units (g) (f) (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 427.16Name 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. Number of Units (g) (f) (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 427.17Name 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. Number of Units (g) (f) (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 427.18Name 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. Number of Units (g) (f) (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 427.19Name 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. Number of Units (g) (f) (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 427.20Name 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. Number of Units (g) (f) (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 427.21Name 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. Number of Units (g) (f) (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 427.22Name 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. Number of Units (g) (f) (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 427.23Name 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. Number of Units (g) (f) (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 427.24Name 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. Number of Units (g) (f) (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)XAn 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 450.1Name 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

(c) (b) (a) (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 128,804,025 Bridger Coal Company 3 supplies 4 5 Coal purchases 12,420,218 Trapper Mining Inc. 151 6 7 MEHC management fee 11,622,757 MEHC 8 1,761,257 MEC 9 1,433,272 MidAmerican Funding 930.2, 426.5, 107 10 816,328 MHC, Inc. 930.2, 426.5 11 5,211 CalEnergy Generation 930.2 12 29,152 CE Electric UK Funding 930.2, 107 13 Charges over cost cap - retained by MEHC -6,667,977 MEHC 426.5 14 15 Net management fee billings (sum of 7 - 13) 9,000,000 MEHC see above 16 17 18 19 20 Non-power Goods or Services Provided for Affiliate 21 Administrative support services/ management fee/ 3,542,671 Bridger Coal Company 146 22 royalties 23 24 25 26 Labor and benefits services (primarily IT costs) 1,218,262 MEHC 146 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 3,308,627 Kern River Gas 501, 547

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

(c) (b) (a) (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 2,053,556 HomeServices 5 6 Captive insurance premiums expense 6,969,001 MEHC Insurance Svcs. 924, 925 7 8 Rail services/ right-of-way fees 29,905,732 BNSF Railway Company 151, 507, 567, 589 9 10 11 Financial transactions related to energy hedging 12 activity and banking services 28,815,677 Wells Fargo & Company 13 14 Water treatment services at generating facilities 3,225,464 Nalco Holding Company 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

(c) (b) (a) (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)XAn 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)XAn 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

Index 2 FERC FORM NO. 1 (ED. 12-95)

### INDEX (continued)

Schedule Page No.

Interest charges, paid on long-term debt, advances, etc ............................................... 256-257 Investments nonutility property .............................................................................. 221 subsidiary companies ......................................................................... 224-225 Investment tax credits, accumulated deferred ..................................................... 266-267 Law, excerpts applicable to this report form .......................................................... iv List of schedules, this report form .................................................................. 2-4 Long-term debt ................................................................................... 256-257 Losses-Extraordinary property ........................................................................ 230 Materials and supplies ............................................................................... 227 Miscellaneous general expenses ....................................................................... 335 Notes to balance sheet ............................................................................. 122-123 to statement of changes in financial position ................................................ 122-123 to statement of income ....................................................................... 122-123 to statement of retained earnings ............................................................ 122-123 Nonutility property .................................................................................. 221 Nuclear fuel materials ........................................................................... 202-203 Nuclear generating plant, statistics ............................................................. 402-403 Officers and officers' salaries ...................................................................... 104 Operating expenses-electric ............................................................................ 320-323 expenses-electric (summary) ...................................................................... 323 Other paid-in capital .................................................................................. 253 donations received from stockholders ............................................................. 253 gains on resale or cancellation of reacquired capital stock .................................................................................... 253 miscellaneous paid-in capital .................................................................... 253 reduction in par or stated value of capital stock ................................................ 253 regulatory assets ................................................................................ 232 regulatory liabilities ........................................................................... 278 Peaks, monthly, and output ........................................................................... 401 Plant, Common utility accumulated provision for depreciation ........................................................... 356 acquisition adjustments .......................................................................... 356 allocated to utility departments ................................................................. 356 completed construction not classified ............................................................ 356 construction work in progress .................................................................... 356 expenses ......................................................................................... 356 held for future use .............................................................................. 356 in service ....................................................................................... 356 leased to others ................................................................................. 356 Plant data ...................................................................................336-337 401-429

Index 3 FERC FORM NO. 1 (ED. 12-95)

### INDEX (continued)

Schedule Page No. Plant - electric accumulated provision for depreciation ........................................................... 219 construction work in progress .................................................................... 216 held for future use .............................................................................. 214 in service ................................................................................... 204-207 leased to others ................................................................................. 213 Plant - utility and accumulated provisions for depreciation amortization and depletion (summary) ............................................................. 201 Pollution control facilities, accumulated deferred income taxes ..................................................................................... 234 Power Exchanges .................................................................................. 326-327 Premium and discount on long-term debt ............................................................... 256 Premium on capital stock ............................................................................. 251 Prepaid taxes .................................................................................... 262-263 Property - losses, extraordinary ..................................................................... 230 Pumped storage generating plant statistics ....................................................... 408-409 Purchased power (including power exchanges) ...................................................... 326-327 Reacquired capital stock ............................................................................. 250 Reacquired long-term debt ........................................................................ 256-257 Receivers' certificates .......................................................................... 256-257 Reconciliation of reported net income with taxable income from Federal income taxes ...................................................................... 261 Regulatory commission expenses deferred .............................................................. 233 Regulatory commission expenses for year .......................................................... 350-351 Research, development and demonstration activities ............................................... 352-353 Retained Earnings amortization reserve Federal ..................................................................... 119 appropriated ................................................................................. 118-119 statement of, for the year ................................................................... 118-119 unappropriated ............................................................................... 118-119 Revenues - electric operating .................................................................... 300-301 Salaries and wages directors fees ................................................................................... 105 distribution of .............................................................................. 354-355 officers' ........................................................................................ 104 Sales of electricity by rate schedules ............................................................... 304 Sales - for resale ............................................................................... 310-311 Salvage - nuclear fuel ........................................................................... 202-203 Schedules, this report form .......................................................................... 2-4 Securities exchange registration ........................................................................ 250-251 Statement of Cash Flows .......................................................................... 120-121 Statement of income for the year ................................................................. 114-117 Statement of retained earnings for the year ...................................................... 118-119 Steam-electric generating plant statistics ....................................................... 402-403 Substations .......................................................................................... 426 Supplies - materials and ............................................................................. 227

Index 4 FERC FORM NO. 1 (ED. 12-90)

### 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

Index 5 FERC FORM NO. 1 (ED. 12-90)