PACIFICORP /OR/ (Form: 10-K, Received: 03/02/2007 05:59:40)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington , D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended

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

For the transition period from April 1, 2006 to December 31, 2006

Commission File Number 1-5152

PACIFICORP

(Exact name of registrant as specified in its charter)

State of Oregon
(State or other jurisdiction
of incorporation or organization)

93-0246090
(I.R.S. Employer Identification No.)

825 N.E. Multnomah Street, Portland, Oregon
(Address of principal executive offices)

97232
(Zip Code)

(503) 813-5000

(Registrant’s telephone number)

Securities registered pursuant to Section 12(b) of the Act: none

Securities registered pursuant to Section 12(g) of the Act:

Title of each Class

5% Preferred Stock (Cumulative; $100 Stated Value)

Serial Preferred Stock (Cumulative; $100 Stated Value)

No Par Serial Preferred Stock (Cumulative; $100 Stated Value)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act) (check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

As of February 22, 2007, there were 357,060,915 shares of common stock outstanding. All shares of outstanding common stock are indirectly owned by MidAmerican Energy Holdings Company, 666 Grand Avenue, Des Moines, Iowa.

TABLE OF CONTENTS

Item Number		Page No.

Definitions		ii
Part I
Item 1.	Business	1
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	28
Item 4.	Submission of Matters to a Vote of Security Holders	28
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 8.	Financial Statements and Supplementary Data	51
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	92
Item 9A.	Controls and Procedures	92
Item 9B.	Other Information	92
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	93
Item 11.	Executive Compensation	94
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	105
Item 13.	Certain Relationships and Related Transactions, and Director Independence	106
Item 14.	Principal Accountant Fees and Services	107
Part IV
Item 15.	Exhibits and Financial Statement Schedules	108
Signatures		111

DEFINITIONS

When the following terms are used in the text, they will have the meanings indicated:

Term		Meaning
CPUC		California Public Utilities Commission
FERC		Federal Energy Regulatory Commission
GWh		Gigawatt-hour(s), one gigawatt continuously for one hour
IPUC		Idaho Public Utilities Commission
kWh		Kilowatt-hour(s), one kilowatt continuously for one hour
MEHC		MidAmerican Energy Holdings Company, an Iowa corporation and indirect parent company of PacifiCorp
MW		Megawatt
MWh		Megawatt-hour(s), one megawatt continuously for one hour
OPUC		Oregon Public Utility Commission
PacifiCorp		PacifiCorp (an Oregon corporation) and subsidiaries
PPW Holdings LLC		PPW Holdings LLC, the direct parent company of PacifiCorp
SEC		United States Securities and Exchange Commission
UPSC		Utah Public Service Commission
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission

PART I

ITEM 1. BUSINESS

OVERVIEW

Ownership by MEHC

On March 21, 2006, MidAmerican Energy Holdings Company (“MEHC”) completed its purchase of all of PacifiCorp’s outstanding common stock from PacifiCorp Holdings, Inc. (“PHI”), a subsidiary of Scottish Power plc (“ScottishPower”). PacifiCorp’s common stock was directly acquired by a subsidiary of MEHC, PPW Holdings LLC. As a result of this transaction, MEHC controls the significant majority of PacifiCorp’s voting securities, which also include preferred stock held by unrelated third parties. MEHC, a global energy company based in Des Moines, Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”).

On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution may only be used by MEHC for the purpose of (i) paying when due MEHC’s debt obligations and (ii) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries, including PacifiCorp. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250.0 million pursuant to one or more drawings authorized by MEHC’s Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC’s common stock. PacifiCorp has no right to make or to cause MEHC to make any equity contribution requests. The Berkshire Hathaway equity commitment will expire on February 28, 2011.

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically identified by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast,” “intend,” and similar terms. These statements are based upon PacifiCorp’s current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside PacifiCorp’s control and could cause actual results to differ materially from those expressed or implied by PacifiCorp’s forward-looking statements. These factors include, among others:

•	The outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies;

•	Changes in prices and availability for both purchases and sales of wholesale electricity and purchases of coal, natural gas and other fuel sources that could have a significant impact on generation capacity and energy costs;

•	Changes in regulatory requirements or other legislation, including limits on the ability of public utilities to recover income tax expense in rates such as Oregon Senate Bill 408;

•	Changes in economic, industry or weather conditions, as well as demographic trends, that could affect customer growth and electricity usage or supply;

•	A high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and costs to balance electricity load and supply;

•	Hydroelectric conditions, as well as the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings, that could have a significant impact on electric capacity and cost and on PacifiCorp’s ability to generate electricity;

•	Performance of PacifiCorp’s generation facilities, including unscheduled outages or repairs;

•	Changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies that could increase operating and capital improvement costs, reduce plant output and/or delay plant construction;

•	Changes resulting from MEHC ownership;

•	The impact of new accounting pronouncements or changes in current accounting estimates and assumptions on financial position and results of operations;

•	The impact of increases in healthcare costs, changes in interest rates and investment performance on pension and other postretirement benefits expense, as well as the impact of changes in legislation on funding requirements;

•	Availability, terms and deployment of capital;

•	Financial condition and creditworthiness of significant customers and suppliers;

•	The impact of financial derivatives used to mitigate or manage interest rate risk and volume and price risk and changes in the commodity prices, interest rates and other conditions that affect the value of the derivatives;

•	Changes in PacifiCorp’s credit ratings;

•

Timely and appropriate completion of PacifiCorp’s resource procurement process, unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generation plants and infrastructure additions;

•	Other risks or unforeseen events, including wars, the effects of terrorism, embargos and other catastrophic events; and

•	Other business or investment considerations that may be disclosed from time to time in the Securities and Exchange Commission (the “SEC”) filings or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting PacifiCorp are described in its filings with the SEC, including Item 1A. Risk Factors and other discussions contained in this Form 10-K. PacifiCorp undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

Operations

PacifiCorp is a regulated electricity company serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. It 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 energy trading, and coal-mining functions are operated under the trade name PacifiCorp Energy. As a vertically integrated electric utility, PacifiCorp owns or has contracts for fuel sources such as coal and natural gas and uses these fuel sources, as well as wind, geothermal and water resources, to generate electricity at its power plants. This electricity, together with electricity purchased on the wholesale market, is then transmitted via a grid of transmission lines throughout PacifiCorp’s six-state region. The electricity is then transformed to lower voltages and delivered to customers through PacifiCorp’s distribution system. PacifiCorp sells electricity primarily in the retail market, with sales to residential, commercial, industrial and other customers. PacifiCorp also sells electricity in the wholesale market in connection with excess electricity generation or other system balancing activities. Subsidiaries of PacifiCorp support its electric utility operations by providing coal-mining facilities and services, steam delivery facilities and environmental remediation services.

PacifiCorp’s primary goal is to provide safe, reliable electricity to its customers at a reasonable cost. In return, PacifiCorp expects that all prudently incurred costs to provide such service will be included as allowable costs for state rate-making purposes, and PacifiCorp will be allowed an opportunity to earn a reasonable return on its investments. In order to meet the needs of its customers, PacifiCorp relies on its generation facilities, as well as purchases of electricity in the wholesale market. PacifiCorp must find new cost-effective and efficient sources of power supply to meet its growing customer demand and replace purchase contracts as they expire. One of PacifiCorp’s goals is to meet more of its retail load obligations with its generation facilities and reduce its dependence on wholesale purchases.

PacifiCorp expects to achieve this goal through demand response programs, energy efficiency programs and the construction or purchase of additional generation, including economically feasible renewable energy production, reduced-emission coal-fired plants, natural gas-fired plants and other viable technological alternatives. PacifiCorp is already working to achieve this goal with the completed Currant Creek Power Plant and the Leaning Juniper Wind Project, as well as the ongoing construction of the Lake Side Power Plant, the Marengo Wind Project and other wind projects. Along with this new generation, PacifiCorp will also invest in its transmission and distribution system to integrate the new generation resources and effectively meet customer load growth. This planned generation, transmission and distribution system expansion will also facilitate meeting the commitments made to state regulatory commissions as a result of the sale of PacifiCorp to MEHC. PacifiCorp expects to fund this construction with cash from operations, long-term debt issuances and equity contributions from PPW Holdings LLC.

In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31.

Regulation

PacifiCorp is subject to comprehensive regulation by the Federal Energy Regulatory Commission (the “FERC”), the Utah Public Service Commission (the “UPSC”), the Oregon Public Utility Commission (the “OPUC”), the Wyoming Public Service Commission (the “WPSC”), the Washington Utilities and Transportation Commission (the “WUTC”), the Idaho Public Utilities Commission (the “IPUC”), the California Public Utilities Commission (the “CPUC”), and other federal, state and local regulatory agencies. These agencies regulate many aspects of PacifiCorp’s business, including, but not limited to, customer rates, service territories, sales of securities, asset acquisitions and sales, wholesale sales and purchases of electricity, the operation of its electric generation and transmission facilities, and accounting policies and practices.

Employees

As of December 31, 2006, PacifiCorp, together with its subsidiaries, had 6,458 employees, 61.4% of which were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, International Brotherhood of Boilermakers and the United Mine Workers of America.

POWER AND FUEL SUPPLY

Generating Plants

The following table shows the estimated percentage of PacifiCorp’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases. See Wholesale Sales and Purchased Electricity below for more information.

	Nine Months Ended December 31,				Years Ended March 31,

	2006		2005		2006		2005

Energy generated:
Coal	62.4	%	67.1	%	67.5	%	67.3	%
Natural gas	7.0		4.0		3.8		4.2
Hydroelectric	5.7		4.9		6.2		4.6
Wind	0.2		0.1		0.2		0.2
Other	0.5		0.5		0.5		0.6

Total energy generated	75.8		76.6		78.2		76.9

Energy purchased:
Long-term contracts	7.4		9.3		8.8		7.9
Short-term contracts and other	16.8		14.1		13.0		15.2

Total energy purchased	24.2		23.4		21.8		23.1

Total energy requirements	100.0	%	100.0	%	100.0	%	100.0	%

The percentage of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snowpack levels, environmental considerations and the market price of electricity.

PacifiCorp owns, or has interests in, various thermal, hydroelectric and wind generating plants. The following table shows PacifiCorp’s existing generating plants as of December 31, 2006:

	Location	Energy Source	Installed	Facility Net Capacity (MW) (a)	Net Owned Capacity (MW)

Coal:
Jim Bridger	Rock Springs, WY	Coal	1974-1979	2,120.0	1,413.4
Huntington	Huntington, UT	Coal	1974-1977	895.0	895.0
Dave Johnston	Glenrock, WY	Coal	1959-1972	762.0	762.0
Naughton	Kemmerer, WY	Coal	1963-1971	700.0	700.0
Hunter No. 1	Castle Dale, UT	Coal	1978	430.0	403.1
Hunter No. 2	Castle Dale, UT	Coal	1980	430.0	259.3
Hunter No. 3	Castle Dale, UT	Coal	1983	460.0	460.0
Cholla No. 4	Joseph City, AZ	Coal	1981	380.0	380.0
Wyodak	Gillette, WY	Coal	1978	335.0	268.0
Carbon	Castle Gate, UT	Coal	1954-1957	172.0	172.0
Craig Nos. 1 and 2	Craig, CO	Coal	1979-1980	856.0	165.0
Colstrip Nos. 3 and 4	Colstrip, MT	Coal	1984-1986	1,480.0	148.0
Hayden No. 1	Hayden, CO	Coal	1965-1976	184.0	45.1
Hayden No. 2	Hayden, CO	Coal	1965-1976	262.0	33.0

				9,466.0	6,103.9

Natural Gas:
Currant Creek	Mona, UT	Natural Gas/Steam	2005-2006	540.0	540.0
Hermiston	Hermiston, OR	Natural Gas/Steam	1996	474.0	237.0
Gadsby Steam	Salt Lake City, UT	Natural Gas	1951-1952	235.0	235.0
Gadsby Peakers	Salt Lake City, UT	Natural Gas	2002	120.0	120.0
Little Mountain	Ogden, UT	Natural Gas	1972	14.0	14.0

				1,383.0	1,146.0

Hydroelectric: (b)
Swift No. 1	Cougar, WA	Lewis River	1958	263.6	263.6
Merwin	Ariel, WA	Lewis River	1931-1958	151.0	151.0
Yale	Amboy, WA	Lewis River	1953	163.6	163.6
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1950-1956	140.6	140.6
John C. Boyle	Keno, OR	Klamath River	1958	83.0	83.0
Copco Nos. 1 and 2	Hornbrook, CA	Klamath River	1918-1925	62.0	62.0
Clearwater Nos. 1 and 2	Toketee Falls, OR	Clearwater River	1953	48.9	48.9
Grace	Grace, ID	Bear River	1908-1923	33.0	33.0
Prospect No. 2	Prospect, OR	Rogue River	1928	36.0	36.0
Cutler	Collingston, UT	Bear River	1927	29.0	29.0
Oneida	Preston, ID	Bear River	1915-1920	27.9	27.9
Iron Gate	Hornbrook, CA	Klamath River	1962	18.8	18.8
Soda	Soda Springs, ID	Bear River	1924	14.0	14.0
Fish Creek	Toketee Falls, OR	Fish Creek	1952	10.4	10.4
30 Minor Hydroelectric Plants (c)	Various	Various	1895-1990	78.3	78.3

				1,160.1	1,160.1

Wind:
Foote Creek	Arlington, WY	Wind Turbines	1997	41.4	32.6
Leaning Juniper 1	Arlington, OR	Wind Turbines	2006	100.5	100.5

				141.9	133.1

Other:
Camas Co-Gen	Camas, WA	Black Liquor	1996	22.0	22.0
Blundell	Milford, UT	Geothermal	1984	23.0	23.0

				45.0	45.0

Total available generating capacity				12,196.0	8,588.1

(a)	Facility net capacity represents the total capability of a generating unit as demonstrated by actual operating or test experience, less power generated and used for auxiliaries and other station uses, and is determined using average annual temperatures.

(b)	Hydroelectric project locations are stated by locality and river watershed.

(c)	For further information on Condit, Cove and Powerdale hydroelectric plants included in this table, see “Hydroelectric Decommissioning” below.

Future Generation and Conservation

The following table shows PacifiCorp’s generating plants under construction as of December 31, 2006:

Plant	Location	Energy Source	Estimated Installation Date	Estimated Facility Nameplate Rating (MW)	Estimated Net MW Owned Nameplate Rating (MW) (a)

Lake Side	Vineyard, UT	Natural Gas-Fired	June 2007	534.0	534.0
Marengo	Dayton, WA	Wind Turbines	August 2007	140.4	140.4

Total estimated capacity under construction				674.4	674.4

(a)	A generator’s nameplate rating is its full-load capacity (in megawatts) under normal operating conditions as defined by the manufacturer.

Integrated Resource Plans

As required by state regulators, PacifiCorp uses Integrated Resource Plans 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 Integrated Resource Plan 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 and other factors. The Integrated Resource Plan is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. Each state commission that has Integrated Resource Plan adequacy rules judges whether the Integrated Resource Plan reasonably meets its standards and guidelines at the time the Integrated Resource Plan is filed. If the Integrated Resource Plan is found to be adequate, then it is formally “acknowledged.” The Integrated Resource Plan can then be used as evidence by parties in rate-making or other regulatory proceedings.

In November 2005, PacifiCorp released an update to its 2004 Integrated Resource Plan. The updated 2004 Integrated Resource Plan identified a need for approximately 2,113.0 megawatts (“MW”) of additional resources by summer 2014, to be met with a combination of thermal generation (1,936.0 MW) and load control programs (177.0 MW). PacifiCorp also planned to implement energy conservation programs of 450.0 average MW, to continue to seek procurement of 1,400.0 MW of economic renewable resources and to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources.

PacifiCorp files its Integrated Resource Plans on a biennial basis and expects to file its 2006 plan in May 2007. The OPUC issued a new set of integrated resource planning guidelines in January 2007, which apply to the 2006 plan. PacifiCorp is modifying its plan to accommodate the new analysis and reporting requirements. In addition, PacifiCorp is developing a resource strategy that accommodates evolving state energy policies and differences in resource preferences among the states that it serves, while still maintaining a system-wide planning focus.

Request for Proposals

In July 2006, PacifiCorp filed its 2012 draft request for proposals under its updated 2004 Integrated Resource Plan with the UPSC and the OPUC. The draft request for proposals is for generation resources of between 840.0 MW and 915.0 MW to be available in 2012 through 2013. The scope of this draft request for proposals is focused on resources capable of delivering energy and capacity in or to PacifiCorp’s network transmission system in PacifiCorp’s eastern service territory. All transaction and resource decisions will be evaluated on a comparable least-cost and risk-balanced approach. In response to issues and concerns from stakeholders, PacifiCorp filed a revised version of the 2012 draft request for proposals in October 2006.

In January 2007, the OPUC issued an order denying the 2012 request for proposal. This denial does not preclude the issuance of the request for proposals. In December 2006, the UPSC issued an order suggesting modifications to the request for proposal. PacifiCorp filed the 2012 request for proposal in Utah for final approval in February 2007. This filing will include a modification to request up to 1,700 MW to be available through 2014.

In addition to new generation resources, substantial transmission investments could be required to deliver power to customers and provide system reliability. The actual investment requirement will depend on the location and other characteristics of the new generation resources. See “Transmission and Distribution” below.

Coal

PacifiCorp’s coal generation portfolio consists of 11 plants with a net owned capacity of 6,103.9 MW. These plants account for 71.1% of PacifiCorp’s total owned generating capacity. As of December 31, 2006, PacifiCorp had an estimated 241.7 million tons of recoverable coal reserves in mines owned or leased by it, including those related to the underground mine described below. During the nine months ended December 31, 2006, these mines supplied 31.1% of PacifiCorp’s total coal requirements, compared to 32.3% during the year ended March 31, 2006 and 28.6% during the year ended March 31, 2005. The remaining coal requirements are acquired through other long- and short-term contracts. PacifiCorp’s mines are located adjacent to many of its coal-fired generating plants, which significantly reduces overall transportation costs included in fuel expense.

In an effort to lower costs and obtain better quality coal, the Jim Bridger Mine is in the process of developing an underground mine to access 57.0 million tons of PacifiCorp’s coal reserves. Underground mine development and limited coal production began during the year ended March 31, 2005 and sustained operations are expected to begin by March 31, 2007. The life of the underground mine is expected to be approximately 15 years.

PacifiCorp believes that the coal reserves available to the Craig, Huntington, Hunter and Jim Bridger Plants, together with coal available under both long- and short-term contracts with external suppliers, will be substantially sufficient to provide these plants with fuel that meets the Clean Air Act standards for their current assumed useful lives. Blending of PacifiCorp-owned and contracted coal, together with electricity plant technologies for controlling sulfur and other emissions, are utilized to meet the applicable standards. PacifiCorp-owned plants held sufficient sulfur dioxide emission allowances to comply with the EPA Title IV requirements during the compliance year. The sulfur content of the coal reserves generally ranges from 0.30% to 0.94%, and the British thermal units value per pound of the reserves ranges from 8,600 to 12,400.

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, 2006, based on PacifiCorp’s most recent engineering studies, were as follows:

Location	Plant Served	Mining Method	Recoverable Tons (in Millions)

Craig, CO	Craig	Surface	47.7	(a)
Huntington & Castle Dale, UT	Huntington and Hunter	Underground	50.3	(b)
Rock Springs, WY	Jim Bridger	Surface/Underground	143.7	(c)

			241.7

(a)	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 21.4%.

(b)	These coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.

(c)	These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. (“PMI”) and a subsidiary of Idaho Power Company. PMI, a subsidiary of PacifiCorp, has a two-thirds interest in the joint venture.

Recoverability by surface mining methods typically ranges from 90.0% to 95.0%. Recoverability by underground mining techniques ranges from 50.0% to 70.0%. 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 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. Refer to Note 7 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information on asset retirement obligations.

Natural Gas

PacifiCorp has four plants with a net owned capacity of 1,146.0 MW and one leased plant with a net capacity of 200.0 MW that are each fueled by natural gas. The owned natural gas plants account for 13.3% of PacifiCorp’s total owned generating capacity. At full capacity, those plants that are not used as peaking plants (comprising eight generating units) require a maximum of 246,000 MMBtu (million British thermal units) of natural gas per day. Eight other generating units are generally used as peaking plants, meaning that they only operate during the peak demand hours of the day.

Additional electric generation resources required by PacifiCorp’s Integrated Resource Plans discussed above, including the Lake Side Power Plant, could increase the natural gas requirement to 413,000 MMBtu or more per day. PacifiCorp has entered into transportation contracts to facilitate movement of natural gas to the Lake Side Power Plant. These contracts reflect PacifiCorp’s fuel strategy that focuses on the management and mitigation of risks associated with supplying natural gas.

The growth of PacifiCorp’s generation fueled by natural gas requires a prudent and disciplined approach to natural gas procurement and hedging. PacifiCorp has developed a natural gas strategy that addresses the need to economically hedge the commodity risk (physical availability and price), the transportation risk and the storage risk associated with its forecasted and potentially growing natural gas requirements. This natural gas strategy, combined with the prospect for increasing natural gas requirements, is expected to increase the volume and types of PacifiCorp’s procurement and economic hedging activity.

PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of natural gas. PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for the purchase of physical natural gas at fixed prices and financial swap contracts that settle in cash based on the difference between a fixed price that PacifiCorp pays and a floating market-based price that PacifiCorp receives. As of December 31, 2006, PacifiCorp had economically hedged 100.0% of its forecasted physical and financial exposure for calendar 2007. For calendar 2008, PacifiCorp currently has hedged 89.0% of its physical exposure and 100.0% of its financial exposure. This economic hedging includes the additional supply requirements needed for the Lake Side Power Plant, which is currently under construction.

Hydroelectric

PacifiCorp’s hydroelectric portfolio consists of 50 plants with a net owned capacity of 1,160.1 MW. These plants account for 13.5% of PacifiCorp’s total owned generating capacity, helping satisfy a significant portion of PacifiCorp’s reserve requirements and providing operational benefits such as flexible generation and voltage control. Hydroelectric plants are located in the following states: Utah, Oregon, Wyoming, Washington, Idaho, California and Montana.

The amount of electricity PacifiCorp is able to generate from its hydroelectric plants depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, plant availability and restrictions imposed by oversight bodies due to competing water management objectives. When these factors are favorable, PacifiCorp can generate more electricity using its hydroelectric plants. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC. These licenses are issued by the FERC for periods of 30 to 50 years. The long-term operating licenses of several of PacifiCorp’s hydroelectric facilities have expired and they are operating under temporary licenses issued by the FERC annually until new long-term operating licenses are issued. Hydroelectric relicensing and the related environmental compliance requirements are subject to a degree of uncertainty. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. If licenses are not issued, significant decommissioning costs may be incurred. Electricity generation reductions may also result from additional environmental requirements. As of December 31, 2006, PacifiCorp had incurred $79.0 million in costs for ongoing hydroelectric relicensing, which are included in Construction work-in-progress on PacifiCorp’s Consolidated Balance Sheet. See “Hydroelectric Relicensing” and “Hydroelectric Decommissioning” below.

Wind and Other Renewable Resources

PacifiCorp is pursuing renewable resources as a viable, economic and environmentally prudent means of generating electricity. The benefits of energy from renewable resources include low to no emissions and typically little or no fossil fuel requirements. Intermittent renewable resources such as wind and solar are complemented by flexible resources, such as thermal or hydroelectric generation. Flexible resources are important to integrating intermittent resources into the electric system.

PacifiCorp currently acquires power and associated energy from wind and other renewable resources through two PacifiCorp-owned wind projects (in Oregon and Wyoming) and various power purchase agreements associated with wind projects in Oregon, Wyoming and Idaho as well as through power purchase agreements associated with resources defined as “qualifying facilities” pursuant to the Public Utility Regulatory Policies Act. PacifiCorp also owns a geothermal plant in Utah. For the nine months ended December 31, 2006, PacifiCorp received 242,924 megawatt-hours (“MWh”) from its owned wind projects and geothermal plants. In this same period, 286,020 MWh of purchases were associated with third-party wind resources, not including qualifying facilities.

In connection with its sale to MEHC, PacifiCorp committed to state regulatory commissions to bring at least 100.0 nameplate-rated MW of cost-effective wind resources in service by March 21, 2007 and, to the extent available, have 400.0 nameplate-rated MW, inclusive of the 100.0 MW nameplate-rated commitment, of cost-effective new renewable resources in PacifiCorp’s generation portfolio by December 31, 2007.

In September 2006, PacifiCorp completed construction and began commercial operation of the 100.5-MW nameplate-rated Leaning Juniper 1 Wind Project. Initial investment in the 140.4-MW nameplate-rated Marengo Wind Project occurred in September 2006 and construction is scheduled to be completed by August 2007. PacifiCorp has executed contracts, subject to customary closing conditions, for the purchase of two additional wind projects with a total nameplate rating of 112.0 MW. These wind project investments partially satisfy the purchase commitments described above.

WHOLESALE SALES AND PURCHASED ELECTRICITY

In addition to its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail load obligations, long-term wholesale obligations, and system balancing requirements. PacifiCorp’s energy requirements supplied by purchased electricity under long- and short-term purchase arrangements were 24.2% for the nine months ended December 31, 2006; 21.8% for the year ended March 31, 2006; and 23.1% for the year ended March 31, 2005.

PacifiCorp enters into wholesale purchase and sale transactions to balance its supply when generation and retail loads are higher or lower than expected. Generation varies with the levels of outages, hydroelectric generation conditions and transmission constraints. Retail load varies with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own plants. PacifiCorp may also sell into the wholesale market excess electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

PacifiCorp’s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged position and enhancing the efficient use of its generating capacity over the long term. Historically, PacifiCorp has been able to purchase electricity from utilities in the western United States for its own requirements. These purchases are conducted through PacifiCorp and third-party transmission systems, which connect with market hubs in the Pacific Northwest to provide access to normally low-cost hydroelectric generation and in the southwestern United States to provide access to normally higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements.

The FERC regulates PacifiCorp’s rates charged to wholesale customers for electricity, and capacity and transmission services. Most of PacifiCorp’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility. A December 2006 decision of the United States Court of Appeals for the Ninth Circuit changed the interpretation of the relevant standard which the FERC should apply when reviewing wholesale contracts for electricity or capacity. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. Parties to this proceeding are seeking review before the United States Supreme Court. Whether the United States Supreme Court will hear the case or the outcome of its ruling, should it decide to consider the matter, cannot be predicted at this time. All sellers subject to the FERC’s jurisdiction, including PacifiCorp, are currently subject to increased risk as a result of this decision.

The FERC conducts a triennial review of PacifiCorp’s market-based pricing authority. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and capacity in their respective control areas. In June 2006, the FERC ruled at the conclusion of its most recent review that PacifiCorp does not have market power and may continue to charge market-based rates. A change in filing status relating to new generation was confirmed by the FERC in February 2007, reaching the same conclusion. Unless a current FERC rulemaking proceeding revises the triennial review requirement, PacifiCorp’s next triennial review will occur in 2009.

TRANSMISSION AND DISTRIBUTION

PacifiCorp operates one control area on the western portion of its service territory and one control area on the eastern portion of its service territory. A control area is a geographic area with electric systems that control generation to maintain schedules with other control areas and ensure reliable operations. In operating the control areas, PacifiCorp is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the control area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries of energy over its transmission system in accordance with prescribed FERC requirements.

Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. During the nine months ended December 31, 2006, PacifiCorp delivered 52,545 gigawatt-hours (“GWh”), not adjusted for line losses, of electricity to retail and wholesale customers in its two control areas through 15,622 miles of transmission lines.

PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electric Coordinating Council. The map under “Service Territories” below shows PacifiCorp’s transmission system. PacifiCorp’s transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements.

Substantially all of PacifiCorp’s generating plants and reservoirs are managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp’s transmission and distribution systems are located:

•	On property owned or leased by PacifiCorp;

•	Under or over streets, alleys, highways and other public places, the public domain and national forests and state lands under franchises, easements or other rights that are generally subject to termination;

•	Under or over private property as a result of easements obtained primarily from the record holder of title; or

•	Under or over Native American reservations under grant of easement by the Secretary of Interior or lease by Native American tribes.

It is possible that some of the easements, and the property over which the easements were granted, may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

As of December 31, 2006, PacifiCorp owned, or participated in, an electric transmission system consisting of:

Nominal Voltage (In kilovolts)		Miles

Transmission Lines
500		716
345		1,898
230		3,314
161		376
138		2,079
115		1,544
69		2,969
57		113
46		2,613

		15,622

As of December 31, 2006, PacifiCorp owned 900 substations.

In connection with its sale to MEHC, PacifiCorp committed to state regulatory commissions to spend approximately $519.5 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization.

PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s Open Access Transmission Tariff. In accordance with the Open Access Transmission Tariff, PacifiCorp offers several transmission services to wholesale customers:

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

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

•	Non-firm point-to-point service (“as available” service with fixed delivery and receipt points).

These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from the generating and marketing business in accordance with the FERC Standards of Conduct. Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in rates approved by state regulatory commissions. See “Regulatory Matters – Federal Regulatory Matters” below for further information related to the Energy Policy Act of 2005, which requires that the FERC establish and enforce standards for electric reliability.

SERVICE TERRITORIES

PacifiCorp serves approximately 1.7 million retail customers in service territories aggregating approximately 136,000 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. Except for in Oregon and Washington, PacifiCorp has an exclusive right to serve electricity customers within its service territories and, in turn, has the obligation to provide electric service to those customers. Under Oregon law, certain commercial and industrial customers have the right to choose alternative electric suppliers. The impact of these programs on PacifiCorp’s financial results has not been and is not expected to be material. In Washington, state statute 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.

The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No single segment of the economy dominates the service territory, which mitigates PacifiCorp’s exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture and manufacturing, with forest products, food processing, high technology and primary metals being the largest industrial sectors. The following map highlights PacifiCorp’s retail service territory, plant locations and PacifiCorp’s primary transmission lines. PacifiCorp’s generating facilities are interconnected through PacifiCorp’s own transmission lines or by contract through the transmission lines owned by others.

(a)	These represent PacifiCorp’s access to other entities’ transmission lines through wheeling arrangements.

(b)	These represent other entities’ transmission lines that PacifiCorp can access via open access transmission tariffs.

The geographic distribution of PacifiCorp’s retail electric operating revenues was as follows:

	Nine Months Ended December 31, 2006		Years Ended March 31,

			2006		2005

Utah	41.9	%	40.9	%	40.6	%
Oregon	28.5		29.3		29.3
Wyoming	13.4		13.3		13.6
Washington	7.7		8.4		8.0
Idaho	6.2		5.7		6.1
California	2.3		2.4		2.4

	100.0	%	100.0	%	100.0	%

PacifiCorp receives authorization from state public utility commissions to serve areas within each state. This authorization is perpetual until withdrawn. In addition, PacifiCorp has received franchises that permit it to provide electric service to customers inside incorporated areas within the states. The average term of these franchises is approximately 30 years, although their terms range from five years to indefinite. PacifiCorp must renew franchises as they expire. Governmental agencies have the right to challenge PacifiCorp’s right to serve in a specific area and can condemn PacifiCorp’s property under certain circumstances. However, PacifiCorp vigorously challenges any attempts from individuals and governmental entities to undertake forced takeover of portions of its service territory.

CUSTOMERS

Electricity sold to retail customers and the number of retail customers, by class of customer, were as follows:

	Nine Months Ended December 31,						Years Ended March 31,

	2006			2005			2006			2005

GWh sold:
Residential	11,158	22.6	%	10,704	22.7	%	14,880	23.4	%	14,117	22.7	%
Commercial	11,713	23.8		11,203	23.7		14,887	23.5		14,642	23.5
Industrial	15,719	31.9		14,993	31.7		19,746	31.1		19,454	31.3
Other	439	0.8		444	0.9		599	0.9		706	1.1

Total retail	39,029	79.1		37,344	79.0		50,112	78.9		48,919	78.6

Wholesale	10,284	20.9		9,906	21.0		13,381	21.1		13,334	21.4

Total GWh sold	49,313	100.0	%	47,250	100.0	%	63,493	100.0	%	62,253	100.0	%

	December 31,											March 31,

	2006						2005					2006					2005

Number of retail customers:
(in thousands)
Residential		1,428		85.6	%		1,396		85.6	%		1,404		85.6	%		1,373		85.5	%
Commercial		202		12.1			197		12.1			198		12.1			194		12.1
Industrial		34		2.0			34		2.1			34		2.1			34		2.1
Other		4		0.3			4		0.2			4		0.2			4		0.3

Total		1,668		100.0	%		1,631		100.0	%		1,640		100.0	%		1,605		100.0	%

Retail customers
Average usage per customer (kWh)		23,607					23,099					30,895					30,825
Average revenue per customer	$	1,358				$	1,296				$	1,732				$	1,669
Revenue per kWh		5.8	¢				5.6	¢				5.6	¢				5.4	¢

PacifiCorp is estimating growth in retail MWh sales in PacifiCorp’s franchise service territories to average between 2.0% and 3.0% annually over the five years to December 2011. This growth will depend on factors such as economic conditions, number of customers, weather, consumer trends, conservation efforts and changes in prices.

Seasonality

Customer demand is typically highest in the summer across PacifiCorp’s service territory when air-conditioning and irrigation systems are heavily used. Customer demand also peaks in the winter months due to heating requirements in the western portion of PacifiCorp’s service territory, as well as in the eastern portion due to other electricity demands.

For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems are contributing to faster summer peak growth. During the nine months ended December 31, 2006, PacifiCorp’s peak load was 9,322 MW in the summer and 8,686 MW in the winter.

RETAIL COMPETITION

During the nine months ended December 31, 2006, PacifiCorp continued to operate its retail business under state regulation, which generally prohibits retail competition. However, under a 1999 Oregon law, certain PacifiCorp commercial and industrial customers in Oregon have the right to choose alternative electricity suppliers. As a result of this law, a group of customers having a total average load of approximately 11.0 MW have chosen service from suppliers other than PacifiCorp. A group of customers having a total average load of approximately 1.0 MW have taken service from PacifiCorp under a market-based pricing option that links the energy charge on a customer’s bill to a representative market price index. PacifiCorp does not expect these two competitive programs to have a material effect on earnings for the year ending December 31, 2007.

In addition to Oregon’s program permitting limited retail competition, others in PacifiCorp’s service territories are seeking to have a choice of suppliers, exploring options to build their own generation or co-generation plants, or considering the use of alternative energy sources such as natural gas. If these customers gain the right to receive electricity from alternative suppliers, they will make their energy purchasing decisions based upon many factors, including price, service and system reliability. The use of alternative energy sources is typically based on availability, price and the general demand for electricity.

ENVIRONMENTAL MATTERS

PacifiCorp is subject to a number of federal, state and local environmental laws and regulations affecting many aspects of its present and future operations. These requirements relate to air emissions, water quality, waste management, hazardous chemical use, noise abatement, land use aesthetics and endangered species.

Environmental laws and regulations currently have, and future modifications may have, the effect of (i) increasing the lead time for the construction of new facilities, (ii) significantly increasing the total cost of new facilities, (iii) requiring modification of PacifiCorp’s existing facilities, (iv) increasing the risk of delay on construction projects, (v) increasing PacifiCorp’s cost of waste disposal, and (vi) reducing the amount of energy available from PacifiCorp’s facilities. Any of these items could have a substantial impact on amounts required to be expended by PacifiCorp in the future. The most significant environmental laws and regulations affecting PacifiCorp include:

•

The federal Clean Air Act, as well as state laws and regulations impacting air emissions, including state implementation plans related to existing and new national ambient air quality standards. Rules issued by the Environmental Protection Agency and certain states require substantial reductions in sulfur dioxide, mercury and nitrogen oxide emissions beginning in 2009 and extending through 2018. PacifiCorp has already installed certain emission control technology and is taking other measures to comply with required reductions. Refer to “Clean Air Standards” below for additional discussion regarding this topic.

•

The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws, which 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. Refer to Note 15 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding environmental contingencies.

•

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. For further information see “Coal” above and Note 7 of the Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K.

•

The Clean Water Act and individual state clean water laws that regulate cooling water intake structures and discharges of wastewater, including storm water runoff. PacifiCorp believes that it currently has, or has initiated the process to receive, all required water quality permits.

•

The FERC oversees the issuance of licenses for new construction of hydroelectric projects and is also responsible for the oversight and relicensing of existing projects, including dam safety inspections and environmental monitoring. Refer to Note 15 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the relicensing of certain existing hydroelectric facilities.

The cost of complying with applicable environmental laws, regulations and rules is expected to be material to PacifiCorp’s operating projects. In particular, the Clean Air Act will likely continue to impact the operation of PacifiCorp’s domestic generating facilities and will likely require PacifiCorp to make emissions reductions at its facilities through the installation of emission controls or to comply with the regulations through the purchase of additional emission allowances or some combination thereof.

Expenditures for compliance-related items such as pollution-control technologies, replacement generation, mine reclamation, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into the routine cost structure of PacifiCorp. An inability to recover these costs from PacifiCorp’s customers, either through regulated rates, long-term arrangements or market prices, could adversely affect PacifiCorp’s future financial results.

Clean Air Standards

PacifiCorp’s fossil fuel-fired electricity generation plants are subject to applicable provisions of the Clean Air Act and related air quality standards promulgated by the Environmental Protection Agency and state air quality laws. The Clean Air Act provides the framework for regulation of certain air emissions and permitting and monitoring associated with those emissions. PacifiCorp owns or has interests in 11 coal-fired generating plants, which represent 71.1% of PacifiCorp’s owned generating capacity. PacifiCorp believes it has all required permits and other approvals to operate its plants and that the plants are in material compliance with applicable requirements.

In connection with the sale of PacifiCorp to MEHC, PacifiCorp committed to state regulators to spend approximately $812.0 million over several years to reduce emissions at PacifiCorp’s generating facilities to address existing and future air quality requirements. These costs and any additional expenditures necessitated by air quality regulations are expected to be recovered in rates and, as a result, would not have a material adverse impact on PacifiCorp’s consolidated results of operations.

National Ambient Air Quality Standards

The Environmental Protection Agency has in recent years implemented more stringent national ambient air quality standards for ozone and new standards for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment of the standard. Areas that fail to meet the standard are designated as being non-attainment areas. Generally, once an area has been designated as a non-attainment area, sources of emissions that contribute to the failure to achieve the ambient air quality standards are required to make emissions reductions. The Environmental Protection Agency has concluded that Utah and Wyoming, where PacifiCorp’s major emission sources are located, are in attainment of the ozone standards and the fine particulate matter standards.

In December 2005, the Environmental Protection Agency proposed a revision of the ambient air quality standards for fine particles that would maintain the current annual standard and set a new, more stringent 24-hour standard for concentration of fine particulate. The final standards became effective on December 18, 2006.

Regulated Air Pollutants

In March 2005, the Environmental Protection Agency released the final Clean Air Mercury Rule. The Clean Air Mercury Rule utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the current nationwide level of 48 tons to 15 tons at full implementation. The Clean Air Mercury Rule’s two-phase reduction program requires initial reductions of mercury emissions in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70.0% by 2018. Individual states are required to implement the Clean Air Mercury Rule through their state implementation plans. Depending on the outcome of the respective states’ implementation rules, the Clean Air Mercury Rule may require PacifiCorp to reduce emissions of mercury from some or all of its coal-fired facilities through the installation of emission controls, the purchase of emission allowances, or some combination thereof.

The Clean Air Mercury Rule could, in whole or in part, be superseded or made more stringent by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level, including pending legislative proposals that contemplate 70.0% to 90.0% reductions of sulfur dioxide, nitrogen oxides and mercury, as well as possible new federal regulation of carbon dioxide and other gases that may affect global climate change. In addition to any federal legislation that could be enacted by the United States Congress to supersede the Clean Air Mercury Rule, the rules could be changed or overturned as a result of litigation. The sufficiency of the standards established by the Clean Air Mercury Rule has been legally challenged in the United States District Court for the District of Columbia. Until final resolution of litigation challenging the Clean Air Mercury Rule, the full impact of the rules on PacifiCorp cannot be determined.

Regional Haze

The Environmental Protection Agency has initiated a regional haze program intended to improve visibility at specific federally protected areas. PacifiCorp and other stakeholders are participating in the Western Regional Air Partnership to help develop the technical and policy tools needed to comply with this program.

New Source Review

Under existing New Source Review provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the Environmental Protection Agency or a state regulatory agency prior to (i) beginning construction of a new stationary source of a New Source Review-regulated pollutant, or (ii) making a physical or operational change to an existing stationary source of such pollutants. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxides and other pollutants below current levels. These reductions will be required to address regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. In the future, PacifiCorp expects to incur significant costs to comply with various stricter air emissions requirements. These potential costs are expected to consist primarily of capital expenditures. PacifiCorp expects these costs would be recovered in rates and, as such, would not have a material adverse impact on PacifiCorp’s financial results. Refer to Note 7 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding asset retirement obligations.

The Environmental Protection Agency has requested information and supporting documentation from several utilities regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the New Source Review and the New Source Performance Standards of the Clean Air Act. In 2001 and 2003, PacifiCorp received requests for information from the Environmental Protection Agency relating to PacifiCorp’s capital projects at seven of its generating plants. PacifiCorp submitted information responsive to the requests and there are currently no outstanding data requests pending from the Environmental Protection Agency. PacifiCorp cannot predict the outcome of these requests at this time.

In 2002 and 2003, the Environmental Protection Agency proposed various changes to its New Source Review rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering New Source Review requirements. These changes have been subject to legal challenge and, until such time as the legal challenges are resolved and the rules are effective, PacifiCorp will continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002. In October 2005, the Environmental Protection Agency proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the New Source Review permitting program for existing power plants. The impact of these proposed changes on PacifiCorp cannot be determined until after the rule is finalized and implemented.

Climate Change

As a result of increased attention to climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority and many congressional observers expect to see passage of climate change legislation within the next several years. While debate continues at the national level over the direction of domestic climate policy, several states are developing state-specific or regional legislative initiatives to reduce greenhouse gas emissions. In December 2005, the states of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont signed a mandatory regional pact to reduce greenhouse gas emissions that would become effective in 2009 and ultimately would require a reduction in greenhouse gas emissions of 10.0% from 1990 levels. An executive order signed by California’s governor in June 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80.0% below 1990 levels by 2050. In addition, California has adopted legislation that imposes a greenhouse gas emission performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation facility, as well as legislation that adopts an economy-wide cap on greenhouse gas emissions to 1990 levels by 2020. In November 2006, Washington voters passed Initiative Measure No. 937, which modified state law to require utilities that serve more than 25,000 Washington customers to obtain at least 15.0% of their electricity from renewable resources by the year 2020. The outcome of federal and state climate change legislation cannot be determined at this time; however, adoption of stringent limits on greenhouse emissions could significantly impact PacifiCorp’s fossil-fueled facilities, and, therefore, its financial results.

Water Quality Standards

The 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 impacts” to aquatic organisms. In February 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities. 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 Court of Appeals remanded almost all aspects of the rule to the EPA, leaving companies with cooling water intake structures uncertain regarding compliance with these requirements. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as further action is taken by the EPA. In the event that PacifiCorp’s existing intake structures require modification or alternative technology is required by new rules, expenditures to comply with these requirements could be significant.

Endangered Species

The federal Endangered Species Act of 1973 and similar state statutes protect species threatened with possible extinction. Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of PacifiCorp’s core activities, including the siting, construction and operation of new and existing transmission and distribution facilities, as well as thermal, hydroelectric and wind generating plants. In addition, issues affecting endangered species can impact the relicensing of existing hydroelectric generating projects. This can generally reduce the generating output and operational flexibility, and potentially increase the costs of operation, of PacifiCorp’s own hydroelectric resources, as well as raise the price PacifiCorp pays to purchase wholesale electricity from hydroelectric facilities owned by others.

REGULATORY MATTERS

PacifiCorp conducts its business in conformance with a multitude of federal and state laws. PacifiCorp is also subject to the jurisdiction of public utility regulatory authorities in each of the states in which it conducts retail electric operations. These authorities regulate various matters, including customer rates, services, allocation of costs by state, issuances of securities, accounting policies and practices and other matters. In addition, PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act and is therefore subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters, including the terms and conditions of transmission service. Most of PacifiCorp’s hydroelectric plants are licensed by the FERC as major projects under the Federal Power Act, and certain of these projects are licensed under the Oregon Hydroelectric Act.

Federal Regulatory Matters

FERC Market Oversight

FERC Order No. 890

In February 2007, the FERC issued Order No. 890 adopting a final rule designed to strengthen the pro forma open access transmission tariff by providing greater specificity and increasing transparency. The most significant revisions to the pro forma open access transmission tariff relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and to exempt intermittent generators, and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation re-dispatch. As a transmission provider with an open-access transmission tariff on file with the FERC, PacifiCorp will be required to comply with the requirements of the new rule. Certain details related to the rule, such as the precise methodology that will be used to calculate available transfer capability, will be determined prospectively and thus, it is difficult to make a precise determination of the effect of this new rule on PacifiCorp’s transmission operations. In addition, it is difficult to determine the effect of this new rule once fully implemented on the availability and price of transmission service from the perspective of the wholesale marketing function. However, at least on a preliminary basis, the rule is not anticipated to have a significant impact on PacifiCorp’s financial results, but it will likely have a significant impact on its transmission operations, planning and wholesale marketing functions.

Energy Policy Act of 2005

On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the law expanded the FERC’s regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.

The Energy Policy Act also gives the FERC “backstop” transmission siting authority and directs the FERC to oversee the establishment of mandatory transmission reliability standards. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2008. Partly as a result of that portion of the law, PacifiCorp began development efforts to add additional wind-powered generation facilities.

Transmission Settlement

In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp’s use of its transmission system while conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff during an internal investigation of its compliance with certain FERC regulations shortly before MEHC’s acquisition of PacifiCorp. Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily related to the way PacifiCorp used its own transmission system to transmit energy using “network service” instead of “point-to-point” service as the FERC believes is required by PacifiCorp’s tariff. This use of transmission service neither enriched PacifiCorp’s shareholders nor harmed its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $0.9 million to other transmission customers in April 2006 and paid a $10.0 million fine to the United States Treasury in January 2007.

FERC Market Power Analysis

Pursuant to the FERC’s orders granting PacifiCorp authority to sell capacity and energy at market-based rates, PacifiCorp and certain of its former affiliates had been required to submit a joint market power analysis every three years. In February 2005, PacifiCorp submitted a joint triennial market power analysis, which indicated that PacifiCorp failed to pass one of the generation market power screens. In May 2005, the FERC issued an order instituting a proceeding pursuant to Section 206 of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. In June and July 2005, PacifiCorp and its formerly affiliated co-applicants submitted additional information and analysis to the FERC to rebut the presumption that PacifiCorp had generation market power. In January 2006, the FERC requested PacifiCorp to amend its previous filings with additional analysis, which was filed in March 2006. In June 2006, the FERC issued an order finding that PacifiCorp does not have market power and terminated the proceeding. In February 2007, FERC approved a change in filing status, relating to new generation, reaching the same conclusion.

California Refund Case

PacifiCorp is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices in 2000 and 2001. PacifiCorp has reserved for these potential refunds. Also in that time period, PacifiCorp experienced defaults of amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator and California Power Exchange as a result of California market conditions. PacifiCorp has reserved for these receivables. As part of the global settlement process underway in the FERC proceeding, as sponsored by the United States Court of Appeals for the Ninth Circuit and the FERC, PacifiCorp has been working with the California parties in an effort to explore settlement of these claims.

Hydroelectric Relicensing

Several of PacifiCorp’s hydroelectric plants are in some stage of the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of four hydroelectric projects. The following summarizes the status of certain of these projects.

Klamath Hydroelectric Project – (Klamath River, Oregon and California)

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169.0-MW nameplate-rated Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license granted by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp will continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. The public comment period on the draft environmental impact statement closed on December 1, 2006. The FERC is expected to issue its final environmental impact statement by April 2007, after which other federal agencies will complete their endangered species analyses. The states of Oregon and California will need to issue water quality certifications prior to the FERC issuing a final license.

Lewis River Hydroelectric Projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 136.0-MW nameplate-rated Merwin and 240.0-MW nameplate-rated Swift No. 1 hydroelectric projects in April 2004. An application for a new license for the 134.0-MW nameplate-rated Yale hydroelectric project was filed with the FERC in April 1999. However, consideration of the Yale application was delayed pending filing of the Merwin and Swift No. 1 applications so that the FERC could complete a comprehensive environmental analysis.

In November 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues related to the pending applications for new licenses for PacifiCorp’s Merwin, Swift No. 1 and Yale hydroelectric projects. As part of this settlement agreement, PacifiCorp agreed to implement certain protection, mitigation and enhancement measures prior to and during a proposed 50-year license period. However, these commitments are contingent on ultimately receiving licenses from the FERC that are consistent with the settlement agreement and other required permits. PacifiCorp has received water quality certificates and a biological opinion from the United States Fish and Wildlife Service. PacifiCorp is expecting a biological opinion from the National Marine Fisheries Service in March 2007. The FERC is expected to make a final decision no earlier than the second quarter of 2007.

Prospect Hydroelectric Project – (Rogue River, Oregon)

In June 2003, PacifiCorp submitted a final license application to the FERC for the Prospect Nos. 1, 2 and 4 hydroelectric projects, whose nameplate ratings total 36.8 MW. The FERC is expected to complete its required analysis and issue a new license before the end of April 2007.

Hydroelectric Decommissioning

Powerdale Hydroelectric Project – (Hood River, Oregon)

In June 2003, PacifiCorp entered into a settlement agreement to remove the 6.0-MW nameplate-rated Powerdale plant rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale plant and associated project features, which is subject to the FERC and other regulatory approvals, is projected to cost $5.9 million excluding inflation. Removal of the plant is scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale plant and rendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp’s request to cease generation at the project until decommissioning activities begin. Also in February 2007, PacifiCorp submitted a request to the FERC to allow the company to defer the remaining net book value and any additional removal costs of this project as a regulatory asset. PacifiCorp is awaiting the FERC’s reply.

Condit Hydroelectric Project – (White Salmon River, Washington)

In September 1999, a settlement agreement to remove the 9.6-MW nameplate-rated Condit hydroelectric project was signed by PacifiCorp, state and federal agencies and non-governmental organizations. Under the original settlement agreement, removal was expected to begin in October 2006, with a total cost to decommission not to exceed $17.2 million, excluding inflation. In early February 2005, the parties agreed to modify the settlement agreement so that removal will not begin until October 2008 for a total cost to decommission not to exceed $20.5 million, excluding inflation. The settlement agreement is contingent upon receiving an amended FERC license and removal order that is not materially inconsistent with the amended settlement agreement and other regulatory approvals. PacifiCorp is in the process of acquiring all necessary permits, within the terms and conditions of the amended settlement agreement.

Cove Hydroelectric Project – (Bear River, Idaho)

In May 2006, the FERC approved PacifiCorp’s application to amend the Bear River license and authorized the removal of the 7.5-MW nameplate-rated Cove hydroelectric plant and facilities. Decommissioning of the Cove facilities has been completed in accordance with the license amendment and the approved removal plan. The removal of the dam, flowline and all facilities, with the exception of the powerhouse, was completed in November 2006. As of December 31, 2006, $2.8 million has been spent for the decommissioning of the Cove hydroelectric project.

State Regulatory Actions

PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. The following discussion provides a state-by-state update.

Utah

In December 2006, the UPSC approved a stipulation settling PacifiCorp’s general rate case filed in March 2006 related to increased investments in Utah due to growing demand for electricity. The stipulation calls for an annual increase of $115.0 million, or 9.95%, with $85.0 million of the increase effective December 11, 2006 and the remaining $30.0 million effective June 1, 2007. Under the terms of the stipulation, PacifiCorp has agreed not to file another rate case until after December 11, 2007, with new rates effective no earlier than August 2008.

Oregon

In September 2006, the OPUC approved a settlement agreement resolving PacifiCorp’s February 2006 general rate case request related to investments in generation, transmission and distribution infrastructure and increases in fuel and general operating expenses, including the maintenance of low-cost but aging power plants. Pursuant to the settlement agreement, PacifiCorp received an annual increase for non-power cost items of $33.0 million effective January 1, 2007. Also on January 1, 2007, PacifiCorp received a $10.0 million increase for power costs through its annual transition adjustment mechanism. After 2007, PacifiCorp’s rates will be adjusted annually based on its expected power costs. PacifiCorp has agreed not to file a new rate case prior to September 1, 2007. If a case is filed on that date, new rates would be effective July 1, 2008.

In September 2005, the OPUC issued an order granting a general rate increase of $25.9 million, or an average increase of 3.2%, effective October 2005. The OPUC’s order reduced PacifiCorp’s revenue requirement by $26.6 million (and therefore denied any related further rate increase) based on the OPUC’s interpretation of Oregon Senate Bill 408 as discussed below. In October 2005, PacifiCorp filed with the OPUC a motion for reconsideration and rehearing of the rate order generally on the basis that the tax adjustment was not made in compliance with applicable law. With the motion, PacifiCorp also filed a deferred accounting application with the OPUC to track revenues related to the disallowed tax expenses. In July 2006, a final order was issued by the OPUC affirming its initial application of Oregon Senate Bill 408. The order also modified the tax adjustment, resulting in an additional annual increase in PacifiCorp’s revenue of $6.1 million effective July 2006, as well as granting deferred accounting for the period from October 2005 to July 2006. In September 2006, PacifiCorp filed an application for deferred accounting treatment of the remainder of the tax adjustment, pending the outcome of the permanent rulemaking for Oregon Senate Bill 408. This application was necessary to ensure that PacifiCorp is allowed the opportunity to recover any revenue shortfall related to its allocated tax expense in rates for 2006, to the extent any such revenue shortfall is not recovered through the Oregon Senate Bill 408 automatic adjustment clause. Because the result of the automatic adjustment clause will not be known until after the October 2007 tax reports are filed, PacifiCorp’s application for deferred accounting of the remainder of the tax adjustment will be postponed until fall 2007.

In September 2005, Oregon’s governor signed into law Oregon Senate Bill 408. This legislation is intended to address differences between income taxes collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or consolidated groups in which utilities are included for income tax reporting purposes.

Oregon Senate Bill 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provided electric or natural gas service to Oregon customers file an annual tax report with the OPUC. Among other information, the tax report must contain; (i) the amount of taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, and (ii) the amount of taxes “authorized to be collected in rates.” If the OPUC determines that the amount of taxes “authorized to be collected” differs by more than $100,000 from the amount of taxes paid, in either direction, the OPUC will require the public utility to implement a rate schedule with an automatic adjustment clause resulting in an increase or decrease on customer bills. The automatic adjustment clause is applicable for years beginning on or after January 1, 2006. The first tax report that can result in a rate adjustment will be filed on or before October 15, 2007 with the resulting increase or decrease if any, implemented in rates on or before June 1, 2008.

The final administrative rules define the amount of federal, state, and local taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, as the lowest of: (i) the total tax liability of the affiliated group of which the utility is a member, (ii) the standalone tax liability of the utility, or (iii) the tax liability calculated using the “apportionment method.” The “apportionment method” uses an evenly weighted three-factor formula premised on property, payroll and sales, with amounts for the regulated operations of the utility in the numerator and amounts for the affiliated group in the denominator, to generate an allocation factor that is applied against the tax liability of PacifiCorp’s respective affiliated group in order to “apportion” part of that tax liability to the regulated operations of the utility. For federal purposes, the affiliated group of which PacifiCorp is a member is Berkshire Hathaway Inc. and its subsidiaries. For state and local purposes, the affiliated group differs based upon jurisdictional filing requirements.

As a result of the law and the final administrative rules, the tax liability of the affiliated group of which PacifiCorp is a member and the affiliated group’s impact on the factor determined under the “apportionment method” may impact the amount of taxes paid and “properly attributed” to PacifiCorp. PacifiCorp cannot predict the financial results and the related impact of its federal affiliated group, Berkshire Hathaway Inc. and subsidiaries, and therefore, cannot determine the impact this law may have on its financial results.

Additionally, the calculation of “taxes authorized to be collected in rates,” as defined by the OPUC, is based upon assumptions in the latest rate case(s) used to set rates for the respective financial reporting period. As such, “taxes authorized to be collected in rates” does not reflect actual tax collections. The resulting difference between actual tax collections and the amount deemed collected pursuant to Oregon Senate Bill 408 may be a benefit or detriment to PacifiCorp and cannot be reasonably predicted.

The OPUC recognizes that a potential conflict between its rules and federal Internal Revenue Code regulations could deny PacifiCorp the tax benefits of accelerated depreciation. As such, at the request of the OPUC, in December 2006 PacifiCorp and the other affected utilities filed requests for private letter rulings from the Internal Revenue Service on this issue, which may result in reconsideration of further changes to the rule or underlying law.

Oregon Senate Bill 408 cannot be used to decrease utility rates below a fair and reasonable level and the final administrative rules expressly provide that a utility may challenge any adjustment if it would result in rates that are not fair, just and reasonable resulting in confiscatory rates.

PacifiCorp continues to evaluate its legal and legislative options.

In April 2006, long-term special contracts for PacifiCorp’s Klamath Basin irrigation customers expired. Under the contracts, customers received power at rates less than PacifiCorp’s average rates charged to other customers on general irrigation tariffs. Following expiration of these contracts, the OPUC issued an order authorizing the transition of Klamath Basin irrigators to generally applicable cost-based rates.

Wyoming

In March 2006, the WPSC approved an agreement that settled the general rate case filed by PacifiCorp in October 2005 and a separate request filed by PacifiCorp in December 2005 to recover increased costs of net wholesale purchased power used to serve Wyoming customers. The agreement provides for an annual rate increase of $15.0 million effective March 1, 2006; an additional annual rate increase of $10.0 million effective July 1, 2006; a power cost adjustment mechanism effective July 1, 2006; and an agreement by the parties to support the principle of a forecast test year in the next general rate case application. A power cost adjustment mechanism addresses the changes in power costs occurring between rate cases subject to threshold requirements and sharing arrangements. Power costs above or below the amounts built into rates may be recovered from or returned to customers according to the provisions in the specific power cost adjustment mechanism. Adjustments are subject to notice by the WPSC and possible intervention, challenges and adjustments by other parties.

Washington

In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23.2 million, or 10.2%. The WUTC set an eight-month schedule with an expected order date of June 15, 2007. As part of the filing, PacifiCorp proposed a Washington-only cost allocation methodology, which is based on PacifiCorp’s western resources. The rate case included a five-year pilot on the proposed allocation methodology and a power cost adjustment mechanism.

In May 2005, PacifiCorp filed a general rate case request with the WUTC for an increase of approximately $39.2 million annually, which was later reduced to approximately $30.0 million. In April 2006, the WUTC issued an order denying PacifiCorp’s request to increase rates. The WUTC determined that application of PacifiCorp’s cost allocation methodology failed to satisfy the statutory requirements that resources must benefit Washington ratepayers. PacifiCorp filed a petition for reconsideration of the order and requested an increase of not less than $11.0 million. PacifiCorp also filed a limited rate request seeking a rate increase of approximately $7.0 million, which represents a 2.99% increase in rates. In June 2006, the WUTC suspended PacifiCorp’s limited rate request and consolidated the request with the general rate case. In July 2006, the WUTC issued an order denying PacifiCorp’s request for reconsideration and rejecting the 2.99% limited rate request filing.

Idaho

In December 2006, the IPUC approved three applications filed by PacifiCorp in June 2006 proposing adjustments to the rates of certain Idaho customers for a total increase of $8.25 million. The applications were based on settlement agreements reached after negotiations between PacifiCorp and the respective customers and took the place of a general rate case originally planned to be filed in 2006. The first application was approved effective as of September 1, 2006 and the remaining two applications were approved effective as of January 1, 2007.

California

In December 2006, the CPUC approved an agreement settling PacifiCorp’s general rate case originally filed in November 2005. The agreement provides for a $7.3 million annual increase in rates and a 10.6% return on equity, a dollar-for-dollar energy cost adjustment clause that allows for annual changes in the level of net power costs, a post-test year adjustment mechanism that provides for inflation-based increases to rates in 2008 and 2009, the ability to seek recovery of the California-allocable portion of major plant additions exceeding $50.0 million, and scheduled rate increases under the terms of the transition plan for Klamath irrigators.

In April 2006, long-term special contracts for PacifiCorp’s Klamath Basin irrigation customers expired. Under the contracts, customers received power at rates less than PacifiCorp’s average rates charged to other customers on general irrigation tariffs. Following expiration of these contracts, the CPUC approved a joint proposal for a transition to standard tariff pricing.

ITEM 1A. RISK FACTORS

Investors, or potential investors, in PacifiCorp should be aware of the significant risks described below. These risks should be carefully considered, together with all of the other information included in this annual report and the other public information filed by us.

We are subject to extensive regulations that affect our operations and costs. These regulations are complex and subject to change.

We are subject to numerous regulation and laws enforced by regulatory agencies. These regulatory agencies include, among others, the FERC, the Environmental Protection Agency and the public utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California.

Regulations affect almost every aspect of our business and limit our ability to independently make management decisions regarding, among other items, business combinations, constructing, acquiring or disposing of operating assets, setting rates charged to customers, establishing capital structures and issuing equity or debt securities, engaging in transactions with our subsidiaries and affiliates, and paying dividends. Regulations are subject to ongoing policy initiatives and we cannot predict the future course of changes in regulatory laws, regulations and orders, or the ultimate effect that regulatory changes may have on us. However, such changes could materially impact our financial results. For example, such changes could result in, but are not limited to, increased retail competition within our service territories, new environmental requirements, the acquisition by a municipality or other quasi-governmental body of our distribution facilities (by negotiation, legislation or condemnation or by a vote in favor of a Public Utility District under Oregon law) or a negative impact on our current cost recovery arrangements, including income tax recovery.

The Energy Policy Act of 2005, or the Energy Policy Act, impacts many segments of the energy industry. To implement the law, the FERC has and will continue to issue new regulations and regulatory decisions addressing electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority, including the ability to assess civil penalties of up to $1.0 million per violation per day, even in the absence of intentional violations. The full impact of those decisions remains uncertain; however, the FERC has recently exercised its enforcement authority by imposing significant civil penalties on us and other companies for violations of its rules and regulations. In addition, the Energy Policy Act requires federal agencies, working together with non-governmental organizations charged with electric reliability responsibilities, to adopt and implement measures designed to ensure the reliability of electric transmission and distribution systems. Such measures could impose more comprehensive or stringent requirements on us, which would result in increased compliance costs and could adversely affect our financial results.

Further, several of our hydroelectric projects whose operating licenses have expired or will expire in the next several years are in some stage of the FERC relicensing process. Hydroelectric relicensing is a political and public regulatory process involving sensitive resource issues and uncertainties. We cannot predict with certainty the requirements (financial, operational or otherwise) that may be imposed by relicensing, the economic impact of those requirements, whether we will be willing to meet the relicensing requirements to continue operating our hydroelectric projects. Loss of hydroelectric resources or additional commitments arising from relicensing could adversely affect our financial results.

Recovery of our costs is subject to regulatory review and approval, and the inability to recover costs may adversely affect our financial results.

State Rate Proceedings

We establish rates for our retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns, but who have the common objective of limiting rate increases. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings.

Each state sets rates based in part upon the state utility commission’s acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state. Rate-making is also generally done on the basis of estimates of normalized costs, so if a given year’s realized costs are higher than normal, rates will not be sufficient to cover those costs. Each state utility commission generally sets rates based on a test year established in accordance with that commission’s policies. Certain states use a future test year and allow for escalation of historical costs, while other states use a historical test year. Use of a historical test year may cause regulatory lag, which results in us incurring costs, including significant new investments, for which recovery through rates is delayed. State commissions also decide the allowed rates of return MEHC will be given an opportunity to earn on its equity investment in us, as well as the allowed levels of expense and investment that they deem just and reasonable in providing service. The commissions may disallow recovery in rates for any costs that do not meet such standard.

In Utah, Washington and Idaho, we are not permitted to pass through energy cost increases in our rates without seeking a general rate increase. Any significant increase in the cost of fuel used for generation or the cost of purchased electricity could have a negative impact on us, despite our efforts to minimize this impact through future general rate cases or the use of hedging instruments. Any of these consequences could adversely affect our financial results.

While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that we will be able to realize a reasonable rate of return.

FERC Jurisdiction

The FERC establishes cost-based tariffs under which we provide transmission services to wholesale markets and retail markets in states that allow retail competition. The FERC also has responsibility for approving both cost- and market-based rates under which we sell electricity at wholesale and has licensing authority over most of our hydroelectric generation facilities. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or may revoke or restrict our ability to sell electricity at market-based rates, which could adversely affect our financial results. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act or FERC rules or orders.

We are actively pursuing, developing and constructing new facilities, the completion and expected cost of which is subject to significant risk, and we have significant funding needs related to our planned capital expenditures.

We are engaged in several large construction or expansion projects, including construction of a new gas-fired generating facility; the Lake Side Power Plant in Utah; construction and development of multiple wind generating plants; various capital projects related to generation, transmission and distribution; and the development of an underground mine. In addition, in connection with MEHC’s acquisition of us in early 2006, MEHC and we have committed to undertake several other capital expenditure projects, principally relating to environmental controls, transmission and distribution, renewable generation and other facilities. Including these investments, we expect to incur substantial construction, expansion and other capital-related costs over the next several years.

The completion of any or all of our pending, proposed or future construction or expansion projects is subject to substantial risk and may expose us to significant costs. The development or construction efforts on any particular project, or the efforts generally, may not be successful. Fluctuations in the price or availability of commodities, manufactured goods, equipment, labor and other items over a multi-year construction period can result in higher than expected costs to complete an asset and place it into service. Such costs, if found to be imprudent, may not be recoverable in rates. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any excess costs through rate-making decisions may materially affect our financial results.

Furthermore, we depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If these funds are not available and MEHC does not elect to provide any needed funding to us, we may need to postpone or cancel planned capital expenditures. Failure to construct these projects could materially increase operating costs, limit opportunities for revenue growth and adversely affect the reliability of electric service to our customers. For example, if we are not able to expand our existing generating facilities, we may be required to enter into long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads. These contracts would result in additional counterparty performance risk, which is described further below.

We are subject to numerous environmental, health, safety and other laws and regulations that may adversely impact financial results.

Operational Standards

We are subject to numerous environmental, health, safety, and other laws and regulations affecting many aspects of our present and future operations, including, among others:

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the Environmental Protection Agency’s Clean Air Mercury Rule, which establishes a cap and trade program to reduce mercury emissions from coal-fired power plants starting in 2010; and

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other laws or regulations that establish or could establish standards for greenhouse gas emissions, water quality, wastewater discharges, solid waste and hazardous waste.

These and related laws, regulations and orders generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals.

Compliance with environmental, health, safety, and other laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, damages arising out of contaminated properties, and fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to regulations could be prohibitively expensive. As a result, some facilities may be required to shut down or alter their operations. Further, we may not be able to obtain or maintain all required environmental regulatory approvals for our operating assets or development projects. Delays in obtaining any required environmental or regulatory permits, failure to comply with the terms and conditions of the permits or increased regulatory or environmental requirements may increase our costs or prevent or delay us from operating our facilities or developing new facilities. If we fail to comply with all applicable environmental requirements, we may be subject to penalties, fines or other sanctions. The costs of complying with current or new environmental, health, safety, and other laws and regulations could adversely affect our financial results.

Further, our regulatory rate structure or long-term customer contracts may not allow us to recover all costs incurred to comply with new environmental regulations. Although we believe that, in most cases, we are legally entitled to recover these kinds of costs, the inability to fully recover such costs in a timely manner could adversely affect our financial results.

Site Cleanup and Contamination

Environmental, health, safety, and other laws and regulations also impose obligations to remediate contaminated properties or to pay for the cost of such remediation, often by parties that did not actually cause the contamination. We are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of our assets, including power generation facilities, and transmission and distribution assets which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions, we may obtain or require indemnification against some environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, we could suffer material losses. We have established liabilities to recognize our obligations for known remediation liabilities. However, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities which may be material.

Inflation and increases in commodity prices and fuel transportation costs may adversely affect our financial results.

Inflation affects us through increased operating costs and increased capital costs for plant and equipment. As a result of regulatory lag and competitive price pressures, we may not be able to pass the costs of inflation on to our customers. If we are unable to manage costs increases or pass them on to our customers, our financial results could be adversely affected.

We are also heavily exposed to changes in prices and availability of coal and natural gas and the transportation of coal and natural gas because a majority of our generation capacity utilizes these fossil fuels. We currently have contracts of varying durations for the supply and transportation of coal for our existing generation capacity, although we obtain some of our coal supply from mines owned or leased by us. When these contracts expire or if they are not honored, we may not be able to purchase or transport coal on terms as favorable as the current contracts. We have similar exposures regarding the market price of natural gas. Changes in the cost of coal or natural gas supply or transportation and changes in the relationship between such costs and the market price of power will affect our financial results. Since the sales price we receive for power may not change at the same rate as our coal or natural gas supply or transportation costs, we may be unable to pass on the changes in costs to our customers.

Our financial results may be adversely affected if we are unable to obtain adequate, reliable and affordable transmission service.

We depend on transmission facilities owned and operated by utilities to transport electricity to both wholesale and retail markets, as well as natural gas purchased to supply some of our electric generation facilities. We have legal obligations to serve our retail customers and some of our wholesale customers, and if adequate transmission is unavailable to serve those customers’ loads economically, we will incur additional costs to deliver power. Such unavailability could also decrease our revenue if we are unable to purchase or sell and deliver products to our other wholesale customers. For these reasons, limits on the availability of transmission service could adversely affect our financial results.

We are subject to market risk, counterparty performance risk and other risks associated with wholesale energy markets.

In general, wholesale market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. We purchase electricity and fuel in the open market or pursuant to short-term or variable-priced contracts as part of our normal operating business. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, we may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when we are a net seller of electricity in the wholesale market, we will earn less revenue.

Wholesale electricity prices in our service areas are influenced primarily by factors throughout the western United States relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability and/or changes in customer loads due to the weather, the economy or customer behavior. Although we plan for resources to meet our current and expected retail and wholesale load obligations, we are a net buyer of electricity during some peak periods and therefore our energy costs may be adversely impacted by market risk. In addition, we may not be able to timely recover all, if any, of those increased costs unless the state regulators authorize such recovery.

We are also exposed to risks related to performance of contractual obligations by our wholesale suppliers and customers. We rely on suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt our ability to deliver electricity and require us to incur additional expenses to meet customer needs. In addition, when these contractual agreements end, we may be unable to purchase commodities on terms equivalent to the terms of current contracts.

We rely on wholesale customers to take delivery of the energy they have committed to purchase and to pay for the energy on a timely basis. Failure of customers to take delivery may require us to find other customers to take the energy at lower prices than the original customers committed to pay. At certain times of year, prices paid by us for energy needed to satisfy our customers’ demand for energy may exceed the amounts we receive through rates from these customers. If the strategy we use to economically hedge the exposure to these risks is ineffective, we could incur significant losses.

Our operating results may fluctuate on a seasonal and quarterly basis.

The sale of electric power is generally a seasonal business. In the markets in which we operate, customer demand peaks in the winter months due to heating requirements and also peaks in the summer months due to irrigation and cooling needs. Extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. In addition, a portion of our supply of electricity comes from hydroelectric projects that are dependent upon rainfall and snowpack.

As a result, our overall financial results may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less power, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our financial results through lower revenues or increased energy costs. Conversely, unusually extreme weather conditions could increase our costs to provide power and adversely affect our financial results. Furthermore, during or following periods of low rainfall or snowpack, we may obtain substantially less electricity from hydroelectric projects and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. The extent of fluctuation in financial results may change depending on a number of factors related to our regulatory environment and contractual agreements, including our ability to recover power costs and terms of the power sale contracts.

We are subject to operating uncertainties which may adversely affect our financial results.

The operation of a complex electric utility (including generating, transmission and distribution systems) involves many operating uncertainties and events that are beyond our control. These potential events include the breakdown or failure of power generation equipment, transmission and distribution lines or other equipment or processes; unscheduled plant outages; work stoppages; shortage of qualified labor; transmission and distribution system constraints or outages; inadequate coal reserves and other fuel shortages or interruptions; unavailability of critical equipment, material and supplies; low water flows; performance below expected levels of output, capacity or efficiency; operator error; and catastrophic events such as severe storms, fires, earthquakes, explosions or mining accidents. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Any of these risks could significantly reduce or eliminate our revenues or significantly increase our expenses. For example, if we cannot operate generation facilities at full capacity due to damage caused by a catastrophic event, our revenues could decrease due to decreased wholesale sales and our expenses could increase due to the need to obtain energy from more expensive sources. Further, current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. Any reduction of revenues for such reason, or any other reduction of our revenues or increase in our expenses resulting from the risks described above could adversely affect our financial results.

Potential terrorist activities or military or other actions could adversely affect us.

The continued threat of terrorism since September 11, 2001 and the impact of military and other actions by the United States and its allies may lead to increased political, economic and financial market instability and subject our operations to increased risk of acts of terrorism. The United States government has issued warnings that energy assets, specifically including electric utility infrastructure, are potential targets of terrorist organizations. Political, economic or financial market instability or damage to our operating assets or the assets of our customers or suppliers may result in business interruptions, lost revenues, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable wholesale energy markets, increased security, repair or other costs that may materially adversely affect us in ways that cannot be predicted at this time. Any of these risks could materially affect our financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital.

The insurance industry changed in response to these events. As a result, insurance covering risks we typically insure against may decrease in scope and availability, and we may elect to self-insure against many such risks. In addition, the available insurance may have higher deductibles, higher premiums and more restrictive policy terms.

Poor performance of plan investments and other factors impacting pension and postretirement benefits plan costs could unfavorably impact our cash flows and liquidity.

Costs of providing our non-contributory defined benefit pension and postretirement benefits plans depend upon a number of factors, including the level and nature of benefits provided, the rates of return on plan assets, discount rates, the interest rates used to measure required minimum funding levels, changes in laws and government regulation and our required or voluntary contributions made to the plans. Our pension and postretirement benefits plans are in underfunded positions, and without sustained growth in the investments over time to increase the value of the plans’ assets, we will be required to make significant cash contributions to fund the plans. Furthermore, the recently enacted Pension Protection Act of 2006 may require us to accelerate contributions to our pension plan for periods after 2007 and may result in more volatility in the amount and timing of future contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on our liquidity by reducing our cash flows.

A downgrade in our credit ratings could negatively affect our access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.

Our debt securities and preferred stock are rated investment grade by various rating agencies but may not continue to be rated investment grade in the future. Although none of our outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase our borrowing costs and commitment fees on our revolving credit agreement and other financing arrangements, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market, our principal source of short-term borrowings, could be significantly limited, resulting in higher interest costs.

Most of our large customers, suppliers and counterparties require sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If our credit ratings or the credit ratings of our subsidiaries were to decline, especially below investment grade, operating costs would likely increase because counterparties may require a letter of credit, collateral in the form of cash-related instruments or some other security as a condition to further transactions with us.

We have a substantial amount of debt, which could adversely affect our ability to obtain future financing and limit our expenditures.

As of December 31, 2006, we had $4.4 billion in total debt securities outstanding. Our principal financing agreements contain restrictive covenants that limit our ability to borrow funds, and any issuance of debt securities requires prior authorization from multiple state regulatory commissions. We expect that we will need to supplement cash generated from operations and availability under committed credit facilities with new issuances of long-term debt. However, if market conditions are not favorable for the issuance of long-term debt, or if an issuance of long-term debt would exceed contractual or regulatory limits, we may postpone planned capital expenditures, or take other actions, to the extent those expenditures are not fully covered by cash from operations, borrowings under committed credit facilities or equity contributions from MEHC.

MEHC may exercise its significant influence over us in a manner that would benefit MEHC to the detriment of our creditors and preferred stockholders.

MEHC, through its subsidiary, owns all of our common stock and therefore has significant influence over our business and any matters submitted for shareholder approval. In circumstances involving a conflict of interest between MEHC and our creditors and preferred stockholders, MEHC could exercise its influence in a manner that would benefit MEHC to the detriment of our creditors and preferred stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS

No information is required to be reported pursuant to this item.

ITEM 2. PROPERTIES

PacifiCorp’s properties consist of physical assets necessary and appropriate to render electric service in its service territories. Electric utility property consists primarily of generation, transmission and distribution facilities and related rights-of-way. It is the opinion of management that the principal depreciable properties owned by PacifiCorp are in good operating condition and well maintained. Substantially all of PacifiCorp’s electric utility properties are subject to the lien of PacifiCorp’s Mortgage and Deed of Trust. See Exhibit 4.1 included in Item 15. Exhibits and Financial Statement Schedules of this Form 10-K. Refer to Item 1. Business of this Form 10-K for additional information about PacifiCorp’s properties.

HEADQUARTERS/OFFICES

PacifiCorp’s corporate offices consist of approximately 800,000 square feet of owned and leased office space located in several buildings in Portland, Oregon, and Salt Lake City, Utah. PacifiCorp’s corporate headquarters are in Portland, but there are several executives and departments located in Salt Lake City. In addition to the corporate headquarters, PacifiCorp owns and leases approximately 1.2 million square feet of field office and warehouse space in various other locations in Utah, Oregon, Wyoming, Washington, Idaho and California. The field location square footage does not include offices located at PacifiCorp’s generating plants.

ITEM 3. LEGAL PROCEEDINGS

In addition to the proceedings described below, PacifiCorp is currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by PacifiCorp to have a material adverse effect on its financial results.

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Clean Air Act’s opacity standards at PacifiCorp’s Jim Bridger Power Plant in Wyoming. Under the Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light in the flue of a generating facility. The complaint alleges thousands of violations and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. PacifiCorp believes it has a number of defenses to the claims, and it has already committed to invest at least $812.0 million in pollution control equipment at its generating facilities, including the Jim Bridger plant, that is expected to significantly reduce emissions. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time.

In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in state district court in Salt Lake City, Utah by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon, 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 is 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 Power Plant. USA Power’s complaint alleges that PacifiCorp misappropriated confidential proprietary information in violation of Utah’s Uniform Trade Secrets Act and accuses PacifiCorp of breach of contract and related claims. USA Power seeks $250.0 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys’ fees. A trial has been scheduled for January 2008. PacifiCorp believes it has a number of defenses and intends to vigorously oppose any claim of liability for the matters alleged by USA Power. Furthermore, PacifiCorp expects that the outcome of this proceeding will not have a material impact on its consolidated financial results.

In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the Ninth Circuit Court of Appeals and briefing was completed in March 2006. Any final order will be subject to appeal. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial results.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No information is required to be reported pursuant to this item.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

PacifiCorp is an indirect subsidiary of MEHC, which owns all shares of PacifiCorp’s outstanding common stock. Therefore, there is no public market for PacifiCorp’s common stock. PacifiCorp declared and paid the following common dividends to its former parent, PHI: $50.8 million during the three months ended June 30, 2005; $52.8 million during the three months ended September 30, 2005; $54.6 million during the three months ended December 31, 2005; and $16.8 million during the three months ended March 31, 2006. PacifiCorp paid no common dividends during the nine months ended December 31, 2006 and does not presently anticipate that it will declare or pay dividends on common stock during the year ending December 31, 2007.

During the nine months ended December 31, 2006, PacifiCorp received capital contributions of $215.0 million in cash from its direct parent company, PPW Holdings LLC.

For a discussion of contractual and regulatory restrictions that limit PacifiCorp’s ability to pay dividends on common stock, see Note 12 of the Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data of this Form 10-K.

I TEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data, which should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and with PacifiCorp’s consolidated financial statements and the related notes to those statements included in Item 8. Financial Statements and Supplementary Data appearing elsewhere in this Form 10-K. The selected financial data has been derived from PacifiCorp’s historical consolidated financial statements. In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31.

(Millions of dollars) (Unaudited)	Nine Months Ended December 31,				Years Ended March 31,

	2006		2005		2006		2005		2004		2003

Statement of Income Data:

Operating revenue	$	2,924.1	$	2,667.1	$	3,896.7	$	3,048.8	$	3,194.5	$	3,082.4
Income from operations		415.2		521.3		792.0		656.4		617.9		488.9
Net income		160.9		213.6		360.7		251.7		248.1		140.1

	December 31,				March 31,

	2006		2005		2006		2005		2004		2003

Balance Sheet Data:

Total assets	$	13,851.3	$	12,827.4	$	12,731.3	$	12,520.9	$	11,677.1	$	11,695.8
Long-term debt, excluding current maturities		3,917.4		3,691.4		3,685.8		3,602.6		3,492.8		3,390.0
Preferred stock subject to mandatory redemption		37.5		45.0		45.0		52.5		60.0		66.7
Preferred stock		41.3		41.3		41.3		41.3		41.3		41.3
Total shareholder's equity		4,426.8		3,805.0		4,051.8		3,377.1		3,320.0		3,235.7

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in combination with the selected financial data and the consolidated financial statements included in Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data of this Form 10-K.

OVERVIEW

PacifiCorp is a regulated electricity company serving approximately 1.7 million retail customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commission in each state approves rates for retail electric sales within that state. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. Wholesale activities are regulated by the FERC. PacifiCorp owns, or has interests in, 69 thermal, hydroelectric and wind generating plants, with a plant net capacity of 8,588.1 MW. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric generation facilities. PacifiCorp transmits electricity through approximately 15,622 miles of transmission lines.

As described in Item 1. Business, MEHC completed its acquisition of PacifiCorp from ScottishPower and PHI on March 21, 2006. In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31.

RESULTS OF OPERATIONS

The following is a discussion of various factors that affected earnings for the periods presented on the Consolidated Statements of Income. Explanations include management’s best estimate of the impacts of weather, customer growth and other factors.

Overview

PacifiCorp’s net income was $160.9 million for the nine months ended December 31, 2006 compared to $213.6 million for the nine months ended December 31, 2005. The decrease in net income was primarily due to higher net unrealized losses on derivative contracts, higher severance costs and higher depreciation expense due to higher plant in service, partially offset by higher retail prices approved by regulators, higher output from hydroelectric and thermal generation plants, higher margins on wholesale system balancing activities and a lower effective tax rate.

Net unrealized losses on derivative contracts were $104.3 million during the nine months ended December 31, 2006 compared to net unrealized gains of $33.5 million during the nine months ended December 31, 2005. The increase in net unrealized losses was due to $58.9 million of higher net unrealized losses on contracts that settled during the current period and $43.9 million of net unrealized losses in the current period resulting from the change in estimate of contracts considered probable of receiving recovery in rates due to regulatory settlements in Utah and Oregon, and $35.0 million of higher net unrealized losses due to net unfavorable movements in forward prices.

Retail energy sales volumes grew by 4.5% during the nine months ended December 31, 2006 compared to the nine months ended December 31, 2005. PacifiCorp’s number of retail customers has been increasing by approximately 2.0% annually over the past five years. This customer growth trend is expected to continue for the foreseeable future. Increased customer usage, which also contributed to the higher volumes, is generally affected by economic and weather conditions, consumer trends and energy savings programs.

Output from PacifiCorp’s thermal plants increased by 510,344 MWh, or 1.4%, during the nine months ended December 31, 2006 compared to the nine months ended December 31, 2005. Output from PacifiCorp-owned hydroelectric facilities for the nine months ended December 31, 2006 increased by 478,148 MWh, or 19.2%, as compared to the nine months ended December 31, 2005. This increase was primarily attributable to current-period water conditions that improved relative to the prior-year period. PacifiCorp’s hydroelectric generation was 103.0% of normal for the nine months ended December 31, 2006, compared to 87.0% of normal for the nine months ended December 31, 2005, based on a 30-year average.

Nine Months Ended December 31, 2006 Compared to Nine Months Ended December 31, 2005

Results of operations for the nine months ended December 31, 2005 are unaudited.

Revenues

(Millions of dollars)	Nine Months Ended December 31,				Favorable/(Unfavorable)

	2006		2005		$ Change		% Change

Retail	$	2,245.1	$	2,095.0	$	150.1	7.2	%
Wholesale sales and other		679.0		572.1		106.9	18.7

Total revenues	$	2,924.1	$	2,667.1	$	257.0	9.6

Retail energy sales (GWh)		39,029		37,344		1,685	4.5
Wholesale energy sales (GWh)		10,284		9,906		378	3.8
Total retail customers (in thousands)		1,668		1,631		37	2.3

Retail revenues increased $150.1 million, or 7.2%, primarily due to:

•	$61.5 million of increases due to higher average customer usage;

•	$60.3 million of increases from higher prices approved by regulators; and

•	$35.8 million of increases related to growth in the number of residential and commercial customers; partially offset by,

•	$7.5 million of decreases due to changes in price mix, resulting from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales and other revenues increased $106.9 million, or 18.7%, primarily due to:

•	$82.8 million of increases due to changes in the fair value of derivative contracts; and

•	$82.3 million of increases related to non-physically settled system balancing transactions; partially offset by,

•	$15.5 million of decreases in wholesale electric sales, primarily due to lower prices, partially offset by higher volumes;

•	$13.6 million of decreases resulting from sales of sulfur dioxide emission allowances in the prior period; and

•	$8.8 million of decreases due to settlements in the prior period of amounts previously disputed with third parties.

Operating Expenses

(Millions of dollars)	Nine Months Ended December 31,				Favorable/(Unfavorable)

	2006		2005		$ Change			% Change

Energy costs	$	1,297.3	$	997.0	$	(300.3	)	(30.1	)%
Operations and maintenance		780.3		740.8		(39.5	)	(5.3	)
Depreciation and amortization		354.6		335.6		(19.0	)	(5.7	)
Taxes, other than income taxes		76.7		72.4		(4.3	)	(5.9	)

Total operating expenses	$	2,508.9	$	2,145.8	$	(363.1	)	(16.9	)

Energy costs increased $300.3 million, or 30.1%, primarily due to:

•	$226.0 million of increases due to changes in the fair value of derivative contracts;

•	$74.1 million of increases related to higher volumes and higher average prices of natural gas primarily due to an increase in thermal generation;

•	$8.3 million of increases related to higher average prices for coal consumed, partially offset by lower volumes; and

•	$6.1 million of increases related to higher wheeling expenses, primarily due to rate increases; partially offset by,

•	$11.3 million of decreases in purchased electricity due to lower average prices, partially offset by higher volumes; and

•	$3.2 million of decreases related to changes in the fair value of a streamflow weather derivative contract that expired in September 2006.

Operations and maintenance expense increased $39.5 million, or 5.3%, primarily due to:

•	$26.0 million of increases in employee severance costs;

•	$25.0 million of increases in third-party contract and service fees including the impact of plant overhauls and vegetation management programs;

•	$7.9 million of increases in pension and other postretirement benefit costs; and

•	$6.0 million of increases resulting from the final assessment of penalties related to compliance with the FERC standards of conduct for transmission; partially offset by,

•	$16.9 million of decreases in annual incentive expenses;

•	$5.2 million of decreases in services rendered by MEHC in the current year compared to ScottishPower in the prior year; and

•	$3.7 million of decreases resulting from the March 2006 amendment to the terms of a generating plant operating lease.

Depreciation and amortization expense increased $19.0 million, or 5.7%, primarily due to higher plant-in-service.

Taxes, other than income taxes increased $4.3 million, or 5.9%, primarily due to:

•	$2.7 million of increases in property taxes primarily due to increases in assessed values, including the impacts of higher levels of taxable property; and

•	$1.2 million of increases in franchise taxes, primarily due to higher retail revenues.

Interest and Other (Income) Expense

	Nine Months Ended December 31,						Favorable/(Unfavorable)

(Millions of dollars)	2006			2005			$ Change			% Change

Interest expense	$	215.3		$	210.5		$	(4.8	)	(2.3	)%
Interest income		(6.3	)		(7.1	)		(0.8	)	(11.3	)
Allowance for borrowed funds		(18.1	)		(13.9	)		4.2		30.2
Allowance for equity funds		(17.2	)		(7.5	)		9.7		129.3
Other		(5.1	)		(3.4	)		1.7		50.0

Total	$	168.6		$	178.6		$	10.0		5.6

Interest expense increased $4.8 million, or 2.3%, primarily due to higher variable rates during the nine months ended December 31, 2006.

Allowance for borrowed and equity funds increased $13.9 million, or 65.0%, primarily due to applying higher prescribed allowance for funds used during construction rates to higher qualified Construction work-in-progress balances during the nine months ended December 31, 2006.

Income Tax Expense

Income tax expense decreased $43.4 million, or 33.6%, primarily due to:

•	$33.7 million of decreases due to lower levels of income from continuing operations before income taxes for the nine months ended December 31, 2006; and

•	$18.2 million of decreases primarily due to the resolution of certain matters previously outstanding with the Internal Revenue Service; partially offset by,

•	$7.8 million of increases from the tax effect of the regulatory treatment of book and tax differences.

Year Ended March 31, 2006 Compared to Year Ended March 31, 2005

Revenues

(Millions of dollars)	Year Ended March 31,				Favorable/(Unfavorable)

	2006		2005		$ Change		% Change

Retail	$	2,808.6	$	2,648.8	$	159.8	6.0	%
Wholesale sales and other		1,088.1		400.0		688.1	172.0

Total revenues	$	3,896.7	$	3,048.8	$	847.9	27.8

Retail energy sales (GWh)		50,112		48,919		1,193	2.4
Wholesale energy sales (GWh)		13,381		13,334		47	0.4
Total retail customers (in thousands)		1,640		1,605		35	2.2

Retail revenues increased $159.8 million, or 6.0%, primarily due to:

•	$74.1 million of increases from higher prices approved by regulators;

•	$43.2 million of increases related to growth in the number of residential and commercial customers;

•	$28.7 million of increases due to higher average residential and industrial customer usage, net of decreases in commercial and other customer usage; and

•	$13.8 million of increases due to changes in price mix, resulting from the levels of customer usage at different customer tariffs in the various states that PacifiCorp serves.

Wholesale sales and other revenues increased $688.1 million, or 172.0%, primarily due to:

•	$554.4 million of increases due to changes in the fair value of derivative contracts;

•	$108.7 million of increases in wholesale electric sales, primarily due to higher prices;

•	$29.2 million of increases resulting from sales of sulfur dioxide emission allowances;

•	$11.0 million of increases in wholesale natural gas sales;

•	$8.2 million of increases in revenues from the settlement of amounts previously disputed with third parties; partially offset by,

•	$28.2 million of decreases related to non-physically settled system balancing transactions.

Operating Expenses

(Millions of dollars)	Year Ended March 31,				Favorable/(Unfavorable)

	2006		2005		$ Change			% Change

Energy costs	$	1,545.1	$	948.0	$	(597.1	)	(63.0	)%
Operations and maintenance		1,014.5		913.1		(101.4	)	(11.1	)
Depreciation and amortization		448.3		436.9		(11.4	)	(2.6	)
Taxes, other than income taxes		96.8		94.4		(2.4	)	(2.5	)

Total operating expenses	$	3,104.7	$	2,392.4	$	(712.3	)	(29.8	)

Energy costs increased $597.1 million, or 63.0%, primarily due to:

•	$469.5 million of increases due to changes in the fair value of derivative contracts;

•	$43.5 million of increases related to unfavorable changes in the fair value of the streamflow weather derivative contract resulting primarily from improved streamflow conditions in the current year compared to prior estimates;

•	$40.7 million of increases in purchased electricity due to higher prices and volumes;

•	$14.8 million of increases related to higher volumes of coal consumed due primarily to an increase in thermal generation;

•	$13.9 million of increases related to higher prices for coal consumed; and

•	$11.2 million of increases related to higher wheeling expenses.

Operations and maintenance expense increased $101.4 million, or 11.1%, primarily due to:

•	$43.7 million of increases in employee expenses, primarily due to an increase in headcount and higher benefit and pension costs;

•	$17.0 million in employee severance expense incurred during the current year;

•	$11.3 million of increases in materials and supplies utilized in plant overhaul activities;

•	$9.7 million of increases in third-party contract and service fees; and

•	$7.2 million of increases from services rendered by Scottish Power UK plc, and charged to PacifiCorp pursuant to the affiliated interest cross-charge policy.

Depreciation and amortization expense increased $11.4 million, or 2.6%, primarily due to:

•	$13.9 million of increases in depreciation expense due to additions to plant in service; partially offset by,

•	$3.0 million of decreases in amortization expense predominantly due to certain capitalized software becoming fully amortized.

Interest and Other (Income) Expense

	Year Ended March 31,						Favorable/(Unfavorable)
(Millions of dollars)
	2006			2005			$ Change			% Change

Interest expense	$	279.9		$	267.4		$	(12.5	)	(4.7	)%
Interest income		(9.5	)		(9.1	)		0.4		4.4
Allowance for borrowed funds		(18.5	)		(8.8	)		9.7		110.2
Allowance for equity funds		(13.9	)		(6.0	)		7.9		131.7
Other		(6.1	)		(7.3	)		(1.2	)	(16.4	)

Total	$	231.9		$	236.2		$	4.3		1.8

Interest expense increased $12.5 million, or 4.7%, primarily due to:

•	Higher average debt outstanding and higher variable rates during the year ended March 31, 2006; partially offset by,

•	Lower average fixed rates on long-term debt during the year ended March 31, 2006.

Allowance for borrowed and equity funds increased $17.6 million, or 118.9%, primarily due to applying higher prescribed allowance for funds used during construction rates to higher qualified Construction work-in-progress balances during the year ended March 31, 2006.

Other changed $1.2 million, primarily due to lower gains on net investments for the year ended March 31, 2006 compared to the year ended March 31, 2005.

Income Tax Expense

Income tax expense increased $30.9 million, or 18.3%, primarily due to:

•	$49.0 million of increases due to higher levels of income from continuing operations before income taxes for the year ended March 31, 2006; and

•	$9.7 million of increases in the income tax contingency reserve; partially offset by,

•	$9.2 million of decreases from the tax effect of the regulatory treatment of book and tax differences;

•	$5.4 million of decreases due to permanent book and tax differences of Internal Revenue Service settlements in the prior year;

•	$5.0 million of decreases from the tax effect of increases in depletion expense; and

•	$4.3 million of decreases from the tax effect of certain state income tax credits.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through long-term debt issuances and through capital cash contributions from PacifiCorp’s direct parent company, PPW Holdings LLC. PacifiCorp expects it will need additional periodic equity contributions from its parent over the next several years. Issuance of long-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash flows provided by operating activities decreased $142.1 million to $431.1 million for the nine months ended December 31, 2006 compared to $573.2 million for the nine months ended December 31, 2005, primarily due to increased employee-related payments, benefits in net cash collateral requirements realized in the comparative period and the net impact of the timing of cash collections and payments, partially offset by higher retail revenues driven by higher prices approved by regulators.

Net cash flows provided by operating activities increased $183.5 million to $894.6 million for the year ended March 31, 2006 compared to $711.1 million for the year ended March 31, 2005, primarily due to higher retail revenues, increased generation output, reduced net cash collateral requirements and the net impact of the timing of cash collection and payments, partially offset by increases in income tax payments and higher fuel inventory levels.

Investing Activities

Net cash used in investing activities increased $367.1 million to $1,055.8 million for the nine months ended December 31, 2006, compared to $688.7 million for the nine months ended December 31, 2005, primarily due to higher capital expenditures compared to the prior year. Capital expenditures totaled $1,050.6 million for the nine months ended December 31, 2006, compared to $716.1 million for the nine months ended December 31, 2005. Capital spending increased primarily due to wind generation investments of $268.5 million, including the purchase of the 100.5-MW Leaning Juniper 1 Wind Project and the initial investment in the 140.4-MW Marengo Wind Project. Other increases resulted from the construction and installation of emission control equipment and various capital projects related to transmission and distribution and other generation facilities. These increases were partially offset by decreases in expenditures for the construction of the Currant Creek Power Plant, which commenced full combined-cycle operation in March 2006, and expenditures for the construction of the 534.0-MW Lake Side Power Plant, which were lower than the previous year.

During the nine months ended December 31, 2006, PacifiCorp spent approximately $94.9 million on environmental capital projects for emissions control equipment to address current and anticipated air quality regulations compared to $44.2 million during the nine months ended December 31, 2005.

Net cash used in investing activities increased $177.4 million to $1,024.1 million for the year ended March 31, 2006, primarily due to higher capital expenditures during the year ended March 31, 2006 compared to the prior year. Capital expenditures totaled $1,049.0 million for the year ended March 31, 2006, compared to $851.6 million for the year ended March 31, 2005. The increase was primarily due to $109.7 million of increased expenditures on the construction of the Lake Side Power Plant, increases in various capital projects related to transmission and distribution and other thermal and hydroelectric facilities and $58.5 million for the installation of emission control equipment at the Huntington Power Plant, partially offset by $113.9 million of decreases in expenditures for the Currant Creek Plant. Expenditures for the Lake Side Power Plant will continue to be capitalized as construction work-in-progress until the plant is placed into service, which is expected to occur by June 2007. The Currant Creek Power Plant was completed in simple and combined-cycle phases. The simple-cycle phase was placed into service during May and June 2005 and combined-cycle phase was placed into service during March 2006.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt increased by $212.9 million during the nine months ended December 31, 2006 to $397.3 million of commercial paper arrangements, primarily due to capital expenditures and scheduled long-term debt maturities in excess of net cash from operations, partially offset by the proceeds received from capital contributions and the long-term debt issuance during the period, as well as from the utilization of short-term investments included in Cash and cash equivalents.

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which an aggregate principal amount of $399.0 million was outstanding at December 31, 2006, with a weighted-average interest rate of 5.3%.

PacifiCorp’s short-term debt decreased by $284.4 million during the year ended March 31, 2006 to $184.4 million, primarily due to proceeds from the long-term debt issuance and common stock financing during the year, partially offset by capital expenditures in excess of net cash from operations.

Revolving Credit and Other Financing Agreements

PacifiCorp has an $800.0 million unsecured revolving credit facility expiring in July 2011. The credit facility includes a variable rate borrowing option based on the London Interbank Offered Rate (LIBOR), plus 0.195%, that varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities, and it supports PacifiCorp’s commercial paper program. At December 31, 2006, there were no borrowings outstanding under this facility.

At December 31, 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $21.0 million of standby letters of credit available to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available at December 31, 2006 and expire periodically through February 2011.

PacifiCorp’s revolving credit and other financing agreements contain customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1. At December 31, 2006, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Long-Term Debt

During the nine months ended December 31, 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1, 2036 and made scheduled long-term debt repayments of $210.6 million.

During the year ended March 31, 2006, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035 and made scheduled long-term debt repayments of $269.7 million.

During the year ended March 31, 2005, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15, 2014 and $200.0 million of its 5.90% Series of First Mortgage Bonds due August 15, 2034. During the year ended March 31, 2005, PacifiCorp made scheduled long-term debt repayments of $239.8 million. Additionally, during December 2004, PacifiCorp redeemed, prior to maturity, all of the 8.625% First Mortgage Bonds due December 13, 2024 totaling $20.0 million. In March 2005, the maturity dates for three series of variable-rate pollution-control revenue bonds totaling $38.1 million were extended to December 1, 2020.

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 and/or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. At December 31, 2006, PacifiCorp estimated it would be able to issue up to $3.9 billion of new First Mortgage Bonds under the most restrictive issuance test in the mortgage. Any issuances would be 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 and/or deposits of cash. See “Limitations” below.

In September 2005, the SEC declared effective PacifiCorp’s shelf registration statement covering $700.0 million of future first mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this registration statement. During February 2007, PacifiCorp filed a shelf registration statement with the SEC covering an additional $800.0 million of first mortgage bond and unsecured debt issuances. This registration statement has been declared effective by the SEC.

PacifiCorp has state regulatory authority from the OPUC and the IPUC to issue up to an additional $1.5 billion of long-term debt. During February 2007, PacifiCorp filed a request with the UPSC to increase this long-term debt issuance authority from $350.0 million to up to $1.5 billion. Notice filings must be made with the WUTC prior to any future long-term debt issuances.

Preferred Stock Redemptions

PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during the nine months ended December 31, 2006, as well as in each of the years ended March 31, 2006 and 2005.

Common Shareholder’s Capital

During the nine months ended December 31, 2006, PacifiCorp received capital contributions of $215.0 million in cash from its direct parent company, PPW Holdings LLC.

During the year ended March 31, 2006, PacifiCorp issued 44,884,826 shares of its common stock to PHI, its former parent company, at a total price of $484.7 million.

Dividends

During the nine months ended December 31, 2006, PacifiCorp had the following dividend activity:

•	$3.7 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $2.1 million was recorded as interest expense; and

•	$3.8 million paid on preferred stock and preferred stock subject to mandatory redemption.

During the year ended March 31, 2006, PacifiCorp had the following dividend activity:

•	$175.0 million declared on common stock and paid to PHI;

•	$5.6 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $3.5 million was recorded as interest expense; and

•	$5.8 million paid on preferred stock and preferred stock subject to mandatory redemption.

During the year ended March 31, 2005, PacifiCorp had the following dividend activity:

•	$193.3 million declared on common stock and paid to PHI;

•	$6.1 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $4.0 million was recorded as interest expense; and

•	$6.2 million paid on preferred stock and preferred stock subject to mandatory redemption.

Capitalization

PacifiCorp manages its capitalization and liquidity position with a key objective of retaining existing credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, ratepayers and creditors and provide a competitive cost of capital and predictable capital market access.

As a result of recent changes in accounting standards, such as FIN 46R, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51, and EITF No. 01-08, Determining Whether an Arrangement Is a Lease , it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as capital lease obligations or debt on PacifiCorp’s financial statements. While PacifiCorp has successfully amended covenants in financing arrangements that may be impacted by these changes, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its immediate parent, PPW Holdings LLC, or take other actions.

Future Uses of Cash

Dividends

PacifiCorp does not currently anticipate that it will declare or pay dividends on common stock during the year ending December 31, 2007.

Capital Expenditure Program

Actual capital expenditures, excluding the non-cash allowance for equity funds used during construction, were $1,050.6 million for the nine months ended December 31, 2006, $1,049.0 million for the year ended March 31, 2006 and $851.6 million for the year ended March 31, 2005. Estimated capital expenditures for the year ending December 31, 2007 are expected to be approximately $1,488.8 million, which includes $730.2 million for ongoing operations projects, including new connections related to customer growth, $632.2 million for generation development and the related transmission projects, and $126.4 million for emissions control equipment to address current and anticipated air quality regulations.

PacifiCorp estimates that it will spend approximately $16.0 billion in capital projects over the next ten years. These capital projects include new generation resources, including renewables; installation of emission control equipment; distribution investments in new connections and substations; and transmission investments in new lines and upgrades. Although this estimate includes commitments made by MEHC and PacifiCorp in connection with state regulatory approvals resulting from the sale of PacifiCorp to MEHC, it is subject to a high degree variability based on several factors, including, among others highlighted in “Forward-Looking Statements” above and discussed below, changes in regulations, laws and market conditions, as well as the outcomes of rate-making proceedings.

Future decisions arising from the Integrated Resource Plan process described in Item 1. Business may impact future estimated capital expenditures. Additionally, capital expenditure needs are regularly reviewed by management and may change significantly as a result of such reviews. In funding its capital expenditure program, PacifiCorp expects to obtain funds required for construction and other purposes from sources similar to those used in the past, including operating cash flows, the issuance of new long-term debt and equity contributions from PacifiCorp’s direct parent company, PPW Holdings LLC. The availability of capital will influence actual expenditures.

The estimate provided above for generation development projects for the year ending December 31, 2007 includes the remaining costs to have the 534.0-MW nameplate-rated Lake Side Power Plant constructed, as well as upgrades of other generation plant equipment. The Lake Side Power Plant is expected to cost approximately $347.0 million, including $13.2 million of non-cash allowance for equity funds used during construction, At December 31, 2006, $274.4 million, excluding $9.6 million of non-cash allowance for equity funds used during construction, had been spent.

PacifiCorp and MEHC committed to invest $812.0 million in capital spending for emission control equipment to address current and future air quality initiatives implemented by the Environmental Protection Agency or by the states in which PacifiCorp operates facilities, which will be incurred over the next several years. Additional capital expenditures for emission reduction projects may be required, depending on the outcome of pending or new air quality regulations. The actual and estimated expenditures for emissions control equipment include amounts for installation of equipment at the Huntington and Cholla Power Plants. The actual expenditures for the Huntington Power Plant were $59.6 million for the nine months ended December 31, 2006, excluding $2.1 million of non-cash allowance for equity funds used during construction. The estimated expenditures for the year ending December 31, 2007 are $11.8 million for the Huntington Power Plant and $73.8 million for the Cholla Power Plant.

PacifiCorp and MEHC also committed to bring at least 100.0 nameplate-rated MW of cost-effective wind resources in service by March 21, 2007 and, to the extent available, add 400.0 nameplate-rated MW, inclusive of the 100.0 MW commitment, of cost-effective renewable resources in PacifiCorp’s generation portfolio by December 31, 2007. The 100.5-MW nameplate-rated Leaning Juniper 1 Wind Project was purchased in July 2006 and became commercially operational in September 2006. Initial investment in the 140.4-MW nameplate-rated Marengo Wind Project occurred in September 2006 and construction is scheduled to be completed in August 2007. The capital expenditure estimate provided above for the year ended December 31, 2007 for generation development projects includes the remaining costs for the construction of the Marengo Wind Project, as well as contracts for investments in two additional wind projects totaling approximately 112.0 nameplate-rated MW.

In addition, PacifiCorp and MEHC have committed to approximately $519.5 million in investments in PacifiCorp’s transmission and distribution system over the next several years.

Contractual Obligations and Commercial Commitments

Contractual Obligations

The table below shows PacifiCorp’s contractual obligations at December 31, 2006.

	Payments due during the year ending December 31,

(Millions of dollars)	2007		2008-2009		2010-2011		Thereafter		Total

Long-term debt, including interest:
Fixed-rate obligations	$	344.3	$	950.3	$	964.1	$	4,397.9	$	6,656.6
Variable-rate obligations (a)		21.4		42.8		42.8		710.4		817.4
Short-term debt, including interest		399.0		—		—		—		399.0
Preferred stock subject to mandatory redemption		37.5		—		—		—		37.5
Capital leases, including interest		6.9		14.0		14.0		91.3		126.2
Operating leases (b)		14.8		11.9		5.9		20.2		52.8
Asset retirement obligations (c)		20.5		30.3		32.7		363.9		447.4
Power purchase agreements: (d)
Electricity commodity contracts		528.9		390.8		243.2		421.7		1,584.6
Electricity capacity contracts		149.4		305.0		275.4		1,219.0		1,948.8
Electricity mixed contracts		23.4		47.3		39.1		248.3		358.1
Transmission		66.5		114.4		103.2		482.4		766.5
Fuel purchase agreements: (d)
Natural gas supply and transporation		334.1		571.2		314.2		168.0		1,387.5
Coal supply and transportation		233.0		442.6		268.6		1,045.9		1,990.1
Purchase obligations (e)		509.9		76.7		31.8		53.0		671.4
Owned hydroelectric commitments (f)		48.5		129.3		144.1		384.3		706.2
Other long-term liabilities (g)		4.7		7.0		2.4		8.9		23.0

Total contractual cash obligations	$	2,742.8	$	3,133.6	$	2,481.5	$	9,615.2	$	17,973.1

(a)

Consists of principal and interest for pollution-control revenue bond obligations with interest rates scheduled to reset within the next 12 months. Future variable interest rates are set at December 31, 2006 rates. Refer to Interest Rate Risk included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this Form 10-K for additional discussion related to variable-rate liabilities.

(b)	Excluded from these amounts are power purchase agreements that meet the definition of an operating lease. Such amounts are included with power purchase agreements.

(c)	Represents expected cash payments adjusted for inflation for estimated costs to perform legally required asset retirement activities.

(d)

Commodity contracts are agreements for the delivery of energy. Capacity contracts are agreements that provide rights to the energy output of a specified facility. Forecasted or other applicable estimated prices were used to determine total dollar value of the commitments for purposes of the table. Amounts included in power purchase agreements include those agreements that meet the definition of an operating lease.

(e)

Includes minimum commitments for maintenance, outsourcing of certain services, contracts for software, telephone, data and consulting or advisory services. Also includes contractual obligations for engineering, procurement and construction costs on the Lake Side Power Plant and for the emission control equipment on the Huntington Power Plant.

The purchase obligation amounts consist of items for which PacifiCorp is contractually obligated to purchase from a third party as of December 31, 2006. These amounts only constitute the known portion of PacifiCorp’s expected future expenses; therefore, the amounts presented in the table will not provide a reliable indicator of PacifiCorp’s expected future cash outflows on a standalone basis. For purposes of identifying and accumulating purchase obligations, PacifiCorp has included all contracts meeting the definition of a purchase obligation (legally binding and specifying all significant terms, including fixed or minimum amount or quantity to be purchased and the approximate timing of the transaction). For those contracts involving a fixed or minimum quantity but variable pricing, PacifiCorp has estimated the contractual obligation based on its best estimate of pricing that will be in effect at the time the obligation is incurred.

(f)

PacifiCorp has entered into settlement agreements with various interested parties to resolve issues necessary to obtain new hydroelectric licenses from the FERC. These settlement agreements generally include clauses that allow for termination of certain of PacifiCorp’s obligations if the FERC license order is not consistent with the settlement agreement. The table only includes contractual obligations made in settlement agreements that are not contingent upon the FERC license being consistent with the settlement agreement and obligations that are required by the FERC licenses. Hydroelectric licenses have varying expiration dates, and several expire within the next few years. The contractual obligations included in the table expire with the license expiration dates. However, PacifiCorp plans to acquire new licenses that will allow for continued operation for more than 30 years and expects contractual obligations to continue or increase.

(g)

Includes environmental commitments recorded on the balance sheet that are contractually or legally binding. Excludes regulatory liabilities and employee benefit plan obligations that are not legally or contractually fixed as to timing and amount. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete year. Excludes contributions expected to be made to PacifiCorp’s pension and other postretirement plans during the year ended December 31, 2007 as disclosed in Note 18 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K.

Commercial Commitments

PacifiCorp’s commercial commitments include surety bonds that provide indemnities for PacifiCorp in relation to various commitments it has to third parties for obligations in the event of default on behalf of PacifiCorp. The majority of these bonds are continuous in nature and renew annually. Based on current contractual commitments, PacifiCorp’s level of surety bonding beyond the nine months ended December 31, 2006 is estimated to be approximately $26.6 million. This estimate is based on current information and actual amounts may vary due to rate changes or changes to the general operations of PacifiCorp.

Credit Ratings

PacifiCorp’s credit ratings at December 31, 2006, were as follows:

	Moody’s	Standard & Poor’s


Issuer/Corporate	Baa1	A-
Senior secured debt	A3	A-
Senior unsecured debt	Baa1	BBB+
Preferred stock	Baa3	BBB
Commercial paper	P-2	A-1
Outlook	Stable	Stable

PacifiCorp has no ratings-downgrade triggers that would accelerate the maturity dates of its debt. A change in ratings is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition to drawing upon PacifiCorp’s credit agreement. However, interest rates on loans under the revolving credit agreement and commitment fees are tied to credit ratings and would increase or decrease when ratings are changed. A ratings downgrade may reduce the accessibility and increase the cost of PacifiCorp’s commercial paper program, its principal source of short-term borrowing, and may result in the requirement that PacifiCorp post collateral under certain of PacifiCorp’s power purchase and other agreements. 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.

In conjunction with its risk management activities, PacifiCorp must meet credit quality standards as required by counterparties. In accordance with industry practice, contractual agreements that govern PacifiCorp’s energy management activities either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed certain ratings-dependent threshold levels, or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s creditworthiness. If one or more of PacifiCorp’s credit ratings decline below investment grade, PacifiCorp would be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy management activities. At December 31, 2006, PacifiCorp’s credit ratings from Standard & Poor’s and Moody’s were investment grade; however, if the ratings fell more than one rating below investment grade, PacifiCorp’s estimated potential collateral requirements would total approximately $395.8 million. PacifiCorp’s potential collateral requirements could fluctuate considerably due to seasonality, market prices and their volatility, a loss of key PacifiCorp generating facilities or other related factors.

Limitations

In addition to PacifiCorp’s capital structure objectives, its debt capacity is also governed by its contractual and regulatory commitments.

PacifiCorp’s revolving credit and other financing agreements contain customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1. At December 31, 2006, management believes that PacifiCorp could have borrowed an additional $3.7 billion without exceeding this threshold. Any additional borrowings would be subject to market conditions and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements.

The state regulatory orders that authorized the acquisition by MEHC contain restrictions on PacifiCorp’s ability to pay common dividends to the extent that they would reduce PacifiCorp’s common stock equity below specified percentages of defined capitalization.

As of December 31, 2006, 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 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. The terms of this commitment treat 50.0% 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, 2006, PacifiCorp’s actual common stock equity percentage, as calculated under this measure, exceeded the minimum threshold.

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. At December 31, 2006, PacifiCorp’s unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and Fitch Ratings and Baa1 by Moody’s Investor Service.

Off-Balance Sheet Arrangements

PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees, indemnifications or similar arrangements. PacifiCorp currently has indemnification obligations for breaches of warranties or covenants in connection with the sale of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with the revised Financial Accounting Standards Board (the “FASB”) Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51 . PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. Refer to Notes 16 and 17 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for more information on these obligations and arrangements.

Inflation

PacifiCorp is subject to rate-of-return regulation and the impact of inflation on the level of cost recovery under regulation varies by state depending upon the type of test-period convention used in the state. In PacifiCorp’s state jurisdictions, a 12-month period of historical costs is typically used as the basis for developing a “test year,” which may also include various adjustments to eliminate abnormal or one-time events, normalize cost levels, or escalate the historical costs to a future level when the new rates will actually be in effect. To the extent that the levels of costs beyond the historical 12-month period can be established either through known adjustments or through the escalation of cost levels in establishing prices, PacifiCorp can mitigate the impacts of inflationary pressures. The majority of PacifiCorp’s retail customer prices are established using forecasts. These forecasts may include, but are not limited to, projected rate base levels and expenses, which are adjusted for both inflation and known and measurable changes. They may also include projected revenue and power cost changes related to load growth.

Accounting Matters

Critical Accounting Policies

Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled in the future. Amounts recognized in the Consolidated Financial Statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the Consolidated Financial Statements will likely increase or decrease in the future as additional information becomes available. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp prepares its Consolidated Financial Statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”), which differs in certain respects from the application of accounting principles generally accepted in the United States of America (“GAAP”) by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PacifiCorp has deferred certain costs and income that will be recognized in earnings over various future periods.

Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based rate-making 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 continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes probable that these costs will not be recovered, the assets and liabilities would be written off and recognized in operating income. As of December 31, 2006, PacifiCorp had recorded specifically identified regulatory assets totaling $1,396.9 million and regulatory liabilities totaling $822.2 million. Refer to Note 3 of the Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding PacifiCorp’s regulatory assets and liabilities.

Derivatives

PacifiCorp is exposed to variations in the market prices of natural gas and electricity as a result of its regulated utility operations and uses derivative instruments, including forward purchases and sales, swaps and options to manage these inherent commodity price risks.

Measurement Principles

Derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualify for the normal purchases and normal sales exemptions afforded by GAAP. The fair values of derivative instruments are determined using 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 of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and uses internally developed, modeled prices when market quotations are unavailable. Refer to Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a summary of fair values determined based on quoted market prices from third-party sources and those based on models and other valuation methods. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contracts.

Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years and, therefore, PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, PacifiCorp’s forward price curves must be estimated in other ways. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach), due to the limited information available. Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes place and a fundamentals forecast of expected spot prices for a commodity in a region based on modeled supply of and demand for the commodity in the region.

Classification and Recognition Methodology

The majority of PacifiCorp’s contracts are either probable of recovery in rates, and therefore recorded as a regulatory net asset or liability, or are accounted for as cash flow hedges and therefore recorded as accumulated other comprehensive income. Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2006, PacifiCorp had $229.8 million recorded as regulatory assets and $3.3 million recorded as accumulated other comprehensive income related to these contracts on the Consolidated Balance Sheets. If it becomes probable that a contract will not be recovered in rates, the amount recorded as a regulatory asset or liability will be written off and recognized in earnings. For cash flow hedges, PacifiCorp discontinues hedge accounting prospectively when it has determined that a derivative 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, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in accumulated other comprehensive income will remain there until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in accumulated other comprehensive income are immediately recognized in earnings.

Pensions and Other Postretirement Benefits

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provide healthcare and life insurance benefits through various plans for eligible retirees. In addition, PacifiCorp sponsors an employee savings plan.

The expense and benefit obligations relating to PacifiCorp’s pension and other postretirement plans are based on actuarial valuations and are measured three months prior to the end of PacifiCorp’s fiscal year. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets and healthcare cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries. Refer to Note 18 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for disclosures about PacifiCorp’s pension and other postretirement plans, including the key assumptions used to calculate the funded status and net periodic cost for these plans as of and for the nine months ended December 31, 2006.

In establishing its assumption as to the expected return on assets, PacifiCorp reviews the expected asset allocation and develops return assumptions for each asset class based on historical performance and independent advisors’ forward-looking views of the financial markets. Pension and other postretirement benefit expenses increase as the expected rate of return on retirement plan and other postretirement plan assets decrease. PacifiCorp regularly reviews its actual asset allocations and periodically rebalances its investments to its targeted allocations.

PacifiCorp chooses a discount rate based upon high quality fixed-income investment yields in effect as of the measurement date. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.

PacifiCorp chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs. The healthcare cost trend rate above gradually declines to 5.0% by 2012 for participants under 65 and by 2010 for participants over 65, at which point the rate is assumed to remain constant. Refer to Note 18 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for health care cost trend rate sensitivity disclosures.

The actuarial assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to the amount of pension and other postretirement benefit expense recorded. If changes were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

(Millions of dollars)	Pension Plans					Other Postretirement Benefit Plan

	+0.5%			-0.5%		+0.5%			-0.5%

Effect on December 31, 2006,
Benefit Obligations:
Discount rate	$	(87.3	)	$	95.6	$	(33.9	)	$	37.6

Effect on 2006 Periodic Cost:
Discount rate	$	(9.7	)	$	9.9	$	(2.7	)	$	2.9
Expected return on assets		(4.3	)		4.3		(1.6	)		1.6

A variety of factors, including the plan funding practices of PacifiCorp, have an affect on the funded status of the plans. The Pension Protection Act of 2006 imposed generally more stringent funding requirements for defined benefit pension plans, particularly for those significantly underfunded, and allowed for greater tax deductible contributions to such plans than previous rules permitted under the Employee Retirement Income Security Act. As a result of the Pension Protection Act of 2006, PacifiCorp does not anticipate any significant changes to the amount of funding previously anticipated through 2007; however, depending upon a variety of factors that impact the funded status of the plan, including actual asset returns, discount rates and plan changes, PacifiCorp may be required to accelerate contributions to its pension plans for periods after 2007 and there may be more volatility in annual contributions than historically experienced, which could have a material impact on cash flows.

Effective with the adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R) , as of December 31, 2006, the funded status of defined benefit pension and postretirement plans must be recognized in the balance sheet. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. The net liability for each plan is accounted for as a regulatory asset based on PacifiCorp’s determination that such amounts are recoverable through rates. PacifiCorp recognized liabilities totaling $330.3 million related to the underfunded status of its pension and other postretirement plans. These liabilities were offset by $329.0 million of increases in assets and a $1.3 million increase in other accumulated comprehensive loss, net of tax. Refer to Note 2 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for further detail on PacifiCorp’s significant accounting policies.

In December 2006, non-bargaining employees were notified that PacifiCorp is switching from a traditional final average pay formula for the Retirement Plan to a cash balance formula, effective June 1, 2007. Benefits under the final average pay formula will be frozen as of May 31, 2007, with no further benefit accrual under that formula. All future benefits will be earned under the cash balance formula. Although PacifiCorp is not yet able to quantify the impact, the changes may result in a significant reduction in Pension and other post employment liabilities, Regulatory assets and Accumulated other comprehensive income.

Income Taxes

In preparing PacifiCorp’s tax returns, management is required to interpret complex tax laws and regulations. PacifiCorp is 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. The Internal Revenue Service has closed its examination of PacifiCorp’s income tax returns through the 2000 tax year. Although the ultimate resolution of PacifiCorp’s federal and state tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, will not have a material adverse affect on PacifiCorp’s financial results.

PacifiCorp is required to pass income tax benefits related to certain property-related basis differences and various other differences on to its customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $416.2 million as of December 31, 2006, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory assets are probable of recovery. If it becomes probable that these costs will not be recovered, the assets would be written off and recognized in earnings.

PacifiCorp recognizes deferred tax assets and liabilities based on differences between the financial statement and tax basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse.

Revenue Recognition - Unbilled Revenues

Revenue is recorded based upon services rendered and electricity and natural gas delivered, distributed or supplied to the end of the period. Unbilled revenue was $177.7 million as of December 31, 2006. Historically, any difference between the actual and estimated amounts has been immaterial.

For PacifiCorp, the determination of sales to individual customers is based on the reading of its meter, which is performed on a systematic basis throughout the month. At the end of each month, PacifiCorp records unbilled revenues representing an estimate of the amount customers will be billed for energy provided between the meter reading dates and the end of the month. 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, historical trends, line losses, economic impacts and composition of customer classes.

New Accounting Standards

For new accounting standards, see Note 2 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PacifiCorp’s Consolidated Balance Sheets include assets and liabilities whose fair values are subject to market risks. PacifiCorp’s significant market risks are primarily associated with commodity prices and interest rates. The following sections address the significant market risks associated with PacifiCorp’s business activities. Refer to Notes 2 and 9 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding PacifiCorp’s accounting for derivative contracts.

RISK MANAGEMENT

PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp’s exposure to market and credit risk, the risk management committee recommends, and executive management establishes, policies, limits and commodity strategies, which are reviewed frequently to respond to changing market conditions.

Risk is an inherent part of PacifiCorp’s business and activities. The risk management process established by PacifiCorp is designed to identify, measure, assess, report and manage market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, PacifiCorp enters into various transactions, including derivative transactions, consistent with PacifiCorp’s risk management policy and procedures. The risk management policy governs energy transactions and is designed for hedging PacifiCorp’s existing energy and asset exposures, and to a limited extent, the policy permits arbitrage and trading activities to take advantage of market inefficiencies. The policy also governs the types of transactions authorized for use and establishes guidelines for credit risk management and management information systems required to effectively monitor such derivative use. PacifiCorp’s risk management policy provides for the use of only those instruments that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions, thereby ensuring that such instruments will be primarily used for hedging. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes.

PacifiCorp actively manages its exposure to commodity price volatility. These activities may include adding to the generation portfolio and entering into transactions that help to shape PacifiCorp’s system resource portfolio, including wholesale contracts and financially settled temperature-related derivative instruments that reduce volume and price risk due to weather extremes.

COMMODITY PRICE RISK

PacifiCorp is exposed to variations in the price of fuel used for generation and the price of wholesale electricity to be purchased or sold. The market prices of fuel and electricity are subject to fluctuations due to unpredictable factors, such as weather, electricity demand, plant performance and transmission constraints, that affect energy supply and demand. PacifiCorp’s energy purchase and sales activities are governed by PacifiCorp’s risk management policy and the risk levels established as part of that policy. Forward contracts are used to economically hedge both committed and forecasted energy purchases and sales. Net unrealized gains and losses on those forward contracts that are accounted for as derivatives, and that are probable of recovery in rates, are recorded as regulatory net assets or liabilities. Cash flows and results of operations may be negatively impacted if the costs of fuel and purchased electricity are higher than what is permitted to be recovered in rates.

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk (“VaR”) approach and other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period. VaR computations for the electricity and natural gas commodity portfolio are based on a historical simulation technique, utilizing historical price changes over a specified (holding) period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions. The quantification of market risk using VaR provides a consistent measure of risk across PacifiCorp’s continually changing portfolio. VaR represents an estimate of possible changes at a given level of confidence in fair value that would be measured on its portfolio assuming hypothetical movements in forward market prices and is not necessarily indicative of actual results that may occur.

PacifiCorp’s VaR computations utilize several key assumptions. The calculation includes short-term derivative commodity instruments, the expected resource and demand obligations from PacifiCorp’s long-term contracts, the expected generation levels from PacifiCorp’s generation assets and the expected retail and wholesale load levels. The portfolio reflects flexibility contained in contracts and assets, which accommodate the normal variability in PacifiCorp’s demand obligations and generation availability. These contracts and assets are valued to reflect the variability PacifiCorp experiences as a load-serving entity. Contracts or assets that contain flexible elements are often referred to as having embedded options or option characteristics. These options provide for energy volume changes that are sensitive to market price changes. Therefore, changes in the option values affect the energy position of the portfolio with respect to market prices, and this effect is calculated daily. When measuring portfolio exposure through VaR, these position changes that result from the option sensitivity are held constant through the historical simulation.

During the nine months ended December 31, 2006, PacifiCorp changed its VaR methodology for risk management purposes. The previous VaR methodology was based on a 24-month forward position, 99.0% confidence interval and five-day holding period. The new methodology is based on a 48-month forward position, 95.0% confidence interval and one-day holding period. The change to 95.0% confidence interval and a one-day holding period makes PacifiCorp’s VaR methodology more consistent with industry practices. The increase in length of the forward position from 24 to 48 months is based on management’s intention to more actively manage exposure to energy cost variability beyond 24 months and up to 48 months.

As of December 31, 2006, PacifiCorp’s estimated potential one-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 48 months was $15.8 million, as measured by the VaR computations described above, compared to $16.2 million as of March 31, 2006. The minimum, average and maximum daily VaR (one-day holding periods) are as follows:

	Nine Months Ended December 31,				Year Ended March 31, 2006
	Nine Months Ended December 31,

(Millions of dollars)	2006		2005

Minimum VaR (measured)	$	6.8	$	10.5	$	9.3
Average VaR (calculated)		11.6		14.6		13.7
Maximum VaR (measured)		16.4		19.5		19.5

PacifiCorp maintained compliance with its VaR limit procedures during the nine months ended December 31, 2006. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

FAIR VALUE OF DERIVATIVES

The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”) for the nine months ended December 31, 2006 and quantifies the reasons for the changes.

							Regulatory Net Asset (Liability)			Accumulated Other Comprehensive (Loss) Income
	Net Asset (Liability)

(Millions of dollars)	Trading			Non-trading

Fair value of contracts outstanding at April 1, 2006	$	0.2		$	7.7		$	94.7		$	—
Contracts realized or otherwise settled during the period		(0.1	)		(77.4	)		19.8			—
Change in valuation techniques		—			1.5			(1.5	)		—
Change in estimate of recoverability (a)		—			—			(40.3	)		(3.6	)
Other changes in fair values (b)		(3.0	)		(157.1	)		157.1			0.3

Fair value of contracts outstanding at December 31, 2006	$	(2.9	)	$	(225.3	)	$	229.8		$	(3.3	)

(a)

During the nine months ended December 31, 2006, PacifiCorp reached a new general rate case stipulation with several parties in Utah and received approval from the OPUC for a new general rate case settlement in Oregon. Utah and Oregon together account for approximately 70.4% of PacifiCorp’s retail electric operating revenues. Based on management’s consideration of the two new rate settlements, as well as the power cost recovery adjustment mechanisms approved in Wyoming and California earlier in 2006, PacifiCorp changed its estimate of the contracts receiving recovery in rates. Effective July 21, 2006, PacifiCorp recorded a $40.3 million decrease in net regulatory assets for previously recorded net unrealized gains related to contracts that it determined were probable of being recovered in rates with a corresponding pre-tax charge to net income of $43.9 million and a pre-tax increase to Accumulated other comprehensive income of $3.6 million.

(b)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts.

The fair value of derivative instruments is determined using 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 of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and internally developed and commercial models with internal and external fundamental data inputs when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the prices in the contract and the applicable forward price curve. Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years, and therefore PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, PacifiCorp must develop forward price curves. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach) due to the limited information available. Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of electricity plants in converting fuel to electricity) in the region where the purchase or sale takes place and a fundamental forecast of expected spot prices based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the assumptions could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward and option components. Forward components are valued against the appropriate forward price curve . The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

PacifiCorp’s valuation models and assumptions are updated daily to reflect current market information, and evaluations and refinements of model assumptions are performed on a periodic basis.

The following table shows summarized information with respect to valuation techniques and contractual maturities of PacifiCorp’s energy-related contracts qualifying as derivatives under SFAS No. 133 at December 31, 2006:

	Fair Value of Contracts at Period-End

(Millions of dollars)	Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years			Total Fair Value

Trading:
Values based on quoted market prices from third-party sources	$	(3.2	)	$	0.3		$	—		$	—		$	(2.9	)

Non-trading:
Values based on quoted market prices from third-party sources	$	34.2		$	(12.8	)	$	(19.0	)	$	(36.5	)	$	(34.1	)
Values based on models and other valuation methods		10.4			42.9			(20.5	)		(224.0	)		(191.2	)

Total	$	44.6		$	30.1		$	(39.5	)	$	(260.5	)	$	(225.3	)

Regulatory net asset (liability)	$	(39.7	)	$	(30.5	)	$	39.5		$	260.5		$	229.8

Standardized derivative contracts that are valued using market quotations are classified as “values based on quoted market prices from third-party sources.” All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as “values based on models and other valuation methods.” Both classifications utilize market curves as appropriate for the first six years.

The following table summarizes the estimated changes in fair value of PacifiCorp’s energy derivative contracts as of December 31, 2006 based upon multiplying a hypothetical 10% increase and a 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (in millions):

	Fair Value			Hypothetical Price Change	Estimated Fair Value after Hypothetical Change in Price

As of December 31, 2006	$	(228.2	)	10% increase	$	(186.6	)
				10% decrease		(269.8	)

INTEREST RATE RISK

PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. PacifiCorp manages its interest rate exposure by maintaining a blend of fixed- and variable-rate debt and by monitoring the effects of market changes in interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by PacifiCorp’s pension plan assets, mining reclamation trust funds and cash balances. PacifiCorp’s principal sources of variable-rate debt are commercial paper and pollution-control revenue bonds remarketed on a periodic basis. Commercial paper is periodically refinanced with fixed-rate debt when needed and when interest rates are considered favorable. PacifiCorp may also enter into financial derivative instruments, including interest rate swaps, swaptions and United States Treasury lock agreements, to manage and mitigate interest rate exposure. PacifiCorp does not anticipate using financial derivatives as the principal means of managing interest rate exposure. PacifiCorp’s weighted-average cost of debt is recoverable in rates. Increases or decreases in interest rates are reflected in PacifiCorp’s cost of debt calculation as rate cases are filed. Any adverse change to PacifiCorp’s credit rating could negatively impact PacifiCorp’s ability to borrow and the interest rates that are charged.

As of December 31, 2006, PacifiCorp had fixed-rate liabilities with an aggregate carrying value of $3,538.9 million and a fair value of $3,739.5 million. Due to their fixed interest rates, these instruments do not expose PacifiCorp to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $130.2 million if interest rates were to increase by 10.0% from their levels as of December 31, 2006. In general, such a decrease in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity. Comparatively, as of March 31, 2006, PacifiCorp had fixed-rate liabilities with an aggregate carrying value of $3,405.4 million and a fair value of $3,597.1 million. The fair value of these instruments would have decreased by approximately $114.3 million if interest rates had increased by 10.0% from their levels as of March 31, 2006.

As of December 31, 2006, PacifiCorp had $939.0 million of variable-rate liabilities and $47.5 million of temporary cash investments compared to $726.1 million of variable-rate liabilities and $113.6 million of temporary cash investments at March 31, 2006. As of December 31, 2006 and March 31, 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of December 31, 2006, for a one-year horizon, PacifiCorp estimates that if market interest rates average 1.0% higher (lower) during the year ending December 31, 2007 than during the twelve months ended December 31, 2006, interest expense, net of offsetting impacts of interest income, would increase (decrease) by $8.9 million. Comparatively, based on a sensitivity analysis as of March 31, 2006, for a one-year horizon, had interest rates averaged 1.0% higher (lower) during the twelve months ending March 31, 2007 than during the year ended March 31, 2006, PacifiCorp estimates that interest expense, net of offsetting impacts of interest income, would have increased (decreased) by $6.1 million. These amounts include the effect of invested cash and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of December 31, 2006 and March 31, 2006. The increase in interest rate sensitivity is primarily due to the increase in outstanding variable-rate commercial paper and the decrease in invested cash. If interest rates change significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that may be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.

CREDIT RISK

PacifiCorp extends unsecured credit to other utilities, energy marketers, and certain commercial and industrial end-users in conjunction with wholesale energy marketing activities. Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of 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 such counterparty.

When PacifiCorp considers a new wholesale purchase or sales transaction, market liquidity and the ability to optimize the transaction are considered. PacifiCorp analyzes the financial condition of each significant 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 a daily basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp enters into netting and collateral arrangements that include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty’s credit support arrangement.

As of December 31, 2006, 66.9% of PacifiCorp’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated “investment grade” credit ratings, while an additional 11.9% of PacifiCorp’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to “investment grade” by PacifiCorp based on internal review.

As of December 31, 2006, 0.7% of PacifiCorp’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated “non-investment grade” credit ratings, while an additional 20.5% of PacifiCorp’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to “non-investment grade” by PacifiCorp based on internal review.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page

Index to Consolidated Financial Statements:
Reports of Independent Registered Public Accounting Firms		52
Consolidated Statements of Income for the Nine Months Ended December 31, 2006 and the Years Ended March 31, 2006 and 2005		54
Consolidated Balance Sheets as of December 31, 2006 and March 31, 2006		55
Consolidated Statements of Cash Flows for the Nine Months Ended December 31, 2006 and the Years Ended March 31, 2006 and 2005		57
Consolidated Statements of Changes in Common Shareholder’s Equity and Comprehensive Income for the Nine Months Ended December 31, 2006 and the Years Ended March 31, 2006 and 2005		58
Notes to the Consolidated Financial Statements		59

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

We have audited the accompanying consolidated balance sheet of PacifiCorp and its subsidiaries (the “Company”) as of December 31, 2006, and the related consolidated statements of income, common shareholder’s equity and comprehensive income and of cash flows for the nine-month period then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries as of December 31, 2006, and the results of their operations and their cash flows for the nine-month period then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) , as of December 31, 2006.

Deloitte & Touche LLP

Portland, Oregon

February 27, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common shareholder’s equity and comprehensive income and of cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2006, and the results of their operations and their cash flows for each of the two years in the period ended March 31, 2006, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Portland, Oregon

May 26, 2006

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of dollars)

				Years Ended March 31,
		Nine Months Ended December 31, 2006
		Nine Months Ended December 31, 2006			2006			2005

Revenues	$	2,924.1		$	3,896.7		$	3,048.8

Operating expenses:
Energy costs		1,297.3			1,545.1			948.0
Operations and maintenance		780.3			1,014.5			913.1
Depreciation and amortization		354.6			448.3			436.9
Taxes, other than income taxes		76.7			96.8			94.4

Total		2,508.9			3,104.7			2,392.4

Income from operations		415.2			792.0			656.4

Interest expense and other (income) expense:
Interest expense		215.3			279.9			267.4
Interest income		(6.3	)		(9.5	)		(9.1	)
Allowance for borrowed funds		(18.1	)		(18.5	)		(8.8	)
Allowance for equity funds		(17.2	)		(13.9	)		(6.0	)
Other		(5.1	)		(6.1	)		(7.3	)

Total		168.6			231.9			236.2

Income before income tax expense		246.6			560.1			420.2
Income tax expense		85.7			199.4			168.5

Net income		160.9			360.7			251.7
Preferred dividend requirement		(1.6	)		(2.1	)		(2.1	)

Earnings on common stock	$	159.3		$	358.6		$	249.6

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of dollars)

	December 31, 2006			March 31, 2006

ASSETS
Current assets:
Cash and cash equivalents	$	59.0		$	119.6
Accounts receivable, net		342.1			266.8
Unbilled revenue		177.7			148.2
Amounts due from affiliates - MEHC		52.6			—
Inventories at average cost:
Materials and supplies		139.7			131.2
Fuel		103.9			80.9
Derivative contract asset		150.9			221.7
Deferred income taxes		27.8			—
Other		57.1			46.9

Total current assets		1,110.8			1,015.3

Property, plant and equipment:
Generation		6,133.6			5,686.3
Transmission		2,689.0			2,591.8
Distribution		4,654.9			4,502.8
Intangible plant		677.6			659.0
Other		1,687.7			1,662.5

Total operating assets		15,842.8			15,102.4
Accumulated depreciation and amortization		(5,841.6	)		(5,611.5	)

Net operating assets		10,001.2			9,490.9
Construction work-in-progress		809.2			618.3

Total property, plant and equipment, net		10,810.4			10,109.2

Other assets:
Regulatory assets		1,396.9			979.0
Derivative contract asset		234.9			345.3
Deferred charges and other		298.3			282.5

Total other assets		1,930.1			1,606.8

Total assets	$	13,851.3		$	12,731.3

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, continued

(Millions of dollars or shares)

	December 31, 2006			March 31, 2006

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	385.4		$	347.6
Amounts due to affiliates - MEHC		0.7			3.8
Accrued employee expenses		85.2			131.7
Taxes payable		30.0			47.0
Interest payable		56.7			63.0
Derivative contract liability		109.5			97.9
Deferred income taxes		—			16.9
Long-term debt and capital lease obligations, currently maturing		126.9			216.9
Preferred stock subject to mandatory redemption, currently maturing		37.5			3.7
Short-term debt		397.3			184.4
Other		134.9			103.2

Total current liabilities		1,364.1			1,216.1

Deferred credits:
Deferred income taxes		1,641.4			1,621.2
Investment tax credits		61.7			67.6
Regulatory liabilities		822.2			804.7
Derivative contract liability		504.5			461.2
Pension and other post employment liabilities		690.9			385.0
Other		372.9			361.4

Total deferred credits		4,093.6			3,701.1

Long-term debt and capital lease obligations, net of current maturities		3,966.8			3,721.0
Preferred stock subject to mandatory redemption, net of current maturities		—			41.3

Total liabilities		9,424.5			8,679.5

Commitments, contingencies and guarantees (See Notes 15 and 16)
Shareholders’ equity:
Preferred stock		41.3			41.3

Common equity:
Common shareholder’s capital (357.1 no par shares issued and outstanding)		3,600.1			3,381.9
Retained earnings		789.3			630.0
Accumulated other comprehensive loss, net		(3.9	)		(1.4	)

Total common equity		4,385.5			4,010.5

Total shareholders’ equity		4,426.8			4,051.8

Total liabilities and shareholders’ equity	$	13,851.3		$	12,731.3

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of dollars)

	Nine Months Ended December 31,			Years Ended March 31,
	Nine Months Ended December 31,
	2006			2006			2005

Cash flows from operating activities:
Net income	$	160.9		$	360.7		$	251.7
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized loss (gain) on derivative contracts, net		104.3			(86.8	)		(8.4	)
Depreciation and amortization		354.6			448.3			436.9
Deferred income taxes and investment tax credits, net		5.9			13.9			120.0
Regulatory asset/liability establishment and amortization		5.1			51.6			66.7
Other		13.8			50.0			(27.0	)
Changes in:
Accounts receivable, net and other assets		(129.0	)		71.1			(137.8	)
Inventories		(31.5	)		(38.9	)		(16.2	)
Amounts due to/from affiliates - MEHC, net		(51.3	)		3.6			—
Amounts due to/from affiliates - ScottishPower, net		—			32.6			(32.8	)
Accounts payable and other liabilities		(1.7	)		(11.5	)		58.0

Net cash provided by operating activities		431.1			894.6			711.1

Cash flows from investing activities:
Capital expenditures		(1,050.6	)		(1,049.0	)		(851.6	)
Proceeds from available-for-sale securities		68.3			123.4			49.1
Purchases of available-for-sale securities		(82.0	)		(84.9	)		(44.7	)
Other		8.5			(13.6	)		0.5

Net cash used in investing activities		(1,055.8	)		(1,024.1	)		(846.7	)

Cash flows from financing activities:
Changes in short-term debt		212.9			(284.4	)		343.9
Proceeds from long-term debt, net of issuance costs		348.3			296.0			395.2
Proceeds from equity contributions		215.0			484.7			—
Dividends paid		(1.6	)		(177.1	)		(195.4	)
Repayments and redemptions of long-term debt and capital lease obligations		(211.1	)		(269.7	)		(259.8	)
Redemptions of preferred stock		(7.5	)		(7.5	)		(7.5	)
Other		8.1			7.8			—

Net cash provided by financing activities		564.1			49.8			276.4

Change in cash and cash equivalents		(60.6	)		(79.7	)		140.8
Cash and cash equivalents at beginning of period		119.6			199.3			58.5

Cash and cash equivalents at end of period	$	59.0		$	119.6		$	199.3

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(Millions of dollars or shares)

	Common Shareholder’s Capital				Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Comprehensive Income (Loss)
	Common Shareholder’s Capital

	Shares	Amounts

Balance at March 31, 2004	312.2	$	2,892.1		$	390.1		$	(3.5	)
Net income	—		—			251.7			—		$	251.7
Other comprehensive loss:
Unrealized loss on available-for-sale securities, net of tax of $(0.1)	—		—			—			(0.2	)		(0.2	)
Minimum pension liability, net of tax of $(0.6)	—		—			—			(1.0	)		(1.0	)
Stock-based compensation expense	—		2.0			—			—			—
Cash dividends declared:
Preferred stock	—		—			(2.1	)		—			—
Common stock ($0.62 per share)	—		—			(193.3	)		—			—

Balance at March 31, 2005	312.2		2,894.1			446.4			(4.7	)	$	250.5

Net income	—		—			360.7			—		$	360.7
Other comprehensive income (loss):
Unrealized loss on available-for-sale securities, net of tax of $(0.9)	—		—			—			(1.6	)		(1.6	)
Minimum pension liability, net of tax of $3.0	—		—			—			4.9			4.9
Common stock issuance	44.9		484.7			—			—			—
Tax benefit from stock option exercises	—		7.5			—			—			—
Separation of employee benefit plans	—		(3.5	)		—			—			—
Other	—		(0.9	)		—			—			—
Cash dividends declared:
Preferred stock	—		—			(2.1	)		—			—
Common stock ($0.53 per share)	—		—			(175.0	)		—			—

Balance at March 31, 2006	357.1		3,381.9			630.0			(1.4	)	$	364.0

Net income	—		—			160.9			—		$	160.9
Other comprehensive income (loss):
Unrealized gain on derivative contracts, net of tax of $1.3	—		—			—			2.0			2.0
Unrealized loss on available-for-sale securities, net of tax of $(1.7)	—		—			—			(2.7	)		(2.7	)
Minimum pension liability, net of tax of $(0.4)	—		—			—			(0.5	)		(0.5	)
Adjustment to initially apply SFAS No. 158, net of tax of $(0.7)	—		—			—			(1.3	)
Equity contributions	—		215.0			—			—			—
Tax benefit from stock option exercises	—		3.2			—			—			—
Cash dividends declared:
Preferred stock	—		—			(1.6	)		—			—

Balance at December 31, 2006	357.1	$	3,600.1		$	789.3		$	(3.9	)	$	159.7

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization and Operations

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electric utility company serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and also engages in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal-mining facilities and services, steam delivery facilities and environmental remediation services.

On March 21, 2006, MidAmerican Energy Holdings Company (“MEHC”) completed its purchase of all of PacifiCorp’s outstanding common stock from PacifiCorp Holdings, Inc. (“PHI”), a subsidiary of Scottish Power plc (“ScottishPower”). PacifiCorp’s common stock was directly acquired by a subsidiary of MEHC, PPW Holdings LLC. As a result of this transaction, MEHC controls the significant majority of PacifiCorp’s voting securities. MEHC, a global energy company based in Des Moines, Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc.

In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. Summarized consolidated unaudited financial data for the comparative period is as follows:

(Millions of dollars)	Nine Months Ended December 31, 2005

Revenues	$	2,667.1
Income from operations		521.3
Income tax expense		129.1
Net income		213.6

Note 2 – Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling interest. Intercompany accounts and transactions have been eliminated. See Note 17 – Variable-Interest Entities.

Reclassifications

Certain amounts in the prior-period Consolidated Financial Statements and supporting note disclosures have been reclassified to conform to the December 31, 2006 presentation. These reclassifications had no effect on previously reported consolidated net income.

Use of Estimates in Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“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 revenues and expenses during the period. These estimates include, but are not limited to: unbilled receivables; valuation of energy contracts; the effects of regulation; the accounting for contingencies, including environmental and regulatory matters; and certain assumptions made in accounting for pension and postretirement benefits. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Cash Equivalents

Cash equivalents consist of funds invested in commercial paper, money market securities and in other investments with a maturity of three months or less when purchased.

Marketable Securities

PacifiCorp’s management determines the appropriate classification of investments in debt and equity securities at the acquisition date and re-evaluates the classifications at each balance sheet date. PacifiCorp’s investments in debt and equity securities are classified as available-for-sale.

Available-for-sale securities are stated at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings, except for gains and losses on the trust fund related to the final reclamation of leased coal-mining property. Unrealized gains and losses are recognized in Accumulated other comprehensive income (loss), net of tax, except for gains and losses on the trust fund related to the final reclamation of leased coal-mining property. Realized and unrealized gains and losses on this trust fund are recorded as a regulatory asset or liability since PacifiCorp expects to recover costs for these activities through rates.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”), which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PacifiCorp has deferred certain costs and income that will be recognized in earnings over various future periods.

Allowance for Doubtful Accounts

The allowance for doubtful accounts is based on PacifiCorp’s assessment of the collectibility of payments from its customers. This assessment requires judgment regarding the outcome of pending disputes, arbitrations and the ability of customers to pay the amounts owed to PacifiCorp. The allowance activity was as follows:

(Millions of dollars)	Nine Months Ended December 31, 2006			Years Ended March 31,

					2006			2005

Beginning balance	$	11.4		$	11.6		$	23.3
Charged to costs and expenses, net		7.7			9.2			5.0
Write-offs, net		(7.2	)		(9.4	)		(16.7	)

Ending balance	$	11.9		$	11.4		$	11.6

Derivatives

PacifiCorp employs a number of different derivative instruments in connection with its electric and natural gas, foreign currency exchange rate and interest rate risk management activities, including forward purchases and sales, swaps and options. Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualifying for the normal purchases and normal sales exemptions afforded by GAAP.

For all hedge contracts, PacifiCorp maintains formal documentation of the hedge. In addition, at inception and on a quarterly basis, PacifiCorp formally assesses whether the hedge contracts are highly effective in offsetting changes in cash flows of the hedged items. PacifiCorp documents hedging activity by transaction type and risk management strategy.

Changes in the fair value of a derivative designated and qualifying as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Changes in Common Shareholder’s Equity and Comprehensive Income as Accumulated other comprehensive income, net of tax, until the hedged item is recognized in income. PacifiCorp discontinues hedge accounting prospectively when it has determined that a derivative 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 no longer qualifies as an effective hedge, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in Accumulated other comprehensive income will remain in Accumulated other comprehensive income until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur, at which time associated deferred amounts in Accumulated other comprehensive income are immediately recognized in earnings.

Certain derivative contracts utilized by PacifiCorp are recoverable through rates. Accordingly, unrealized changes in fair value of these contracts are deferred as regulatory net assets or liabilities pursuant to SFAS No. 71.

Derivative contracts for commodities used in PacifiCorp’s 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 pursuant to the exemptions provided by GAAP. Recognition of these contracts in Revenue or Energy costs in the Consolidated Statements of Income occurs when the contracts settle.

When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts without available quoted market prices, fair value is determined based on internally developed modeled prices.

Inventories

Inventories consist mainly of materials and supplies, coal stocks and fuel oil, which are valued at the lower of average cost or market.

Property, Plant and Equipment, Net

General

Property, plant and equipment are recorded at historical cost. PacifiCorp capitalizes all construction-related material, direct labor costs and contract services, as well as indirect construction costs, which include allowance for funds used during construction. The cost of major additions and betterments are capitalized, while costs for replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are charged to operating expense.

When PacifiCorp retires its regulated property, plant and equipment, it charges the original cost to accumulated depreciation. The cost of removal is charged against the regulatory liability established through depreciation rates. Generally, when depreciable regulated assets are sold, the cost is removed from the property accounts and the related accumulated depreciation and amortization accounts are reduced and any residual gain or loss is amortized through depreciation rates in the future.

PacifiCorp records an allowance for funds used during construction, which represents the estimated cost of debt and equity costs of capital funds necessary to finance construction of plants. Allowance for funds used during construction is capitalized as a component of Property, plant and equipment, with offsetting credits to the Consolidated Statements of Income. After construction is completed, PacifiCorp is permitted to earn a return on these costs by their inclusion in rate base, as well as recover these costs through depreciation expense over the useful life of the related assets.

The weighted-average aggregate rates used for the allowance for funds used during construction were 7.5% for the nine months ended December 31, 2006, 6.5% for the year ended March 31, 2006; and 4.5% for the year ended March 31, 2005. PacifiCorp’s allowance for funds used during construction rates do not exceed the maximum allowable rates determined by regulatory authorities.

Intangible plant consists primarily of computer software costs that are originally recorded at cost. Accumulated amortization on Intangible plant was $358.4 million at December 31, 2006 and $329.8 million at March 31, 2006. Amortization expense on Intangible plant was $35.1 million for the nine months ended December 31, 2006; $45.5 million for the year ended March 31, 2006; and $48.5 million for the year ended March 31, 2005. The estimated aggregate amortization on Intangible plant for the years ending from December 31, 2007 through 2011 is $44.4 million in 2007, $36.7 million in 2008, $29.2 million in 2009, $25.5 million in 2010 and $23.2 million in 2011. Unamortized computer software costs were $177.2 million at December 31, 2006 and $186.7 million at March 31, 2006.

PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in property, plant and equipment purchased from other regulated utilities over their net book value in those assets. These unallocated acquisition adjustments had an original cost of $157.2 million and accumulated depreciation of $79.9 million at December 31, 2006.

Asset Retirement Obligations

PacifiCorp recognizes legal asset retirement obligations, mainly related to the final reclamation of leased coal-mining property. The fair value of a liability for a legal asset retirement obligation is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability 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 liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to Property, plant and equipment) and for accretion of the liability due to the passage of time. The difference between the asset retirement obligations liability, the corresponding asset retirement obligations asset included in Property, plant and equipment and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability. Estimated removal costs that PacifiCorp recovers through approved depreciation rates but that do not meet the requirements of a legal asset retirement obligations are accumulated in removal costs within regulatory liabilities in the Consolidated Balance Sheets.

Depreciation and Amortization

Depreciation and amortization are computed by the straight-line method either over the life prescribed by PacifiCorp’s various regulatory jurisdictions for regulated assets or over the assets’ estimated useful lives. Composite depreciation rates of average depreciable assets on utility Property, plant and equipment (excluding amortization of capital leases) were 3.0% for the nine months ended December 31, 2006 and for each of the years ended March 31, 2006 and 2005.

The average depreciable lives of Property, plant and equipment currently in use by category are as follows:

Generation
Steam plant		20 – 43 years
Hydroelectric plant		14 – 85 years
Wind projects		20 – 25 years
Other plant		15 – 35 years
Transmission		20 – 70 years
Distribution		44 – 50 years
Intangible plant		5 – 50 years
Other		5 – 30 years

Computer software costs included in Intangible plant are initially assigned a depreciable life of 5 to 10 years.

Revenue Recognition

Revenue from customers is recognized as electricity is delivered and includes amounts for services rendered. Amounts recognized include unbilled as well as billed amounts. Rates charged are subject to federal and state regulation.

Electricity sales to retail customers are determined based on meter readings taken throughout the month. PacifiCorp accrues an estimate of unbilled revenues, which are earned but not yet billed, net of estimated line losses, each month for electric service provided after the meter reading date to the end of the month. The process of calculating the Unbilled revenue estimate consists of three components: quantifying PacifiCorp’s total electricity delivered during the month, assigning unbilled revenues to customer type and valuing the unbilled energy. Factors involved in the estimation of consumption and line losses relate to weather conditions, amount of natural light, historical trends, economic impacts and customer type. Valuation of unbilled energy is based on estimating the average price for the month for each customer type.

Certain taxes assessed by governmental authorities on revenue-producing transactions are collected directly from PacifiCorp’s customers and remitted directly to taxing authorities. This collection and remittance activity is recorded on a net basis and thus has no income statement impact.

Income Taxes

As a result of the sale of PacifiCorp to MEHC on March 21, 2006, Berkshire Hathaway Inc. commenced including PacifiCorp in its U.S. federal income tax return. PacifiCorp’s provision for income taxes has been computed on the basis that it files separate consolidated income tax returns. Prior to the sale, PacifiCorp was included in PHI’s consolidated U.S. federal income tax return.

Deferred tax assets and liabilities are based on differences between the financial statements and tax bases of assets and liabilities using the estimated tax rates 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 are charged or credited directly to Other comprehensive income. Otherwise, changes in deferred income tax assets and liabilities are included as a component of income tax expense.

PacifiCorp is required to pass income tax benefits related to certain property-related basis differences and other various differences on to its customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $416.2 million as of December 31, 2006, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory assets are probable of recovery. If it becomes probable that these costs will not be recovered, the assets would be written off and recognized in earnings.

Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory jurisdictions.

In determining PacifiCorp’s tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax returns, PacifiCorp is 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. The Internal Revenue Service has closed its examination of PacifiCorp’s income tax returns through 2000. Although the ultimate resolution of PacifiCorp’s federal and state tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, will not have a material adverse effect on PacifiCorp’s financial condition, results of operations or cash flows. PacifiCorp’s provision for tax uncertainties is included in Deferred charges and other in the Consolidated Balance Sheets.

Segment Information

PacifiCorp currently has one segment, which includes the regulated retail and wholesale electric utility operations.

New Accounting Standards

FIN 48

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes– an interpretation of FASB Statement No. 109 (“FIN 48”) . FIN 48 clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, Accounting for Income Taxes , and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective on January 1, 2007. PacifiCorp is currently evaluating the impact and based upon its assessment to date does not believe the adoption of FIN 48 will have a material effect on its consolidated financial position and results of operations.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”) . SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather, it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. PacifiCorp is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”). SFAS No. 158 requires an employer to recognize an asset or liability for the over- or underfunded status of a defined benefit postretirement plan measured as the difference between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree healthcare plan, the benefit obligation is the accumulated postretirement benefit obligation. SFAS No. 158 also requires entities to recognize as a component of other comprehensive income, net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period, but that were not recognized as components of net periodic benefit cost of the period pursuant to SFAS No 87, Employers’ Accounting for Pensions (“SFAS No. 87”), and SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (“SFAS No. 106”). However, as PacifiCorp is subject to SFAS No. 71, it recognized as regulatory assets substantially all amounts that would have been otherwise charged to other comprehensive income including the tax effect of any additional recovery expected from regulatory treatment. SFAS No. 158 does not impact the calculation of net periodic benefit cost and the amounts recognized in either Accumulated other comprehensive income or as a regulatory asset will be adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of SFAS No. 87 and SFAS No. 106.

PacifiCorp adopted the recognition and related disclosure provisions of SFAS No. 158 as of December 31, 2006. The incremental impacts of such adoption to the Consolidated Balance Sheet as of December 31, 2006 are as follows:

	Pension and Other Postretirement Plans

(Millions of dollars)	Before SFAS No. 158			Increase (Decrease)			After SFAS No. 158

Deferred income taxes	$	26.3		$	1.5		$	27.8
Regulatory assets		1,055.6			341.3			1,396.9
Deferred charges and other		312.1			(13.8	)		298.3
Total assets		13,522.3			329.0			13,851.3
Other current liabilities		130.9			4.0			134.9
Pension and other post employment liabilities		325.6			365.3			690.9
Deferred income taxes		1,680.4			(39.0	)		1,641.4
Total liabilities		9,094.2			330.3			9,424.5
Accumulated other comprehensive loss, net of tax		(2.6	)		(1.3	)		(3.9	)
Total shareholders’ equity		4,428.1			(1.3	)		4,426.8

SFAS No. 158 also requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87 and SFAS No. 106 to measure up to three months prior to the financial statement date. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. PacifiCorp did not adopt the measurement date provisions of the statement during the period ended December 31, 2006. Upon adoption of the measurement date provisions, PacifiCorp will be required to record a transitional adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in rates.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment to SFAS No. 115 (“SFAS No. 159”). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting standards that require certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. PacifiCorp is currently evaluating the impact of adopting SFAS No. 159 on its consolidated financial position and results of operations.

Note 3 - Regulatory Assets and Liabilities

PacifiCorp is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations with respect to prices, services, accounting, issuance of securities and other matters. At present, PacifiCorp is subject to cost-based rate-making for its business. PacifiCorp is a “licensee” and a “public utility” as those terms are used in the Federal Power Act and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (the “FERC”) as to accounting policies and practices, certain prices and other matters.

Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp’s regulatory assets reflected on the accompanying Consolidated Balance Sheets consist of the following:

(Millions of dollars)	Weighted Average Remaining Life	December 31, 2006		March 31, 2006

Deferred income taxes (a)	29 years	$	464.1	$	480.3
Pension and other postretirement liability (b)	11 years		565.9		—
Derivative contracts (c)	6 years		229.8		94.7
Minimum pension liability (b)	—		—		257.7
Unamortized issuance expense on retired debt	12 years		25.4		29.0
Asset retirement obligation	21 years		23.9		17.3
Environmental costs	6 years		13.8		13.1
Various other costs	Various		74.0		86.9

Total		$	1,396.9	$	979.0

(a)	Amounts represent income tax benefits related to certain property-related basis differences and other various differences that were previously flowed through to customers and will be included in rates when the temporary differences reverse.

(b)

Amount represents unrecognized components of benefit plans’ funded status that are recoverable in rates when recognized in net periodic benefit cost. As of December 31, 2006, PacifiCorp adopted SFAS No. 158, which eliminated the concept of the minimum pension liability and required the recognition of PacifiCorp’s underfunded status of its pension and other postretirement plans. See Note 2 for further discussion on SFAS No. 158.

(c)

During the nine months ended December 31, 2006, PacifiCorp reached a new general rate case stipulation with several parties in Utah and received approval from the Oregon Public Utility Commission for a new general rate case settlement in Oregon. Utah and Oregon together account for approximately 70.4% of PacifiCorp’s retail electric operating revenues. Based on management’s consideration of the two new rate settlements, as well as the power cost recovery adjustment mechanisms approved in Wyoming and California earlier in 2006, PacifiCorp changed its estimate of the contracts receiving recovery in rates. Effective July 21, 2006, PacifiCorp recorded a $40.3 million decrease in net derivative contract regulatory assets for previously recorded net unrealized gains related to contracts that it determined were probable of being recovered in rates with a corresponding pre-tax charge to net income of $43.9 million and a pre-tax increase to Accumulated other comprehensive income of $3.6 million.

PacifiCorp had regulatory assets not earning a return on investment of $1,269.3 million at December 31, 2006.

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp’s regulatory liabilities reflected on the accompanying Consolidated Balance Sheets consist of the following:

(Millions of dollars)	Average Remaining Life	December 31, 2006			March 31, 2006

Cost of removal (a)(b)	29 years	$	698.0	$	687.9
Deferred income taxes	29 years		47.9		43.7
Bonneville Power Administration Regional Exchange Program	5 years		24.1		23.3
Asset retirement obligation (a)	21 years		15.5		11.9
Various other costs	Various		36.7		37.9

Total		$	822.2	$	804.7

(a)	These regulatory liabilities are deducted from rate base.

(b)	Amounts represent the remaining estimated costs, as accrued through depreciation rates, of removing electric utility assets in accordance with accepted regulatory practices.

Note 4 – Marketable Securities

PacifiCorp, by contract with Idaho Power Company, the minority owner of Bridger Coal Company (an indirect subsidiary of PacifiCorp), maintains a trust relating to final reclamation of a leased coal-mining property. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. Trust fund assets associated with Bridger Coal Company recorded at fair value included in Deferred charges and other were $109.8 million at December 31, 2006 and $101.9 million at March 31, 2006, including the Idaho Power Company minority-interest portion. Realized and unrealized gains and losses on the Bridger Coal Company reclamation trust are recorded as a regulatory liability in accordance with the prescribed regulatory treatment. See also Note 7 for information regarding asset retirement obligations.

Minority interest in Bridger Coal Company was $65.1 million at December 31, 2006 and $49.5 million at March 31, 2006.

The amortized cost and fair value of reclamation trust securities and other investments included in Deferred charges and other on PacifiCorp’s Consolidated Balance Sheets, which are classified as available-for-sale, were as follows:

(Millions of dollars)	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value

December 31, 2006
Debt securities	$	47.3	$	0.3	$	(0.1	)	$	47.5
Equity securities		53.5		8.1		(0.5	)		61.1

Total	$	100.8	$	8.4	$	(0.6	)	$	108.6

March 31, 2006
Debt securities	$	25.9	$	0.2	$	(0.6	)	$	25.5
Equity securities		61.7		7.0		(0.7	)		68.0

Total	$	87.6	$	7.2	$	(1.3	)	$	93.5

The quoted market price of securities is used to estimate their fair value.

The amortized cost and estimated fair value of debt and equity securities by contractual maturities are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

	December 31, 2006				March 31, 2006

(Millions of dollars)	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value

Debt securities
Due in one year or less	$	1.6	$	1.6	$	0.7	$	0.6
Due after one year through five years		20.9		20.9		6.5		6.4
Due after five years through ten years		6.0		6.1		9.9		9.8
Due after ten years		18.8		18.9		8.8		8.7
Equity securities		53.5		61.1		61.7		68.0

Total	$	100.8	$	108.6	$	87.6	$	93.5

Proceeds, gross gains and gross losses from realized sales of available-for-sale securities using the specific identification method were as follows:

(Millions of dollars)	Nine Months Ended December 31, 2006			Years Ended March 31,

				2006			2005

Proceeds	$	68.3		$	123.4		$	49.1

Gross gains	$	4.6		$	16.6		$	6.3
Gross losses		(0.9	)		(2.3	)		(2.2	)

Net gains		3.7			14.3			4.1
Less net gains included in Regulatory liabilities		(2.2	)		(16.6	)		(5.6	)

Net gains (losses) included in Net income	$	1.5		$	(2.3	)	$	(1.5	)

Note 5 – Short-Term Borrowings

Short-Term Debt

PacifiCorp’s outstanding short-term borrowings consisted of commercial paper arrangements of $397.3 million at an average interest rate of 5.3% at December 31, 2006 and $184.4 million at an average interest rate of 4.8% at March 31, 2006.

Revolving Credit Agreement

PacifiCorp has an $800.0 million unsecured revolving credit facility expiring in July 2011. The credit facility includes a variable interest rate borrowing option based on the London Interbank Offered Rate (LIBOR), plus 0.195%, that varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities, and supports PacifiCorp’s commercial paper program. At December 31, 2006, there were no borrowings outstanding under this facility.

PacifiCorp’s revolving credit and other financing agreements contain customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1.0. At December 31, 2006, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Note 6 - Long-Term Debt and Capital Lease Obligations

PacifiCorp’s long-term debt and capital lease obligations were as follows:

	December 31, 2006					March 31, 2006

(Millions of dollars)	Amount			Average Interest Rate		Amount			Average Interest Rate

First mortgage bonds
4.3% to 9.2%, due through 2011	$	1,277.8		6.6	%	$	1,488.4		6.5	%
5.0% to 8.8%, due 2012 to 2016		457.0		5.6			457.0		5.6
8.4% to 8.5%, due 2017 to 2021		21.7		8.5			21.7		8.5
6.7% to 8.3%, due 2022 to 2026		404.0		7.4			404.0		7.4
7.7% due 2031		300.0		7.7			300.0		7.7
5.3 % to 6.1%, due 2034 to 2036		850.0		5.8			500.0		5.5
Unamortized discount		(5.3	)				(4.7	)
Guaranty of pollution-control revenue bonds
Variable rates, due 2013 (a) (b)		40.7		4.0			40.7		3.1
Variable rates, due 2014 to 2025 (b)		325.2		3.9			325.2		3.2
Variable rates, due 2024 (a) (b)		175.8		4.0			175.8		3.2
3.4% to 5.7%, due 2014 to 2025 (a)		184.0		4.5			184.0		4.5
6.2%, due 2030		12.7		6.2			12.7		6.2
Unamortized discount		(0.5	)				(0.5	)
Funds held by trustees		—					(2.2	)
Capital lease obligations
10.4% to 14.8%, due through 2036		50.6		11.7			35.8		11.7

Total		4,093.7					3,937.9
Less current maturities		(126.9	)				(216.9	)

Total	$	3,966.8				$	3,721.0

(a)	Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution-control revenue bonds.

(b)	Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.

First mortgage bonds of PacifiCorp may be issued in amounts limited by PacifiCorp’s property, earnings and other provisions of the mortgage indenture. Approximately $14.6 billion of the eligible assets (based on original cost) of PacifiCorp were subject to the lien of the mortgage at December 31, 2006.

In September 2005, the Securities and Exchange Commission declared effective PacifiCorp’s shelf registration statement covering $700.0 million of future first mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this registration statement. During February 2007, PacifiCorp filed a shelf registration statement with the SEC covering an additional $800.0 million of first mortgage bond and unsecured debt issuances. This registration statement has been declared effective by the SEC.

As of December 31, 2006, $2.7 billion of first mortgage bonds were redeemable at PacifiCorp’s option at redemption prices dependent upon United States Treasury yields. As of December 31, 2006, $541.7 million of variable-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par. As of December 31, 2006, $71.2 million of fixed-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par and another $12.7 million at 102.0% of par. The remaining long-term debt was not redeemable at December 31, 2006.

In August 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1, 2036.

At December 31, 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $21.0 million of standby letters of credit to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available at December 31, 2006 and expire periodically through February 2011.

PacifiCorp’s standby letters of credit and standby bond purchase agreements generally contain similar covenants and default provisions to those contained in PacifiCorp’s revolving credit agreement, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1. PacifiCorp monitors these covenants on a regular basis in order to ensure that events of default will not occur and at December 31, 2006, PacifiCorp was in compliance with these covenants.

PacifiCorp has entered into long-term agreements that expire at various dates through October 2036 for transportation services, real estate and for the use of certain equipment which qualify as capital leases. The transportation services agreements included as capital leases are for the right to use newly constructed pipeline facilities to provide natural gas to two of PacifiCorp’s power plants. Non-cash additions to property, plant and equipment related to these capital leases were $16.6 million during the nine months ended December 31, 2006, $12.4 million during the year ended March 31, 2006 and zero during the year ended March 31, 2005. Assets accounted for as capital leases of $49.3 million as of December 31, 2006 and $33.9 million as of March 31, 2006 were included in Property, plant and equipment - Other on the Consolidated Balance Sheets.

The annual maturities of long-term debt and capital lease obligations for the years ending December 31 are:

(Millions of dollars)	Long-term Debt			Capital Lease Obligations			Total

2007	$	125.7		$	6.9		$	132.6
2008		412.4			7.0			419.4
2009		138.5			7.0			145.5
2010		14.6			7.0			21.6
2011		586.7			7.0			593.7
Thereafter		2,771.0			91.3			2,862.3

		4,048.9			126.2			4,175.1
Unamortized discount		(5.8	)		—			(5.8	)
Amounts representing interest		—			(75.6	)		(75.6	)

	$	4,043.1		$	50.6		$	4,093.7

Note 7 – Asset Retirement Obligations

PacifiCorp records asset retirement obligation liabilities for long-lived physical assets that qualify as legal obligations. PacifiCorp estimates its asset retirement obligation 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. PacifiCorp then records an asset retirement obligation asset associated with the liability. The asset retirement obligation assets are depreciated over their expected lives and the asset retirement obligation liabilities are accreted to the projected spending date. Changes in estimates could occur due to plan revisions, changes in estimated costs and changes in timing of the performance of reclamation activities.

PacifiCorp does not recognize liabilities for asset retirement obligations 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 and distribution and other assets cannot currently be estimated and no amounts are recognized in the accompanying Consolidated Financial Statements other than those included in the regulatory removal cost liability as established in approved depreciation rates.

On March 31, 2006, PacifiCorp adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations , an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations , refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, PacifiCorp is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.

In conjunction with the adoption of FIN 47 at March 31, 2006, PacifiCorp recorded an asset retirement obligation liability at a net present value of $22.7 million. PacifiCorp also increased net depreciable assets by $1.8 million, reclassified $13.5 million of costs accrued for removal from regulatory liabilities to asset retirement obligation liabilities, increased regulatory liabilities by $0.4 million and increased regulatory assets by $7.8 million for the difference between retirement costs approved by regulators and obligations under FIN 47.

The total asset retirement obligation liability at March 31, 2005, computed on a pro forma basis as if FIN 47 had been adopted on April 1, 2004, would have been $222.1 million.

The following table describes the changes to PacifiCorp’s asset retirement obligation liability for the nine months ended December 31, 2006 and the year ended March 31, 2006:

(Millions of dollars)	December 31, 2006			March 31, 2006

Liability recognized at beginning of period	$	212.1		$	199.6
Liabilities incurred		4.7			25.2
Liabilities settled		(4.2	)		(10.4	)
Revisions in cash flow (a)		0.6			(11.2	)
Accretion expense		7.8			8.9

Asset retirement obligation		221.0			212.1
Less current portion (b)		20.5			7.0

Long-term asset retirement obligation at end of period (c)	$	200.5		$	205.1

(a)	Results from changes in the timing and amounts of estimated cash flows for certain plant reclamation.

(b)	Amount included in Other current liabilities on the Consolidated Balance Sheets.

(c)	Amount included in Deferred credits - other on the Consolidated Balance Sheets.

PacifiCorp had trust fund assets recorded at fair value, primarily relating to mine reclamation, that were included in Deferred charges and other of $111.5 million at December 31, 2006 and $103.4 million at March 31, 2006, including the minority-interest joint-owner portions.

Note 8 – Preferred Stock Subject to Mandatory Redemption

PacifiCorp’s Preferred stock subject to mandatory redemption was as follows:

	December 31, 2006			March 31, 2006
(Thousands of shares, millions of dollars)
Series	Shares		Amount	Shares		Amount

No Par Serial Preferred, 16,000 shares authorized
$100 stated value
$7.48	375	$	37.5	450	$	45.0

All outstanding shares are subject to mandatory redemption on June 15, 2007. Holders of Preferred stock subject to mandatory redemption are entitled to certain voting rights. PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during the nine months ended December 31, 2006 and each of the years ended March 31, 2006 and 2005. Dividends declared but unpaid on Preferred stock subject to mandatory redemption that were included in Interest payable were $0.7 million at December 31, 2006 and $0.8 million at March 31, 2006.

Note 9 – Risk Management and Hedging Activities

PacifiCorp is directly exposed to the impact of market fluctuations in the prices of natural gas and electricity. PacifiCorp is exposed to interest rate risk as a result of the issuance of fixed and variable rate debt. PacifiCorp employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, swaps and options. The risk management process established by PacifiCorp is designed to identify, measure, assess, report and manage each of the various types of risk involved in its business. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes. As of December 31, 2006 and March 31, 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Commodity Price Risk

PacifiCorp is exposed to market risk due to the variations in the price of fuel used for generation and the price of wholesale electricity to be purchased or sold. To manage this commodity price risk, as well as to optimize the utilization of power generation assets and related contracts, PacifiCorp enters into forward purchases and sales. Such energy purchase and sales activities are governed by PacifiCorp’s risk management policy.

PacifiCorp makes continuing projections of future retail and wholesale loads and future resource availability to meet these loads based on a number of criteria, including historical load and forward market and other economic information and experience. Based on these projections, PacifiCorp purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and sells any surplus at the prevailing market price. This process involves hedging transactions, which include the purchase and sale of firm energy under long-term contracts, forward physical contracts or financial contracts for the purchase and sale of a specified amount of energy at a specified price over a given period of time.

Derivative Instruments

Forward purchases and sales that do not qualify for the exemptions afforded by GAAP are accounted for as derivatives and are recorded on the Consolidated Balance Sheets as assets or liabilities measured at estimated fair value. Where PacifiCorp’s derivative instruments are subject to a master netting agreement and the criteria of FIN 39, Offsetting of Amounts Related to Certain Contracts – An Interpretation of APB Opinion No. 10 and FASB Statement No. 105 , are met, PacifiCorp presents its derivative assets and liabilities, as well as accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets. For those energy purchase and sales contracts that are probable of recovery in rates, the unrealized gains and losses on derivative instruments are recorded as a regulatory net asset or liability.

Realized gains and losses on contracts that qualify as normal purchases and normal sales under GAAP (and therefore exempted from fair value accounting) are reflected in the Consolidated Statements of Income at the contract settlement date.

Unrealized gains and losses on derivative contracts held for trading purposes are presented on a net basis in the Consolidated Statements of Income as Revenues. Unrealized gains and losses on derivative contracts not held for trading purposes are presented in the Consolidated Statements of Income as Revenues for sales contracts and as Energy costs and Operations and maintenance expense for purchase contracts and financial swaps. Realized gains and losses on physically settled derivative contracts not held for trading purposes are presented in the Consolidated Statements of Income as Revenues for sales contracts and as Energy costs for purchase contracts. Realized gains and losses on non-physically settled derivative contracts not held for trading purposes are presented on a net basis in the Consolidated Statements of Income as Revenues.

The following table summarizes the various derivative mark-to-market positions included in the accompanying Consolidated Balance Sheet as of December 31, 2006:

												Accumulated Other Comprehensive Income (Loss) (a)
(Millions of dollars)	Net Assets (Liability)								Regulatory Net Asset (Liability)

	Assets		Liabilities			Total


Commodity hedges	$	382.5	$	(614.0	)	$	(231.5	)	$	233.1		$	(3.3	)
Foreign currency swaps		3.3		—			3.3			(3.3	)		—

	$	385.8	$	(614.0	)	$	(228.2	)	$	229.8		$	(3.3	)


Current	$	150.9	$	(109.5	)	$	41.4
Non-current		234.9		(504.5	)		(269.6	)

Total	$	385.8	$	(614.0	)	$	(228.2	)

(a)	Before income taxes.

The following table summarizes the various derivative mark-to-market positions included in the accompanying Consolidated Balance Sheet as of March 31, 2006:

									Regulatory Net Asset (Liability)		Accumulated Other Comprehensive Income (Loss) (a)
(Millions of dollars)	Net Assets (Liability)

	Assets		Liabilities			Total


Commodity hedges	$	567.0	$	(559.1	)	$	7.9		$	94.7	$	—


Current	$	221.7	$	(97.9	)	$	123.8
Non-current		345.3		(461.2	)		(115.9	)

Total	$	567.0	$	(559.1	)	$	7.9

(a)	Before income taxes.

Cash Flow Hedging

In order to reduce the impact of fluctuations in forward prices of electricity and natural gas on PacifiCorp’s results of operations, PacifiCorp initiated cash flow hedging in April 2006 for a portion of its derivative contracts, primarily electricity sales and natural gas purchase contracts. Changes in the fair value of derivative contracts designated as cash flow hedges are recorded as other comprehensive income to the extent the hedges are effective in offsetting changes in future cash flows for forecasted electricity and natural gas purchase and sales transactions. Amounts included in Accumulated other comprehensive income are reclassified to Revenues or Energy costs when the forecasted sale or purchase transaction is recognized in earnings, or when it is probable that the forecasted transaction will not occur.

At December 31, 2006, PacifiCorp had cash flow hedges with expiration dates through December 2007. During the nine months ended December 31, 2006, hedge ineffectiveness was insignificant. At December 31, 2006, $3.3 million of pre-tax net unrealized gains are forecasted to be reclassified from Accumulated other comprehensive income into earnings over the next twelve months as contracts settle. Hedge ineffectiveness and reclassifications from Accumulated other comprehensive income to earnings are presented in Revenues for sales contracts and contracts held for trading purposes and in Energy costs for purchase contracts and financial swaps.

Summary of Activity

The following table summarizes the amount of the pre-tax unrealized gains and losses included within the Consolidated Statements of Income associated with changes in the fair value of PacifiCorp’s derivative contracts that are not included in rates:

				Years Ended March 31,
	Nine Months Ended
(Millions of dollars)	December 31, 2006			2006			2005

Revenues	$	29.3		$	224.4		$	(330.0	)
Operating expenses:
Energy costs		(133.8	)		(131.1	)		338.4
Operations and maintenance		0.2			(6.5	)		—

Total unrealized (loss) gain on derivative contracts	$	(104.3	)	$	86.8		$	8.4

Fair Value Calculations

PacifiCorp bases its forward price curves upon market price quotations when available and bases them on internally developed and commercial models, with internal and external fundamental data inputs, when market quotations are unavailable. Market quotes are obtained from independent energy brokers, as well as direct information received from third-party offers and actual transactions executed by PacifiCorp. Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years and therefore PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, forward price curves must be developed. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve (beyond the first six years) is based upon the use of a fundamentals model (cost-to-build approach) due to the limited information available. The fundamentals model is updated as warranted, at least quarterly, to reflect changes in the market, such as long-term natural gas prices and expected inflation rates.

Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward price curve. 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 . The optionality is valued using a modified Black-Scholes model approach or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.

Foreign Currency Derivatives

PacifiCorp has entered into an agreement with a turbine supplier in connection with the construction of a wind project that requires PacifiCorp to make certain payments in Euros (“€”). To mitigate the related exposure to fluctuations in foreign currency exchange rates, PacifiCorp entered into a forward contract to purchase €76.8 million at a fixed price of U.S. Dollars. This contract has a series of payments and settlement dates extending to March 15, 2007 that correspond to the payments to be made in Euros in accordance with the supply agreement. The forward contract qualifies as a derivative instrument. As the cost of the associated wind project is expected to be recovered in rates, the unrealized gain on this contract of $3.3 million at December 31, 2006 was recorded as a net regulatory asset.

Weather Derivatives

PacifiCorp had a non-exchange-traded streamflow weather derivative contract to reduce PacifiCorp’s exposure to variability in weather conditions that affect hydroelectric generation. The contract expired on September 30, 2006. PacifiCorp paid an annual premium in return for the right to make or receive payments if streamflow levels were above or below certain thresholds. PacifiCorp estimates and records an asset or liability corresponding to the total expected future cash flow under the contract in accordance with EITF No. 99-2, Accounting for Weather Derivatives . The net asset (liability) recorded for this contract was zero at December 31, 2006 and $(2.1) million at March 31, 2006 and was included in other current assets (liabilities) in the Consolidated Balance Sheets. PacifiCorp recognized a loss of $12.4 million for the nine months ended December 31, 2006; loss of $15.6 million for the year ended March 31, 2006; and a gain of $27.9 million for the year ended March 31, 2005.

Note 10 - Income Taxes

Income tax expense (benefit) consists of the following:

	Nine Months Ended			Years Ended March 31,
	December 31,
(Millions of dollars)	2006			2006			2005

Current:
Federal	$	70.9		$	167.3		$	58.6
State		8.9			18.2			(10.1	)

Total		79.8			185.5			48.5

Deferred:
Federal		11.2			19.7			112.6
State		0.6			2.1			15.3

Total		11.8			21.8			127.9

Investment tax credits		(5.9	)		(7.9	)		(7.9	)

Total income tax expense	$	85.7		$	199.4		$	168.5

A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before income tax expense follows:

	Nine Months Ended		Years Ended March 31,
	December 31,
	2006		2006		2005

Federal statutory rate	35.0	%	35.0	%	35.0	%
State taxes, net of federal benefit	3.5		2.9		3.8
Effect of regulatory treatment of depreciation differences	6.0		2.5		4.1
Tax reserves	(4.6	)	1.1		(0.9	)
Tax credits	(4.2	)	(2.6	)	(2.3	)
Other	(0.9	)	(3.3	)	0.4

Effective income tax rate	34.8	%	35.6	%	40.1	%

The net deferred tax liability consists of the following:

(Millions of dollars)	December 31, 2006			March 31, 2006

Deferred tax assets:
Regulatory liabilities	$	319.9		$	316.9
Employee benefits		294.6			170.9
Derivative contracts		102.3			44.0
Other deferred tax assets		127.8			134.5

		844.6			666.3

Deferred tax liabilities:
Property, plant and equipment	$	(1,525.9	)	$	(1,531.2	)
Regulatory assets		(726.9	)		(623.0	)
Derivative contract regulatory assets		(87.2	)		(35.9	)
Other deferred tax liabilities		(118.2	)		(114.3	)

		(2,458.2	)		(2,304.4	)

Net deferred tax liability	$	(1,613.6	)	$	(1,638.1	)

As of December 31, 2006 and March 31, 2006, PacifiCorp had no federal or state net operating loss carryforwards. PacifiCorp has Oregon business energy tax credits of approximately $3.0 million at December 31, 2006 available to reduce future income tax liabilities. These credits begin to expire in 2015. PacifiCorp has Idaho investment tax credits of approximately $2.3 million at December 31, 2006 that are available to reduce future income tax liabilities. These credits begin to expire in 2016. PacifiCorp anticipates utilizing the tax credits prior to the expiration dates.

PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Consolidated Balance Sheets to provide for the possibility of adverse outcomes in tax proceedings. In addition, tax benefits are recognized in the period in which resolution is reached with taxing authorities. The reserve for net federal and state contingencies decreased $11.4 million during the nine months ended December 31, 2006. The decrease was primarily attributable to resolution of certain items previously outstanding with the Internal Revenue Service related to the examination of tax years ended March 31, 2001 through 2003. PacifiCorp anticipates that the resolution of the remaining outstanding issues related to federal income tax returns through March 31, 2003 and other unresolved issues will not have a material adverse impact on its consolidated financial results.

The sale of PacifiCorp to MEHC on March 21, 2006 triggered the recognition of a deferred intercompany gain or loss for tax purposes. The recognition of the tax effects of this item is considered to have occurred immediately prior to the closing of the sale of PacifiCorp while it was part of the PHI consolidated group. However, no adjustments have been recorded as PacifiCorp is not yet able to estimate the amount of the tax effect, if any, or determine a range of the potential tax effect. As the transaction was deemed to be with shareholders and as a result of formal agreements among PacifiCorp, MEHC, PHI and ScottishPower, PacifiCorp does not believe any adjustments resulting from the tax effect of a deferred intercompany gain or loss will have a material impact on its consolidated financial results.

Note 11 – Preferred Stock

PacifiCorp’s preferred stock, not subject to mandatory redemption, was as follows:

(Thousands of shares, millions of dollars, except per share amounts)	Redemption		December 31, 2006			March 31, 2006
	Price
Series	Per Share		Shares	Amount		Shares	Amount

Serial Preferred, $100 stated value, 3,500 shares authorized
4.52 %	$	103.5	2	$	0.2	2	$	0.2
4.56		102.3	85		8.4	85		8.4
4.72		103.5	70		6.9	70		6.9
5.00		100.0	42		4.2	42		4.2
5.40		101.0	66		6.6	66		6.6
6.00		Non-redeemable	6		0.6	6		0.6
7.00		Non-redeemable	18		1.8	18		1.8
5% Preferred, $100 stated value, 127 shares authorized		110.0	126		12.6	126		12.6

			415	$	41.3	415	$	41.3

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. Any premium paid on redemptions of preferred stock is capitalized, and recovery is sought through future rates. 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.

Dividends declared but unpaid on preferred stock were $0.5 million at December 31, 2006 and $0.5 million at March 31, 2006.

Note 12 - Common Shareholder’s Equity

Common Shareholder’s Equity

PacifiCorp has one class of common stock with no par value. A total of 750,000,000 shares were authorized and 357,060,915 shares were issued and outstanding at December 31, 2006 and March 31, 2006.

During the nine months ended December 31, 2006, PacifiCorp received equity contributions of $215.0 million in cash from its direct parent company, PPW Holdings LLC.

During the year ended March 31, 2006, PacifiCorp issued 44,884,826 shares of its common stock to PHI, its former parent company, at a total price of $484.7 million.

Common Dividend Restrictions

Through PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp’s common stock. The state regulatory orders that authorized the acquisition of PacifiCorp by MEHC 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, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to either PPW Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. The terms of this commitment treat 50.0% 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, 2006, PacifiCorp’s actual common stock equity percentage, as calculated under this measure, exceeded the minimum threshold.

PacifiCorp is also subject to maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 5 and Note 6.

Note 13 – Stock-Based Compensation

PacifiCorp Stock Incentive Plan (“PSIP”)

The PSIP expired on November 29, 2001 and all outstanding options under the plan were fully vested at March 31, 2005. As a result of the sale of PacifiCorp to MEHC and in accordance with the PSIP provisions regarding a change in control, all outstanding options, which give the holders the right to acquire ScottishPower American Depository Shares, must be exercised by March 21, 2007 (12 months after the date of the sale of PacifiCorp) or they will be forfeited.

ScottishPower Executive Share Option Plan (“ExSOP”)

In prior years, a select group of PacifiCorp employees received grants of stock options under the ScottishPower ExSOP. As a result of the sale of PacifiCorp to MEHC on March 21, 2006, all ExSOP options held by PacifiCorp employees became fully vested in accordance with the change-in-control provisions of the ExSOP. The change-in-control provisions also provide that all outstanding options, which give the holders the right to acquire ScottishPower American Depository Shares, are exercisable up to the later of 12 months after the date of the sale of PacifiCorp or 42 months after the date of original option grant. Options that are not exercised within this time period will be forfeited. Upon its sale, PacifiCorp ceased to participate in the plan; however, as of December 31, 2006, there were still options outstanding and exercisable by PacifiCorp employees.

The table below summarizes the stock option activity under the PSIP and the ExSOP:

	PSIP				ExSOP

ScottishPower American Depository Shares	Number of Shares		Weighted Average Price		Number of Shares		Weighted Average Price

Outstanding options at March 31, 2004	2,924,049		$	31.64	1,648,456		$	23.94
Granted	—			—	763,843			28.72
Exercised	(750,126	)		26.10	(483,667	)		23.84
Forfeited	(40,310	)		35.36	(30,136	)		26.37

Outstanding options at March 31, 2005	2,133,613			33.52	1,898,496			25.85
Exercised	(1,325,284	)		31.32	(1,404,637	)		25.58
Forfeited	(30,578	)		35.86	(16,096	)		27.59
Transfers due to separation	(68,710	)		37.35	(164,677	)		25.56

Outstanding options at March 31, 2006	709,041			37.15	313,086			27.15
Exercised	(496,111	)		36.93	(278,230	)		27.16

Outstanding options at December 31, 2006	212,930			37.66	34,856			27.13

Information with respect to options outstanding and options exercisable under the PSIP and the ExSOP were as follows:

	Options Outstanding and Exercisable

Range of Exercise Prices	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Life (in years)

December 31, 2006
PSIP: $25.70 - $41.38	212,930	$	37.66	0.2
ExSOP: $23.55 - $28.72	34,856		27.13	0.7
March 31, 2006
PSIP: $25.70 - $41.38	709,041	$	37.15	1.0
ExSOP: $23.55 - $28.72	313,086		27.15	1.4

Note 14 – Components of Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss is included in shareholders’ equity in the Consolidated Balance Sheets and consists of the following components, net of tax:

(Millions of dollars)	December 31, 2006			March 31, 2006

Unrealized gain on derivative contracts	$	2.0		$	—
Unrealized gain on available-for-sale securities		—			2.7
Minimum pension liability		—			(4.1	)
Pension and other postretirement liability		(5.9	)		—

Total accumulated other comprehensive loss	$	(3.9	)	$	(1.4	)

Note 15 - 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 effect 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 and penalties in substantial amounts.

Environmental Matters

PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act, related air quality standards promulgated by the Environmental Protection Agency and various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws have the potential for impacting PacifiCorp’s operations. Specifically, the Clean Air Act will likely continue to impact the operations of PacifiCorp’s generating facilities and will likely require PacifiCorp to reduce emissions from those facilities through the installation of additional or improved emission controls, the purchase of additional emission allowances, or some combination thereof. As of December 31, 2006, PacifiCorp’s environmental contingencies principally consist of air quality matters. Pending or proposed air regulations would, if enacted, require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxide and other pollutants at its generating plants below current levels. PacifiCorp believes it is in material compliance with current environmental requirements.

PacifiCorp’s policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on assessments of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement, PacifiCorp’s proportionate share and any coverage provided by insurance policies. Remediation costs that are fixed and determinable have been discounted to their present value using credit-adjusted, risk-free discount rates based on the expected future annual borrowing costs of PacifiCorp. The liability recorded was $39.7 million at December 31, 2006 and $38.5 million at March 31, 2006 and is included in Deferred credits – other on the accompanying Consolidated Balance Sheets. The December 31, 2006 recorded liability included $18.9 million of discounted liabilities. Had none of the liabilities included in the $39.7 million balance recorded at December 31, 2006 been discounted, the total would have been $42.6 million. The expected payments for each of the years ending December 31, 2007 through 2011 and thereafter are as follows: $6.4 million in 2007, $5.9 million in 2008, $4.2 million in 2009, $1.7 million in 2010, $1.5 million in 2011 and $22.9 million thereafter.

It is possible that future findings or changes in estimates could require that additional amounts be accrued. Should current circumstances change, it is possible that PacifiCorp could incur an additional undiscounted obligation of up to approximately $40.6 million relating to existing sites. However, management believes that completion or resolution of these matters will have no material adverse effect on PacifiCorp’s consolidated financial position, results of operations or cash flows.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 50 plants with an aggregate plant net owned capacity of 1,160.1 MW. The FERC regulates 97.9% of the net capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $79.0 million in costs at December 31, 2006 for ongoing hydroelectric relicensing, which are reflected in Construction work-in-progress on the Consolidated Balance Sheets.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169.0-MW nameplate-rated Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp will continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

As of December 31, 2006, PacifiCorp has incurred Klamath hydroelectric project relicensing costs of $42.1 million, which are reflected in Construction work-in-progress in the accompanying Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

FERC Issues

California Refund Case

Note 16 – Guarantees and Other Commitments

Guarantees

PacifiCorp is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. The following represent the indemnification obligations of PacifiCorp at December 31, 2006.

PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning guarantees require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation obligations require PacifiCorp to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint participants, PacifiCorp potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability. PacifiCorp has recorded its estimated share of the decommissioning and reclamation obligations.

In connection with the sale of PacifiCorp’s Montana service territory, PacifiCorp entered into a purchase and sale agreement with Flathead Electric Cooperative in October 1998. Under the agreement, PacifiCorp agreed to indemnify Flathead Electric Cooperative for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The indemnification has a cap of $10.1 million until October 2008 and a cap of $5.1 million thereafter (less expended costs to date). Two indemnity claims relating to environmental issues have been tendered, but remediation costs for these claims, if any, are not expected to be material.

Unconditional Purchase Obligations

	Payments due during the year ending December 31,

(Millions of dollars)	2007		2008		2009		2010		2011		Thereafter		Total

Construction	$	312.6	$	24.4	$	4.1	$	0.6	$	—	$	—	$	341.7
Operating leases		14.8		8.4		3.5		3.0		2.9		20.2		52.8
Purchased electricity		701.7		385.0		358.1		314.3		243.4		1,889.0		3,891.5
Transmission		66.5		54.2		60.2		54.3		48.9		482.4		766.5
Fuel		567.1		515.0		498.8		366.7		216.1		1,213.9		3,377.6
Other		271.0		103.3		111.5		150.2		60.2		810.1		1,506.3

Total commitments	$	1,933.7	$	1,090.3	$	1,036.2	$	889.1	$	571.5	$	4,415.6	$	9,936.4

Construction

PacifiCorp has an ongoing construction program to meet increased electricity usage, customer growth and system reliability objectives. At December 31, 2006, PacifiCorp had estimated long-term unconditional purchase obligations for construction of the new Lake Side Power Plant.

Operating leases

PacifiCorp leases offices, certain operating facilities, land and equipment under operating leases that expire at various dates through the years ending December 31, 2092. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Excluded from the operating lease payments above are any power purchase agreements that meet the definition of an operating lease.

Net rent expense was $18.6 million for the nine months ended December 31, 2006; $28.8 million for the year ended March 31, 2006; and $26.1 million for the year ended March 31, 2005.

Minimum non-cancelable sublease rent payments expected to be received through the years ended December 31, 2017 total $20.2 million.

Purchased electricity

As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and/or exchange agreements. Included in the purchased electricity payments above are any power purchase 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 projects under long-term arrangements with public utility districts. These purchases are made on a “cost-of-service” basis for a stated percentage of project output and for a like percentage of project operating expenses and debt service. These costs are included in Energy costs in the Consolidated Statements 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.

At December 31, 2006, PacifiCorp’s share of long-term arrangements with public utility districts was as follows:

(Millions of dollars)

Generating Facility	Year Contract Expires	Nameplate (MW)	Percentage of Output		Annual Costs (a)

Wanapum	2009	194.1	18.7	%	$	7.6
Rocky Reach	2011	67.8	5.3			3.9
Priest Rapids	2045	62.1	6.5			2.7
Wells	2018	53.4	6.9			2.7

Total		377.4			$	16.9

(a)	Includes debt service totaling $9.1 million.

PacifiCorp’s minimum debt service and estimated operating obligations included in purchased electricity above for the years ending December 31 are as follows:

(Millions of dollars)	Minimum Debt Service		Operating Obligations

2007	$	11.4	$	8.6
2008		11.3		8.8
2009		11.3		8.9
2010		5.3		5.2
2011		5.3		5.3
Thereafter		73.2		93.5

	$	117.8	$	130.3

PacifiCorp has a 4.0% entitlement to the generation of the Intermountain Power Project, located in central Utah, through a power purchase agreement. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles will purchase capacity and energy from PacifiCorp’s 4.0% entitlement of the Intermountain Power Project at a price equivalent to 4.0% of the expenses and debt service of the project.

Fuel

PacifiCorp has “take or pay” coal and natural gas contracts that require minimum payments.

Other

Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable only under certain conditions. PacifiCorp has such commitments related to legal or contractual asset retirement obligations, environmental obligations, hydroelectric obligations, equipment maintenance and various other service and maintenance agreements.

Note 17 – Variable-Interest Entities

Variable-Interest Entities Required to be Consolidated

PacifiCorp holds an undivided interest in 50.0% of the 474-MW Hermiston Plant (see Note 21), procures 100.0% of the fuel input into the plant and subsequently receives 100.0% of the generated electricity, 50.0% of which is acquired through a long-term purchase power agreement. As a result, PacifiCorp holds a variable-interest in the joint owner of the remaining 50.0% of the plant and is the primary beneficiary. However, upon adoption of FIN 46R, PacifiCorp was unable to obtain the information necessary to consolidate the entity, because the entity did not agree 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 $26.4 million during the nine months ended December 31, 2006; $35.2 million during the year ended March 31, 2006; and $34.8 million during the year ended March 31, 2005. 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.

Note 18 - Employee Benefit Plans

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides healthcare and life insurance benefits through various plans for eligible retirees. In addition, PacifiCorp sponsors an employee savings plan.

As a result of the sale of PacifiCorp to MEHC, plan participants that were employees or retirees of certain ScottishPower affiliates and a former PacifiCorp mining subsidiary ceased to participate in PacifiCorp’s plans. This separation resulted in a net $3.5 million reduction in Common shareholder’s equity during the year ended March 31, 2006.

Pension and Other Postretirement Plans

PacifiCorp’s pension plans include the Retirement Plan (the “Retirement Plan”), the Supplemental Executive Retirement Plan (the “SERP”) and joint trust plans to which PacifiCorp contributes on behalf of certain bargaining units. Benefits under the Retirement Plan are based on the employee’s years of service and average monthly pay in the 60 consecutive months of highest pay out of the last 120 months, with adjustments to reflect benefits estimated to be received from social security. Pension costs are funded annually by no more than the maximum amount that can be deducted for federal income tax purposes.

In December 2006, non-bargaining employees were notified that PacifiCorp is switching from a traditional final average pay formula for the Retirement Plan to a cash balance formula effective June 1, 2007. Benefits under the final average pay formula will be frozen as of May 31, 2007, with no further benefit accrual under that formula. All future benefits will be earned under the cash balance formula. Although PacifiCorp is not yet able to quantify the impact, the changes may result in a significant reduction in Pension and other post employment liabilities and Regulatory assets.

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 other postretirement benefits through a combination of funding vehicles. PacifiCorp also contributes to joint trust plans for postretirement benefits offered to certain bargaining units.

Plan assets and obligations are measured three months prior to PacifiCorp’s fiscal year end. Accordingly, plan assets were measured as of September 30 in the current period and as of December 31 in the prior periods.

Net periodic benefit cost for the pension and other postretirement plans included the following components:

	Pension									Other Postretirement

(Millions of dollars)	Nine Months Ended December 31, 2006			Years Ended March 31,						Nine Months Ended December 31, 2006			Years Ended March 31,

				2006			2005						2006			2005

Service cost (a)	$	22.6		$	30.8		$	25.9		$	6.7		$	8.8		$	8.5
Interest cost		56.4			74.4			73.8			24.6			30.4			31.0
Expected return on plan assets (b)		(54.3	)		(76.9	)		(77.7	)		(19.3	)		(26.3	)		(26.4	)
Amortization of unrecognized net transition obligation		2.0			8.4			8.4			9.0			12.2			12.2
Amortization of unrecognized prior service cost		0.8			1.2			1.4			2.1			2.1			0.1
Amortization of unrecognized loss		19.9			21.5			8.5			4.4			2.7			0.6
Cost of termination benefits		1.8			3.0			—			—			—			—
Curtailment loss		0.7			—			—			—			—			—

Net periodic benefit cost	$	49.9		$	62.4		$	40.3		$	27.5		$	29.9		$	26.0

(a)	Service cost excludes $6.4 million of contributions to the joint trust plans for the nine months ended December 31, 2006 and $1.4 million for the year ended March 31, 2006. There were no contributions to the joint trust plans for the year ended March 31, 2005.

(b)

The market-related value of plan assets, among other factors, is used to determine expected return on plan assets. 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 in the first year in which they occur. As differences between expected and actual investment returns are recognized, they are included in the Amortization of prior year loss component of Net periodic benefit cost.

The following table is a reconciliation of the fair value of plan assets as of the end of the period:

	Pension						Other Postretirement

(Millions of dollars)	December 31, 2006			March 31, 2006			December 31, 2006			March 31, 2006

Plan assets at fair value at beginning of period	$	824.9		$	806.5		$	292.1		$	286.6
Employer contributions		79.3			63.8			29.9			22.5
Participant contributions		—			—			6.9			8.3
Actual return on plan assets		55.4			72.6			18.9			20.4
Benefits paid		(75.7	)		(84.1	)		(29.4	)		(41.6	)
Separation of former participants		—			(32.0	)		—			(4.1	)
Transfers		—			(1.9	)		—			—

Plan assets at fair value at end of period	$	883.9		$	824.9		$	318.4		$	292.1

The SERP has no plan assets, and accordingly, the fair value of the plan assets was zero as of December 31, 2006 and March 31, 2006. Although the SERP had no assets, 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. Although the SERP liabilities are included in the table below, because this plan is nonqualified, the assets in the Rabbi trust are not considered plan assets. 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 $38.6 million at December 31, 2006 and $36.4 million at March 31, 2006.

The following table is a reconciliation of the benefit obligation at the end of the period:

	Pension						Other Postretirement

(Millions of dollars)	December 31, 2006			March 31, 2006			December 31, 2006			March 31, 2006

Benefit obligation, beginning of period	$	1,342.2		$	1,338.1		$	582.4		$	528.3
Service cost		22.6			30.8			6.7			8.8
Interest cost		56.4			74.4			24.6			30.4
Participant contributions		—			—			6.9			8.3
Plan amendments		—			2.9			—			22.8
Actuarial (gain) loss		(14.4	)		22.9			(24.9	)		34.3
Benefits paid		(75.7	)		(84.1	)		(29.4	)		(41.6	)
Cost of termination benefits		1.8			3.0			—			—
Separation of former participants		—			(44.3	)		—			(8.9	)
Transfers		—			(1.5	)		—			—

Benefit obligation, end of period	$	1,332.9		$	1,342.2		$	566.3		$	582.4

Accumulated benefit obligation as of the measurement date	$	1,164.9		$	1,170.9		$	—		$	—

The portion of the pension plans’ projected benefit obligation, included in the table above, related to the SERP was $53.5 million at December 31, 2006 and $52.3 million at March 31, 2006. The SERP’s accumulated benefit obligation totaled $53.2 million at December 31, 2006 and $50.5 million at March 31, 2006.

As of December 31, 2006 the funded status of the pension and other postretirement plans was recorded in the Consolidated Balance Sheet as required under the adoption of SFAS No. 158. Balance sheet amounts recorded as of March 31, 2006 did not include the unrecognized net actuarial losses, prior service costs and net transition obligations of $452.9 million for the pension plans and $241.3 million for the other postretirement plans. However, an additional minimum pension liability of $281.6 million was recorded for the pension plans as of March 31, 2006. The combined funded status of the plans and the net liability recognized in the accompanying Consolidated Balance Sheets is as follows:

	Pension						Other Postretirement

(Millions of dollars)	December 31, 2006			March 31, 2006			December 31, 2006			March 31, 2006

Plan assets at fair value, end of period	$	883.9		$	824.9		$	318.4		$	292.1
Less - Benefit obligation, end of period		1,332.9			1,342.2			566.3			582.4

Funded status		(449.0	)		(517.3	)		(247.9	)		(290.3	)
Unrecognized actuarial losses and other		—			452.9			—			241.3
Contribution made after measurement date but before year-end		—			3.7			27.3			29.7

Net liability recognized in the Consolidated Balance Sheets	$	(449.0	)	$	(60.7	)	$	(220.6	)	$	(19.3	)

Net amounts recognized in the Consolidated Balance Sheets consist of:
Regulatory assets	$	—		$	257.7		$	—		$	—
Deferred charges and other assets:
Intangible assets		—			17.3			—			—
Other current liabilities		(4.0	)		—			—			—
Pension and other post employment liabilities		(445.0	)		(342.3	)		(220.6	)		(19.3	)
Accumulated other comprehensive loss, pre-tax		—			6.6			—			—

Net liability recognized in the Consolidated Balance Sheets	$	(449.0	)	$	(60.7	)	$	(220.6	)	$	(19.3	)

Amounts not yet recognized as components of net periodic benefit cost:
Net losses	$	400.1		$	435.6		$	109.2		$	138.1
Prior service cost		8.5			10.0			19.9			22.1
Net transition obligation		5.3			7.3			72.2			81.1

Total	$	413.9		$	452.9		$	201.3		$	241.3


SFAS No. 158 amounts have been recorded as follows based upon expected recovery in rates:
Regulatory assets	$	404.9					$	161.0
Deferred income taxes		—						39.8
Accumulated other comprehensive loss, before tax		9.0						0.5

Total	$	413.9					$	201.3

As of March 31, 2006, the net liability recognized for the pension plans was comprised of accrued pension cost of $60.7 million and an additional minimum pension liability of $281.6 million, which resulted in a total accrued benefit liability of $342.3 million for the pension plans. The table above reconciles the total accrued benefit liability to the accrued pension cost as of March 31, 2006 by presenting the offsetting effects of the additional minimum pension liability in Regulatory assets, Intangible assets and Accumulated other comprehensive loss.

The net loss, prior service cost and net transition obligation that will be amortized from the above amounts in 2007 into net periodic benefit cost are estimated to be as follows:

(Millions of dollars)	Net Losses		Prior service Cost		Net transition Obligation		Total

Pension benefits	$	27.1	$	1.1	$	2.6	$	30.8
Other postretirement benefits		4.5		2.8		12.0		19.3

Total	$	31.6	$	3.9	$	14.6	$	50.1

Plan Assumptions

Assumptions used to determine benefit obligations and net benefit cost were as follows:

	Pension						Other Postretirement

	Nine Months Ended December 31, 2006						Nine Months Ended December 31, 2006		Years Ended March 31,
			Years Ended March 31,						Years Ended March 31,

			2006		2005				2006		2005

Benefit obligation as of the measurement date:
Discount rate	5.85	%	5.75	%	5.75	%	6.00	%	5.75	%	5.75	%
Rate of compensation increase	4.00		4.00		4.00		N/A		N/A		N/A

Net benefit cost for the period ended:
Discount rate	5.75	%	5.75	%	6.25	%	5.75	%	5.75	%	6.25	%
Expected return on plan assets	8.50		8.75		8.75		8.50		8.75		8.75
Rate of compensation increase	4.00		4.00		4.00		N/A		N/A		N/A

Assumed health care cost trend rates as of the measurement date:

	Nine Months Ended December 31, 2006		Years Ended March 31,
			Years Ended March 31,

			2006		2005

Health care cost trend rate assumed for next year - under 65	10.0	%	10.0	%	7.5	%
Health care cost trend rate assumed for next year - over 65	8.0		10.0		9.5
Rate that the cost trend rate gradually declines to	5.0		5.0		5.0
Year that rate reaches the rate it is assumed to remain at - under 65	2012		2011		2007
Year that rate reaches the rate it is assumed to remain at - over 65	2010		2011		2009

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	Increase (decrease) in Expense

(Millions of dollars)	One Percentage-Point Increase		One Percentage-Point Decrease

Effect on total service and interest cost	$	2.5	$	(1.9	)
Effect on other postretirement benefit obligation		42.0		(34.4	)

Contributions and Benefit Payments

PacifiCorp expects to contribute approximately $88.0 million to the pension plans and $33.7 million to the other postretirement plan for 2007.

PacifiCorp’s expected benefit payments to participants for its pension and other postretirement plans for 2007 through 2011 and for the five years thereafter are summarized below:

(Millions of dollars)	Projected Benefit Payments

			Other Postretirement

Years ending December 31,	Pension		Gross		Medicare Subsidy		Net of Subsidy

2007	$	89.3	$	40.1	$	3.3	$	36.8
2008		90.6		42.0		3.7		38.3
2009		94.1		43.8		4.1		39.7
2010		98.5		45.4		4.4		41.0
2011		103.3		47.3		4.7		42.6
2012 to 2016 (inclusive)		568.9		261.7		30.3		231.4

Investment Policy and Asset Allocation

Retirement Plan and other postretirement plan assets are managed and invested in accordance with all applicable requirements, including the Employee Retirement Income Security Act and the Internal Revenue Code. PacifiCorp employs an investment approach that primarily uses a mix of equities and fixed-income investments to maximize the long-term return of plan assets at a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of primarily equity, fixed-income and other alternative investments as shown in the table below. Equity investments are diversified across United States and non-United States stocks, as well as growth and value companies, and small and large market capitalizations. Fixed-income investments are diversified across United States and non-United States bonds. Other assets, such as private equity investments, are used to enhance long-term returns while improving portfolio diversification. PacifiCorp primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.

The assets for other postretirement benefits are composed of three different trust accounts. The 401(h) account is invested in the same manner as the pension account. Each of the two Voluntary Employees’ Beneficiaries Association Trusts has its own investment allocation strategies.

PacifiCorp’s asset allocation was as follows:

	Pension & Other Postretirement						Voluntary Employees’ Beneficiaries Association Trust

	December 31, 2006		March 31, 2006		Target		December 31, 2006		March 31, 2006		Target

Equity securities	58.0	%	58.5	%	53.0 — 57.0	%	65.3	%	66.0	%	53.0 — 65.0	%
Debt securities	34.6		34.5		35.0		34.7		34.0		35.0
Other	7.4		7.0		8.0 — 12.0		N/A		N/A		0.0 — 12.0

Defined Contribution Plan

PacifiCorp’s employee savings plan qualifies as a tax-deferred arrangement under the Internal Revenue Code. Participating employees may defer up to 50.0% of their compensation, subject to certain statutory limitations, and can select a variety of investment options. PacifiCorp matches 50.0% of employee contributions on amounts deferred up to 6.0% of total compensation, with the company match vesting over the initial five years of an employee’s qualifying service. Thereafter, PacifiCorp’s contributions vest immediately. PacifiCorp may also make an additional contribution equal to a percentage of the employee’s eligible earnings, which are immediately vested. PacifiCorp’s contributions to the Savings Plan were $16.4 million for the nine months ended December 31, 2006; $22.5 million for the year ended March 31, 2006; and $20.2 million for the year ended March 31, 2005.

In December 2006, PacifiCorp communicated to its non-bargaining employees that effective June 1, 2007, PacifiCorp will match 65.0% of employee contributions on amounts deferred up to 6.0% of total compensation.

Severance

PacifiCorp has undertaken a review of its organization and workforce. As a result of the review, PacifiCorp incurred severance expense of $30.6 million during the nine months ended December 31, 2006 compared to $17.0 million during the year ended March 31, 2006.

Note 19 - Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. In addition, the carrying amount of variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates.

The fair value of PacifiCorp’s fixed-rate long-term debt, current maturities of long-term debt and redeemable preferred stock has been estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to borrowers with similar credit ratings and for the same maturities.

The following table presents the carrying amount and estimated fair value of the named financial instruments:

	December 31, 2006				March 31, 2006

(Millions of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt (a)	$	4,043.1	$	4,243.3	$	3,902.1	$	4,091.4
Preferred stock subject to mandatory redemption		37.5		37.9		45.0		46.3

(a)	Includes long-term debt classified as currently maturing, less capital lease obligations.

Note 20 – Related-Party Transactions

Transactions while owned by MEHC

As discussed in Note 1, PacifiCorp was acquired by a subsidiary of MEHC on March 21, 2006. The following describes PacifiCorp’s transactions and balances with unconsolidated related parties while owned by MEHC.

As a result of a settlement agreement between MEHC, the Utah Committee of Consumer Services and Utah Industrial Energy Consumers, MEHC contributed to PacifiCorp, at no cost, MEHC’s indirect 100.0% ownership interest in Intermountain Geothermal Company, which controlled 69.3% of the steam rights associated with the geothermal field serving PacifiCorp’s Blundell Geothermal Plant in Utah. Intermountain Geothermal Company therefore became a wholly owned subsidiary of PacifiCorp in March 2006, subsequent to the sale of PacifiCorp to MEHC. During the nine months ended December 31, 2006, PacifiCorp acquired an additional 25.2% of the steam rights associated with the geothermal field.

In the ordinary course of business, PacifiCorp engages in various transactions with several of its affiliated companies. Services provided by PacifiCorp and charged to affiliates related primarily to the administrative services, financial statement preparation and direct-assigned employees. These receivables were $0.6 million at December 31, 2006 and zero at March 31, 2006. Services provided by affiliates and charged to PacifiCorp related primarily to the transport of natural gas and administrative services provided under the intercompany administrative services agreement among MEHC and its affiliates. These payables were $0.7 million at December 31, 2006 and zero at March 31, 2006. These expenses totaled $7.6 million for the nine months ended December 31, 2006 and zero for March 21, 2006 through March 31, 2006.

Effective March 21, 2006, PacifiCorp began participating in a captive insurance program provided by MEHC Insurance Services Ltd. (“MISL”), a wholly owned subsidiary of MEHC. MISL covers all or 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 are established 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 are capped through December 31, 2010. Certain costs associated with the program are prepaid and amortized over the policy coverage period expiring March 20, 2007. Prepayments to MISL were $1.6 million at December 31, 2006 and $7.2 million at March 31, 2006. Receivables for claims were $8.2 million at December 31, 2006 and zero at March 31, 2006. Premium expenses were $5.5 million for the nine months ended December 31, 2006 and $0.2 million for March 21, 2006 through March 31, 2006.

As of December 31, 2006, Amounts due from affiliates – MEHC included $43.8 million of income taxes receivable. As of March 31, 2006, Amounts due to affiliates – MEHC included $3.8 million of income taxes payable.

Transactions while owned by ScottishPower

Under ScottishPower ownership, PacifiCorp engaged in various transactions with several of its former affiliated companies pursuant to ScottishPower’s affiliated interest cross-charge policy. Revenues from these former affiliates related primarily to wheeling services and totaled $7.8 million for the year ended March 31, 2006 and $5.9 million for the year ended March 31, 2005. Services provided by PacifiCorp and recharged to these former affiliates related primarily to administrative services, costs associated with retention agreements and severance benefits reimbursed by ScottishPower, and payroll costs and related benefits of PacifiCorp employees working on international assignment in the United Kingdom. These charges totaled $13.5 million for the year ended March 31, 2006 and $12.4 million for the year ended March 31, 2005. Services provided by former affiliates and recharged to PacifiCorp related primarily to lease payments, captive insurance, administrative services and payroll costs and related benefits of ScottishPower employees working on international assignment in the United States. These expenses totaled $44.9 million for the year ended March 31, 2006 and $35.7 million for the year ended March 31, 2005.

Note 21 - Jointly Owned Utility Plants

Under joint plant ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation and transmission plants. PacifiCorp accounts for its proportional share of each plant.

Each participant has provided financing for its share of each unit. Operating costs of each plant are assigned to joint owners based on ownership percentage or energy taken, depending on the nature of the cost. Operating expenses on the accompanying Consolidated Statements of Income include PacifiCorp’s share of the expenses of these units.

As of December 31, 2006, PacifiCorp’s share in jointly owned plants was as follows:

(Millions of dollars)	PacifiCorp Share		Plant in Service		Accumulated Depreciation/ Amortization		Construction Work-in- Progress

Jim Bridger Nos. 1 - 4 (a)	66.7	%	$	941.8	$	459.9	$	10.0
Wyodak	80.0			337.2		167.5		0.9
Hunter No. 1	93.8			305.3		141.9		0.9
Colstrip Nos. 3 and 4 (a)	10.0			241.2		114.3		1.1
Hunter No. 2	60.3			193.8		84.6		0.2
Hermiston (b)	50.0			168.3		36.3		0.8
Craig Nos. 1 and 2	19.3			166.2		73.0		0.2
Hayden No. 1	24.5			42.6		18.6		0.2
Foote Creek	78.8			36.3		11.5		0.1
Hayden No. 2	12.6			26.6		12.8		0.2
Other transmission and distribution plants	Various			79.2		18.1		0.4

Total			$	2,538.5	$	1,138.5	$	15.0

(a)	Includes transmission lines and substations.

(b)	Additionally, PacifiCorp has contracted to purchase the remaining 50.0% of the output of the Hermiston Plant. See Note 17.

Under the joint ownership agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. PacifiCorp’s portion is recorded in its applicable construction work-in-progress, operations, maintenance and tax accounts, which is consistent with wholly owned plants.

Note 22 – Supplemental Cash Flow Information

A summary of supplemental cash flow information is presented in the following table:

(Millions of dollars)	Nine Months Ended December 31, 2006		Years Ended March 31,



			2006		2005

Cash paid during the year for:
Income taxes	$	121.2	$	140.0	$	92.0
Interest expense, net of amounts capitalized		191.7		240.3		220.4

Note 23 – Unaudited Quarterly Operating Results

	Three Months Ended

(Millions of dollars)	June 30, 2006		September 30, 2006		December 31, 2006

Revenues	$	859.9	$	1,097.4	$	966.8
Income from operations		122.4		132.5		160.3
Net income		42.6		59.4		58.9
Earnings on common stock		42.1		58.9		58.3

	Three Months Ended

	June 30, 2005		September 30, 2005		December 31, 2005		March 31, 2006

Revenues	$	881.4	$	620.7	$	1,165.0	$	1,229.6
Income from operations		135.9		129.2		256.2		270.7
Net income		46.4		39.4		127.8		147.1
Earnings on common stock		45.9		38.9		127.2		146.6

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

No information is required to be reported pursuant to this item.

ITEM 9A. CONTROLS AND PROCEDURES

At the end of the period covered by this Annual Report on Form 10-K, PacifiCorp carried out an evaluation, under the supervision and with the participation of PacifiCorp’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of PacifiCorp’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that PacifiCorp’s disclosure controls and procedures are effective in timely alerting them to material information relating to PacifiCorp required to be included in PacifiCorp’s periodic SEC filings.

On March 21, 2006, MEHC completed its purchase of PacifiCorp, at which time PacifiCorp became a subsidiary of MEHC. Although PacifiCorp has maintained its disclosure controls and procedures that were in effect prior to the acquisition, subsequent to the acquisition there have been material changes in PacifiCorp’s internal control over financial reporting. The material changes are due to the effect of the acquisition on PacifiCorp’s control environment, which includes changes in the composition of PacifiCorp’s board of directors, senior management and organizational structure, including a reorganization of the corporate finance department. PacifiCorp believes these changes have not negatively affected its internal control over financial reporting.

There has been no other change in PacifiCorp’s internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

No information is required to be reported pursuant to this item.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor any arrangements or understanding between any officer and any other person pursuant to which the officer was appointed.

Set forth below is certain information, as of February 28, 2007 with respect to each of the foregoing officers and directors.

GREGORY E. ABEL , 44, Chief Executive Officer and Chairman. Mr. Abel was elected Chief Executive Officer and Chairman of the Board of Directors in March 2006. Mr. Abel is also the President and Chief Operating Officer and a director of MEHC. Mr. Abel joined MEHC in 1992.

DOUGLAS L. ANDERSON , 48, Director. Mr. Anderson has been a director since March 2006. He is the Senior Vice President, General Counsel and Corporate Secretary of MEHC. Mr. Anderson joined MEHC in February 1993 and has served in various legal positions, including General Counsel of MEHC’s independent power affiliates. Prior to that, Mr. Anderson was a corporate attorney in private practice.

WILLIAM J. FEHRMAN , 46, President, PacifiCorp Energy and director. Mr. Fehrman was elected President of PacifiCorp Energy and a Director in March 2006. Previously, he joined MEHC in March 2006 to oversee integration activities of MEHC’s acquisition of PacifiCorp. Prior to joining MEHC, Mr. Fehrman was President and Chief Executive Officer of Nebraska Public Power District in Columbus, Nebraska. He joined Nebraska Public Power in 1981, serving as its President and Chief Executive Officer since January 2003 and before that as Vice President of Energy Supply.

BRENT E. GALE , 55, Director. Mr. Gale has been a director since March 2006. He was appointed Senior Vice President of Regulation and Legislation of MEHC in March 2006. Previously Mr. Gale had been Senior Vice President of MidAmerican Energy Company, a MEHC subsidiary, since July 2004. He has served in various legal, regulatory and strategic positions with MidAmerican Energy Company and its predecessors for more than five years prior to that.

PATRICK J. GOODMAN , 40, Director. Mr. Goodman has been a director since March 2006. He was appointed Senior Vice President and Chief Financial Officer of MEHC in 1999. Mr. Goodman joined MEHC in 1995.

NOLAN E. KARRAS , 62, Director. Mr. Karras has been a director since February 1993. He is President of The Karras Company, Inc., an investment adviser, and has served in that capacity since 1983. Mr. Karras is Chief Executive Officer of Western Hay Company, Inc., a non-executive director of Beneficial Life Insurance Company and a Registered Principal for Raymond James Financial Services. Mr. Karras also serves as Chief Executive Officer of S.K. Hart Management, LLC, a family office for a family based in Salt Lake City, Utah.

A. ROBERT LASICH , 47, Director. Mr. Lasich joined PacifiCorp as Vice President and General Counsel, PacifiCorp Energy, and was elected director in March 2006. Previously he served as Vice President of MEHC with responsibility for integration and transition matters related to the acquisition of PacifiCorp since July 2005. Prior to that, Mr. Lasich was Vice President of Gas Supply and Trading for MidAmerican Energy Company since August 2004. He joined MidAmerican Energy Company in October 1997 and has also served as a senior attorney in its legal department.

DAVID J. MENDEZ , 39, Senior Vice President and Chief Financial Officer. Mr. Mendez was appointed Senior Vice President and Chief Financial Officer in August 2006. Mr. Mendez joined PacifiCorp in 2002 as External Reporting Director and was named Chief Accounting Officer a year later. Prior to joining PacifiCorp, Mr. Mendez was a Senior Manager at PricewaterhouseCoopers LLP.

MARK C. MOENCH , 51, Director. Mr. Moench was named PacifiCorp General Counsel in February 2007. He joined PacifiCorp as Senior Vice President and General Counsel, Rocky Mountain Power, and was elected director in March 2006. He previously served as Senior Vice President, Law, of MEHC with responsibility for regulatory approvals of the PacifiCorp acquisition since June 2005. Prior to that, Mr. Moench was Vice President and General Counsel of Kern River Gas Transmission Company since 2002, when Kern River was acquired by MEHC from the Williams Companies, Inc., which he joined in 1987. Mr. Moench served the Williams Companies in various senior legal positions, including as General Counsel of Kern River.

PATRICK REITEN , 45, President, Pacific Power, and Director. Mr. Reiten was elected President of Pacific Power and director in September 2006. Previously he served as President and Chief Executive Officer of PNGC Power since 2002. Mr. Reiten joined PNGC Power in 1993 serving as Director of Government Relations, then as Vice President of Marketing and Public Affairs.

A. RICHARD WALJE , 55, President, Rocky Mountain Power, and Director. Mr. Walje was elected President of Rocky Mountain Power in March 2006 and has responsibility for the electric distribution operations of PacifiCorp in Utah, Idaho and Wyoming. He has been a director since July 2001. Mr. Walje previously served as PacifiCorp’s Executive Vice President since April 2004 and as Chief Information Officer since May 2000. He also served as Senior Vice President of Corporate Business Services from May 2001 to April 2004 and as Vice President for Transmission and Distribution Operations and Customer Service from 1998 to 2000. Mr. Walje has been with PacifiCorp since 1986.

STANLEY K. WATTERS , 48, Director. Mr. Watters was elected a director in March 2006 and Senior Vice President in August 2006. Previously he served as President of Pacific Power since March 2006 and as PacifiCorp’s Senior Vice President of Commercial and Trading since June 2003. Mr. Watters served as Vice President of Trading and Origination from July 2001 to June 2003 and as Managing Director of Wholesale Energy Services since 1998. Mr. Watters has been with PacifiCorp since 1982.

Audit Committee and Audit Committee Financial Expert

During the nine months ended December 31, 2006, and as of the date of this Report, PacifiCorp’s Board of Directors had no audit committee.

Because PacifiCorp’s common stock is indirectly, wholly owned by MEHC, its Board of Directors consists primarily of MEHC and PacifiCorp employees and it is not required to have an audit committee. However, the audit committee of MEHC acts as the audit committee for PacifiCorp.

Code of Ethics

PacifiCorp has adopted a code of ethics that applies to its principal executive officers, principal financial officer and to its controller, or persons acting in such capacities. The code of ethics is filed as an exhibit to this annual report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

Compensation Philosophy and Overall Objectives

We and our parent company, MEHC, believe that the compensation paid to our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers, whom we collectively refer to as our named executive officers (“NEO”), should be closely aligned with our performance as well as that of each NEO’s individual performance on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for our organization. Our compensation programs are designed to provide NEOs meaningful incentives for superior performance. Performance is evaluated using both financial and non-financial objectives that we believe contribute to our long-term success. Among these objectives are financial strength, customer service, operational excellence, employee commitment, environmental respect and regulatory integrity.

How is Compensation Determined

Our Compensation Committee consists solely of the Chairman of our Board of Directors, Gregory E. Abel. Mr. Abel also serves as our Chief Executive Officer and as MEHC’s President and Chief Operating Officer. He is employed by MEHC and receives no direct compensation from us; accordingly, references to NEOs in this Item 11 exclude Mr. Abel unless otherwise indicated.

Mr. Abel is responsible for the establishment and oversight of our compensation policy, and for approving merit increases and incentive performance awards.

Due to the unique nature of each NEO’s duties, our criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. We do not specifically use companies in similar industries as benchmarks when initially establishing NEOs’ compensation. We do, however, review peer company data when making annual base salary and incentive recommendations.

Discussion of Specific Compensation Elements

The following describes the components of our executive compensation program and the basis upon which recommendations and determinations were made for the nine months ended December 31, 2006.

Base Salary

We determine base salaries for all of our NEOs by reviewing company and individual performance, the value each NEO brings to us and general labor market conditions. While base salary provides a base level of compensation intended to be competitive with the external market, the base salary for each NEO is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. The base salaries of NEOs are reviewed on an annual basis, and any annual increase is the result of an evaluation of the company and of the individual NEO’s performance for the period. Annual merit increases, which are approved by the Chairman and Chief Executive Officer, take effect on January 1 of each year. For the nine months ended December 31, 2006, merit increases for NEOs were effective April 26, 2006. An increase or decrease in base pay may also result from a promotion or other significant change in an NEO’s responsibilities during the year.

Short-Term Incentive Compensation

The objective of short-term incentive compensation is to reward significant annual corporate goal achievement while also providing NEOs with competitive total cash compensation.

Annual Incentive Plan

Under our Annual Incentive Plan, NEOs (other than Mr. Abel) are eligible for an annual cash incentive award. Our Chairman and Chief Executive Officer establishes a target bonus opportunity, expressed as a percentage of base salary and is intended to reflect fully effective performance, for each NEO prior to the beginning of each year. Awards paid under the plan are based on a variety of measures linked to our overall performance and each NEO’s contributions to that performance. Individual NEO’s performance is measured against defined objectives that commonly include both financial (e.g., net income and cash flow) and non-financial (e.g., customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity) measures, as well as response to issues and opportunities that arise during the year. Incentive award payouts are discretionary, the ultimate amounts are determined on a subjective basis, and they are not based on a specific formula or cap. Annual incentive awards determined by the Chairman and Chief Executive Officer are paid prior to year-end. NEOs who terminated employment prior to the end of the calendar year, were eligible to receive the annual incentive award.

Performance Awards

In addition to the annual awards under the Annual Incentive Plan, we may grant cash performance awards periodically during the year to one or more NEOs to reward the accomplishment of significant non-recurring tasks or projects. For the nine months ended December 31, 2006, no awards were granted. These awards are discretionary and approved by the Chairman and Chief Executive Officer.

Long-Term Incentive Compensation

The objective of long-term incentive compensation is to retain employees, reward exceptional performance and motivate NEOs to create long-term, sustainable value. Our current long-term incentive compensation programs are all cash-based. Under MEHC ownership, we do not utilize equity-based compensation, such as stock option awards or equity incentive plan awards granted by ScottishPower in prior years. All previously awarded stock options exercisable for ScottishPower stock are fully vested. Time-based vesting of ScottishPower equity incentive plan awards ceased upon our acquisition by MEHC. The ultimate payout of these awards is subject to the satisfaction of ScottishPower performance conditions through 2008, and is the responsibility of ScottishPower.

MEHC Long-Term Incentive Partnership Plan

The MEHC Long-Term Incentive Partnership Plan is designed to retain key employees and to align our interests and the interests of the NEOs. The NEOs participating in our Long-Term Incentive Partnership Plan are Messrs. Fehrman, Mendez and Walje. The MEHC Long-Term Incentive Partnership Plan provides for annual awards based upon significant accomplishments by the individual participants and the achievement of net income, safety, risk management, environmental and other company goals. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated in January of each plan year. Participation is discretionary and is determined by the Chairman and Chief Executive Officer, who does not participate. Except for limited situations of extraordinary performance, awards are capped at 1.5 times base salary, and the value is finalized in January of the following year. These cash-based awards are subject to mandatory deferral and ratable vesting over a five-year period starting in the performance year. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation election. The participant may defer all or a part of the award or receive payment in cash. Vested balances (including any investment profits or losses thereon) of terminating participants are paid at the time of termination.

Other Employee Benefit Plans

NEOs are eligible to participate in the health and welfare, 401(k) and retirement benefit plans that are offered to our other employees. Additionally, if eligible, the NEO may be a participant in the following plans:

Supplemental Executive Retirement Plan

The SERP is a closed plan that provides additional retirement benefits to only legacy participants, as previously approved by our Board of Directors. The NEOs who participated in our SERP during the nine months ended December 31, 2006 were Messrs. Haller, Peach and Walje. The SERP provides annual retirement benefits of up to 65.0% of a participant’s total cash compensation in effect immediately prior to retirement, subject to an annual $1.0 million maximum retirement benefit. Total cash compensation means the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus the average of the participant’s last three years awards under an annual incentive bonus program and special, additional or non-recurring bonus awards, if any, that are required to be included in total cash compensation pursuant to a participant’s employment agreement or approved for inclusion by our Board of Directors. All participating NEOs have met the five-year service requirement under the plan. The SERP benefit will be reduced by the amount of the participant’s regular retirement benefit under our Retirement Plan and ratably for retirement between ages 55 and 65.

Compensation Reduction Plan

Our Compensation Reduction Plan as in effect through December 31, 2006 provided a means for all NEOs to make voluntary deferrals of up to 100.0% of base salary and 100.0% of short- and long-term incentive compensation awards. The deferrals and any investment returns grow on a tax-deferred basis. The plan offered a single fixed income investment option and allowed participants to choose from five forms of distribution.

Effective January 1, 2007, the Compensation Reduction Plan was restated as our Executive Voluntary Deferred Compensation Plan. As restated, the plan allows for voluntary deferrals of up to 50.0% of base salary and 100.0% of short- and long-term incentive compensation awards. Amounts deferred under the Executive Voluntary Deferred Compensation Plan receive a rate of return based on eight notional investment options elected by the participant and the plan allows participants to choose from three forms of distribution. While the plan allows for company discretionary contributions, we have not made contributions to date. We include the Executive Voluntary Deferred Compensation Plan as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.

Executive Life Insurance

This benefit provides all NEOs with basic life insurance having a death benefit of one times annual base salary during employment. The value of the benefit in excess of $50,000 is included in the NEOs taxable income. We include the executive life insurance as part of the participating named executive’s overall compensation in order to provide a comprehensive, competitive package.

Impact of Accounting and Tax

Compensation paid under our executive compensation plans has been reported as an expense in our historical financial statements. Recent changes in rules issued by the FASB, principally SFAS No. 123(R), Share Based Payments , which took effect for most public companies for fiscal years beginning after June 15, 2005, have had no impact on how we design or account for our executive compensation plans.

Potential Payments Upon Termination or Change-in-Control

Retention Agreements

In May 2005, we entered into retention agreements with our former Senior Vice President and Chief Financial Officer, Richard D. Peach, and our current Senior Vice President and Chief Financial Officer, David J. Mendez. The agreements entitled Messrs. Peach and Mendez to retention bonuses (up to $160,000 for Mr. Peach and $100,000 for Mr. Mendez), payable in two installments, for remaining employed at an acceptable level of performance in our corporate finance department through May 30, 2007 and developing succession and risk mitigation plans for the department (Mr. Peach only) and their positions. The first payment of $80,000 to Mr. Peach was made on June 1, 2006. Mr. Peach forfeited his second payment of $80,000 due to his resignation on November 22, 2006. The first payment of $50,000 to Mr. Mendez was made on June 1, 2006 and the second payment of $50,000 is due on June 1, 2007.

In August 2005, our NEOs (other than Messrs. Abel and Fehrman) entered into agreements with ScottishPower for awards under the Transaction Incentive Program, which was a $6.0 million pool created by ScottishPower for retention incentives during the period of completion of ScottishPower’s sale of us to MEHC. The agreement signed by each NEO provided for a transaction incentive award in an amount equal to the executive officer’s base salary (in the case of Messrs. Peach and Mendez, the amounts were adjusted for their existing retention agreements). Mr. Peach’s retention was payable as follows:

•	25.0% of the award was paid within one month of execution and delivery of the award agreement;

•	50.0% of the award was paid within three months after the closing of our sale to MEHC, provided there were no claims by MEHC against ScottishPower; and

•	25.0% of the award is payable 12 months after the closing, again as long as there are no claims by MEHC against ScottishPower.

Mr. Mendez received a one-time payment of $25,000 at the closing of our sale to MEHC.

Continued employment by us, observance of confidentiality obligations and satisfactory performance in support of the transaction until the sale’s completion were conditions to the executive officer’s receipt of these payments. Award payments were the obligation of ScottishPower. Ultimate determination of award eligibility was made by ScottishPower’s Chief Executive Officer, subject to review by its Remuneration Committee.

On May 24, 2006, we entered into certain retention agreements with each of Messrs. Haller and Peach. Under each retention agreement, provided that the executive had not voluntarily resigned or had his employment with us terminated for cause prior to December 31, 2006 for Mr. Haller and November 22, 2006 for Mr. Peach, the executive (i) would be entitled to the same benefits the executive would have been entitled to under our SERP had the executive terminated his employment during the two-month window period following the first anniversary of a change in control, and (ii) would be entitled, upon any termination on or following the applicable retention date, to the same benefits the executive would have been entitled to under our Executive Severance Plan had such termination occurred in connection with a material alteration in position or compensation within the 24-month period following a change in control.

Severance Arrangements

Our Executive Severance Plan is a closed plan that provides severance benefits to only legacy participants previously designated by our Compensation Committee under ScottishPower ownership. Other than Messrs. Haller and Peach, who both became entitled to benefits under this plan due to their resignations, Mr. Walje is our only NEO participating in this plan.

Severance benefits are payable by us for voluntary terminations as a result of certain material alterations in position or compensation that have a detrimental impact on the executive’s employment or involuntary terminations (including a resignation initiated by us) for reasons other than cause. Severance payments generally equal one or two times the executive’s annual cash compensation, three months of health insurance benefits and outplacement services.

The Executive Severance Plan also provides enhanced severance benefits in the event of certain terminations during the 24-month period following a qualifying change-in-control transaction; with respect to MEHC’s acquisition of us, this qualifying period commenced on May 23, 2005. Participants are eligible for change-in-control benefits resulting from either a termination without cause initiated by us or a resignation generally within two months after certain material alterations in position or compensation. Under these provisions, Mr. Walje may be eligible for, and Messrs. Haller and Peach received, severance pay in an amount equal to two times annual cash compensation. In the event that benefits are paid, we are required to make an additional payment to compensate the executive for the effect of any excise tax. Participants are also entitled to continuation of subsidized health insurance from six to 24 months, depending on length of service, vehicle allowance and outplacement services. The plan will be terminated effective May 23, 2007, when the qualifying period related to the MEHC acquisition expires.

Potential post-termination payments to NEOs are also discussed in the “Post-Termination and Change-in-Control Payments” section of this Item.

COMPENSATION COMMITTEE REPORT

Mr. Abel, our Chairman and Chief Executive Officer, has reviewed and discussed the Compensation Discussion and Analysis with management and has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Form 10-K.

EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth information regarding compensation earned by each of our NEOs during the nine months ended December 31, 2006 (the transition period):

Name and Principal Position	Year	Base Salary (d)		Bonus (e)		Change in Pension Value and Non-Qualified Deferred Compensation Earnings (f)		All Other Compensation (g)		Total (h)

Gregory E. Abel (a) Chairman and Chief Executive Officer	Transition	$	—	$	—	$	—	$	—	$	—
William J. Fehrman President, PacifiCorp Energy	Transition		201,042		522,147		—		51,912		775,101
Andrew P. Haller (b) Senior Vice President, General Counsel and Corporate Secretary	Transition		261,377		260,980		147,696		2,494,648		3,164,701
David J. Mendez Senior Vice President and Chief Financial Officer	Transition		147,635		158,488		6,903		86,707		399,733
Richard D. Peach (c) Former Senior Vice President and Chief Financial Officer	Transition		269,917		265,332		8,130		1,736,424		2,279,803
A. Richard Walje President, Rocky Mountain Power	Transition		248,108		377,106		168,501		177,982		971,697

(a)

Mr. Abel receives no direct compensation from us. We reimburse MEHC for the cost of Mr. Abel’s time spent on PacifiCorp matters, 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, 2006 (File No. 001-14881) for executive compensation information for Mr. Abel.

(b)	Mr. Haller resigned as a director and executive officer effective December 31, 2006 and resigned employment January 2, 2007.

(c)	Mr. Peach resigned November 22, 2006.

(d)	Salary includes amounts deferred pursuant to the Compensation Reduction Plan of $6,750 for Mr. Walje.

(e)	Consists of the following:

(i)

Awards earned pursuant to the Annual Incentive Plan in the amounts of $250,000 to Mr. Fehrman; $260,980 to Mr. Haller; $136,627 to Mr. Mendez; $265,332 to Mr. Peach; and $308,789 to Mr. Walje.

(ii)

The vested portion of awards earned and changes in fair value of previously earned awards pursuant to the MEHC Long-Term Incentive Partnership Plan in the amounts of $232,857 ($20,039 in investment profits) to Mr. Fehrman; $21,861 to Mr. Mendez; and $68,317 to Mr. Walje.

MEHC Long-Term Incentive Partnership Plan awards vest equally over five years with any unvested balances forfeited upon termination of employment. Vested balances (including any investment performance profits or losses thereon) are paid to the participant at the time of termination. The participant may elect to defer or receive payment of part of or the entire award. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation election. Because the amounts to be paid out may increase or decrease depending on investment performance, the ultimate payouts are undeterminable.

The initial values of the 2006 MEHC Long-Term Incentive Partnership Plan awards granted to Messrs. Fehrman, Mendez and Walje were based upon the following matrix and a MEHC net income target goal, which we do not disclose herein:

	MEHC Net Income		Award

	Less than or equal to target goal		None *
	Exceeds target goal by 0.01% - 3.25%		15% of excess
	Exceeds target goal by 3.251% - 6.50%		15% of the first 3.25% excess;
			25% of excess over 3.25%
	Exceeds target goal by more than 6.50%		15% of the first 3.25% excess;
			25% of the next 3.25% excess;
			35% of excess over 6.50%

	*	The MEHC Long-Term Incentive Partnership Plan provides annual awards based upon significant accomplishments by the individual participant and the achievement of net income, safety, risk management, environmental and other corporate goals.
	(iii)	Relocation bonus to Mr. Fehrman in the amount of $39,290.

(iv)

Includes amounts deferred pursuant to the Compensation Reduction Plan of $143,789 for Mr. Walje.

(f)

Amounts are based upon the aggregate increase in the actuarial present value of all qualified and non-qualified defined benefit plans, which include the SERP and the Retirement Plan, as applicable. Amounts are computed using the SFAS No. 87 assumptions used in preparing the applicable pension disclosures included in our Notes to the Consolidated Financial Statements and are as of the pension plans’ measurement dates. No participant in our Deferred Compensation Plan earned “above market or preferential” earnings on amounts deferred.

(g)	In addition to the amounts listed below, also includes amounts related to international assignment premiums, life insurance premiums, and medical and disability insurance premiums that we paid on behalf of the NEOs.

(i)

Severance benefits, including enhancements related to our change in control, paid during the year ended, or payable or accrued as of, December 31, 2006, were as follows:

(a)

Salary in the amounts of $697,006 to Mr. Haller and $820,000 to Mr. Peach.

(b)

Annual incentive in the amounts of $236,982 to Mr. Haller and $246,000 to Mr. Peach.

(c)

Accrued change-in-control SERP enhancements related to our change in control in the amounts of $709,000 to Mr. Haller and $333,000 to Mr. Peach.

(d)

Excise tax gross-up payments to be made by us to the Internal Revenue Service on behalf of Mr. Haller of $586,262.

(e)

Payout of accrued personal time in the amounts of $32,992 to Mr. Haller and $44,921 to Mr. Peach.

(f)

Benefits continuation in the amounts of $7,200 to Mr. Haller and $27,060 to Mr. Peach.

(g)

Vehicle allowance in the amounts of $18,000 each to Messrs. Haller and Peach.

(h)

Outplacement services in the amounts of $13,000 each to Messrs. Haller and Peach.

(ii)

Retention payments in connection with the sale of us to MEHC and paid by ScottishPower in the amounts of $174,252 to Mr. Haller; $25,000 to Mr. Mendez; $125,000 to Mr. Peach; and $165,406 to Mr. Walje.

(iii)

Retention payments in the amounts of $50,000 to Mr. Mendez and $80,000 to Mr. Peach.

(iv)

Relocation expense of $50,407 to Mr. Fehrman.

(v)

International assignment benefits of $11,376 to Mr. Peach.

(vi)

Vehicle allowance in the amount of $6,750 to Mr. Haller and $5,925 to Mr. Peach.

(vii)

Company contributions to our Employee Savings and Stock Ownership Plan of $11,000 each to Messrs. Haller, Mendez and Walje, and $13,833 to Mr. Peach.

(h)

Under MEHC ownership, we do not utilize equity-based compensation, such as stock or stock option awards, or non-equity incentive plans as part of our long-term incentive compensation package. Therefore, we have omitted the Stock Awards, Option Awards and Non-Equity Incentive Plan Compensation columns from the Summary Compensation Table.

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Outstanding Equity Awards at Fiscal Year-End

The following table sets forth information regarding outstanding equity awards held by each of our NEOs as of December 31, 2006. All option awards are for ScottishPower American Depository Shares and include options granted under the PacifiCorp Stock Incentive Plan, expiring March 21, 2007, and the ScottishPower Executive Share Option Plan, expiring November 27, 2007. All stock awards are for ScottishPower American Depository Shares and were granted under the ScottishPower Long-Term Incentive Plan.

	Option Awards (d)						Stock Awards(d)

Name	Number of Securities Underlying Unexercised Options	Number of Securities Underlying Unexercised Options	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price		Option Expiration Date	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested(e)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested(e)



	Exercisable	Unexercisable

Gregory E. Abel (a)	—	—	—	$	—	—	—	$	—
William J. Fehrman	—	—	—		—	—	—		—
Andrew P. Haller (b)	—	—	—		—	—	5,484		320,430
	—	—	—		—	—	2,872		168,160
	—	—	—		—	—	1,033		60,223
David J. Mendez	—	—	—		—	—	—		—
Richard D. Peach (c)	—	—	—		—	—	6,586		384,820
	—	—	—		—	—	4,150		242,461
	—	—	—		—	—	1,562		91,020
A. Richard Walje	13,050	—	—		41.38	March 21, 2007	7,195		420,404
	13,340	—	—		32.76	March 21, 2007	4,097		239,414
	5,329	—	—		31.75	March 21, 2007	1,471		85,754
	6,613	—	—		28.72	November 21, 2007	—		—

(a)	Mr. Abel receives no direct compensation from us. Please refer to MEHC’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-14881) for executive compensation information for Mr. Abel.

(b)	Mr. Haller resigned as director and executive officer effective December 31, 2006 and resigned employment January 2, 2007.

(c)	Mr. Peach resigned November 22, 2006.

(d)	Under MEHC ownership, we do not utilize equity-based compensation, such as stock or stock option awards, as part of our long-term incentive compensation package. All outstanding stock options relate to previously granted options held by Messrs. Haller, Peach and Walje.
(e)	The number of vested shares and market value have been prorated to reflect only the portion of the three-year performance period in which PacifiCorp was owned by ScottishPower.

Option Exercises

The following table sets forth information regarding option exercises and stock vested by each of our NEOs during the nine months ended December 31, 2006. All option awards are for ScottishPower American Depository Shares and include options granted under the PacifiCorp Stock Incentive Plan and the ScottishPower Executive Share Option Plan.

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	Option Awards (d)			Stock Awards

Name	Number of Shares Acquired On Exercise	Value Realized on Exercise		Number of Shares Acquired On Exercise	Value Realized on Vesting

Gregory E. Abel (a)	—	$	—	—	$	—
William J. Fehrman	—		—	—		—
Andrew P. Haller (b)	12,288		150,806	—		—
David J. Mendez	—		—	—		—
Richard D. Peach (c)	—		—	—		—
A. Richard Walje	113,027		1,927,131	—		—

(a)	Mr. Abel receives no direct compensation from us. Please refer to MEHC’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-14881) for executive compensation information for Mr. Abel.

(b)	Mr. Haller resigned as director and executive officer effective December 31, 2006 and resigned employment effective January 2, 2007.

(c)	Mr. Peach resigned November 22, 2006.

(d)	Under MEHC ownership, we do not utilize equity-based compensation, such as stock or stock option awards, as part of our long-term incentive compensation package. All stock options relate to previously granted options held by Messrs. Haller, Peach and Walje.

Pension Benefits

We have adopted non-contributory defined benefit retirement plans for our employees, other than employees subject to collective bargaining agreements that do not provide for coverage. Messrs. Haller, Peach and Walje also participate in our non-qualified SERP. The following description assumes participation in both our Retirement Plan and our SERP. Participants receive benefits at retirement payable for life based on length of service with us and average pay in the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose would include salary and annual incentive plan payments reflected in the Summary Compensation Table above. Benefits are based on 50.0% of final average pay plus 1.0% of final average pay for each fiscal year that we meet certain performance goals set for each fiscal year by our Compensation Committee. The maximum benefit is 65.0% of final average pay. Participants may also elect actuarially equivalent alternative forms of benefits. Retirement benefits are adjusted to reflect social security benefits as well as certain prior employer retirement benefits. Participants are entitled to receive full benefits upon retirement after age 60 with at least 15 years of service. Participants are also entitled to receive reduced benefits upon early retirement after age 55 or after age 50 with at least 15 years of service and five years of participation in the SERP. The early retirement reduction is 0.25% for each month benefit commencement precedes age 60.

The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of our NEO as of September 30, 2006:

Name	Plan Name	Number of Years Credited Service (e)	Present Value of Accumulated Benefits (f)		Payments During Last Fiscal Year

Gregory E. Abel (a)		—	$	—	$	—
William J. Fehrman (b)	Retirement	—		—		—
Andrew P. Haller (c)	Retirement	5.75		125,336		—
	SERP	5.75		698,245		—
David J. Mendez	Retirement	3.92		29,125		—
Richard D. Peach (d)	Retirement	1.42		15,259		—
	SERP	11.42		—		—
A. Richard Walje	Retirement	20.58		597,035		—
	SERP	20.58		1,216,381		—

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(a)	Mr. Abel receives no direct compensation from us. Please refer to MEHC’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-14881) for executive compensation information for Mr. Abel.

(b)	Mr. Fehrman joined us in March 2006 and will not be eligible to participate in our pension plan until March 2007.

(c)	Mr. Haller resigned as director and executive officer effective December 31, 2006 and resigned employment January 2, 2007.

(d)	Mr. Peach resigned November 22, 2006.

(e)	Participants become vested in the plans after five years of credited service. Mr. Peach is fully vested in our pension plan due to his ScottishPower service, but is receiving only the change-in-control benefits under our SERP.

(f)

Amounts are computed using the SFAS No. 87 assumptions used in preparing the applicable pension disclosures included in the Notes to the Consolidated Financial Statements and are as of September 30, 2006, the plans’ measurement date. Single life annuities were assumed for the SERP calculations of the present value of accumulated benefits. For our Retirement Plan calculations of the present value of accumulated benefits, the following assumptions were used: 50.0% lump sum and 50.0% single life annuity. The present value assumptions used in calculating the present value of accumulated benefits for the SERP were as follows: a discount rate of 5.85%; an expected retirement age of 60; and postretirement mortality using the RP-2000 tables. The present value assumptions used in calculating the present value of accumulated benefits for our Retirement Plan were as follows: a discount rate of 5.85%; an expected retirement age of 65; postretirement mortality using the RP-2000 tables; a lump sum interest rate of 4.85%; and lump sum mortality using the 1994 GAR tables.

Non-Qualified Deferred Compensation

The following table sets forth certain information regarding our Compensation Reduction Plan accounts held by each of our NEO as of December 31, 2006:

Name	Executive Contributions in Last Fiscal Year (d)		Registrant Contributions in Last Fiscal Year		Aggregate Earnings in Last Fiscal Year		Aggregate Withdraws/ Distributions		Aggregate Balance at Last Fiscal Year-End

Gregory E. Abel (a)	$	—	$	—	$	—	$	—	$	—
William J. Fehrman		—		—		—		—		—
Andrew P. Haller (b)		—		—		35,807		—		411,542
David J. Mendez		—		—		—		—		—
Richard D. Peach (c)		—		—		—		—		—
A. Richard Walje		150,539		—		101,057		—		1,449,201

(a)	Mr. Abel receives no direct compensation from us. Please refer to MEHC’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-14881) for executive compensation information for Mr. Abel.

(b)	Mr. Haller resigned as director and executive officer effective December 31, 2006 and resigned employment January 2, 2007.

(c)	Mr. Peach resigned November 22, 2006.

(d)	The contribution amounts shown are included within the total compensation reported for these individuals in the Summary Compensation Table and are not additional earned compensation.

Potential Payments Upon Termination or Change-in-Control

As described above in “Severance Arrangements” and detailed in the Summary Compensation Table, as of December 31, 2006, Messrs. Haller and Peach both became entitled to benefits under our Executive Severance Plan due to their resignations. Mr. Walje also currently participates in the Executive Severance Plan. In addition, Messrs. Haller and Peach will receive, and Mr. Walje is eligible to receive, enhanced benefits under our SERP in the case of (i) an involuntary termination of employment within 24 months of a qualifying change in control or (ii) a voluntary termination at least 12 months, and no more than 14 months, after a qualifying change in control. An involuntary termination includes a resignation following a material alteration in the participant’s employment position. The enhancements consist primarily of receiving credit for three additional benefit years and a 3.0% increase in final average pay under the SERP.

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In addition to the enhanced benefits provided to Messrs. Haller and Peach, and potentially payable to Mr. Walje, under the Executive Severance Plan and SERP, the MEHC Long-Term Incentive Partnership Plan provides for full vesting of awards upon death or disability. Other than these arrangements, our NEOs (excluding Mr. Abel) are not entitled to enhanced benefits upon termination of employment. Please refer to MEHC’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-14881) for information about potential post-termination and change-in-control payments to Mr. Abel.

The table below shows the enhanced benefits that Mr. Walje would have received as of December 31, 2006 upon involuntary termination or resignation following material alteration in position within 24 months of a change in control.

Cash Severance		Incentive		SERP (a)		Benefits Continuation (b)		Excise Tax Gross-up

$	661,622	$	330,811	$	543,060	$	55,720	$	499,791

(a)	Amount is based upon the aggregate increase in the actuarial present value.
(b)	Includes continuation of medical benefits of $24,720; vehicle allowance of $18,000; and outplacement services of $13,000.

In the event of a resignation following a material alteration in position not in connection with a qualifying change-in-control, our Executive Severance Plan would entitle Mr. Walje to cash severance of $330,811; incentive of $115,406; outplacement services of $10,000; vehicle allowance of $9,000; and benefits continuation of $2,736. However, this plan will be terminated when the qualifying period related to the MEHC acquisition ends, which is May 23, 2007. At that time, Mr. Walje would no longer be eligible for any of the potential enhanced benefits described above (other than under the SERP).

Messrs. Fehrman, Mendez and Walje are also entitled to full vesting of outstanding awards under the MEHC Long-Term Incentive Partnership Plan in the event of death or disability. As of December 31, 2006, the values of the unvested portions of outstanding awards under this plan were $881,329 for Mr. Fehrman (including an award received while employed by MEHC); $87,446 for Mr. Mendez; and $273,269 for Mr. Walje.

Director Compensation

With the exception of Nolan Karras, all of our directors are employees of MEHC or PacifiCorp and do not receive additional compensation for service as a director. During the nine months ended December 31, 2006, Mr. Karras received a fee in the amount of $10,000 for serving as a member of one of our regional advisory boards, of which $9,000 was deferred under our Compensation Reduction Plan, in which Mr. Karras participates. Mr. Karras’ service on a regional advisory board is unrelated to his service as one of our directors, for which he is not compensated. Earnings on regional advisory board fees deferred by Mr. Karras were $39,629 for the nine months ended December 31, 2006. All directors are reimbursed for their expenses incurred in attending Board meetings.

Compensation Committee Interlocks and Insider Participation

Mr. Abel is our Chairman of the Board and Chief Executive Officer and also the President and Chief Operating Officer of MEHC, our majority owner. None of our executive officers serve as a member of the compensation committee of any company that has an executive officer serving as a member of our Board of Directors. None of our executive officers serve as a member of the board of directors of any company (other than MEHC) that has an executive officer serving as a member of our compensation committee. See also Item 13. Certain Relationships and Related Transactions, and Director Independence.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

All outstanding shares of common stock of PacifiCorp are indirectly owned by MEHC, 666 Grand Avenue, Des Moines, Iowa 50309. MEHC is a consolidated subsidiary of Berkshire Hathaway, which owns approximately 88.2% of MEHC’s common stock (86.6% on a diluted basis). The balance of MEHC’s common stock is owned by a private investor group comprised of Walter Scott, Jr. (including family members and related entities), David L. Sokol and Gregory E. Abel, PacifiCorp’s Chairman and Chief Executive Officer.

Based on a Schedule 13G filed with the SEC on February 15, 2006, CAM North America, LLC, 399 Park Avenue, New York, NY 10022, is the beneficial owner of 38,910 shares, or 10.38%, of PacifiCorp’s outstanding 7.48% Series Preferred Stock.

No PacifiCorp executive officer or director owns shares of PacifiCorp’s preferred stock or shares of the Class B common stock of Berkshire Hathaway. The following table sets forth certain information as of December 31, 2006 regarding the beneficial ownership of common stock of MEHC and the Class A common stock of Berkshire Hathaway by (i) each of the executive officers named in the Summary Compensation Table under Item 11. Executive Compensation above, (ii) each director of PacifiCorp as detailed under Item 10. Directors and Executive Officers of the Registrant, and (iii) all executive officers and directors of PacifiCorp as a group.

	MEHC Common Stock			Berkshire Hathaway Class A Common Stock

Beneficial Owner	Number of shares Beneficially Owned (a)	Percentage of Class (a)		Number of shares Beneficially Owned (a)	Percentage of Class (a)(b)

Gregory E. Abel (c)	749,992	1.01	%	—	—	%
Douglas L. Anderson	—	—		3		*
William J. Fehrman	—	—		—	—
Brent E. Gale	—	—		—	—
Patrick J. Goodman	—	—		2		*
Nolan E. Karras	—	—		—	—
A. Robert Lasich	—	—		—	—
Mark C. Moench	—	—		1		*
A. Richard Walje	—	—		—	—
Stanley K. Watters	—	—		—	—
All executive officers and directors as a group (10 persons)	749,992	1.01	%	6		*

(a)	Includes shares as to 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.

(b)	* Indicates beneficial ownership of less than one percent of all outstanding shares.
(c)	Includes options to purchase 524,052 shares of common stock which are exercisable within 60 days. Excludes 10,041 shares reserved for issuance pursuant to a deferred compensation plan.
	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, 2007, Mr. Abel would be entitled to exchange his shares of MEHC common stock and his shares acquired by exercise of options to purchase MEHC common stock for 1,193 shares of Berkshire Hathaway Class A stock or 35,792 shares of Berkshire Hathaway Class B stock. Assuming an exchange of all available MEHC shares under the shareholders agreement 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.

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 stock to be exchanged is based on the fair market value of MEHC common stock divided by the closing price of the Berkshire Hathaway stock on the day prior to the date of exchange.

105

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

According to the terms of Andrew P. Haller’s offer letter, we made a $200,000.00 loan to Mr. Haller on May 21, 2001 for the repayment of obligations to his former employer. The loan accrued interest at the annual rate of 4.74%. The largest outstanding loan balance, including accrued interest, at any time during the nine months ended December 31, 2006 was $55,521.23 at June 12, 2006. As of December 31, 2006, the loan has been repaid in full.

Review, Approval or Ratification of Transactions with Related Persons

The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of Business Conduct, (together the “Codes”), which apply to all of our directors, officers and employees and those of our subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which we or any of our subsidiaries participate and in which one or more of our directors, executive officers, holders of more than 5.0% of our voting securities or any of such persons’ immediate family members have a direct or indirect material interest.

Under the Codes, all of our directors and executive officers (including those of our subsidiaries) must disclose to our legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with our interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For our 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 our interests.

Under an intercompany administrative services agreement we have entered into with MEHC and its other subsidiaries, the cost of certain administrative services provided by MEHC to us or by us 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 we serve retail customers. We also provide an annual report of all transactions with our affiliates to the state regulatory commission, who have the authority to refuse recovery in retail rates for payments we make to our affiliates deemed to have the effect of subsidizing the separate business activities of MEHC or its other subsidiaries.

Director Independence

Because our common stock is indirectly, wholly owned by MEHC, our Board of Directors consists primarily of MEHC and PacifiCorp employees and we are not required to have independent directors or audit, nominating or compensation committees consisting of independent directors.

Based on the standards of the New York Stock Exchange, on which the common stock of our ultimate parent company, Berkshire Hathaway Inc., is listed, our Board of Directors has determined that Nolan Karras is our only director serving during the nine-month period ended December 31, 2006 who is “independent.” Our remaining directors would not be considered independent because of their employment by MEHC or PacifiCorp. In making the determination that Mr. Karras is independent, our Board of Directors affirmatively determined that he has no material relationship with us and that none of the express disqualifications contained in the New York Stock Exchange rules establishing independence standards applied to Mr. Karras. In addition to reviewing matters involving Mr. Karras that might be inconsistent with applicable New York Stock Exchange rules, our Board of Directors considered the nominal compensation we pay Mr. Karras for service on one of our regional advisory boards, as described in Item 11, “Executive Compensation—Director Compensation.” Our Board of Directors considered no transactions, relationships or arrangements involving Mr. Karras not disclosed in this Annual Report on Form 10-K.

See Item 8. Financial Statements and Supplementary Data – Note 20 – Related-Party Transactions for other information on related-party transactions.

106

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

On May 31, 2006, PricewaterhouseCoopers LLP was advised that it had been dismissed and would not be appointed as PacifiCorp’s independent registered public accounting firm for the transitional nine-month period ending December 31, 2006. The transitional nine-month period arose from PacifiCorp’s election on May 10, 2006 to change its fiscal year-end from March 31 to December 31. The decision to change its independent registered public accounting firm was approved by the Audit Committee of PacifiCorp’s parent company, MidAmerican Energy Holdings Company. Also, on May 31, 2006, MEHC’s Audit Committee approved the engagement of Deloitte & Touche LLP as the independent registered public accounting firm to audit PacifiCorp’s financial statements, commencing with the transitional nine-month period ending December 31, 2006.

FEES AND PRE-APPROVAL POLICY

MEHC’s Audit Committee has an Audit and Non-Audit Services Pre-Approval Policy (the “Policy”) which sets forth the procedures and the conditions pursuant to which services to be performed by the independent registered public accountant are to be pre-approved. Pursuant to the Policy, certain services described in detail in the Policy may be pre-approved on an annual basis together with pre-approved maximum fee levels for such services. The services eligible for annual pre-approval consist of services that would be included under the categories of Audit fees, Audit-related fees and Tax fees defined below. If not pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being performed by the independent registered public accountant. In addition, any services that receive annual pre-approval but exceed the pre-approved maximum fee level also will require separate approval by the Audit Committee prior to being performed. The PacifiCorp Board of Directors has not adopted any pre-approval policy that is in addition to or different than the MEHC Audit Committee’s pre-approval policy.

The following table presents fees billed by Deloitte & Touche LLP for the nine months ended December 31, 2006 and by PricewaterhouseCoopers LLP for the year ended March 31, 2006:

(Millions of dollars)	Nine Months Ended December 31, 2006		Year Ended March 31, 2006

Audit fees	$	1.8	$	1.4
Audit-related fees		0.2		0.4
Tax fees		—		1.4
Other fees		—		0.1

Total	$	2.0	$	3.3

Audit fees are for the audit and review of PacifiCorp’s financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States), including comfort letters, statutory and regulatory audits, consents and services related to SEC matters.

Audit-related fees are for assurance and related services that are related to the audit or review of PacifiCorp’s financial statements, including employee benefit plan audits, due diligence services and financial accounting and reporting consultation.

Tax fees are fees for tax compliance services and related costs.

Other fees are mainly for services rendered in connection with requests from state regulatory commissions and for regulatory matters.

107

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

The list of all financial statements filed as a part of this report is included in Item 8. Financial Statements and Supplementary Data.

Schedules:*

All schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements included under “Item 8. Financial Statements and Supplementary Data.”

Exhibits:

Exhibit Number		Exhibit Title


3.1*		Third Restated Articles of Incorporation of PacifiCorp (Exhibit (3)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152).

3.2*		Bylaws of PacifiCorp, as amended May 23, 2005.

4.1*		Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and JP Morgan Chase Bank (formerly known as The Chase Manhattan Bank), Trustee, Ex. 4-E, Form 8-B, File No. 1-5152, as supplemented and modified by 19 Supplemental Indentures as follows:

Exhibit Number	File Type	File Date	File Number

(4)(b)			33-31861
(4)(a)	8-K	January 9, 1990	1-5152
4(a)	8-K	September 11, 1991	1-5152
4(a)	8-K	January 7, 1992	1-5152
4(a)	10-Q	Quarter ended March 31, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	8-K	April 1, 1993	1-5152
4(a)	10-Q	Quarter ended September 30, 1993	1-5152
(4)b	10-Q	Quarter ended June 30, 1994	1-5152
(4)b	10-K	Year ended December 31, 1994	1-5152
(4)b	10-K	Year ended December 31, 1995	1-5152
(4)b	10-K	Year ended December 31, 1996	1-5152
4(b)	10-K	Year ended December 31, 1998	1-5152
99(a)	8-K	November 21, 2001	1-5152
4.1	10-Q	Quarter ended June 30, 2003	1-5152
99	8-K	September 8, 2003	1-5152
4	8-K	August 24, 2004	1-5152
4	8-K	June 13, 2005	1-5152
4	8-K	August 14, 2006	1-5152

4.2*	Third Restated Articles of Incorporation and Bylaws. See 3.1 and 3.2 above.

In reliance upon item 601(4)(iii) of Regulation S-K, various instruments defining the rights of holders of long-term debt of the Registrant and its subsidiaries are not being filed because the total amount authorized under each such instrument does not exceed 10.0% of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.

108

10.1	Summary of Key Terms of Named Executive Officer Compensation.

10.2*	Form of Transaction Incentive Program Award Agreement for Named Executive Officers (Exhibit 10, Current Report on Form 8-K, filed September 1, 2005, File No. 1-5152).

10.3	Amended and Restated Compensation Reduction Plan.

10.4*	Supplemental Executive Retirement Plan (Exhibit 10.7, Annual Report on Form 10-K, filed May 27, 2005, File No. 1-5152).

10.5*	Amendment No. 10 to PacifiCorp Supplemental Executive Retirement Plan dated June 2, 2006 (Exhibit 10.5, Quarterly Report on Form 10-Q, filed August 7, 2006, File No. 1-5152).

10.6*	Amendment No. 11 to PacifiCorp Supplemental Executive Retirement Plan dated June 2, 2006 (Exhibit 10.6, Quarterly Report on Form 10-Q, filed August 7, 2006, File No. 1-5152).

10.7*	Executive Severance Plan (Exhibit 10.3, Current Report on Form 8-K, filed May 6, 2005, File No. 1-5152).

10.8*	Amendment to PacifiCorp Executive Severance Plan, dated effective October 31, 2005 (Exhibit 10.2, Quarterly Report on Form 10-Q, filed February 14, 2006, File No. 1-5152).

10.9*	Amendment No. 1 to PacifiCorp Executive Severance Plan dated June 2, 2006 (Exhibit 10.3, Quarterly Report on Form 10-Q, filed August 7, 2006, File No. 1-5152).

10.10*	Richard Peach Retention Agreement (Exhibit 10.15, Annual Report on Form 10-K, filed May 30, 2006, File No. 1-5152).

10.11*	Richard Peach Retention Agreement (Exhibit 10.4, Current Report on Form 8-K, filed May 6, 2005, File No. 1-5152).

10.12*	Andrew Haller Retention Agreement (Exhibit 10.14, Annual Report on Form 10-K, filed May 30, 2006, File No. 1-5152).

10.13*	Andrew Haller Retention Agreement (Exhibit 10.14, Annual Report on Form 10-K, filed May 30, 2006, File No. 1-5152).

10.14	David Mendez Retention Agreement.

10.15*	Andrew Haller Promissory Note (Exhibit 10.11, Annual Report on Form 10-K, filed May 27, 2005, File No. 1-5152).

12.1	Statements of Computation of Ratio of Earnings to Fixed Charges.

12.2	Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

14.1	Code of Ethics.

23.1	Consent of Deloitte & Touche LLP.

23.2	Consent of PricewaterhouseCoopers LLP.

24	Power of Attorney.

31.1	Section 302 Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a).

31.2	Section 302 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a).

109

32.1	Section 906 Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350.

32.2	Section 906 Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

* Incorporated herein by reference.

(b)	See (a) 3. above.

(c)	See (a) 2. above.

110

SIGNATURES

PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED THEREUNTO DULY AUTHORIZED.

		PacifiCorp
		By:	/s/ DAVID J. MENDEZ

			David J. Mendez
			(SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER)

Date: March 1, 2007

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.

SIGNATURE	TITLE	DATE


* GREGORY E. ABEL	Chairman of the Board of Directors And Chief Executive Officer (Principal Executive Officer)	March 1, 2007

Gregory E. Abel

/s/ DAVID J. MENDEZ	Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	March 1, 2007

David J. Mendez

* DOUGLAS L. ANDERSON	) )

Douglas L. Anderson
	)
* WILLIAM J. FEHRMAN	) ) )

William J. Fehrman
	)
* BRENT E. GALE	) ) ) Director	March 1, 2007

Brent E. Gale
	)
* PATRICK J. GOODMAN	) ) )

Patrick J. Goodman

111


* NOLAN E. KARRAS	) ) )

Nolan E. Karras
	)
* A. ROBERT LASICH	) ) )

A. Robert Lasich
	)
* MARK C. MOENCH	) ) ) Director	March 1, 2007

Mark C. Moench
	)
/s/ R. PATRICK REITEN	) ) )

R. Patrick Reiten
	)
* A. RICHARD WALJE	) ) )

A. Richard Walje
	)
* STANLEY K. WATTERS	) ) )

Stanley K. Watters

*By: /s/ DAVID J. MENDEZ

David J. Mendez, as Attorney-in-Fact

112

EXHIBIT 10.1

SUMMARY OF KEY TERMS OF COMPENSATION ARRANGEMENTS WITH

PACIFICORP NAMED EXECUTIVE OFFICERS AND DIRECTORS

PacifiCorp’s continuing named executive officers (other than its Chairman and Chief Executive Officer, Greg Abel) each receive an annual salary and participate in health insurance and other benefit plans on the same basis as other employees, as well as certain other benefit plans described in PacifiCorp’s Annual Report on Form 10-K. Mr. Abel is employed by PacifiCorp’s parent company, MidAmerican Energy Holdings Company (“MEHC”) and is not directly compensated by PacifiCorp. PacifiCorp reimburses MEHC for the cost Mr. Abel’s time spent on PacifiCorp matters, including compensation paid to him by MEHC, pursuant to an intercompany administrative services agreement among MEHC and its subsidiaries.

The other named executive officers are also eligible for a cash incentive under the PacifiCorp Annual Incentive Plan (“AIP”) and participate in MEHC’s Long-Term Incentive Partnership Plan (“LTIP”). A copy of the LTIP is attached as Exhibit 10.71 to the MidAmerican Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated by reference herein. Base salary and target bonus opportunities for continuing named executive officers for PacifiCorp’s fiscal year ending December 31, 2007 (excluding Mr. Abel):

Name and Title	Base Salary	AIP Target Opportunity (percentage of base salary)

William J. Fehrman President, PacifiCorp Energy	$300,000	75.0%

David J. Mendez Senior Vice President and Chief Financial Officer	$214,200	30.0%

A. Richard Walje President, Rocky Mountain Power	$335,811	50.0%

With the exception of Nolan Karras, all of PacifiCorp’s directors are employees of MEHC or PacifiCorp and do not receive additional compensation for service as directors. For the fiscal year ending December 31, 2007, Mr. Karras will receive a fee in the amount of $2,500 for serving as a member of one of PacifiCorp’s regional advisory boards. Mr. Karras’ service on the regional advisory board is unrelated to his service as a director, for which he is not compensated.

Exhibit 10.3

PACIFICORP

EXECUTIVE VOLUNTARY DEFERRED COMPENSATION PLAN

(as restated effective as of January 1, 2005)

PACIFICORP

EXECUTIVE VOLUNTARY DEFERRED COMPENSATION PLAN

PacifiCorp hereby amends and restates the PacifiCorp Compensation Reduction Plan, most recently restated effective as of January 1, 2002 (“Plan”) for the benefit of certain Employees and other Participants. The primary purpose of the Plan is to provide additional compensation to Participants upon termination of employment or service with the Employer. The Employer will pay benefits under the Plan only in accordance with the terms and conditions set forth in the Plan. This Plan is a restated plan effective as of January 1, 2005, with respect to all provisions of the Plan necessary to bring the Plan into compliance with Code §409A, including, but not limited to, the applicable provisions of Sections 2.02, 2.05, Article IV, Section 5.01(A) and Section 6.03, and any applicable definitions. All other provisions of the Plan shall be effective as of January 1, 2007, and for the period January 1, 2005 through December 31, 2006, the provisions of the Plan prior to this restatement shall apply.

PREAMBLE

Plan Type. The Plan is an unfunded nonqualified deferred compensation plan maintained “primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” (“top-hat plan”).

Possible Nonuniformity . The Employer need not provide the same Plan benefits or apply the same Plan terms and conditions to all Participants, even as to Participants who are of similar pay, title and other status with the Employer. The Employer may create a separate exhibit for one or more Participants, specifying such terms and conditions as are applicable to a given Participant. The Employer, in a separate exhibit, may modify any Plan provision with respect to one or more Participants.

I. DEFINITIONS

1.01 “Account” means the account the Employer establishes under the Plan for each Participant and as applicable means a Participant’s Elective Deferral Account, or Employer Contribution Account. An Elective Deferral Account shall consist of subaccounts as selected by the Participant, and which shall be a Retirement Account, an In-Service Account and an Education Account.

1.02 “Accrued Benefit” means the total dollar amount credited to a Participant’s Account.

1.03 “Applicable Guidance” means Treasury Regulations issued pursuant to Code §409A, or other written Treasury or IRS guidance regarding Code §409A, which is in addition to IRS Notice 2005-1 (“Notice 2005-1”).

1.04 “Base Salary” means a Participant’s compensation consisting only of regular annual salary and excluding any other compensation.

1.05 “Beneficiary” means the person or persons entitled to receive Plan benefits in the event of a Participant’s death.

1.06 “Change in Control” of the Employer means a change: (i) in the ownership of the Employer; (ii) in the effective control of the Employer; or (iii) in the ownership of a substantial portion of the assets of the Employer, within the meaning of Notice 2005-1, Q/As 11-14 or in Applicable Guidance.

1.07 “Change in the Employer’s Financial Health” means an adverse change in the Employer’s financial condition as described in Applicable Guidance.

1.08 “Code” means the Internal Revenue Code of 1986, as amended.

1.09 “Compensation” means Base Salary, performance awards annual incentive bonuses (other than Employer long term incentive awards), and fees for serving as a member of an Advisory Board (See definition of Participant below). Inclusion of any other forms of compensation is subject to approval of the Employer.

1.10 “Disability” means a condition of a Participant who by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months: (i) is unable to engage in any substantial gainful activity; or (ii) is receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering Employees.

1.11 “Deferred Compensation” means the Participant’s Account Balance attributable to Elective Deferrals and Employer Contributions and includes Earnings on such amounts. “Compensation Deferred” is Compensation that the Participant or the Employer has deferred under this Plan.

1.12 “Earnings” means the notional earnings, gain and loss applicable to a Participant’s Account as described in Section 5.02.

1.13 “Effective Date” of the Plan as amended and restated is January 1, 2005 as to the provisions relating to compliance with Code §409A and is January 1, 2007 as to all other provisions (See the opening paragraph of the Plan).

1.14 “Elective Deferral” means Compensation a Participant elects to defer into the Participant’s Account under the Plan.

1.15 “Elective Deferral Account” means the portion of a Participant’s Account attributable to Elective Deferrals and Earnings thereon (and which shall consist of Retirement, In-Service and Education subaccounts).

1.16 “Employee” means a person providing services to the Employer in the capacity of a common law employee of the Employer.

1.17 “Employer” means PacifiCorp, an Oregon corporation.

1.18 “Employer Contribution” means amounts, if any, the Employer contributes or credits to an Account under the Plan, excluding Elective Deferrals.

1.19 “Employer Contribution Account” means the portion of a Participant’s Account attributable to Employer Contributions and Earnings thereon.

1.20 “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

1.21 “ Participant” means an Employee of the Employer who has met the eligibility requirements of Section 2.01 and who has accrued a benefit under the Plan, and Participant also means a member of the Rocky Mountain Power Regional Advisory Board and a member of the Pacific Power Regional Advisory Board (together the “Advisory Boards”) and who has accrued a benefit under the Plan.

1.22 “Performance-Based Compensation” means such amounts described in Applicable Guidance .

1.23 “ Plan” means the PacifiCorp Executive Voluntary Deferred Compensation Plan . For purposes of applying Code §409A requirements: (i) this Plan is an account balance plan under Notice 2005-1; (ii) this plan constitutes a separate plan for each Participant; and (iii) except as the Plan otherwise provides, all Deferred Compensation for a Participant is aggregated with that Participant’s deferrals under any other account balance nonqualified deferred compensation plan of the Employer in which the Participant participates.

1.24 “Retirement Age” means a Participant’s attainment of age 55 or, for any Participant who was a Participant in the Plan on December 31, 2006, age 50 with 5 “Years of Participation” in the PacifiCorp Supplemental Executive Retirement Plan (the “SERP”), as such term is defined in the SERP, and 15 “Years of Service” in the PacifiCorp Retirement Plan, as such term is defined in the PacifiCorp Retirement Plan.

1.25 “Separation from Service” means an Employee’s termination of employment with the Employer or as otherwise defined in Applicable Guidance.

1.26 “Specified Employee” means a Participant who is described in Code §416(i), disregarding paragraph (5) thereof. However, a Participant is not a Specified Employee unless any stock of the Employer (or of a member of the same group of controlled entities as Employer) is publicly traded on an established securities market or otherwise.

1.27 “Specified Time or Pursuant to a Fixed Schedule” means a specific time or schedule (but not the occurrence of an event) as a Participant or Employer payment election may specify, and otherwise as described in Applicable Guidance.

1.28 “State” means: (i) one of the fifty states of the United States or the District of Columbia, or (ii) a political subdivision of a State, or any agency or instrumentality of a State or its political subdivision. A State does not include the federal government or an agency or instrumentality thereof.

1.29 “Substantial Risk of Forfeiture” means as to 409A Amounts (described in Article VII), Deferred Compensation which is payable conditioned: (i) on the performance of substantial future services by any person including the Participant; or (ii) on the occurrence of a condition related to a purpose of the Deferred Compensation, and where under clause (i) or (ii) the possibility of forfeiture is substantial. A Substantial Risk of Forfeiture does not include any addition of a condition after commencement of the service period to which the Deferred Compensation relates or to the extension of any period to which a Substantial Risk of Forfeiture applies. Deferred Compensation is not subject to a Substantial Risk of Forfeiture merely because payment is conditioned on the Participant’s refraining from performing services. A Substantial Risk of Forfeiture also means those events or cirucmstances as described in Notice 2005-1, Q/A-10 or in Applicable Guidance.

1.30 “ Taxable Year” means the 12 consecutive month period ending each December 31.

1.31 “ Trust” means a trust described in Section 5.01.

1.32 “Unforeseeable Emergency” means: (i) a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Code §152(a)) of the Participant; (ii) loss of the Participant’s property due to casualty; or (iii) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the Participant’s control. The amount of the distribution may not exceed the amount necessary to satisfy the Unforeseeable Emergency plus taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which the hardship may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets, to the extent that liquidation of such assets would not itself cause severe financial hardship.

1.33 “ Valuation Date” means the last day of each calendar month and such other dates as the Employer may determine.

1.34 “Vested” means Deferred Compensation which is not subject to a Substantial Risk of Forfeiture or to a requirement to perform further services for the Employer.

II. PARTICIPATION

2.01 Participant Designated. The Chairman of the Board of Directors of the Employer shall designate and approve the Employees who are eligible to participate in the Plan, such designation to be either by name, job title or other classification. The Chairman may also notify any Participant, including any Advisory Board member, that he or she is no longer eligible to make future deferrals into the Plan. Such termination of eligibility shall be effective as of January 1 following such written notification by the Chairman to the individual.

2.02 Elective Deferrals . Participants may make separate Elective Deferrals to their Accounts with respect to Base Salary and Compensation that is not Base Salary. All elections to defer shall terminate upon Separation from Service, Disability or a distribution based on an Unforeseeable Emergency.

(A) Limitations. The maximum Elective Deferral for Base Salary is 50%. There is no limit for Compensation that is not Base Salary. The minimum Elective Deferral for any type of Compensation is 1%.

(B) Form and Timing . A Participant must make his/her Elective Deferral election on an election form the Employer provides for that purpose. A Participant must deliver his/her election to the Employer prior to the beginning of the Taxable Year for which it is to go into effect (or at such other time as Applicable Guidance may provide).

(C) New Participant . If an Employee first becomes a Participant on a date which is not the first day of a Taxable Year, the Participant must make and deliver his/her Elective Deferral election for that Taxable Year not later than 30 days after the Participant becomes a Participant. The election may apply only to Compensation for services the Participant performs subsequent to the date the Participant delivers the election to the Employer. For Compensation that is earned for a specified performance period, including an annual bonus, and where the new Participant makes an Elective Deferral election after the service period commences, the Employer will pro rate the election by multiplying the performance based Compensation by the ratio of the number of days left in the performance period at the time of the election, over the total number of days in the entire performance period.

(D) Performance-Based Compensation . As to any Performance-Based Compensation based on services performed over a period of at least 12 months, a Participant may elect for a period up to 6 months before the end of the service period to defer such Compensation, provided that the Participant: (i) continuously must perform services from a date no later than the date the Employer establishes the performance criteria and at least through the date of the Participant’s election; and (ii) may not make an election after the Compensation has become substantially certain to be paid and is readily ascertainable.

(E) Election Duration . A Participant’s Elective Deferral election applies only to the Participant’s Compensation earned in the next Taxable Year following the Taxable Year in which the Participant makes the election. A Participant, subject to Plan requirements regarding election timing, including those in Article VII, may make a new election, or revoke or modify an existing election effective no earlier than for the next Taxable Year.

2.03 Employer Contributions . In each Taxable Year, the Employer may make discretionary Employer Contributions for any or all Participants, which need not be uniform among Participants.

2.04 Allocation Conditions . There are no conditions generally applicable to receive an allocation of Employer Contributions, unless the Employer establishes conditions with respect to a particular discretionary Employer Contribution.

2.05 Timing . The Employer may elect to make any Employer Contribution for a Taxable Year at such times as Code §409A or Applicable Guidance may permit.

2.06 Administration . The Employer will administer all Employer Contributions in the same manner as Elective Deferrals, except as the Plan otherwise provides. The Employer will credit any Elective Deferrals to a Participant’s Account as soon as practicable after the date the amount of the Elective Deferral would otherwise have become due and payable to the Participant and will credit any Employer Contributions to a Participant’s Account as soon as practicable after the date of the amount of the Employer Contribution is determined. Any Employer Contribution is not subject to an immediate Participant right to elect a cash payment in lieu of the Employer Contribution and such amounts are payable only in accordance with the Plan terms.

III. VESTING AND FORFEITURE

3.01 Vesting Schedule . Participants shall always be immediately one hundred percent (100%) vested in their Elective Deferral Accounts. The Employer may separately establish a vesting schedule for any Employer Contributions.

3.02 Application of Forfeitures . A Participant will forfeit any non-Vested Accrued Benefit upon Separation from Service. The Employer will keep all forfeitures.

IV. BENEFIT PAYMENTS

4.01 Separation from Service or Death . The Plan will pay to the Participant the Vested Accrued Benefit held in the Participant’s Account following the earlier of the Participant’s Separation from Service or death. Payment will commence at the time and payment will be made in the form and method specified under Section 4.03. In the event of the Participant’s death, the Plan will pay to the Participant’s Beneficiary the Participant’s Vested Accrued Benefit or any remaining amount thereof if benefits to the Participant already have commenced, in accordance with the Participant’s election.

(A) Distribution to Specified Employees . Notwithstanding anything to the contrary in the Plan or in a Participant or Employer payment election, the Plan may not distribute to a Specified Employee, based on Separation from Service, earlier than 6 months following Separation from Service (or if earlier, upon the Specified Employee’s death).

4.02 Other Payment Events . In addition to the payment events under Section 4.01, the Plan will pay to a Participant all or any part of the Participant’s Account: (i) at a Specified Time or Pursuant to a Fixed Schedule elected by the Participant with respect to Education and In-Service subaccounts; or (ii) based upon an Unforeseeable Emergency. Payment will commence at the time and payment will be made in the form and method specified under Section 4.03.

4.03 Form, Timing and Method/ Payment Election . All distributions will be in cash. Subject to the provisions of this paragraph, a Participant shall make an initial payment election as to the method of payment under Section 4.03(A) and may make a change to an election under Section 4.03(B). Until the Plan completely distributes a Participant’s Vested Accrued Benefit, the Plan will continue to credit the Participant’s Account with Earnings, in accordance with Section 5.02. Except as provided below, a Participant may elect either a lump sum payment or substantially equal annual installments (not to exceed 10) with respect to a Retirement subaccount and an In-Service subaccount. If no election is made as to method, payment shall be made in a lump sum. Distribution from an Education subaccount may only be made in 4 substantially equal annual installments. Distributions from a Retirement Account as a result of Separation from Service after Retirement Age shall be made (or commence) in January following the calendar year in which Separation from Service occurs. Distributions from an In-Service subaccount, an Education subaccount, or a Retirement subaccount, when a Separation from Service occurs prior to Retirement Age (including death prior to Retirement Age), shall be made as soon as administratively practicable following the date of Separation from Service (or death), and shall be made in a lump sum payment (except that payments from the remaining account balance in an Education subaccount or In-Service subaccount, where payments have already commenced prior to Separation from Service, shall continue to be made under the schedule then in effect). Payments made because of Unforeseeable Emergency shall be made (or commence) as soon as administratively practicable following such event. Disability shall not be treated as a distribution event. In the event of death after attaining Retirement Age or after payments from an Account have begun, a lump sum payment to the Beneficiary shall be made as soon as administratively practical after date of death if the Participant had previously elected a lump sum distribution to the Beneficiary pursuant to Section 4.03(A) (initial payment election) or pursuant to Section 4.03(B)(1) (change to payment election).

(A) Initial Payment Election . A Participant, as to an In-Service subaccount shall make an initial payment election with respect to a Specified Time and a Fixed Schedule at the time of the Participant’s first Elective Deferral election into such subaccount. A Participant, as to an Education subaccount, shall make an initial election with respect to a Specified Time at the time of the Participant’s first Elective Deferral election into such subaccount (the Fixed Schedule being 4 substantially equal annual payments). As to a Retirement subaccount, a Participant shall make an initial payment election as to a method of payment (Fixed Schedule) at the time of his or her first deferred election into such subaccount (the Specified Time being upon Separation of Service as provided in Section 4.03 above). A Participant shall make any permissible initial payment election on a form the Employer provides for that purpose. At the time of any such first Elective Deferral election into any Account, a Participant may elect to have a lump sum payment made to his or her Beneficiary in lieu of the form of payment that otherwise has been selected for payout during the Participant’s life.

(B) Changes to Payment Election . A Participant may change the Participant’s initial payment election (or change election) as to any or all Deferred Compensation, including any Plan default payment applicable in the absence of an election. Any such change election must comply with this Section 4.03(B). A Participant must make any change election on a form the Employer provides for such purpose.

(1) Conditions on Changes to Payment Elections. Any Participant change election: (i) may not take effect until at least 12 months following the date of the change election; (ii) must result in the first payment under the change election being made not earlier than 5 years following the date upon which the originally-elected payment would have been made (except if payment is on account of death, or Unforeseeable Emergency); and (iii) if the change election relates to a Participant’s previous election of a Specified Time or Fixed Schedule, the Participant must make the change election not less than 12 months prior to the date of the first scheduled payment under the election being changed (or, in the case of installment payments treated as a single payment, 12 months prior to the date the first amount was scheduled to be paid).

(2) Definition of “Payment.” Except as otherwise provided in Section 4.03(B)(3), a “payment” for purposes of applying Section 4.03(B)(1) is each separately identified amount the Plan is obligated to pay to a Participant on a determinable date and includes amounts paid for the benefit of the Participant. An amount is “separately identified” only if the Employer can objectively determine the amount. A payment includes the provision of any taxable benefit, including payment in cash or in-kind. A payment includes, but is not limited to, the transfer, cancellation or reduction of an amount of Deferred Compensation in exchange for benefits under a welfare benefit plan, fringe benefits excludible under Code §§119 or 132, or any other benefit that is excluded from gross income.

(3) Installment Payments. A series of installment payments will be treated as a single payment. For purposes of this Section 4.03(B)(3), a “series of installment payments” means payment of a series of substantially equal periodic amounts to be paid over a predetermined number of years, except to the extent that any increase in the payment amounts reflects reasonable Earnings through the date of payment.

(4) Coordination with Anti-Acceleration Rule. In applying Section 4.03(C), “payment” means as described in Sections 4.03(B)(2) and (3). A Participant under a change payment election may change the form of payment to a more rapid schedule (including a change from installments to a lump-sum payment) without violating Section 4.03(C), provided any such change remains subject to the change payment election provisions under this Section 4.03(B). Accordingly, if the Participant’s payment change election modifies the payment method from installments to a lump-sum payment, a change payment election must satisfy Section 4.03(B)(1) measured from the first installment payment. If a change payment election only modifies the timing of an installment payment, the change payment election must apply to each installment and must satisfy Section 4.03(B) measured from each installment payment.

(C) No Acceleration . Neither the Employer nor the Participant may accelerate the time or schedule of any Plan payment except as Applicable Guidance may permit. For this purpose, the following are not an acceleration: (i) a payment required under a domestic relations order under Code §414(p)(1)(B); (ii) a payment required under a certificate of divestiture under Code §1043(b)(2); or (iii) a payment to pay the FICA tax (and income tax withholding related to the FICA) on the Deferred Compensation.

(D) Cash-Out Upon Separation . Notwithstanding a Participant’s payment election or any contrary Plan terms, the Plan will distribute in a single cash payment the entire Vested Accrued Benefit of a Participant who has incurred a Separation from Service (including Grandfathered and 409A Amounts) where the Participant’s Vested Accrued Benefit does not exceed $10,000. The Employer will make any payment under this Section 4.03(D) in January in the calendar year following the calendar year of the Participant’s Separation from Service.

4.04 Withholding . The Employer will withhold from any payment made under the Plan and from any amount taxable under Code §409A, all applicable taxes, and any and all other amounts required to be withheld under federal, state or local law, including Notice 2005-1 and Applicable Guidance.

4.05 Beneficiary Designation . A Participant may designate a Beneficiary (including one or more primary and contingent Beneficiaries) to receive payment of any Vested Accrued Benefit remaining in the Participant’s Account at death. The Employer will provide each Participant with a form for this purpose and no designation will be effective unless made on that form and delivered to the Employer. A Participant may modify or revoke an existing designation of Beneficiary by executing and delivering a new designation to the Employer. In the absence of a properly designated Beneficiary, the Employer will pay a deceased Participant’s Vested Accrued Benefit to the Participant’s surviving spouse and if no spouse, to the Participant’s children, including adopted children, in equal shares, and if no spouse or children, to the Participant’s estate. If a Beneficiary is a minor or otherwise reasonably determined by the Employer to be legally incompetent, the Employer may cause the Plan or Trust to pay the Participant’s Vested Accrued Benefit to a guardian, trustee or other proper legal representative of the Beneficiary. Payment by the Employer of the deceased Participant’s Vested Accrued Benefit to the Beneficiary or proper legal representative of the Beneficiary completely discharges the Employer, the Plan and Trust of all further obligations under the Plan.

4.06 Administration of Payment Date(s) . The Employer may cause the Plan or Trust to pay a Participant’s Vested Accrued Benefit on any date that is administratively practicable following any Plan specified payment date or the date specified in any valid payment election.

V. TRUST ELECTION AND PLAN EARNINGS

5.01 Unfunded Plan/Trust Election . The Employer intends this Plan to be an unfunded plan that is wholly or partially exempt under ERISA. No Participant, Beneficiary or successor thereto has any legal or equitable right, interest or claim to any property or assets of the Employer, including assets held in any Account under the Plan except as the Plan otherwise permits. The Employer’s obligation to pay Plan benefits is an unsecured promise to pay. If the Employer elects to create a Trust, the applicable provisions of the Plan continue to apply, including those of this Section 5.01. The Trustee will pay Plan benefits in accordance with the Plan terms or upon the Employer’s direction consistent with Plan terms. The Employer intends to make notional contributions in lieu of actual contributions to the Plan, and the Employer, therefore, may elect not to invest any Plan contributions. If the Employer elects to invest any Plan contributions, such investments may be held for the Employer’s benefit in providing for the Employer’s obligations under the Plan or for such other purposes as the Employer may determine. Any assets held in Plan Accounts remain subject to claims of the Employer’s general creditors and no Participant’s or Beneficiary’s claim to Plan assets has any priority over any general unsecured creditor of the Employer.

(A) Restriction on Trust Assets . If an Employer establishes, directly or indirectly, a Trust (or any other arrangement Applicable Guidance may describe), the Trust and the Trust assets must be and must remain located within the United States, except with respect to a Participant who performs outside the United States substantially all services giving rise to the Deferred Compensation, in which case the Employer may, in its sole discretion, choose to establish a Trust outside the United States to cover the obligations of Participants who perform outside the United States substantially all services giving rise to the Deferred Compensation . The Trust may not contain any provision limiting the Trust assets to the payment of Plan benefits upon a Change in the Employer’s Financial Health, even if the assets remain subject to claims of the Employer’s general creditors. For this purpose, the Employer, upon a Change in the Employer’s Financial Health, may not transfer Deferred Compensation to the Trust. Any Trust the Employer establishes under this Plan shall be further subject to Applicable Guidance, compliance with which is necessary to avoid the transfer of assets to the Trust being treated as a transfer of property under Code § 83.

5.02 Notional Earnings. The Employer, under the Plan, periodically will credit notional Plan contributions with a determinable amount of notional Earnings (at a specified fixed or floating interest rate or other specified index or indices based on established and published financial investment benchmarks) to each Participant’s Account. The Participant has the right to direct the investment of the Participant’s Account pursuant to conditions established by the Employer. This right is limited strictly to investment direction and the Participant will not be entitled to the distribution of any Account asset except as the Plan otherwise permits. Except as otherwise provided in the Plan or Trust, all Plan assets, including all incidents of ownership, at all times will be the sole property of the Employer.

VI. MISCELLANEOUS

6.01 No Assignment . Except with respect to a payment required under a domestic relations order under Code §414(p)(l)(B), no Participant or Beneficiary has the right to anticipate, alienate, assign, pledge, encumber, sell, transfer, mortgage or otherwise in any manner convey in advance of actual receipt, the Participant’s Account. Prior to actual payment, a Participant’s Account is not subject to the debts, judgments or other obligations of the Participant or Beneficiary and is not subject to attachment, seizure, garnishment or other process applicable to the Participant or Beneficiary.

6.02 Not Employment Contract . This Plan is not a contract for employment between the Employer and any Employee who is a Participant. This Plan does not entitle any Participant to continued employment with the Employer, and benefits under the Plan are limited to payment of a Participant’s Vested Accrued Benefit in accordance with the terms of the Plan.

6.03 Amendment and Termination .

(A) Amendment. The Chairman of the Board of Directors of the Company reserves the right to amend the Plan at any time to comply with Code §409A, Notice 2005-1, Prop. Treas. Reg. §1.409A and other Applicable Guidance or for any other purpose, provided that such amendment will not result in taxation to any Participant under Code §409A. Except as the Plan and Applicable Guidance otherwise may require, the Chairman may make any such amendments effective immediately.

(B) Termination. The Employer, by action of the Board, may terminate, but is not required to terminate, the Plan and distribute Plan Accounts under the following circumstances; provided, however, that with respect to termination under subsections (2), (3) and (4) below, the Employer must receive written approval of such termination from any Participant who was a Participant in the Plan on the effective date of the closing of the transaction that resulted in the acquisition of the Employer by MidAmerican Energy Holdings Company, and provided further that failure to obtain approval from any such Participant shall result only in the continuation of the Plan for such Participant and shall not affect termination of the Plan with respect to all other Participants (This proviso shall not limit the Employer from terminating the right to make future contributions to the Plan.):

(1) Dissolution/Bankruptcy. The Employer may terminate the Plan within 12 months following a dissolution of a corporate Employer taxable under Code §331 or with approval of a Bankruptcy court under 11 U.S.C. §503(b)(1)(A), provided that the Deferred Compensation is paid to the Participants and is included in the Participants’ gross income in the latest calendar year: (i) in which the plan termination occurs; (ii) in which the amounts no longer are subject to a Substantial Risk of Forfeiture; or (iii) in which the payment is administratively practicable.

(2) Change in Control. The Employer may terminate the Plan within the 30 days preceding or the 12 months following a Change in Control provided the Employer distributes all Plan Accounts (and must distribute the accounts under any substantially similar Employer plan which plan the Employer also must terminate) within 12 months following the Plan termination.

(3) Other. The Employer may terminate the Plan for any other reason in the Employer’s discretion provided that: (i) the Employer also terminates all Aggregated Plans in which any Participant also is a participant; (ii) the Plan makes no payments in the 12 months following the Plan termination date other than payments the Plan would have made irrespective of Plan termination; (iii) the Plan makes all payments within 24 months following the Plan termination date; and (iv) the Employer within 5 years following the Plan termination date does not adopt a new plan covering any Participant that would be an Aggregated Plan.

(4) Applicable Guidance. The Employer may terminate the Plan under such other circumstances as Applicable Guidance may permit.

(C) Effect on Vesting. Any Plan amendment or termination will not reduce the Vested Accrued Benefit held in any Participant Account at the date of the amendment or termination and also may not accelerate vesting except as may be permitted without subjecting any Participant to taxation under Code §409A.

(D) Cessation of Future Contributions. The Employer may elect at any time to amend the Plan to cease future Elective Deferrals as of a specified date. In such event, the Plan remains in effect (except those provisions permitting the frozen contribution type) until all Accounts are paid in accordance with the Plan terms, or, if earlier, upon the Employer’s termination of the Plan.

6.04 Severability . If any provision of the Plan is determined by a proper authority to be invalid, the remaining portions of the Plan will continue in effect and will be interpreted consistent with the elimination of the invalid provision.

6.05 Notice and Elections . Any notice given or election made under the Plan must be in writing and delivered (electronically, by facsimile, or by mail), to the Employer or to the Participant or Beneficiary as appropriate. The Employer will prescribe the form of any Plan notice or election to be given to or made by Participants. Any notice or election will be deemed given or made as of the date of actual receipts, or if given or made by certified mail, as of 3 business days after mailing.

6.06 Administration . This Plan shall be administered by a committee (“Committee”). The Chairman of the Board of Directors of the Employer shall constitute the sole member of the Committee unless the Chairman appoints one or more other individuals to serve on the Committee. The Committee shall have a chair, who shall be chosen from among its members or who is the sole member of the Committee. As a condition of receiving any Plan benefit to which a Participant or Beneficiary otherwise may be entitled, a Participant or Beneficiary will provide such information and perform such other acts as the Employer reasonably may request. The Committee may retain agents to assist in the administration of the Plan and may delegate to agents or to an officer of the Employer such duties as it sees fit. The decision of the Committee or its designee concerning the administration of the Plan is final and is binding upon all persons having any interest in the Plan. The Employer will indemnify, defend and hold harmless members of the Committee and any Employee designated by the Committee to assist in the administration of the Plan from any and all loss, damage, claims, expense or liability with respect to this Plan (collectively, “claims”) except claims arising from the intentional acts or gross negligence of the Committee member or Employee designated to assist in the administration of the Plan.

6.07 Account Statements . The Employer will provide each Participant with a statement of the Participant’s Vested Accrued Benefit at least annually as of the last Valuation Date in the Plan Year. The Employer also will provide Account statements to any Beneficiary of a deceased Participant with a Vested Accrued Benefit remaining in the Plan.

6.08 Accounting . The Employer will maintain for each Participant as is necessary for proper administration of the Plan, an Elective Deferral Account (and Retirement, In-Service and Education subaccounts.

6.09 Costs and Expenses . The Employer will pay the costs, expenses and fees associated with the operation of the Plan, excluding those incurred by Participants or Beneficiaries. The Employer will pay costs, expenses or fees charged by or incurred by the Trustee only as provided in the Trust or other agreement between the Employer and the Trustee.

6.10 Reporting . The Employer will report on Form W-2 Deferred Compensation for Participants who were Employees when compensation was deferred and will report on Form 1099-MISC Deferred Compensation for Participants who were not Employees when compensation was deferred, all in accordance with Notice 2005-1 and Applicable Guidance.

6.11 Claims Procedure.

(A) Claim. Any person or entity claiming a benefit, requesting an interpretation or ruling under the Plan (hereinafter referred to as “Claimant”), or requesting information under the Plan shall present the request in writing to the Employer, which shall respond in writing as soon as practicable.

(B) Denial of Claim . If the claim or request is denied, the written notice of denial shall state:

The reasons for denial, which specific reference to the Plan provisions on which the denial is based;

A description of any additional material or information required and an explanation of why it is necessary; and

An explanation of the Plan’s claim review procedure.

(C) Review of Claim . Any Claimant whose claim or request is denied or who has not received a response within sixty (60) days may request a review by notice given in writing to the Employer. Such request must be made within sixty (60) days after receipt by the Claimant of the written notice of denial, or in the event Claimant has not received a response sixty (60) days after receipt by the Employer of Claimant’s claim or request. The claim or request shall be reviewed by the Board of Directors which may, but shall not be required to, grant the Claimant a hearing. On review, the Claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

(D) Final Decision . The decision on review shall normally be made within sixty (60) days after the Employer’s receipt of Claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the Claimant shall be notified and the time limit shall be one hundred twenty (120) days. The decision shall be in writing and shall state the reasons and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.

VII. 2005, 2006 AND 2007 TRANSITION RULES AND PROVISIONS APPLICABLE

BECAUSE PLAN WAS EFFECTIVE BEFORE 2005

7.01 Code §409A Amounts . The terms of this Plan control as to any Compensation Deferred prior to January 1, 2005, in addition to all Compensation Deferred after December 31, 2004. Thus, all amounts under the Plan are considered “409A Amounts”.

7.02 2005, 2006 and 2007 Operational Rules . The following provisions apply to the Plan during the 2005 and 2006 Taxable Years, as specifically provided in each subsection.

(A) Good Faith . As to 409A Amounts, the Employer will operate the Plan during the 2005 and 2006 Taxable Years in good faith compliance in accordance with: (i) Notice 2005-1; (ii) Code §409A; and (iii) any Applicable Guidance as of the effective date hereof. The Employer also may operate the Plan consistent with the Prop. Treas. Reg. §1.409A before such regulations become effective and may apply such regulations to the extent that they are inconsistent with Notice 2005-1. Although the Employer intends this Plan document to comply with the provisions of Notice 2005-1 and of Prop. Treas. Reg. §1.409A, the Employer will not apply any Plan provision which is inconsistent therewith and, by December 31, 2007, will amend any such provision to comply with Applicable Guidance. The Employer and the Participants may not exercise discretion under the Plan in a manner that would violate Code §409A.

(B) Participant’s Revised Deferral Election . A Participant, on or before December 31, 2007, may make a new payment election as to any previously deferred 409A Amount, except that a Participant cannot in 2006 change payment elections with respect to payments that the Participant would otherwise receive in 2006, or to cause payments to be made in 2006, and a Participant cannot in 2007 change payment elections with respect to payments that the Participant would otherwise receive in 2007 or to cause payments to be made in 2007. Any such election must be a permissible election under Section 4.03(A), but an election under this Section 7.02(B) is not treated as a change in the timing or form of distribution and need not comply with Section 4.03(B) as it applies to such changes.

(C) 2005 Deferral Election by March 15, 2005. Notwithstanding Section 2.02, if the Plan was in existence on or before December 31, 2004 (as described in Notice 2005-1, Q/A 21), a Participant may make an Elective Deferral election as to 409A Amounts earned for service to the Employer through December 31, 2005. A Participant must make an election under this Section7.05(C) no later than March 15, 2005, and in accordance with the Plan terms as in effect on or before December 31, 2005. The election applies only as to amounts not paid or payable to the Participant at the time of the election. Any amounts subject to this election otherwise are 409A Amounts. This Section applies only to the 2005 Taxable Year and is applicable only if the Employer executed, on or before January 1, 2006, a separate amendment to the Plan that includes provisions similar to this subsection.

(D) Cancellation of Election/Participation. A Participant as to 409A Amounts, on or before December 31, 2005, may elect to cancel any or all existing Elective Deferral elections. The Plan will distribute to an affected Participant all 409A Amounts subject to an election under this 7.05(D) and the Participant will include such amounts in income, in the 2005 Taxable Year, or if later, in the Taxable Year in which such amounts are Vested. This section is applicable only if the Employer executed, on or before January 1, 2006, a separate amendment to the Plan that includes provisions similar to this subsection.

7.03 Incorporation of Applicable Guidance . In the event of Applicable Guidance that is contrary to any Plan provision, the Employer, as of the effective date of the Applicable Guidance, will operate the Plan in conformance therewith and will disregard any inconsistent Plan provision. Any such Applicable Guidance is deemed to be incorporated by reference into the Plan and to supersede any contrary provision during any period in which the Employer is permitted to comply operationally with the Applicable Guidance and before a formal Plan amendment is required.

IN WITNESS WHEREOF, PacifiCorp has caused this instrument to be signed by its duly authorized officer on this ___ day of December, 2006.

		PACIFICORP
		By:

		Greg E. Abel, Chairman of the Board of Directors

INTERNAL CORRESPONDENCE

Exhibit 10.14

Date:		May 30, 2005

To:		David Mendez

From:		Richard Peach

Subject: Retention Agreement

You have been identified as being critical to our success as we proceed through the challenges and work associated with the Finance and Sarbanes initiatives. To encourage you to continue your employment through this period, the Company is offering you the following special payments (“Retention Bonus”):

•

A payment in the amount of $50,000 (less applicable withholding) on June 1, 2006.

•

A payment in the amount of $50,000 (less applicable withholding) on June 1, 2007

Performance Milestone:

During the defined period, the employee is to identify an individual(s) as successors and act as a mentor. The purpose of this is to begin building a solid internal development structure for future growth and succession within the team.

This retention award will be included in your paycheck at the time of payment. The above dates reflect PacifiCorp pay dates.

Payments comprising the Retention Bonuses are subject to applicable payroll deductions and tax withholding and may constitute taxable income to you. You are responsible for all tax obligations and should consult with your own tax advisor regarding the tax treatment of the Retention Bonuses.

In addition to the performance milestone noted above, in order to be eligible for the first payment, you must remain employed in your present department within PacifiCorp through May 30, 2006 and maintain an acceptable level of performance (as determined by management) during this period. In order to be eligible for the second payment, you must remain within the ScottishPower group through May 30, 2007 and maintain an acceptable level of performance (as determined by management). If you leave the Company voluntarily or involuntarily for cause prior to these dates, or transfer out of your present department voluntarily, you will automatically forfeit all rights to any unpaid Retention Bonuses. If you are terminated involuntarily due to displacement following a workforce reduction prior to any unpaid Retention Bonuses, you will be paid the amount of any unpaid Retention Bonus specified in this memo at the time of termination. You must also meet the other terms and conditions identified in this memorandum.

This offer is considered confidential. As a condition to receiving the Retention Bonus, you agree to keep confidential the terms and conditions of this memorandum as well as the content of discussions pertaining to the offer of the Retention Bonus and this memorandum. You may, however, discuss the offer of the Retention Bonus and this memorandum with your attorney, financial advisor or immediate family members on a confidential basis. Should you have any questions about this memorandum you may contact me or Erich Wilson in the Compensation department.

Page 2

Retention Agreement - Mendez

Again, thank you for your many contributions to date. I am pleased to be able to demonstrate our appreciation and recognition of your skills and contributions to the Company in this way. Please acknowledge your acceptance of this offer by signing and returning the enclosed copy of this memorandum.

/s/ Richard Peach			/s/ David Mendez
Richard Peach			David Mendez

4/19/05			4/21/05
Date			Date

EXHIBIT 12.1

PACIFICORP

STATEMENTS OF COMPUTATION OF RATIO

OF EARNINGS TO FIXED CHARGES

(IN MILLIONS OF DOLLARS)

	Nine Months Ended December 30, 2006			Years ended March 31,

				2006			2005			2004			2003

Fixed Charges, as defined:*
Interest expense	$	215.3		$	279.9		$	267.4		$	256.5		$	270.3
Estimated interest portion of rentals charged to expense		6.2			9.6			8.7			9.8			7.0
Preferred dividends of wholly owned subsidiaries *		—			—			—			18.5			47.7

Total fixed charges	$	221.5		$	289.5		$	276.1		$	284.8		$	325.0

Earnings, as defined:*
Income (loss) from continuing operations	$	160.9		$	360.7		$	251.7		$	249.0		$	142.0
Add (deduct):
Provision for income taxes		85.7			199.4			168.5			144.5			97.2
Minority interest		0.9			0.2			0.4			—			—
Undistributed loss (income) of less than 50% owned affiliates		—			—			—			—			—
Fixed charges as above		221.5			289.5			276.1			284.8			325.0

Total earnings	$	469.0		$	849.8		$	696.7		$	678.3		$	564.2

Ratio of Earnings to Fixed Charges		2.1	x		2.9	x		2.5	x		2.4	x		1.7	x

Fixed charges represent consolidated interest charges, an estimated amount representing the interest factor in rents and preferred dividends of wholly-owned subsidiaries. Preferred dividends of wholly-owned subsidiaries represents preferred dividends multiplied by the ratio which pre-tax income from continuing operations bears to income from continuing operations. Earnings represent the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees.

EXHIBIT 12.2

PACIFICORP

STATEMENTS OF COMPUTATION OF RATIO

OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

(IN MILLIONS OF DOLLARS)

		Nine Months Ended December 30, 2006	Years ended March 31,

				2006		2005		2004		2003

Fixed Charges, as defined:*
Interest expense	$	215.3	$	279.9	$	267.4	$	256.5	$	270.3
Estimated interest portion of rentals charged to expense		6.2		9.6		8.7		9.8		7.0
Preferred dividends of wholly owned subsidiaries		—		—		—		18.5		47.7

Total fixed charges		221.5		289.5		276.1		284.8		325.0
Preferred stock dividends as defined:*		2.4		3.2		3.5		5.3		12.2

Total fixed charges and preferred dividends	$	223.9	$	292.7	$	279.6	$	290.1	$	337.2

Earnings, as defined:*
Income (loss) from continuing
operations	$	160.9	$	360.7	$	251.7	$	249.0	$	142.0
Add (deduct):
Provision for income taxes		85.7		199.4		168.5		144.5		97.2
Minority interest		0.9		0.2		0.4		—		—
Undistributed loss (income) of less than 50% owned affiliates		—		—		—		—		—
Fixed charges as above		221.5		289.5		276.1		284.8		325.0

Total earnings	$	469.0	$	849.8	$	696.7	$	678.3	$	564.2

Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		2.1x		2.9x		2.5x		2.3x		1.7x

Fixed charges represent consolidated interest charges, an estimated amount representing the interest factor in rents and preferred dividends of wholly-owned subsidiaries. Preferred stock dividends represent preferred dividend requirements multiplied by the ratio which pre-tax income from continuing operations bears to income from continuing operations. Earnings represent the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees.

Exhibit 14.1

PACIFICORP

CODE OF ETHICS FOR CHIEF EXECUTIVE OFFICER, CHIEF FINANCIAL OFFICER AND OTHER COVERED OFFICERS

A. SCOPE.

PacifiCorp’s parent company, MidAmerican Energy Holdings Company, has a Code of Business Conduct for Managers and Rules of Conduct for All Employees (collectively, the “Rules of Conduct”) that establish standards addressing, among other things, business conduct, improper payment, the proper recording and disclosure of funds or assets, and financial reporting. The Rules of Conduct are applicable to, among others, PacifiCorp’s principal executive officer, principal financial officer, principal accounting officer or controller, and any president, or persons performing similar functions (collectively the “Covered Officers”). To further reinforce the Rules of Conduct, the Covered Officers are subject to the following Code of Ethics.

B. PURPOSE.

PacifiCorp (the “Company”) is proud of the values with which it and its subsidiaries conduct business. It has and will continue to uphold the highest levels of business ethics and personal integrity in all types of transactions and interactions. To this end, this Code of Ethics serves to (1) emphasize the Company’s commitment to ethics and compliance with the law; (2) set forth basic standards of ethical and legal behavior; (3) provide reporting mechanisms for known or suspected ethical or legal violations; and (4) help prevent and detect wrongdoing.

Given the variety and complexity of ethical questions that may arise in the course of business of the Company and its subsidiaries, this Code of Ethics serves only as a rough guide. Confronted with ethically ambiguous situations, the Covered Officers should remember the Company’s commitment to the highest ethical standards and seek independent advice, where necessary, to ensure that all actions they take on behalf of the Company and its subsidiaries honor this commitment.

C. ETHICS STANDARDS.

1. Honest and Ethical Conduct.

The Covered Officers shall behave honestly and ethically at all times and with all people. They shall act in good faith, with due care, and shall engage only in fair and open competition, by treating ethically competitors, suppliers, customers, and colleagues. They shall not misrepresent facts or engage in illegal, unethical, or anti-competitive practices for personal or professional gain.

This fundamental standard of honest and ethical conduct extends to the handling of conflicts of interest. The Covered Officers shall avoid any actual, potential, or apparent conflicts of interest with the Company and its subsidiaries and any personal activities, investments, or associations that might give rise to such conflicts. They shall not compete with or use the Company or any of its subsidiaries for personal gain, self-deal, or take advantage of corporate opportunities. They shall act on behalf of the Company and its subsidiaries free from improper influence or the appearance of improper influence on their judgment or performance of duties. A Covered Officer shall disclose any material transaction or relationship that reasonably could be expected to give rise to such a conflict to the MidAmerican Energy Holdings Company General Counsel or the Chair of the Audit Committee of MidAmerican Energy Holdings Company’s Board of Directors. No action may be taken with respect to such transaction or party unless and until the General Counsel and the Audit Committee has approved such action.

2. Timely and Truthful Disclosure.

In reports and documents filed with or submitted to the Securities and Exchange Commission and other regulators by the Company or its subsidiaries, and in other public communications made by the Company or its subsidiaries, the Covered Officers shall make disclosures that are full, fair, accurate, timely, and understandable. The Covered Officers shall provide thorough and accurate financial and accounting data for inclusion in such disclosures. The Covered Officers shall not knowingly conceal or falsify information, misrepresent material facts, or omit material facts necessary to avoid misleading the Company’s or any of its subsidiaries’ independent public auditors or investors.

3. Legal Compliance.

In conducting the business of the Company and its subsidiaries, the Covered Officers shall comply with applicable governmental laws, rules, and regulations at all levels of government in the United States and in any non-U.S. jurisdiction in which the Company or any of its subsidiaries does business, as well as applicable rules and regulations of self-regulatory organizations of which the Company or any of its subsidiaries is a member. If the Covered Officer is unsure whether a particular action would violate an applicable law, rule, or regulation, he or she should seek the advice of inside counsel (if available), and, where necessary, outside counsel before undertaking it.

D. VIOLATIONS OF ETHICAL STANDARDS.

1. Reporting Known or Suspected Violations.

The Covered Officers will promptly bring to the attention of the MidAmerican Energy Holdings Company General Counsel or the Chair of the MidAmerican Energy Holdings Company Audit Committee any information concerning a material violation of any of the laws, rules or regulations applicable to the Company and the operation of its businesses, by the Company or any agent thereof, or of violation of the Rules of Conduct, or the Code of Ethics. Reports of violations will be investigated by the MidAmerican Energy Holdings Company General Counsel and the findings communicated to the Audit Committee.

2. Accountable for Violations.

If the Audit Committee determines that this Code of Ethics has been violated, either directly, by failure to report a violation, or by withholding information related to a violation, it may discipline the offending Covered Officer for non-compliance with penalties up to and including termination of employment. Violations of this Code of Ethics may also constitute violations of law and may result in criminal penalties and civil liabilities for the offending Covered Officer and the Company or its subsidiaries.

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements Nos. 333-140611 and 333-128134 on Form S-3 of our report dated February 27, 2007 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 158 as of December 31, 2006), relating to the consolidated financial statements of PacifiCorp and its subsidiaries, appearing in this Transition Report on Form 10-K of PacifiCorp for the nine-month period ended December 31, 2006.

/s/ Deloitte & Touche LLP
Deloitte & Touche LLP

Portland, Oregon
February 27, 2007

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-140661 and 333-128134) of PacifiCorp of our report dated May 26, 2006, relating to the financial statements, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Portland, Oregon
February 28, 2007

Exhibit 24

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints David J. Mendez his true and lawful attorney and agent, with full power of substitution and resubstitution for him and in his name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the fiscal year ended December 31, 2006 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney and agent full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney and agent or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Dated: February 21, 2007.


		/s/ GREGORY E. ABEL
		Gregory E. Abel

POWER OF ATTORNEY

Dated: February 22, 2007.


		/s/ DOUGLAS L. ANDERSON
		Douglas L. Anderson

POWER OF ATTORNEY

Dated: February 22, 2007.


		/s/ WILLIAM J. FEHRMAN
		William J. Fehrman

POWER OF ATTORNEY

Dated: February 21, 2007.


		/s/ BRENT E. GALE
		Brent e. Gale

POWER OF ATTORNEY

Dated: February 22, 2007.


		/s/ PATRICK J. GOODMAN
		Patrick J. Goodman

POWER OF ATTORNEY

Dated: February 28, 2007.


		/s/ NOLAN E. KARRAS
		Nolan E. Karras

POWER OF ATTORNEY

Dated: February 22, 2007.


		/s/ A. ROBERT LASICH
		A. Robert Lasich

POWER OF ATTORNEY

Dated: February 26, 2007.


		/s/ MARK C. MOENCH
		Mark C. Moench

POWER OF ATTORNEY

Dated: February 26, 2007.


		/s/ A. RICHARD WALJE
		A. Richard Walje

POWER OF ATTORNEY

Dated: February 28, 2007.


		/s/ STANLEY K. WATTERS
		Stanley K. Watters

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Gregory E. Abel, certify that:

1)	I have reviewed this transition report on Form 10-K of PacifiCorp;

2)	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3)	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4)	The registrant’s other certifying officer(s)and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant’s internal control over financial reporting; and

5)	The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


	Date: March 1, 2007		/s/ Gregory E. Abel
			/s/ Gregory E. Abel
			Gregory E. Abel
			Chairman of the Board of Directors and Chief Executive Officer, PacifiCorp

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, David J. Mendez, certify that:

1)	I have reviewed this transition report on Form 10-K of PacifiCorp;

2)	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3)	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4)	The registrant’s other certifying officer(s)and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant’s internal control over financial reporting; and

5)	The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


	Date: March 1, 2007		/s/ David J. Mendez
			/s/ David J. Mendez
			David J. Mendez
			Chief Financial Officer, PacifiCorp

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Transition Report of PacifiCorp (the “Company”) on Form 10-K for the nine-month period ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gregory E. Abel, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 1, 2007			/s/ Gregory E. Abel

			Gregory E. Abel
			Chairman of the Board of Directors and Chief Executive Officer, PacifiCorp

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Transition Report of PacifiCorp (the “Company”) on Form 10-K for the nine-month period ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David J. Mendez, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date: March 1, 2007	By:	/s/ David J. Mendez
		David J. Mendez
		Chief Financial Officer, PacifiCorp