PACIFICORP /OR/ - Annual Report: 2008 (Form 10-K)

pacificorp10k2007.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2007

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _____ to _____

Commission	Exact name of registrant as specified in its charter	IRS Employer
File Number	State or other jurisdiction of incorporation or organization	Identification No.

1-5152	PACIFICORP	93-0246090
	(An Oregon Corporation)
	825 N.E. Multnomah Street
	Portland, Oregon 97232
	503-813-5000

N/A
(Former name, former address and former fiscal year, if changed since last report)

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 T No o

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 T

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 T 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. T

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer T

Smaller reporting company o

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

Yes o No T

As of January 31, 2008, 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

PART I

Item 1.	Business	3
Item 1A.	Risk Factors	28
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	36
Item 4.	Submission of Matters to a Vote of Security Holders	37

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	61
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	105
Item 9A(T).	Controls and Procedures	105
Item 9B.	Other Information	105

PART III

Item 10.	Directors, Executive Officers and Corporate Goverance	106
Item 11.	Executive Compensation	107
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	116
Item 13.	Certain Relationships and Related Transactions, and Director Independence	117
Item 14.	Principal Accountant Fees and Services	118

PART IV

Item 15.	Exhibits and Financial Statement Schedules	120
Signatures		122

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,” “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:

·	General economic, political and business conditions in the jurisdictions in which PacifiCorp’s facilities are located;

·	Changes in governmental, legislative or regulatory requirements affecting PacifiCorp or the electric utility industry, including limits on the ability of public utilities to recover income tax expense in rates, such as Oregon Senate Bill 408;

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

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

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

·	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;

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

·	Financial condition and creditworthiness of significant customers and suppliers;

·	Changes in business strategy or development plans;

·	Availability, terms and deployment of capital;

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

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

·	The impact of increases in health care costs, changes in interest rates, mortality, morbidity and investment performance on pension and other post-retirement benefits expense, as well as the impact of changes in legislation on funding requirements;

·	Changes in PacifiCorp’s credit ratings;

·	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;

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

·	Other risks or unforeseen events, including litigation and 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 filings with the United States Securities and Exchange Commission (the “SEC”) 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 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.

PART I

ITEM 1. BUSINESS

OVERVIEW

Ownership by MidAmerican Energy Holdings Company

On March 21, 2006, a wholly owned subsidiary of MidAmerican Energy Holdings Company (“MEHC”) acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of Scottish Power plc (“ScottishPower”). As a result of the acquisition, MEHC controls substantially all of PacifiCorp’s voting securities, which include both common and preferred stock. MEHC, a holding company owning subsidiaries that are principally engaged in energy businesses, is a consolidated 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 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.

Operations

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States regulated electricity company serving 1.7 million retail customers, including residential, commercial, industrial and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, 68 thermal, hydroelectric and wind-powered generating plants, with a plant net capacity of 9,286 megawatts (“MW”). PacifiCorp also owns, or has interests in, electric transmission and distribution assets, and transmits electricity through approximately 15,700 miles of transmission lines. PacifiCorp buys and sells electricity on the wholesale market with public and private utilities, energy marketing companies and incorporated municipalities in connection with excess electricity generation or other system balancing activities. The regulatory commission in each state approves rates for retail electric sales within that state. Subsidiaries of PacifiCorp support its electric utility operations by providing coal-mining facilities and services and environmental remediation services.

PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power. PacifiCorp’s electric generation, commercial and 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’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.

PacifiCorp is experiencing growth in retail loads and expects this to continue for the foreseeable future. PacifiCorp seeks to manage this growth in customer demand through the construction and purchase of new cost-effective, environmentally prudent and efficient sources of power supply and through demand response and energy efficiency programs. During 2007, PacifiCorp added the 548-MW Lake Side natural gas-fired plant and the 140-MW (nameplate rating) Marengo wind plant, as well as expanded the capacity at its Blundell geothermal facility by 11 MW, to help meet its retail load growth and replace expiring wholesale supply contracts.

During 2008, PacifiCorp expects to place into service wind plants totaling 461 MW or more. Additionally, PacifiCorp continues to pursue other cost-effective wind plants scheduled for completion in 2009 and beyond. PacifiCorp is also investing in its transmission and distribution system to integrate 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.

Employees

As of December 31, 2007, PacifiCorp, together with its subsidiaries, had 6,470 employees, 61% of which were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America.

Fiscal Year-End Change

In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. As a result of PacifiCorp’s election to change its fiscal year from March 31 to December 31, the audited periods presented in the Consolidated Statements of Income include the year ended December 31, 2007, the nine-month transition period ended December 31, 2006 and the year ended March 31, 2006.

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. Refer to “Wholesale Sales and Purchased Electricity” below for more information.

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,
	2007			2006			2006

Coal		64	%		62	%		68	%
Natural gas		11			7			4
Hydroelectric		5			6			6
Other		1			1			-
Total energy generated		81			76			78
Energy purchased-long-term contracts		5			7			9
Energy purchased-short-term contracts and other		14			17			13
		100	%		100	%		100	%

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 snow-pack levels, other weather-related impacts, 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, 2007:

					Facility Net		Net
	Location	Energy Source	Installed		Capacity (MW) (a)(b)		MW Owned (a)(c)
Coal:
Jim Bridger	Rock Springs, WY	Coal		1974-1979		2,120		1,414
Huntington	Huntington, UT	Coal		1974-1977		895		895
Dave Johnston	Glenrock, WY	Coal		1959-1972		762		762
Naughton	Kemmerer, WY	Coal		1963-1971		700		700
Hunter No. 1	Castle Dale, UT	Coal	1978			430		403
Hunter No. 2	Castle Dale, UT	Coal	1980			430		259
Hunter No. 3	Castle Dale, UT	Coal	1983			460		460
Cholla No. 4	Joseph City, AZ	Coal	1981			380		380
Wyodak	Gillette, WY	Coal	1978			335		268
Carbon	Castle Gate, UT	Coal		1954-1957		172		172
Craig Nos. 1 and 2	Craig, CO	Coal		1979-1980		856		165
Colstrip Nos. 3 and 4	Colstrip, MT	Coal		1984-1986		1,480		148
Hayden No. 1	Hayden, CO	Coal		1965-1976		184		45
Hayden No. 2	Hayden, CO	Coal		1965-1976		262		33
						9,466		6,104
Natural Gas:
Lake Side	Vineyard, UT	Natural Gas/Steam	2007			548		548
Currant Creek	Mona, UT	Natural Gas/Steam		2005-2006		540		540
Hermiston	Hermiston, OR	Natural Gas/Steam	1996			474		237
Gadsby Steam	Salt Lake City, UT	Natural Gas		1951-1952		235		235
Gadsby Peakers	Salt Lake City, UT	Natural Gas	2002			120		120
Little Mountain	Ogden, UT	Natural Gas	1972			14		14
						1,931		1,694
Hydroelectric: (d)
Swift No. 1	Cougar, WA	Lewis River	1958			264		264
Merwin	Ariel, WA	Lewis River		1931-1958		151		151
Yale	Amboy, WA	Lewis River	1953			163		163
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River		1950-1956		141		141
John C. Boyle	Keno, OR	Klamath River	1958			83		83
Copco Nos. 1 and 2	Hornbrook, CA	Klamath River		1918-1925		62		62
Clearwater Nos. 1 and 2	Toketee Falls, OR	Clearwater River	1953			49		49
Grace	Grace, ID	Bear River		1908-1923		33		33
Prospect No. 2	Prospect, OR	Rogue River	1928			36		36
Cutler	Collingston, UT	Bear River	1927			29		29
Oneida	Preston, ID	Bear River		1915-1920		28		28
Iron Gate	Hornbrook, CA	Klamath River	1962			19		19
Soda	Soda Springs, ID	Bear River	1924			14		14
28 Minor Hydroelectric Plants (e)	Various	Various		1895-1990		86		86
						1,158		1,158
Wind:
Foote Creek	Arlington, WY	Wind	1997			41		33
Leaning Juniper 1	Arlington, OR	Wind	2006			101		101
Marengo	Dayton, WA	Wind	2007			140		140
						282		274
Other:
Camas Co-Gen	Camas, WA	Black Liquor	1996			22		22
Blundell	Milford, UT	Geothermal		1984, 2007		34		34
						56		56

Total available generating capacity						12,893		9,286

Projects under construction: (f)
Goodnoe Hills	Goldendale, WA	Wind	2008			94		94
Marengo expansion	Dayton, WA	Wind	2008			70		70
Glenrock	Glenrock, WY	Wind	2008			99		99
Rolling Hills	Glenrock, WY	Wind	2008			99		99
Seven Mile Hill	Medicine Bow, WY	Wind	2008			99		99
						461		461

(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. Net MW owned indicates current legal ownership.
(b)	For wind plants, nameplate ratings are used in place of facility net capacity. A generator’s nameplate rating is its full-load capacity (in MW) under normal operating conditions as defined by the manufacturer.
(c)	All or some of the renewable energy attributes associated with generation from these facilities may be used in future years to comply with state or federal renewable portfolio standards (“RPS”).
(d)	Hydroelectric project locations are stated by locality and river watershed.
(e)	For information regarding the decommissioning of certain of PacifiCorp’s hydroelectric plants, refer to “Hydroelectric Decommissioning” below.
(f)	Expected to be complete by the end of 2008.

Future Generation and Conservation

Integrated Resource Plans

As required by certain state regulations, PacifiCorp uses an Integrated Resource Plan (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. When the IRP is filed, each state commission with IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines. PacifiCorp requests “acknowledgement” of its IRP filing from the Utah Public Service Commission (the “UPSC”), the Oregon Public Utility Commission (the “OPUC”), the Idaho Public Utilities Commission (the “IPUC”) and the Washington Utilities and Transportation Commission (the “WUTC”) pursuant to those states’ IRP adequacy rules. The IRP can be used as evidence by parties in rate-making or other regulatory proceedings. PacifiCorp files its IRP on a biennial basis.

In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for approximately 3,171 MW of additional resources by summer 2016 to satisfy the difference between projected retail load obligations and available resources. PacifiCorp plans to meet this need through demand response and energy efficiency programs; the construction or purchase of additional generation, including cost-effective renewable energy, combined heat and power, and thermal generation; and wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources. PacifiCorp is currently seeking acknowledgement of its 2007 IRP from state regulators and expects the acknowledgement process to be complete in 2008.

Requests for Proposal

PacifiCorp has issued a series of separate requests for proposal (“RFP”), each of which focuses on a specific category of resources as provided in the IRP. The IRP and the RFP provide for the identification and staged procurement of resources in future years to achieve load/resource balance. As required by applicable laws and regulations, PacifiCorp files draft RFP with the UPSC, the OPUC and the WUTC prior to issuance to the market.

In February 2007, PacifiCorp filed a modified 2012 RFP in Utah for up to 1,700 MW of additional resources to become available beginning in 2012 through 2014. The RFP was approved by the UPSC and issued to the market in April 2007. In June 2007, proposals from qualifying bidders were received by commission-directed independent evaluators. These bids included various structures, ranging from purchase or lease of coal, natural gas, and geothermal power plants to power purchase agreements. PacifiCorp initiated negotiations with short-listed bidders in January 2008.

In January 2008, PacifiCorp issued to the market a 2008 renewable RFP for less than 100 MW or greater than 100 MW for a power purchase agreement with a term of less than five years, to become available prior to December 2009.

In February 2008, PacifiCorp filed an all source 2008 RFP with the UPSC, the OPUC and the WUTC for base load, intermediate or third quarter summer peaking products delivered into PacifiCorp’s system. The all source 2008 RFP seeks up to 2,000 MW of resources to become available beginning in 2012 through 2016.

In addition to new generation resources, substantial transmission investments are expected to be required to deliver energy to PacifiCorp’s growing customer base and to enhance system reliability. The actual investment requirement will depend on the location and other characteristics of the new generation resources. Refer to “Transmission and Distribution” below.

Demand-side Management

PacifiCorp has provided a comprehensive set of demand-side management programs to its customers since the 1970s. The programs are designed to reduce growth in peak load and energy consumption. Current programs offer customers services such as energy engineering and audits, as well as rebates for high efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors and process equipment and systems; new construction; and load management (curtailment) programs for large commercial and industrial customers and residential customers whose central air conditioners are controlled during summer peak load periods. Subject to random prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for demand-side management programs and services through the energy efficiency service charges to all retail electric customers. In 2007, $53 million was expended on the demand-side management programs in PacifiCorp’s six-state service area, resulting in an estimated 300,000 megawatt hours (“MWh”) of first year energy savings and 170 MW of peak load management.

Coal

PacifiCorp’s coal generation portfolio consists of 11 plants with a net owned capacity of 6,104 MW. These plants account for 66% of PacifiCorp’s total net owned generating capacity. As of December 31, 2007, PacifiCorp had an estimated 232 million tons of recoverable coal reserves in company-owned or leased mines, including those related to the underground mine described below. These mines supplied 31% of PacifiCorp’s total coal requirements during the year ended December 31, 2007 and the nine-month period ended December 31, 2006, compared to 32% during the year ended March 31, 2006. The remaining coal requirements are acquired through long- and short-term third-party 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.

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 to supply its remaining plants, will be substantially sufficient to provide these plants with fuel for their currently expected useful lives. To meet applicable standards, PacifiCorp blends coal mined at its owned mines with contracted coal, and utilizes electricity plant technologies for controlling sulfur dioxide and other emissions.

In an effort to lower costs and obtain better quality coal, the Jim Bridger mine developed an underground mine to access 57 million tons of PacifiCorp’s coal reserves. Sustained operations at the underground mine commenced in March 2007 and production continues at its surface operations. The life of the underground mine is expected to be approximately 15 years.

During the year ended December 31, 2007, PacifiCorp-owned plants held sufficient sulfur dioxide emission allowances to comply with the Environmental Protection Agency (the “EPA”) Title IV requirements. The sulfur content of the coal reserves generally ranges from 0.30% to 0.94%, and the British thermal units value per pound of PacifiCorp’s coal reserves ranges from 8,600 to 12,400.

Recoverable coal reserves as of December 31, 2007, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):

Location	Plant Served	Mining Method	Recoverable Tons

Craig, CO	Craig	Surface		47	(a)
Huntington & Castle Dale, UT	Huntington and Hunter	Underground		45	(b)
Rock Springs, WY	Jim Bridger	Surface/Underground		140	(c)
				232

(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%.
(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. The amount included above represents only PacifiCorp’s two-thirds interest in the coal reserves.

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. Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. Most of PacifiCorp’s coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended only with the consent of the lessor and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities. Refer to Note 7 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on asset retirement obligations.

Natural Gas

PacifiCorp’s natural gas-fired generation portfolio consists of five plants with a net owned capacity of 1,694 MW, including the 548-MW Lake Side plant, which commenced full combined-cycle operation in September 2007. These plants account for 18% of PacifiCorp’s total net owned generating capacity. PacifiCorp also leases, through May 2008, one natural gas-fired peaking plant with a net capacity of 200 MW.

PacifiCorp uses natural gas as fuel for its combined- and simple-cycle natural gas-fired plants. Oil and natural gas are also used for igniter fuel and to fuel generation for transmission support and standby purposes. Although these sources are presently in adequate supply and available to meet PacifiCorp’s needs, the increase in 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 procurement strategy that addresses the need to economically hedge the estimated commodity risk (physical availability and price), transportation risk and storage risk associated with its forecasted natural gas requirements.

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 forecasted physical natural gas requirements 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, 2007, PacifiCorp had economically hedged 82% of its forecasted physical exposure and 97% of its financial exposure for 2008. For 2009, PacifiCorp currently has hedged 61% of its physical exposure and 84% of its financial exposure.

Hydroelectric

PacifiCorp’s hydroelectric portfolio consists of 47 plants with a net owned capacity of 1,158 MW. These plants account for 12% of PacifiCorp’s total net 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 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 snow-pack in the mountains upstream of its hydroelectric plants, 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 Federal Energy Regulatory Commission (the “FERC”) with terms of 30 to 50 years. Several of PacifiCorp’s long-term operating licenses have expired and they are operating under temporary annual licenses issued by the FERC 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, 2007 and 2006, PacifiCorp had incurred $89 million and $79 million, respectively, in costs for ongoing hydroelectric relicensing, which are included in Construction work-in-progress in the Consolidated Balance Sheets. Refer to “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. The intermittent nature of some renewable resources, such as wind, is complemented by other generating resources, such as thermal or hydroelectric generation, which are important to integrating intermittent wind resources into the electric system.

PacifiCorp currently generates power and associated energy from wind and other renewable resources through three PacifiCorp-owned wind plants (in Oregon, Washington and Wyoming), including the 140-MW (nameplate rating) Marengo wind plant that was placed into service in August 2007. PacifiCorp also acquires power and associated energy from renewable resources through various power purchase agreements, some associated with wind plants in Oregon, Wyoming, Utah and Idaho, and others associated with resources defined as “qualifying facilities” pursuant to the Public Utility Regulatory Policies Act. In addition to these wind plant resources, PacifiCorp owns a geothermal plant in Utah.

In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp committed to state regulatory commissions to bring at least 100 MW (nameplate ratings) of cost-effective wind resources into service by March 21, 2007, and, to the extent available, have 400 MW (nameplate ratings) (inclusive of the 100 MW (nameplate ratings) commitment) of cost-effective new renewable resources in PacifiCorp’s generation portfolio by December 31, 2007. PacifiCorp met the requirements of its commitment to bring 100 MW of cost-effective wind resources into service by March 21, 2007 with the completion of the 101-MW Leaning Juniper 1 wind plant, which was placed into service in September 2006. PacifiCorp has also met the requirements of its commitment to have 400 MW (nameplate ratings) of cost-effective new renewable resources in its portfolio by December 31, 2007 by completing the 140-MW (nameplate rating) Marengo wind plant, which was placed into service in August 2007; entering into power purchase agreements for output associated with the 65-MW Wolverine Creek wind plant and two biomass facilities owned by retail customers for 20 MW and 10 MW; completion of a 11-MW bottoming cycle to the Blundell geothermal facility; and beginning construction of the 94-MW Goodnoe Hills wind plant, which is expected to be placed into service during 2008.

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 and long-term wholesale obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long term. PacifiCorp’s total energy requirements supplied by purchased electricity, under long- and short-term purchase arrangements, were 19% during the year ended December 31, 2007; 24% during the nine-month period ended December 31, 2006; and 22% during the year ended March 31, 2006. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. These wholesale activities are regulated by the FERC.

PacifiCorp enters into wholesale purchase and sale transactions to balance its electricity supply when generation and retail loads are higher or lower than expected. Generation can vary with the levels of outages, hydroelectric and wind generation conditions, operational factors and transmission constraints. Retail load can vary 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. Delivery of these purchases is 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.

TRANSMISSION AND DISTRIBUTION

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

Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. During the year ended December 31, 2007, PacifiCorp delivered 67,114 gigawatt-hours (“GWh”), net of line losses, of electricity to retail and wholesale customers in its two balancing authority areas through approximately 15,700 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 Electricity Coordinating Council (the “WECC”). The map under “Service Territories” below shows PacifiCorp’s primary 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, 2007, PacifiCorp owned, or participated in, an electric transmission system consisting of approximately:

Nominal Voltage
(In kilovolts)
Transmission Lines	Miles
500		700
345		2,000
230		3,300
161		400
138		2,100
115		1,500
69		3,000
57		100
49		2,600
		15,700

As of December 31, 2007, PacifiCorp owned approximately 900 transmission and distribution substations.

PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s Open Access Transmission Tariff (“OATT”). In accordance with OATT, 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, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from 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. Refer to “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; FERC Order 693, which addresses the FERC’s responsibility for establishing and enforcing electric reliability standards; and FERC Orders 890 and 890-A, which address OATTs.

In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp committed to state regulatory commissions to spend approximately $520 million in investments (to be made over several years following the acquisition 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. As of December 31, 2007, PacifiCorp had incurred $112 million of capital expenditures and $16 million of operating expenses pursuant to this commitment.

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The estimated $4.1 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the Western United States. These transmission lines are expected to be placed into service beginning 2010 and continuing through 2014. PacifiCorp is also collaborating with other utilities to address transmission needs, including new development and system reliability.

SERVICE TERRITORIES

PacifiCorp serves approximately 1.7 million regulated 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 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 law does not provide for exclusive service territory allocation. PacifiCorp’s service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC.

The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urban, manufacturing and government service centers. No single segment of the economy dominates the service territory, which helps mitigate 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, agriculture 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, 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 transmission lines owned by others.

(a)	Access to other entities’ transmission lines through wheeling arrangements.
(b)	Access to other entities’ transmission lines through OATTs.

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

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31, 2007			December 31, 2006			March 31, 2006

Utah		43	%		42	%		41	%
Oregon		29			29			29
Wyoming		13			13			13
Washington		7			8			9
Idaho		6			6			6
California		2			2			2
		100	%		100	%		100	%

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 attempts from individuals and governmental entities to undertake forced takeover of portions of its service territory.

CUSTOMERS

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

					Nine-Month
	Year Ended				Period Ended				Year Ended
	December 31, 2007				December 31, 2006				March 31, 2006
GWh sold:
Residential		15,975	24	%		11,158	22	%		14,880	23	%
Commercial		15,951	24			11,713	24			14,887	24
Industrial		20,892	31			15,719	32			19,746	31
Other		572	1			439	1			599	1
Total retail		53,390	80			39,029	79			50,112	79

Wholesale		13,724	20			10,284	21			13,381	21

Total GWh sold		67,114	100	%		49,313	100	%		63,493	100	%

Average number of retail customers (in thousands):
Residential		1,441	86	%		1,415	86	%		1,388	86	%
Commercial		205	12			200	12			196	12
Industrial		34	2			34	2			34	2
Other		4	-			4	-			4	-
Total		1,684	100	%		1,653	100	%		1,622	100	%

Retail customers:
Average usage per customer (kilowatt hours)		31,712				23,607				30,895
Average revenue per customer	$	1,931			$	1,358			$	1,732
Revenue per kilowatt hour		6¢				6¢				6¢

PacifiCorp is estimating growth in retail MWh sales in PacifiCorp’s franchise service territories to average between 1% and 3% annually over the next five years, with significant growth estimated in Wyoming due to the extraction of natural resources and large oil and natural gas industrial development within the state. Customer 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 in the western portion of PacifiCorp’s service territory primarily due to heating requirements and 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 have contributed to increased summer peak load growth. During the year ended December 31, 2007, PacifiCorp’s peak load was 9,775 MW in the summer and 8,650 MW in the winter. During the year ended December 31, 2007, PacifiCorp’s average load was 7,185 MW for the summer and 7,028 MW for the winter.

RETAIL COMPETITION

During the year ended December 31, 2007, 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 load of approximately 12 average MW have chosen service from suppliers other than PacifiCorp. PacifiCorp does not expect this competitive program to have a material effect on its financial results during the year ending December 31, 2008.

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.

REGULATORY MATTERS

PacifiCorp is subject to comprehensive regulation by the FERC, the UPSC, the OPUC, the Wyoming Public Service Commission (the “WPSC”), the WUTC, the IPUC, the California Public Utilities Commission (the “CPUC”), the WECC, and other federal, state and local regulatory agencies. These authorities regulate various matters, including, but not limited to, customer rates, service territories, allocation of costs by state, asset acquisitions and sales, wholesale sales and purchases of electricity, the operation of PacifiCorp’s electric generation and transmission facilities, 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

For a discussion of California and Northwest Refund cases, refer to Note 15 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

The Bonneville Power Administration Residential Exchange Program

The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration (the “BPA”) in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. In October 2000, PacifiCorp entered into a settlement agreement with the BPA that provided Residential Exchange Program benefits to PacifiCorp’s customers from October 2001 through September 2006. In May 2001, PacifiCorp entered into a load reduction agreement with the BPA that eliminated the BPA’s obligation to deliver power to PacifiCorp from October 2001 through September 2006 in exchange for cash payments. This agreement also contained a “reduction of risk discount” provision, which provided that the BPA would reduce the cash payments to PacifiCorp if by December 1, 2001, PacifiCorp and other utilities were able to negotiate and enter into settlement agreements with the publicly owned utilities and other of the BPA’s preference customers dismissing certain lawsuits. If these parties did not reach settlement by the specified date, the clause would expire and the BPA would make cash payments to PacifiCorp based on the original rate for the October 2002 through September 2006 period. Settlement was not reached and the clause expired, obligating the BPA to make the full cash payment to PacifiCorp. In May 2004, PacifiCorp, the BPA and other parties executed an additional agreement, which modified both the October 2000 and May 2001 agreements, which provides for a guaranteed range of benefits to customers from October 2006 through September 2011.

Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. In May 2007, the Ninth Circuit issued two decisions. The first decision sets aside the October 2000 Residential Exchange Program settlement agreement as being inconsistent with the BPA’s settlement authority. The second decision holds, among other things, that the BPA acted contrary to law when it allocated to its preference customers, which include public utilities, cooperatives and federal agencies, part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. As a result of the ruling, in May 2007, the BPA notified the Pacific Northwest’s six utilities, including PacifiCorp, that it was immediately suspending payments. This has resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho. In October 2007, the Ninth Circuit issued one published decision and three unpublished decisions. The published decision remanded the May 2004 agreement modifying the October 2000 and May 2001 agreements to the BPA for further action consistent with the Ninth Circuit’s May 2007 decisions. The other three unpublished decisions dismiss cases in which the publicly owned utilities sought review of the BPA’s decision to implement the reduction of risk discount provision and make the full cash payment to PacifiCorp. In February 2008, the BPA initiated a rate proceeding under section 7(i) of the Northwest Power Act to reconsider the level of benefits for the years 2002 through 2006 consistent with the Ninth Circuit’s decisions, to re-establish the level of benefits for years 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on PacifiCorp’s consolidated financial results.

FERC Market Oversight

FERC Order No. 693

In March 2007, the FERC issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System, which imposes penalties of up to $1 million per day per violation for failure to comply with new electric reliability standards. The FERC approved 83 reliability standards developed by the North American Electric Reliability Corporation (the “NERC”). Responsibility for compliance and enforcement of these standards has been given to the WECC. The 83 standards comprise over 600 requirements and sub-requirements with which PacifiCorp must comply. On June 18, 2007, the standards became mandatory and enforceable under federal law. PacifiCorp expects that the existing standards will change as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement. On January 18, 2008, the FERC approved eight additional cyber security and critical infrastructure protection standards proposed by the NERC. The additional standards will become effective on April 7, 2008. PacifiCorp cannot predict the effect that these standards will have on its consolidated financial results; however, they will likely have a significant impact on transmission operations and resource planning functions. Also during 2007, the WECC audited PacifiCorp’s compliance with several of the reliability standards approved by the FERC. PacifiCorp is analyzing the preliminary results of the audit and, at this time, cannot predict the impact of potential penalties, if any, on its consolidated financial results.

FERC Orders No. 890 and 890-A

In February 2007, the FERC adopted a final rule in Order No. 890 designed to strengthen the pro forma OATT by providing greater specificity and increasing transparency. The most significant revisions to the pro forma OATT 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 is required to comply with the requirements of the new rule. The first compliance filing, which amends the OATT, was filed in July 2007. Certain details related to the precise methodology that will be used to calculate available transfer capability were filed with the FERC in September 2007. A number of parties to the proceeding, including PacifiCorp, have requested rehearing or clarification of various portions of the final rule. In December 2007, the FERC issued Order No. 890-A generally affirming the provisions of the final rule as adopted in Order No. 890 with certain limited clarifications. Although PacifiCorp has requested a limited clarification of Order No. 890-A, the final rule as revised 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 as discussed above. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007, with subsequent legislation extending the credit to December 31, 2008. Partly as a result of that portion of the law, PacifiCorp began development efforts to add additional wind plants.

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 $1 million to other transmission customers in April 2006 and paid a $10 million fine to the United States Treasury in January 2007.

Wholesale Electricity and Capacity

The FERC regulates PacifiCorp’s rates charged to wholesale customers for electricity, capacity and transmission services. Most of PacifiCorp’s electric wholesale sales and purchases take place under market-based rate pricing allowed by the FERC and are therefore subject to market volatility. A December 2006 decision of the Ninth Circuit changed the interpretation of the relevant standard that the FERC should apply when reviewing wholesale contracts for electricity or capacity from a stringent “public policy” standard to a broader “just and reasonable” standard making contracts more vulnerable to challenge. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. The United States Supreme Court is reviewing the case on appeal and the outcome of its ruling 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 rate 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 balancing authority areas. Under the FERC’s market-based rules, PacifiCorp must file a notice of change in status when 100 MW of incremental generation becomes operational. Following separate filings by PacifiCorp of a change in status notice relating to new generation, the FERC in February and November 2007 confirmed that PacifiCorp does not have market power and may continue to charge market-based rates. In accordance with the filing schedule established by the FERC in Order No. 697, PacifiCorp’s next triennial review will occur in 2010.

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 certain 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-MW (nameplate rating) 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 expects to 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. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the hydroelectric project’s impact on endangered species under the proposed new FERC license. The United States Fish and Wildlife Service asserts the hydroelectric project is currently not covered by previously issued biological opinions, and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp disputes these assertions, and believes federal case law is clear that consultation on annual FERC licenses is not required. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

Lewis River Hydroelectric Projects – (Lewis River, Washington)

PacifiCorp filed new license applications for the 136-MW (nameplate rating) Merwin and 240-MW (nameplate rating) Swift No. 1 hydroelectric projects in April 2004. An application for a new license for the 134-MW (nameplate rating) 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 and other required permits that are consistent with the settlement agreement. PacifiCorp has received water quality certificates from the Washington Department of Ecology and biological opinions from the United States Fish and Wildlife Service and the National Marine Fisheries Service. Regulatory documents needed to license the projects have been submitted to the FERC and PacifiCorp is awaiting the issuance of new FERC licenses.

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 37 MW. The Oregon Department of Environmental Quality issued a 401 Water Quality certificate for the project in April 2007, which effectively concluded the license process. The FERC is expected to issue a new license before the end of May 2008.

Hydroelectric Decommissioning

Powerdale Hydroelectric Project – (Hood River, Oregon)

In June 2003, PacifiCorp entered into a settlement agreement to remove the 6-MW (nameplate rating) 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 dam and associated project features, which is subject to the FERC and other regulatory approvals, is projected to cost $6 million excluding inflation. Removal was 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. In May 2007, the FERC issued an order that approved PacifiCorp’s proposed accounting entries, thereby allowing PacifiCorp to reclassify the net book value and the estimated removal costs to a regulatory asset. PacifiCorp has received approval from its state commissions to defer and recover these costs.

Condit Hydroelectric Project – (White Salmon River, Washington)

In September 1999, a settlement agreement to remove the 10-MW (nameplate rating) 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 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 $21 million, excluding inflation. The settlement agreement is contingent upon receiving a FERC surrender order and other regulatory approvals that are not materially inconsistent with the amended settlement agreement. PacifiCorp is in the process of acquiring all necessary permits, within the terms and conditions of the amended settlement agreement. If the permitting process continues into the second quarter of 2008, the decommissioning will not begin until October 2009.

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 8-MW (nameplate rating) 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 that has been designated a historical landmark, was completed in November 2006. As of December 31, 2007, $3 million had been spent for the decommissioning of the Cove hydroelectric project.

American Fork Hydroelectric Project – (American Fork Creek, Utah)

In August 2004, the FERC authorized the removal of the 1-MW (nameplate rating) American Fork hydroelectric plant and facilities. Decommissioning of the American Fork facilities has been completed in accordance with the approved removal plan. The removal of the dam, flowline and all facilities, with the exception of the powerhouse that has been designated a historical landmark, was completed in December 2007. As of December 31, 2007, $4 million had been spent for the decommissioning of the American Fork hydroelectric project.

United States Mine Safety

Mining operations are regulated by the federal Mine Safety and Health Administration (“MSHA”), which administers federal mine safety and health laws, regulations and state regulatory agencies. The Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”), enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health and accident preparedness. The MINER Act, portions of which are not yet fully implemented, requires operators of underground coal mines to develop a written emergency response plan specific to each mine they operate. These plans must be updated and re-certified by MSHA every six months. It also requires every mine to have at least two rescue teams located within one hour, and it limits the legal liability of rescue team members and the companies that employ them. The MINER Act also increases civil and criminal penalties for violations of federal mine safety standards and gives MSHA the ability to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay the penalties or fines.

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 2007, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million, or an average price increase of 11%. The increase is primarily due to increased capital spending and net power costs, both of which are driven by load growth. In February 2008, the UPSC issued an order determining that the proper test period should end December 2008. PacifiCorp is currently determining the reduction to the originally requested amount that will result from the change in the test period. Hearings on the revenue requirement portion of the case are scheduled for June 2008, with the rate-design phase scheduled for October 2008. PacifiCorp expects that initial rates, if approved, will become effective no later than August 2008.

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 called for an annual increase of $115 million, or an average price increase of 10%, with $85 million of the increase effective December 11, 2006 and the remaining $30 million increase effective June 1, 2007.

Oregon

In August 2007, PacifiCorp filed a renewable cost adjustment clause that will allow for timely recovery between rate cases of the costs of eligible renewable resources and associated transmission under the RPS. The RPS required the OPUC to approve an automatic adjustment clause for timely recovery of these costs by January 1, 2008. In December 2007, the OPUC approved a settlement stipulation filed by the parties to the proceedings that established the renewable adjustment clause (“RAC”) mechanism, with an effective date of January 1, 2008. Under the RAC mechanism, PacifiCorp will submit a filing on April 1 of each year, with rates to become effective January 1 of the following year, to recover the revenue requirement of new renewable resources and associated transmission that are not reflected in general rates. As part of the RAC mechanism, the OPUC authorized PacifiCorp to defer eligible costs not yet included in rates until the next annual RAC filing.

In July 2007, as part of PacifiCorp’s annual compliance filing with the OPUC to update forecasted net power costs, PacifiCorp requested an increase of approximately $30 million, or an average price increase of 3%, to take effect January 1, 2008. The annual filing, called the transition adjustment mechanism (“TAM”), was adjusted for new contracts through October 2007 and for other changes to forecasted net power costs, such as coal and natural gas prices, through November 2007. In October 2007, the OPUC issued an order that approved the TAM increase subject to PacifiCorp updating its net power cost forecast to reflect changes adopted in the decision. In November 2007, PacifiCorp submitted a compliance filing with an updated net power cost forecast, which reflected a $22 million increase, or an average price increase of 2%. In December 2007, the OPUC approved the TAM with rates effective January 1, 2008.

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 million effective January 1, 2007. Also on January 1, 2007, PacifiCorp received a $10 million increase for power costs through its annual TAM.

For a discussion of Oregon Senate Bill 408, refer to Note 3 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

Wyoming

In June 2007, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $36 million, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource recovery mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. In January 2008, PacifiCorp reached a settlement in principle with parties to the case, subject to entering into a final stipulation and approval by the WPSC. The settlement provides for an annual rate increase of $23 million, or an average price increase of 5%. In addition, the parties also agreed to a forecast power cost mechanism and discontinuation of the current power cost adjustment mechanism (“PCAM”) by April 2011, unless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp’s marginal cost pricing tariff proposal will not be implemented, but will be the subject of a collaborative process to seek a new pricing proposal. Also as part of the settlement, PacifiCorp agreed to withdraw from this filing its request for a renewable resource recovery mechanism. The stipulation was executed and filed with the WPSC in January 2008 and will be the subject of a hearing for approval beginning in March 2008. PacifiCorp expects the new rates to become effective by May 2008.

In February 2008, PacifiCorp filed its annual deferred net power cost adjustment application with the WPSC in the amount of $31 million for costs incurred during the period December 1, 2006 through November 30, 2007.

In February 2007, PacifiCorp filed its first annual deferred net power cost adjustment application with the WPSC in the amount of $3 million for costs incurred during the period July 1, 2006 through November 30, 2006. In March 2007, PacifiCorp received approval from the WPSC to implement interim rates effective April 1, 2007, in the amount of $3 million. In May 2007, PacifiCorp filed a stipulation and agreement with the WPSC that resolved all issues in the application and reduced the deferred net power cost adjustment to $2 million. The revised rates were effective July 1, 2007.

Washington

In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or an average price increase of 15%, with an effective date no later than January 2009.

In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23 million, or an average price increase of 10%. 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 period on the proposed allocation methodology and a PCAM. In June 2007, the WUTC issued an order approving a rate increase of $14 million, or an average price increase of 6%, effective June 27, 2007, and accepted PacifiCorp’s proposed western balancing authority area cost-allocation methodology for a five-year pilot period. The WUTC found that PacifiCorp demonstrated the need for a PCAM, but it did not approve the design of the proposal in this case. The order authorized PacifiCorp to file a revised PCAM proposal, with or without a request to file power cost-only rate cases, outside the context of a general rate case within 12 months of the order.

Idaho

In June 2007, PacifiCorp filed a general rate case with the IPUC for an annual increase of $18 million, or an average price increase of 10%, with a request for an effective date of January 1, 2008. In November 2007, an all-party stipulation was reached on all issues in the general rate case, resulting in an annual increase of $12 million, or an average price increase of 6%. The IPUC approved the settlement stipulation in December 2007, with new rates effective January 1, 2008. The settlement also provides for rate increases effective January 1, 2009 and 2010 for PacifiCorp’s two special contract industrial customers and no additional rate changes for those two special contract customers effective prior to January 1, 2011. Additional rate increases for the remaining customer classes may be requested if needed to maintain cost of service coverage.

California

In October 2007, PacifiCorp filed two advice letters requesting authority to implement components of the post test-year adjustment mechanism (“PTAM”), a mechanism that allows for annual rate adjustments for changes in operating costs and plant additions outside of the context of a traditional rate case. The combined requested increase totaled $2 million, or an average price increase of 2%. The CPUC approved the increase in November 2007. In December 2007, PacifiCorp revised the increase based on updated capital additions, and the CPUC issued a revised order for a $1 million increase, or an average price increase of 1% effective January 1, 2008.

In August 2007, PacifiCorp filed an energy cost adjustment clause application with the CPUC to update actual and forecasted net variable power costs, requesting a rate increase of $6 million, or an average price increase of 8%, with an effective date of January 1, 2008. In December 2007, the CPUC issued an order for a $5 million increase, or an average price increase of 7%, with an effective date of January 1, 2008.

Depreciation Rate Changes

In August 2007, PacifiCorp filed applications with the regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation and extend the depreciable lives of certain assets, based on a new depreciation study. Agreements have been reached in each of these states and are in various stages of approval. When approved by the state commissions, the agreements will make the new depreciation rates effective January 1, 2008. For further discussion on depreciation rate changes, refer to Note 2 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

ENVIRONMENTAL REGULATION

PacifiCorp is subject to federal, state and local laws and regulations with regard to air and water quality, RPS, climate change, hazardous and solid waste disposal and other environmental matters and is subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance including fines, injunctive relief and other sanctions. PacifiCorp believes it is in material compliance with all laws and regulations. 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 EPA and certain states require substantial reductions in sulfur dioxide 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 Water Pollution Control Act (“Clean Water Act”) and individual state clean water laws 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. Refer to “Water Quality 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 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. Refer to Note 7 of the Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

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

PacifiCorp is subject to federal, state and local laws and regulations with regard to air and water quality, RPS, climate change, hazardous and solid waste disposal and other environmental matters. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to PacifiCorp. In particular, future mandates may impact the operation of PacifiCorp’s generating facilities and may require PacifiCorp to reduce emissions at its generating facilities through the installation of additional emission control equipment or to purchase additional emission allowances or offsets in the future. PacifiCorp is not aware of any established technology that reduces the carbon dioxide emission at coal-fired facilities and PacifiCorp is uncertain when, or if, such technology will be commercially available.

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

The Clean Air Act provides a framework for protecting and improving the nation’s air quality and controlling mobile and stationary sources of air emissions. The major Clean Air Act programs, which most directly affect PacifiCorp’s electric generating facilities, are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional, more stringent requirements.

In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp committed to state regulators to spend approximately $812 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. As of December 31, 2007, PacifiCorp had incurred $205 million in capital expenditures pursuant to this commitment.

National Ambient Air Quality Standards

The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. The counties in Washington, Oregon, Montana, Wyoming, Colorado, Utah and Arizona where PacifiCorp’s major emission sources are located are in attainment of the current ambient air quality standards. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. Air quality modeling and preliminary air quality monitoring data indicate that portions of the states in which PacifiCorp has major emission sources may not meet the new standards. Until three years of data are collected and attainment designations under the new fine particulate standard are made, the impact of these new standards on PacifiCorp will not be known.

In July 2007, the EPA proposed revisions to the primary and secondary national ambient air quality standards for ozone, including lowering the current level of the 8-hour standard from 0.08 parts per million to a range of 0.070 and 0.075 parts per million. The EPA also solicited public comments through October 9, 2007 on alternative levels between 0.060 parts per million and the current 8-hour standard. Final action on the standards must be completed by March 12, 2008. States will then have until June 2009 to characterize their attainment status, with the EPA’s determinations regarding non-attainment made by June 2010 and state implementation plans due in 2013. Until the EPA makes its final determination on the revised standards and attainment designations are made, the impact of any new standards on PacifiCorp will not be known.

Regulated Air Pollutants

In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”), a two-phase program that utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons. The CAMR required initial reductions of mercury emissions in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. The individual states in which PacifiCorp operates facilities regulated under the CAMR submitted state implementation plans reflecting their regulations relating to state mercury control programs. On February 8, 2008, the United States Court of Appeals for the District of Columbia Circuit held that the EPA improperly removed electricity generating units from Section 112 of the Clean Air Act and, thus, that the CAMR was improperly promulgated under Section 111 of the Clean Air Act. The court vacated the CAMR’s new source performance standards and remanded the matter to the EPA for reconsideration. In light of this decision, it is not known the extent to which future mercury rules may impact PacifiCorp’s current plans to reduce mercury emissions at its coal-fired facilities.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s plants meet the threshold applicability criteria under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit state implementation plans by December 2007 to demonstrate reasonable progress toward achieving natural visibility conditions in certain Class I areas by requiring emission controls, known as best available retrofit technology, on sources with emissions that are anticipated to cause or contribute to impairment of visibility. Wyoming has not yet submitted its state implementation plan and is continuing to review the results of analyses relating to planned emission reductions at PacifiCorp’s Wyoming generating plants. Utah has not yet submitted its state implementation plan, but expects to do so in the near term. PacifiCorp believes that its planned emission reduction projects will satisfy the regional haze requirements in Utah and Wyoming; however, it is possible that some additional controls may be required once the respective state implementation plans have been submitted.

New Source Review

Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (i) beginning construction of a new major stationary source of an NSR-regulated pollutant, or (ii) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a “best available control technology” analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states and environmental groups, among others, potentially subject a utility to material expenses for fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating plants. Between 2001 and 2003, PacifiCorp responded to requests for information relating to its capital projects at its generating plants and has been engaged in periodic discussions with the EPA over several years regarding this matter. An NSR enforcement case against another utility has been decided by the United States Supreme Court, holding that an increase in annual emissions of a facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp cannot predict the outcome of the EPA’s review of the data it has submitted at this time.

In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge, and in March 2006, a panel of the United States Court of Appeals for the District of Columbia Circuit invalidated portions of the EPA’s new NSR rules, holding that they conflicted with the wording of the statute. However, the EPA has asked the United States Supreme Court to review portions of the case. Until such time as the legal challenges are resolved and the revised rules are effective, PacifiCorp will continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects, which are now subject to permitting under the PSD program. In 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the permitting process and allow facilities to undertake activities that improve their safety, reliability and efficiency without triggering NSR requirements. In April 2007, the EPA issued a supplemental notice of proposed rulemaking to determine emissions increases for electric generating units, proposing to use both hourly and annual emissions tests to determine whether utilities trigger the NSR permitting program when an existing power plant makes a physical or operational change. The supplemental proposal was issued three weeks after the United States Supreme Court issued a unanimous opinion in Environmental Defense v. Duke Energy that the EPA was correct in applying an annual emissions test to determine NSR compliance.

Refer to “Liquidity and Capital Resources” included in Item 7 of this Form 10-K for additional information regarding planned capital expenditures related to air quality standards. Refer to Note 15 of Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding commitments and litigation related to air quality standards.

Renewable Portfolio Standards

The RPS described below could significantly impact PacifiCorp’s financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state-to-state. Each state’s RPS requires some form of compliance reporting and PacifiCorp can be subject to penalties in the event of non-compliance.

In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative. PacifiCorp expects to be able to recover its costs of complying with the RPS, either through rate cases or an adjustment mechanism.

In June 2007, the Oregon Renewable Energy Act (the “Act”) was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the Act, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the Act, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy facilities and associated transmission costs. The OPUC and the Oregon Department of Energy have undertaken additional rulemaking proceedings to further implement the initiative. PacifiCorp expects to be able to recover its costs of complying with the RPS through the automatic adjustment mechanism. For further discussion of the automatic adjustment mechanism, refer to “Regulatory Matters – State Regulatory Actions – Oregon” above.

California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance from the CPUC on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in early 2008. Absent further direction from the CPUC on treatment of SMJUs, PacifiCorp cannot predict the impact of the California RPS on its financial results.

Climate Change

As a result of increased attention to global 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 the passage of climate change legislation within the next several years. The Lieberman-Warner Climate Security Act of 2007 (S. 2191) was passed by the United States Senate Environment and Public Works Committee on December 5, 2007. The bill would impose an economy-wide cap on greenhouse gas emissions to reduce emissions 70% from 2005 levels by 2050. Included within the bill’s definition of a covered facility is any facility that uses more than 5,000 tons of coal in a calendar year, which includes all of PacifiCorp’s coal-fired generating plants. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the EPA has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. Furthermore, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired plants are expected to become active. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions, including:

In February 2007, the governors of California, Arizona, New Mexico, Oregon and Washington signed the Western Regional Climate Action Initiative (the “Western Climate Initiative”) that directed their respective states to develop a regional target for reducing greenhouse gases by August 2007. Utah joined the Western Climate Initiative in May 2007. The states in the Western Climate Initiative announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020, with Utah establishing its reduction goal by August 2008. By August 2008, they are expected to devise a market-based program, such as a load-based cap-and-trade program for the electricity sector, to reach the regional target. The Western Climate Initiative participants also have agreed to participate in a multi-state registry to track and manage greenhouse gas emissions in the region.

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% 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.

The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing economy-wide goals for the reduction of greenhouse gas emissions in their respective states. Washington’s goals seek to (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25% below 1990 levels; and (iii) by 2050, reduce emissions to 50% below 1990 levels, or 70% below Washington’s forecasted emissions in 2050. Oregon’s goals seek to (i) by 2010, cease the growth of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10% below 1990 levels; and (iii) by 2050, reduce greenhouse gas levels to at least 75% below 1990 levels. Each state’s legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals. The impact of the enacted legislation on PacifiCorp cannot be determined at this time.

PacifiCorp continues to add renewable electric capacity to its generation portfolio. In addition, PacifiCorp has engaged in voluntary programs designed to either reduce or avoid greenhouse gas emissions, including the EPA’s sulfur hexafluoride reduction program and refrigerator recycling programs. PacifiCorp is a member of the California Climate Action Registry and The Climate Registry, under which it reports and certifies its greenhouse gas emissions.

The impact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact PacifiCorp’s current and future 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 impact” to aquatic organisms. In July 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water a day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit 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. Petitions for certiorari are pending before the United States Supreme Court regarding the Second Circuit’s decision. Compliance and the potential costs of compliance therefore cannot be ascertained until such time as further action is taken by the EPA. Currently, PacifiCorp’s Dave Johnston plant exceeds the 50 million gallons of water per day in-take threshold. 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.

ITEM 1A. RISK FACTORS

We are subject to certain risks in our business operations as described below. Careful consideration of these risks, together with all of the other information included in this annual report and the other public information filed by us, should be made before making an investment decision. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known or that are currently deemed immaterial may also impair our business operations.

We are subject to extensive regulations that affect our operations and costs. These regulations are complex, dynamic 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 WECC, the EPA 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 and implement 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 debt or equity 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, including the implementation of RPS and greenhouse gas emissions reduction goals; 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. The United States Congress granted the FERC additional authority in the Energy Policy Act, which expanded its regulatory role from a regulatory body to an enforcement agency. To implement the law, the FERC has and will continue to issue new regulations and regulatory decisions addressing electric system reliability, electric transmission planning, operation, expansion and pricing, regulation of utility holding companies, and enforcement authority, including the ability to assess civil penalties of up to $1 million per day per infraction for non-compliance. The full impact of those decisions remains uncertain; however, the FERC has vigorously exercised its enforcement authority by imposing significant civil penalties for violations of its rules and regulations. In addition, as a result of past events affecting electric reliability, 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. Since the adoption of the Energy Policy Act, the FERC has approved numerous electric reliability, cyber security and critical infrastructure protection standards developed by the NERC. A transmission owner’s reliability compliance issues with these and future standards may result in financial penalties. In FERC Order No. 693, the FERC implemented its authority to impose penalties of up to $1 million per day per violation for failure to comply with electric reliability standards. The adoption of these and future electric reliability standards will impose more comprehensive and stringent requirements on us, which could result in increased compliance costs and could adversely affect our financial results.

The FERC has issued a series of orders to foster greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. In FERC Orders No. 888, 889, 890 and 890-A, the FERC required electric utilities to adopt a proforma OATT by which transmission service would be provided on a just, reasonable and not unduly discriminatory or preferential basis. The rules adopted by these orders promote transparency and consistency in the administration of the OATT, increase the ability of customers to access new generating resources and promote efficient utilization of transmission by requiring an open, transparent and coordinated transmission planning process. Together with the increased reliability standards required of transmission providers, the cost of operating the transmission system and providing transmission service has increased and, to the extent such increased costs are not recovered in rates charged to customers, it 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, and whether new licenses will ultimately be issued or 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 regulated 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 retail 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 or 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. They also decide the allowed levels of expense and investment that they deem is just and reasonable in providing service. The state 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 electric 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 obtain 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 (pursuant to pending or future proceedings) 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 the FERC’s rules or orders.

We are actively pursuing, developing and constructing new or expanded 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 and development of multiple wind plants and various capital projects related to generation, transmission and distribution. 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. Additional significant investments may be incurred as a result of the issuance and implementation of state and federal RPS and greenhouse gas emissions reduction goals.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor and other items over a multi-year construction period. These risks may result in higher than expected costs to complete an asset and place it into service. Such costs may not be recoverable in the regulated rates we are able to charge our customers. It is also possible that additional generation needs may be obtained through power purchase agreements which could increase long-term purchase obligations and force our subsidiaries to rely on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs 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, we may need to postpone or cancel planned capital expenditures. Failure to construct these projects could limit opportunities for revenue growth, increase operating costs 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 bilateral long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.

We are subject to numerous environmental, health, safety and other laws, regulations and other requirements 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:

the provisions of the Mine Improvement and New Emergency Response Act of 2006 to improve underground coal mine safety and emergency preparedness;

the implementation of federal and state RPS; and

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, regulations and other requirements 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 or active opposition by third parties to 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 result in increased costs or prevent or delay us from operating our facilities, developing new facilities, expanding existing facilities or favorably locating 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, regulations and other requirements could adversely affect our financial results. Not being able to operate existing facilities or develop new electric generating facilities to meet customer energy needs could require us to increase our purchases of power from the wholesale markets, which could increase market and price risks and adversely affect our financial results. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called “greenhouse gases” such as carbon dioxide, a by-product of burning fossil fuels, methane (the primary component of natural gas), and methane leaks from pipelines. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.

Further, our current regulatory rate structure or long-term customer contracts may not necessarily 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, regulations and other requirements 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 electric 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 reserves to recognize our estimated obligations for known remediation liabilities, but such estimates may change materially over time. PacifiCorp is required to fund its portion of the costs of mine reclamation at its coal mining operations, which include principally site restoration. In addition, 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 that may be material.

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

Inflation affects our business through increased operating costs and increased capital costs for plant and equipment. As a result of existing rate agreements 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 cost increases or pass them on to our customers, our financial results could be adversely affected.

We are also exposed to changes in prices and availability of coal and natural gas and the transportation of coal and natural gas because a substantial portion 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.

A significant decrease in demand for electricity in the markets served by us would significantly decrease our operating revenues and thereby adversely affect our business and financial results.

A sustained decrease in demand for electricity in the markets served by us would significantly reduce our operating revenue and adversely affect our financial results. Factors that could lead to a decrease in market demand include, among others:

a recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity;

an increase in the market price of electricity or a decrease in the price of other competing forms of energy;

efforts by customers to reduce their consumption of energy through various conservation and energy efficiency measures and programs; and

higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or the fuel source for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels.

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 other utilities to transport electricity to both wholesale and retail markets, as well as natural gas purchased to supply some of our electric generation facilities. If adequate transmission is unavailable, we may be unable to purchase and sell and deliver electricity. Such unavailability could also hinder our ability to provide adequate or economical electricity to our wholesale and retail customers and 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, regulations 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 contracts terminate, we may be unable to purchase the 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 the 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 minimize these risk exposures is ineffective, significant losses could result.

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. Periods of low rainfall or snow-pack may also impact electric generation at our generation hydroelectric projects.

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 margins. 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 snow-pack, 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 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; 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 or other operational 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 sales and our expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks and 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 benefit design, 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 in 2008 and beyond 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 agreements 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, 2007, we had $5 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 certain of our 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 generally has control over the election of our directors and all decisions requiring shareholder approval. In circumstances involving a conflict of interest between MEHC and our creditors and preferred stockholders, MEHC could exercise its control in a manner that would benefit MEHC to the detriment of our creditors and preferred stockholders.

We are involved in numerous legal proceedings, the outcomes of which are uncertain and could negatively affect our financial results.

We are parties to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is possible that the final resolution of some of the matters in which we are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our financial results. Similarly, it is also possible that the terms of resolution could require that we change business practices and procedures, which could also have a material adverse effect on our financial results. Further, litigation could result in the imposition of financial penalties or injunctions which could limit our ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct our business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on our financial results.

Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which may change the way analysts measure our business or financial performance.

Accounting irregularities discovered in the past few years in various industries have caused regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will ultimately develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (“FASB”), the FERC or the SEC could enact new or revised accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets and liabilities.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

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 the 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. Refer to Exhibit 4.1 included in Item 15 of this Form 10-K. Refer to Item 1 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 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 December 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by the Klamath Riverkeeper (a local environmental group); Leaf Hillman (a Karuk Tribe member); Howard McConnell and Robert Attebery (Yurok Tribe members); and Blythe Reis (a resort owner). The complaint alleges that reservoirs behind the hydroelectric dams that PacifiCorp operates on the Klamath River provide an environment for the growth of a blue-green algae known as microcystis aeruginosa, which can generate a toxin called microcystin. The complaint alleges that such algae is a “solid waste” under the federal Resource Conservation and Recovery Act, that PacifiCorp “generates” and “stores” such algae in its reservoirs, that PacifiCorp “disposes” of such algae when it passes through the dams, and that such “generation,” “storage” and “disposal” causes or threatens to cause an imminent and substantial endangerment to health and the environment. The complaint seeks a Court order declaring that PacifiCorp is violating the Resource Conservation and Recovery Act, enjoining PacifiCorp from storing or disposing of the algae, requiring PacifiCorp to “remediate all contamination of or other damage to health or the environment” from such algae, and requiring PacifiCorp to pay civil penalties of up to $27,500 per day per violation from February 2001 to March 2004, and up to $32,500 per day per violations from March 2004 and thereafter. PacifiCorp believes these claims to be without merit and filed a motion to dismiss in December 2007. In February 2008, a court order was issued conditionally allowing the consolidation of the December 2007 blue-green algae case with the May 2007 blue-green algae case described below. Subsequently, the plaintiffs filed a motion seeking clarification of the order. The plaintiffs have until February 29, 2008 to agree to the conditions of the order, which are to pay for certain of PacifiCorp's costs and fees associated with any delay caused by the consolidation of the two cases. If the plaintiffs do not agree to pay the delay costs, the December 2007 blue-green algae case will be dismissed.

In May 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by Leaf Hillman and Terance J. Supahan (Karuk Tribe members); Frankie Joe Myers, Howard McConnell and Robert Attebery (Yurok Tribe members); Michael T. Hudson (a commercial fisherman); Blythe Reis (a resort owner); and the Klamath Riverkeeper (a local environmental group) alleging that toxic algae “introduced” by PacifiCorp into Klamath hydroelectric project reservoirs is released by PacifiCorp to the river downstream of the project, and caused or will cause the plaintiffs physical, property, and economic harm. Plaintiffs allege seven causes of action based on nuisance, trespass, negligence, and unlawful business practices, all under California law. Elevated concentrations of microcystis aeruginosa (blue-green algae) have been identified in Klamath River hydroelectric project reservoirs, and now farther downstream on the Klamath River. The algae occur naturally across Oregon, California, and throughout the world. Elevated concentrations tend to appear in areas of slack water that is relatively warm. It has been identified for years on Klamath Lake. Plaintiffs seek unspecified damages and injunctive relief; however, in an order filed by the court in August 2007, the court dismissed plaintiffs’ claims for injunctive relief based on federal preemption under the Federal Power Act. PacifiCorp denies the allegations and is vigorously defending the case, which is currently in the discovery phase.

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 Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal 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 that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods 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. The court granted a motion to bifurcate the trial into separate liability and remedy phases. A five-day trial on the liability phase is scheduled to begin in April 2008. The remedy-phase trial has not yet been set. The court is considering several summary judgment motions filed by the parties, but has not yet ruled on any of them. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

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 plant. USA Power’s complaint alleged that PacifiCorp misappropriated confidential proprietary information in violation of Utah’s Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and related claims. USA Power seeks $250 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys’ fees. After considering various motions for summary judgment, the court ruled in October 2007 in favor of PacifiCorp on all counts and dismissed the plaintiffs’ claims in their entirety. Plaintiffs are expected to appeal this decision and PacifiCorp believes that its defenses that prevailed in the trial court will prevail on appeal. Furthermore, PacifiCorp expects that the outcome of any appeal 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 and briefing was completed in March 2006. In February 2008, the Ninth Circuit held oral argument on the briefs. 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

Not applicable.

PART II

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

MEHC indirectly owns all of the shares of PacifiCorp’s outstanding common stock. Therefore, there is no public market for PacifiCorp’s common stock. PacifiCorp did not pay dividends on common stock during the year ended December 31, 2007 or during the nine-month period ended December 31, 2006. PacifiCorp does not expect to declare or pay dividends on common stock during the year ending December 31, 2008.

During the year ended December 31, 2007, PacifiCorp received capital contributions of $200 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, refer to Note 12 of the Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth PacifiCorp’s selected consolidated historical financial data, which should be read in conjunction with Item 7 of this Form 10-K and with PacifiCorp’s historical Consolidated Financial Statements and notes thereto included in Item 8 of this Form 10-K. The selected consolidated historical financial data has been derived from PacifiCorp’s audited historical Consolidated Financial Statements and notes thereto (in millions). In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31.

			Nine-Month
	Year Ended		Period Ended		Years Ended
	December 31,		December 31,		March 31,
	2007		2006		2006		2005		2004

Statement of Income Data:
Revenues	$	4,258	$	2,924	$	3,897	$	3,049	$	3,195
Income from operations		888		415		792		656		618
Net income		439		161		361		252		248

	As of December 31,				As of March 31,
	2007		2006		2006		2005		2004

Balance Sheet Data:
Total assets	$	14,907	$	13,852	$	12,731	$	12,521	$	11,677
Long-term debt and capital lease obligations, excluding current maturities		4,753		3,967		3,721		3,629		3,520
Preferred stock subject to mandatory redemption, excluding current maturities		-		-		41		49		56
Preferred stock		41		41		41		41		41
Total shareholders’ equity		5,080		4,426		4,052		3,377		3,320

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

The following is management’s discussion and analysis of certain significant factors that have affected the financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management’s best estimate of the impacts of weather, customer growth and other factors. This discussion should be read in conjunction with Item 6 of this Form 10-K and with the Consolidated Financial Statements and notes thereto included in Item 8 of this Form 10-K. PacifiCorp’s actual results in the future could differ significantly from the historical results.

RESULTS OF OPERATIONS

As a result of PacifiCorp’s election to change its fiscal year from March 31 to December 31, the audited periods presented in the Consolidated Statements of Income include the year ended December 31, 2007, the nine-month transition period ended December 31, 2006 and the year ended March 31, 2006. To facilitate a better understanding of PacifiCorp’s results of operations and business trends, the following discussion is based on the comparison of the audited year ended December 31, 2007 to the unaudited year ended December 31, 2006. Financial information for the year ended December 31, 2006 is derived from PacifiCorp’s audited consolidated financial statements for the nine-month transition period ended December 31, 2006 and PacifiCorp’s unaudited consolidated financial statements for the three-month period ended March 31, 2006.

Overview

PacifiCorp’s net income was $439 million for the year ended December 31, 2007 compared to $308 million for the year ended December 31, 2006. The $131 million increase in net income was primarily due to higher retail revenues and higher net wholesale sales and purchases, partially offset by higher fuel costs.

Retail revenues increased due to higher retail prices approved by regulators, as well as continued growth in the number of retail customers and usage. Net margin on wholesale activities increased primarily due to higher average prices on wholesale sales and lower purchased electricity volumes. PacifiCorp’s financial results were further improved by higher output at PacifiCorp’s thermal plants serving higher retail load. These improvements were partially offset by increased natural gas consumed at PacifiCorp’s natural gas-fired generation plants, primarily due to higher output at the Currant Creek plant and the addition of the 548-MW Lake Side plant that was placed into service in September 2007; higher prices of coal, natural gas and purchased electricity; and lower hydroelectric generation.

Retail energy sales volumes grew by 3% during the year ended December 31, 2007 compared to the year ended December 31, 2006. PacifiCorp’s number of retail customers has been increasing by approximately 2% 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 5,022,219 MWh, or 10%, during the year ended December 31, 2007 compared to the year ended December 31, 2006. Output from PacifiCorp-owned hydroelectric facilities during the year ended December 31, 2007 decreased by 872,509 MWh, or 19%, as compared to the year ended December 31, 2006. This decrease was primarily attributable to current-period water flow conditions that were less favorable compared to the prior-year period. PacifiCorp’s hydroelectric generation was 90% of normal for the year ended December 31, 2007, compared to 111% of normal for the year ended December 31, 2006, based on a 30-year average.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Revenues (dollars in millions)

	Years Ended December 31,				Favorable/(Unfavorable)
	2007		2006		$ Change			% Change

Retail	$	3,251	$	2,959	$	292			10	%
Wholesale sales and other		1,007		1,195		(188	)		(16	)
Total revenues	$	4,258	$	4,154	$	104			3

Retail energy sales (GWh)		53,390		51,797		1,593			3
Wholesale energy sales (GWh)		13,724		13,657		67			-
Average retail customers (in thousands)		1,684		1,649		35			2

Retail revenues increased $292 million, or 10%, primarily due to:

·	$187 million of increases from higher prices approved by regulators;

·	$54 million of increases due to higher average customer usage, primarily as a result of weather conditions; and

·	$53 million of increases related to growth in the number of residential and commercial customers, primarily in Utah and Oregon.

Wholesale sales and other revenues decreased $188 million, or 16%, primarily due to:

·	$313 million of decreases due to changes in the fair value of derivative contracts; partially offset by,

·	$126 million of increases due to higher average prices on wholesale electric sales and higher margins on non-physically settled system-balancing transactions.

Operating Expenses (in millions)

	Years Ended December 31,				Favorable/(Unfavorable)
	2007		2006		$ Change			% Change

Energy costs	$	1,768	$	1,845	$	77			4	%
Operations and maintenance		1,004		1,054		50			5
Depreciation and amortization		497		468		(29	)		(6	)
Taxes, other than income taxes		101		101		-			-
Total operating expenses	$	3,370	$	3,468	$	98			3

Energy costs decreased $77 million, or 4%, primarily due to:

·	$364 million of decreases due to changes in the fair value of derivative contracts;

·	$25 million of decreases primarily due to the deferral of incurred power costs in accordance with established adjustment mechanisms; and

·	$13 million of decreases due to the prior period loss on the streamflow weather derivative contract; partially offset by,

·	$208 million of increases due to higher volumes of natural gas consumed as a result of an increase in thermal generation and higher average prices;

·	$79 million of increases in the cost of coal consumed substantially due to higher average prices;

·	$24 million of increases in purchased electricity due to higher average prices, substantially offset by lower volumes; and

·	$13 million of increases related to higher wheeling expenses driven by new agreements.

Operations and maintenance expense decreased $50 million, or 5%, primarily due to:

·	$36 million of decreases in employee severance costs;

·	$27 million of decreases in employee expenses, substantially due to reduced workforce; and

·	$10 million of decreases due to the assessment of penalties related to compliance with the FERC standards of conduct for transmission in the prior period; partially offset by

·	$28 million of increases in maintenance costs and related contracts, primarily associated with generation plant overhauls.

Depreciation and amortization expense increased $29 million, or 6%, primarily due to increases in production plant assets placed into service during the year ended December 31, 2007.

Interest and Other Expense (Income) (in millions)

	Years Ended December 31,						Favorable/(Unfavorable)
	2007			2006			$ Change			% Change

Interest expense	$	314		$	284		$	(30	)		(11	)%
Interest income		(15	)		(8	)		7			88
Allowance for borrowed funds		(29	)		(23	)		6			26
Allowance for equity funds		(41	)		(23	)		18			78
Other		-			(8	)		(8	)		(100	)
Total	$	229		$	222		$	(7	)		(3	)

Interest expense increased $30 million, or 11%, primarily due to higher average debt outstanding during the year ended December 31, 2007.

Allowance for borrowed and equity funds increased $24 million, or 52%, 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 December 31, 2007.

Income Tax Expense

Income tax expense increased $64 million, or 41%, during the year ended December 31, 2007 to $220 million compared to $156 million during the year ended December 31, 2006, primarily due to higher pre-tax earnings. The effective tax rates were 33% and 34% for the years ended December 31, 2007 and 2006, respectively.

Nine-Month Period Ended December 31, 2006 Compared to Nine-Month Period Ended December 31, 2005

Consistent with management's discussion and analysis included in PacifiCorp's Transition Report on Form 10-K for the transition period from April 1, 2006 to December 31, 2006, the following discussion is based on the comparison of the audited nine-month period ended December 31, 2006 to the unaudited nine-month period ended December 31, 2005.

Revenues (dollars in millions)

	Nine-Month Periods
	Ended December 31,				Favorable/(Unfavorable)
	2006		2005		$ Change		% Change

Retail	$	2,245	$	2,095	$	150		7	%
Wholesale sales and other		679		572		107		19
Total revenues	$	2,924	$	2,667	$	257		10

Retail energy sales (GWh)		39,029		37,344		1,685		5
Wholesale energy sales (GWh)		10,284		9,906		378		4
Average retail customers (in thousands)		1,653		1,617		36		2

Retail revenues increased $150 million, or 7%, primarily due to:

·	$62 million of increases due to higher average customer usage;

·	$60 million of increases from higher prices approved by regulators; and

·	$36 million of increases related to growth in the number of residential and commercial customers; partially offset by,

·	$8 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 $107 million, or 19%, primarily due to:

·	$83 million of increases due to changes in the fair value of derivative contracts; and

·	$67 million of increases substantially due to higher margins on non-physically settled system-balancing transactions and higher wholesale electric sales volumes, partially offset by decreases resulting from lower average prices on wholesale electric sales; partially offset by,

·	$14 million of decreases resulting from lower sales of sulfur dioxide emission allowances in the current period; and

·	$9 million of decreases due to settlements in the prior period of amounts previously disputed with third parties.

Operating Expenses (in millions)

	Nine-Month Periods
	Ended December 31,				Favorable/(Unfavorable)
	2006		2005		$ Change			% Change

Energy costs	$	1,297	$	997	$	(300	)		(30	)%
Operations and maintenance		780		741		(39	)		(5	)
Depreciation and amortization		355		336		(19	)		(6	)
Taxes, other than income taxes		77		72		(5	)		(7	)
Total operating expenses	$	2,509	$	2,146	$	(363	)		(17	)

Energy costs increased $300 million, or 30%, primarily due to:

·	$226 million of increases due to changes in the fair value of derivative contracts;

·	$74 million of increases related to higher volumes of natural gas consumed due to an increase in thermal generation, as well as higher average prices;

·	$8 million of increases related to higher average prices for coal consumed, partially offset by lower volumes; and

·	$6 million of increases related to higher wheeling expenses, primarily due to rate increases; partially offset by,

·	$11 million of decreases in purchased electricity due to lower average prices, partially offset by higher volumes; and

·	$3 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 million, or 5%, primarily due to:

·	$26 million of increases in employee severance costs;

·	$25 million of increases in third-party contract and service fees, including the impact of plant overhauls and vegetation management programs;

·	$8 million of increases in pension and other postretirement benefit costs; and

·	$6 million of increases resulting from the final assessment of penalties related to compliance with the FERC standards of conduct for transmission; partially offset by,

·	$17 million of decreases in annual incentive expenses;

·	$5 million of decreases in services rendered by MEHC in the current year compared to ScottishPower in the prior year; and

·	$4 million of decreases resulting from the March 2006 amendment to the terms of a generating plant operating lease.

Depreciation and amortization expense increased $19 million, or 6%, primarily due to higher plant-in-service during the nine-month period ended December 31, 2006.

Interest and Other Expense (Income) (in millions)

	Nine-Month Periods
	Ended December 31,						Favorable/(Unfavorable)
	2006			2005			$ Change			% Change

Interest expense	$	215		$	211		$	(4	)		(2	)%
Interest income		(6	)		(7	)		(1	)		(14	)
Allowance for borrowed funds		(18	)		(14	)		4			29
Allowance for equity funds		(17	)		(8	)		9			113
Other		(6	)		(4	)		2			50
Total	$	168		$	178		$	10			6

Interest expense increased $4 million, or 2%, primarily due to higher variable rates during the nine-month period ended December 31, 2006.

Allowance for borrowed and equity funds increased $13 million, or 59%, primarily due to applying higher prescribed allowance for funds used during construction rates to higher qualified Construction work-in-progress balances during the nine-month period ended December 31, 2006.

Income Tax Expense

Income tax expense decreased $43 million, or 33%, during the nine-month period ended December 31, 2006 to $86 million compared to $129 million during the nine-month period ended December 31, 2005, primarily due to lower pre-tax earnings and tax benefits recognized from the resolution of certain matters previously outstanding with the Internal Revenue Service, partially offset by the tax effect of the regulatory treatment of book-tax differences. The effective tax rates were 35% and 38% for the nine-month periods ended December 31, 2006 and 2005, respectively.

LIQUIDITY AND CAPITAL RESOURCES

As a result of PacifiCorp’s election to change its fiscal year from March 31 to December 31, the audited periods presented on the Consolidated Statements of Income include the year ended December 31, 2007, the nine-month transition period ended December 31, 2006 and the year ended March 31, 2006. To facilitate a better understanding of PacifiCorp’s results of operations and business trends, certain portions of the following discussion are based on the comparison of the audited year ended December 31, 2007 to the unaudited year ended December 31, 2006 and the audited nine-month period ended December 31, 2006 to the unaudited nine-month period ended December 31, 2005.

Financial information for the year ended December 31, 2006 is derived from PacifiCorp’s audited consolidated financial statements for the nine-month transition period ended December 31, 2006 and PacifiCorp’s unaudited consolidated financial statements for the three-month period ended March 31, 2006.

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. To the extent funds are not available to support capital expenditures, projects may be delayed and operating income may be reduced. 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 cash capital contributions from PacifiCorp’s direct parent company, PPW Holdings LLC. PacifiCorp expects it will need additional periodic cash capital contributions from its parent company over the next several years. Issuance of long-term securities is influenced by levels of short-term debt, cash flows provided by operating activities, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash flows provided by operating activities increased $72 million to $824 million during the year ended December 31, 2007, compared to $752 million during the year ended December 31, 2006, primarily due to higher retail revenues and higher net wholesale sales and purchases, partially offset by the timing of payments and cash collections and higher fuel costs.

Net cash flows provided by operating activities decreased $142 million to $431 million during the nine-month period ended December 31, 2006 compared to $573 million during the nine-month period 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.

Investing Activities

Net cash used in investing activities increased $105 million to $1,497 million during the year ended December 31, 2007, compared to $1,392 million during the year ended December 31, 2006, primarily due to higher capital expenditures. Capital expenditures totaled $1,519 million during the year ended December 31, 2007, compared to $1,384 million during the year ended December 31, 2006. Capital spending increased primarily due to wind plant investments of $575 million, including the completion of the 140-MW (nameplate rating) Marengo wind plant and additional investments for the Goodnoe Hills, Marengo expansion, Glenrock, Rolling Hills and Seven Mile Hill wind plants. Additional increases resulted from the construction of various capital projects related to transmission, distribution and other generation facilities. These increases were partially offset by decreases in expenditures as compared to the previous year for the construction of the 548-MW Lake Side plant, which commenced full combined-cycle operation in September 2007.

Net cash used in investing activities increased $367 million to $1,056 million during the nine-month period ended December 31, 2006, compared to $689 million during the nine-month period ended December 31, 2005, primarily due to higher capital expenditures. Capital expenditures totaled $1,051 million during the nine-month period ended December 31, 2006, compared to $716 million during the nine-month period ended December 31, 2005. Capital spending increased primarily due to wind plant investments of $269 million, including the purchase of the 101-MW Leaning Juniper 1 wind plant, which was placed into service in September 2006, and the initial investment in the 140-MW (nameplate rating) Marengo wind plant. 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 plant, which commenced full combined-cycle operation in March 2006, and expenditures for the construction of the 548-MW Lake Side plant, which were lower than the previous year.

Financing Activities

Short-Term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. PacifiCorp had no short-term debt outstanding at December 31, 2007, a decrease of $397 million compared to December 31, 2006. The decrease in short-term debt was primarily due to the proceeds from the issuance of long-term debt and the capital contributions received during the year, partially offset by capital expenditures and maturities of long-term securities in excess of net cash provided by operating activities.

PacifiCorp’s short-term debt increased by $213 million during the nine-month period ended December 31, 2006 to $397 million of commercial paper arrangements, primarily due to capital expenditures and scheduled long-term debt maturities in excess of net cash provided by operating activities, 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.

Revolving Credit and Other Financing Agreements

At December 31, 2007, PacifiCorp had $1.5 billion available under its unsecured revolving credit facilities. During the year ended December 31, 2007, PacifiCorp entered into an unsecured revolving credit facility with total bank commitments of $700 million available through October 23, 2012. Under PacifiCorp’s previously existing unsecured revolving credit facility, $800 million is available through July 6, 2011 and $760 million is available from July 7, 2011 through July 6, 2012. The bank facilities support PacifiCorp’s commercial paper program and include a variable interest rate borrowing option based on the London Interbank Offered Rate (“LIBOR”), plus a margin that is currently 0.195%, and varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities. At December 31, 2007, PacifiCorp did not have any borrowings outstanding under either credit facility.

In addition to these committed bank facilities, PacifiCorp had $214 million in money market accounts included in Cash and cash equivalents at December 31, 2007, available to meet its liquidity needs, as well as provide for future capital expenditures and contractual obligations. Refer to “Future Uses of Cash” below.

At December 31, 2007, PacifiCorp had $518 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. These committed bank arrangements were fully available at December 31, 2007 and expire periodically through May 2012.

In addition, at December 31, 2007, PacifiCorp had approximately $18 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, 2007 and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.

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, 2007, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Long-Term Debt

In addition to the debt issuances discussed herein, PacifiCorp made scheduled repayments on long-term debt totaling $126 million during the year ended December 31, 2007, $211 million during the nine-month period ended December 31, 2006 and $270 million during the year ended March 31, 2006.

During the year ended December 31, 2007, PacifiCorp issued $600 million of its 5.75% First Mortgage Bonds due April 1, 2037 and $600 million of its 6.25% First Mortgage Bonds due October 15, 2037.

During the nine-month period ended December 31, 2006, PacifiCorp issued $350 million of its 6.10% Series of First Mortgage Bonds due August 1, 2036.

During the year ended March 31, 2006, PacifiCorp issued $300 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035.

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, 2007, PacifiCorp estimated it would be able to issue up to $5.3 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. Refer to “Limitations” below.

In January 2008, PacifiCorp received regulatory authority from the OPUC and the IPUC to issue up to an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. Also in January 2008, PacifiCorp filed a shelf registration statement with the United States Securities and Exchange Commission (the “SEC”) covering future first mortgage bond issuances.

Preferred Stock Redemptions

During the year ended December 31, 2007, PacifiCorp redeemed 375,000 shares totaling $38 million of its $7.48 No Par Serial Preferred Stock Series, representing the remaining outstanding shares of Preferred stock subject to mandatory redemption.

PacifiCorp redeemed 75,000 shares totaling $8 million of Preferred stock subject to mandatory and optional redemption during the nine-month period ended December 31, 2006 and during the year ended March 31, 2006.

Common Shareholder’s Capital

During the year ended December 31, 2007, PacifiCorp received capital contributions of $200 million in cash from its direct parent company, PPW Holdings LLC.

During the nine-month period ended December 31, 2006, PacifiCorp received capital contributions of $215 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 common stock to PHI, its former parent company, at a total price of $485 million.

Common Dividends

During the year ended March 31, 2006, PacifiCorp declared and paid common dividends totaling $175 million to PHI, its former parent company.

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, customers and creditors and provide a competitive cost of capital and predictable capital market access.

As a result of accounting standards, such as FASB Interpretation No. 46R, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51 (“FIN 46R”), and Emerging Issues Task Force 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 direct parent company, PPW Holdings LLC, or take other actions.

Future Uses of Cash

Capital Expenditures Program

Fiscal year 2007

Actual capital expenditures, excluding the non-cash allowance for equity funds used during construction, were $1,519 million during the year ended December 31, 2007, $1,051 million during the nine-month period ended December 31, 2006 and $1,049 million during the year ended March 31, 2006.

During the year ended December 31, 2007, capital expenditures for generation development and related transmission projects, excluding the non-cash allowance for equity funds used during construction, totaled $681 million. These expenditures were substantially driven by the development of PacifiCorp’s wind plant portfolio and included costs incurred for the 140-MW (nameplate rating) Marengo wind plant that was placed into service in August 2007, as well as construction costs for the 94-MW Goodnoe Hills, 70-MW Marengo expansion, 99-MW Glenrock, 99-MW Rolling Hills and 99-MW Seven Mile Hill wind plants.

Also included in capital expenditures for generation development and related transmission projects was the remaining cost to complete the 548-MW Lake Side plant, which was placed into service in September 2007, as well as upgrades of other generation plant equipment. As of December 31, 2007, $326 million, excluding $17 million of non-cash allowance for equity funds used during construction, had been incurred for the Lake Side plant. The Lake Side plant is 100% owned and operated by PacifiCorp.

During the year ended December 31, 2007, capital expenditures for emissions control equipment, excluding the non-cash allowance for equity funds used during construction, totaled $110 million and included the installation of emissions control equipment at the Huntington and Cholla plants.

The remaining $728 million in capital expenditures during the year ended December 31, 2007 related to ongoing operation projects, including new connections related to customer growth, transmission investments in new and upgraded lines and substations, and generation plant overhauls.

Fiscal years 2008 through 2017

PacifiCorp estimates that it will spend approximately $20 billion on capital projects over the next ten years, excluding non-cash allowance for equity funds used during construction. These capital projects include new generation resources, including renewables; installation of emissions control equipment on existing generation plants; transmission investments; and distribution investments in new connections, lines and substations. Capital projects for emissions control equipment are expected to help achieve the commitments agreed to by PacifiCorp and MEHC as described in “Environmental Matters” in Item 1 of this Form 10-K. Capital projects for transmission include PacifiCorp’s plans to invest an estimated $4.1 billion to build in excess of 1,200 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. These transmission lines are expected to be placed into service beginning 2010 and continuing through 2014. Also included in the above estimate is PacifiCorp’s commitment for transmission and distribution investments resulting from the sale of PacifiCorp to MEHC. For further discussion of transmission and distribution investments, refer to “Transmission and Distribution” in Item 1 of this Form 10-K.

Estimated capital expenditures for the year ending December 31, 2008 are expected to be approximately $2.0 billion, excluding non-cash allowance for equity funds used during construction, and include $845 million for ongoing operations projects, including new connections related to customer growth and generation plant overhauls; $656 million for generation development and the related transmission projects; $283 million for transmission system expansion and upgrades; and $212 million for emission control equipment for existing generation plants to address current and anticipated air quality regulations.

The capital expenditure estimate for generation development projects provided above for the year ended December 31, 2008, includes the remaining construction costs for the development of the 94-MW Goodnoe Hills, 70-MW Marengo expansion, 99-MW Glenrock, 99-MW Rolling Hills and 99-MW Seven Mile Hill wind plant projects expected to be placed into service through December 31, 2008. Evaluation and development efforts are in progress related to additional prospective wind plants scheduled for completion in 2008, 2009 and beyond.

The capital expenditure estimate for transmission system expansion and upgrades for the year ended December 31, 2008 includes $218 million for the construction of a 127-mile, double-circuit, 345-kilovolt transmission line to be built between the Populus substation located in southern Idaho and the Terminal substation located in Utah. This line will be constructed in the Path C Transmission corridor, a primary transmission corridor in PacifiCorp’s balancing authority area. PacifiCorp expects to complete construction of this line in 2010.

The capital expenditure estimate for emissions control equipment projects includes equipment to meet anticipated air quality and visibility targets and the reduction of sulfur dioxide emission. Capital expenditures to complete the installation of emissions control equipment at the Cholla plant are estimated to be $46 million during the year ending December 31, 2008. Additionally, the replacement of an existing sulfur dioxide scrubber on Unit 4 and the addition of a new scrubber on Unit 3 of the Dave Johnston plant will begin in 2008 and is expected to be completed in 2012. Estimated capital expenditures for this project during the year ended December 31, 2008 are $102 million.

The estimates and projects described above are subject to a high degree of variability based on several factors, including, among others highlighted in “Forward-Looking Statements” herein and discussed below, changes in regulations, laws, the economy and market conditions, as well as the outcomes of rate-making proceedings. Future decisions arising from the IRP process described in Item 1 of this Form 10-K may impact the 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.

Credit Ratings

PacifiCorp’s credit ratings at January 31, 2008, 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 rating-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 agreements. However, interest rates on loans under the revolving credit agreements and commitment fees are tied to credit ratings and would increase or decrease when ratings are changed. A rating 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. If PacifiCorp’s unsecured ratings fell more than one rating below investment grade, PacifiCorp’s estimated potential collateral requirements as of December 31, 2007 would have totaled approximately $412 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. Management believes that PacifiCorp could have borrowed an additional $4.3 billion at December 31, 2007 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, 2007, 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% after December 31, 2011. The terms of this commitment treat 50% of PacifiCorp’s remaining balance of preferred stock in existence prior to the acquisition of PacifiCorp by MEHC as common equity. As of December 31, 2007, 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, 2007, PacifiCorp’s unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and Fitch Ratings and Baa1 by Moody’s Investor Service.

Obligations and Commitments

Contractual Obligations

The table below shows PacifiCorp’s contractual obligations at December 31, 2007 (in millions).

	Payments Due During the Years Ending December 31,
	2008			2009-2010		2011-2012	Thereafter		Total

Long-term debt, including interest:
Fixed-rate obligations	$	693	$	671	$	1,067	$	7,224	$	9,655
Variable-rate obligations (a)		20		39		39		677		775
Capital leases, including interest		7		14		14		85		120
Operating leases (b)		9		8		6		35		58
Asset retirement obligations (c)		30		75		19		426		550
Power purchase agreements: (d)
Electricity commodity contracts		549		551		138		516		1,754
Electricity capacity contracts		160		310		264		1,131		1,865
Electricity mixed contracts		25		40		36		227		328
Transmission		61		124		101		404		690
Fuel purchase agreements: (d)
Natural gas supply and transportation		349		507		195		146		1,197
Coal supply and transportation		258		469		199		958		1,884
Purchase obligations (e)		386		64		26		51		527
Owned hydroelectric commitments (f)		39		109		126		538		812
Other long-term liabilities (g)		74		5		3		15		97
Total contractual cash obligations	$	2,660	$	2,986	$	2,233	$	12,433	$	20,312

(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, 2007 rates. Refer to Interest Rate Risk included in Item 7A 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 energy output, generally 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. The purchase obligation amounts consist of items for which PacifiCorp is contractually obligated to purchase from a third party as of December 31, 2007. 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. 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 in the Consolidated Balance Sheets 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 excluded since cash payments are based primarily on taxable income for each year. Uncertain tax positions are also excluded because the amounts and timing of cash payments are not certain. Includes contributions expected to be made to the PacifiCorp Retirement Plan during the year ending December 31, 2008 as disclosed in Note 18 of Notes to the Consolidated Financial Statements included in Item 8 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 year ended December 31, 2007, is estimated to be approximately $25 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.

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 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 FIN 46R. 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 of this Form 10-K for more information on these obligations and arrangements.

Accounting Matters

New Accounting Standards

For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of the Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

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, 2007, PacifiCorp had recorded specifically identified regulatory assets totaling $1,091 million and regulatory liabilities totaling $799 million. Refer to Note 3 of the Notes to the Consolidated Financial Statements included in Item 8 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 in 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 exemption 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. The fair value of these instruments are a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty credit worthiness and duration of contracts. Refer to Item 7A of this Form 10-K 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 probable of recovery in rates, and therefore recorded as a net regulatory asset or liability, or are accounted for as cash flow hedges, and therefore changes in fair value are recorded as accumulated other comprehensive income. Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2007, PacifiCorp had $256 million recorded as regulatory assets and $- million recorded as accumulated other comprehensive income related to these contracts in 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 and other postretirement benefit plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in joint trust plans to which PacifiCorp contributes. PacifiCorp recognizes the funded status of its defined benefit pension and postretirement plans in the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2007, PacifiCorp recognized a liability totaling $294 million for the under-funded status of its defined benefit pension and other postretirement benefit plans.

The expense and benefit obligations relating to PacifiCorp’s pension and other postretirement benefit 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 health care 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 and market conditions. Refer to Note 18 of Notes to the Consolidated Financial Statements included in Item 8 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 year ended December 31, 2007.

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 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 benefit 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 that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.

PacifiCorp chooses a health care cost trend rate that reflects the near and long-term expectations of increases in medical costs. The health care cost trend rate above gradually declines to 5% 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 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 (in millions):

							Other Postretirement
	Pension Plans						Benefit Plan
		+0.5	%		-0.5	%		+0.5	%		-0.5	%

Effect on December 31, 2007,
Benefit obligations:
Discount rate	$	(62	)	$	68		$	(32	)	$	35

Effect on 2007 periodic cost:
Discount rate	$	(7	)	$	9		$	(3	)	$	3
Expected return on assets		(4	)		4			(2	)		2

A variety of factors, including the plan funding practices of PacifiCorp, have an effect 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 2008; however, depending on a variety of factors that impact the funded status of the plans, including asset returns, discount rates and plan changes, PacifiCorp may be required to accelerate contributions to its pension plans for periods after 2008 and there may be more volatility in annual contributions than historically experienced, which could have a material impact on cash flows.

Effective June 1, 2007, PacifiCorp switched from a traditional final average pay formula for the PacifiCorp Retirement Plan (for its non-union employees) to a cash balance formula. As a result of the change, benefits under the traditional final average pay formula were frozen as of May 31, 2007, and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million.

Income Taxes

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 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 effect 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 of $423 million as of December 31, 2007, 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 bases 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 delivered, distributed or supplied to the end of the period. Unbilled revenue was $192 million as of December 31, 2007. 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.

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. PacifiCorp also has established guidelines for credit risk management. Refer to Notes 2 and 9 of Notes to the Consolidated Financial Statements included in Item 8 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 subject to significant commodity price risk. Exposures include variations in the price of fuel costs to generate electricity and the price of wholesale electricity that is purchased and sold. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other unpredictable items, changing weather, energy supply and demand, plant performance and transmission constraints. 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. Accordingly, 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 net regulatory assets or liabilities. Financial results 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-month period 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% confidence interval and five-day holding period. The new methodology is based on a 48-month forward position, 95% confidence interval and one-day holding period. The change to 95% 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, 2007, 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 $14 million, as measured by the VaR computations described above, compared to $16 million as of December 31, 2006. The minimum, average and maximum daily VaR (one-day holding periods) are as follows (in millions):

			Nine-Month
	Year Ended		Period Ended		Year Ended
	December 31, 2007		December 31, 2006		March 31, 2006

Minimum VaR (measured)	$	7	$	7	$	9
Average VaR (calculated)		12		12		14
Maximum VaR (measured)		20		16		19

PacifiCorp maintained compliance with its VaR limit procedures during the year ended December 31, 2007. 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 year ended December 31, 2007 and quantifies the reasons for the changes (in millions):

										Accumulated
										Other
							Net Regulatory			Comprehensive
	Net Asset (Liability)						Asset			(Income)
	Trading			Non-trading			(Liability)			Loss

Fair value of contracts outstanding at December 31, 2006	$	(3	)	$	(225	)	$	230		$	(3	)
Contracts realized or otherwise settled during the period		3			(41	)		39			3
Change in valuation techniques		-			27			(27	)		-
Other changes in fair values (a)		-			(17	)		14			-

Fair value of contracts outstanding at December 31, 2007	$	-		$	(256	)	$	256		$	-

(a)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, and 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. Option components are valued using Black-Scholes-type option models, such as European option, Asian option, spread option and best-of option, with the appropriate forward price curve and other inputs.

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, 2007 (in millions):

	Fair Value of Contracts at Period-End
	Maturity									Maturity in			Total
	Less Than			Maturity			Maturity			Excess of			Fair
	1 Year			1-3 Years			4-5 Years			5 Years			Value

Trading:
Values based on quoted market prices from third-party sources	$	-		$	1		$	(1	)	$	-		$	-

Non-trading:
Values based on quoted market prices from third-party sources	$	21		$	32		$	17		$	-		$	70
Values based on models and other valuation methods		5			46			(94	)		(283	)		(326	)

Total	$	26		$	78		$	(77	)	$	(283	)	$	(256	)

Net regulatory asset (liability)	$	(26	)	$	(78	)	$	77		$	283		$	256

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 table that follows summarizes PacifiCorp’s commodity risk on energy derivative contracts as of December 31, 2007 and shows the effects of 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 – Asset (Liability)			Hypothetical Price Change	Estimated Fair Value after Hypothetical Change in Price
As of December 31, 2007	$	(256	)	10% increase	$	(199	)
				10% decrease		(313	)

Interest Rate Risk

As of December 31, 2007, PacifiCorp had fixed-rate liabilities with an aggregate carrying value of $4.58 billion with a total fair value of $4.81 billion. Because of 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 $241 million if interest rates were to increase by 10% from their levels as of December 31, 2007. Comparatively, as of December 31, 2006, PacifiCorp had fixed-rate liabilities with an aggregate carrying value of $3.54 billion and a fair value of $3.74 billion. The fair value of these instruments would have decreased by approximately $130 million if interest rates had increased by 10% 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.

As of December 31, 2007, PacifiCorp had $542 million of variable-rate liabilities and $214 million of temporary cash investments compared to $939 million of variable-rate liabilities and $48 million of temporary cash investments at December 31, 2006. As of December 31, 2007 and 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of December 31, 2007, for a one-year horizon, PacifiCorp estimates that if market interest rates average 1% higher (lower) during the year ending December 31, 2008 than during the year ended December 31, 2007, interest expense, net of offsetting impacts of interest income, would increase (decrease) by $3 million. Comparatively, based on a sensitivity analysis as of December 31, 2006, for a one-year horizon, PacifiCorp estimates that had market interest rates averaged 1% higher (lower) during the year ended December 31, 2007 than during the year ended December 31, 2006, interest expense, net of offsetting impacts of interest income, would have increased (decreased) by $9 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, 2007 and December 31, 2006. The decrease in interest rate sensitivity is due to the decrease in outstanding variable-rate commercial paper and the increase 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.

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, 2007, 71% of PacifiCorp’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated “investment grade” credit ratings, while an additional 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, 2007, less than 1% 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 19% 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

Reports of Independent Registered Public Accounting Firms	62

Consolidated Statements of Income for the Year Ended December 31, 2007, the Nine-Month Period Ended December 31, 2006 and the Year Ended March 31, 2006	64

Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006	65

Consolidated Statements of Cash Flows for the Year Ended December 31, 2007, the Nine-Month Period Ended December 31, 2006 and the Year Ended March 31, 2006	67

Consolidated Statements of Changes in Common Shareholder’s Equity and Comprehensive Income for the Year Ended December 31, 2007, the Nine-Month Period Ended December 31, 2006 and the Year Ended March 31, 2006	68

Notes to the Consolidated Financial Statements	69

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

We have audited the accompanying consolidated balance sheets of PacifiCorp and its subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income and of cash flows for the year ended December 31, 2007 and the nine-month period ended December 31, 2006. 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 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 audits 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 audits provide 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, 2007 and 2006, and the results of their operations and their cash flows for the year ended December 31, 2007 and the nine-month period ended December 31, 2006, 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, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

In our opinion, the accompanying consolidated statements of income, common shareholder’s equity and comprehensive income and of cash flows for the year ended March 31, 2006 present fairly, in all material respects, the results of operations and cash flows of PacifiCorp and its subsidiaries for the year 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 audit. We conducted our audit 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 audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Portland, Oregon

May 26, 2006

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Amounts in millions)

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,
	2007			2006			2006

Revenues	$	4,258		$	2,924		$	3,897

Operating expenses:
Energy costs		1,768			1,297			1,545
Operations and maintenance		1,004			780			1,015
Depreciation and amortization		497			355			448
Taxes, other than income taxes		101			77			97

Total		3,370			2,509			3,105

Income from operations		888			415			792

Interest and other expense (income):
Interest expense		314			215			280
Interest income		(15	)		(6	)		(10	)
Allowance for borrowed funds		(29	)		(18	)		(19	)
Allowance for equity funds		(41	)		(17	)		(14	)
Other		-			(6	)		(5	)

Total		229			168			232

Income before income tax expense		659			247			560
Income tax expense		220			86			199

Net income	$	439		$	161		$	361

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)

	As of
	December 31,			December 31,
ASSETS	2007			2006

Current assets:
Cash and cash equivalents	$	228		$	59
Accounts receivable, net		391			342
Unbilled revenue		192			178
Amounts due from affiliates		34			53
Inventories at average cost:
Materials and supplies		163			140
Fuel		129			104
Derivative contracts		143			151
Deferred income taxes		55			28
Other		141			57
Total current assets		1,476			1,112

Property, plant and equipment:
Generation		6,814			6,134
Transmission		2,878			2,689
Distribution		4,885			4,655
Intangible plant		671			678
Other		1,766			1,687
Property, plant and equipment in service		17,014			15,843
Accumulated depreciation and amortization		(6,125	)		(5,842	)
Net property, plant and equipment in service		10,889			10,001
Construction work-in-progress		960			809
Total property, plant and equipment, net		11,849			10,810

Other assets:
Regulatory assets		1,091			1,397
Derivative contracts		215			235
Deferred charges and other		276			298
Total other assets		1,582			1,930

Total assets	$	14,907		$	13,852

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, continued

(Amounts in millions)

	As of
	December 31,			December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY	2007			2006

Current liabilities:
Accounts payable	$	449		$	385
Amounts due to affiliates		2			1
Accrued employee expenses		80			85
Taxes payable, other than income taxes		28			30
Interest payable		74			57
Derivative contracts		117			110
Long-term debt and capital lease obligations, currently maturing		414			127
Preferred stock subject to mandatory redemption, currently maturing		-			38
Short-term debt		-			397
Other		149			135
Total current liabilities		1,313			1,365

Deferred credits:
Deferred income taxes		1,701			1,641
Investment tax credits		54			62
Regulatory liabilities		799			822
Derivative contracts		497			504
Pension and other post employment liabilities		315			691
Other		395			374
Total deferred credits		3,761			4,094

Long-term debt and capital lease obligations, net of current maturities		4,753			3,967

Total liabilities		9,827			9,426

Commitments, contingencies and guarantees (Notes 15 and 16)

Shareholders' equity:
Preferred stock		41			41
Common equity:
Common shareholder's capital - 750 shares authorized, no par value, 357 shares issued and outstanding		3,804			3,600
Retained earnings		1,239			789
Accumulated other comprehensive loss, net		(4	)		(4	)

Total common equity		5,039			4,385

Total shareholders’ equity		5,080			4,426

Total liabilities and shareholders’ equity	$	14,907		$	13,852

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,
	2007			2006			2006
Cash flows from operating activities:
Net income	$	439		$	161		$	361
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized loss (gain) on derivative contracts, net		(1	)		104			(87	)
Depreciation and amortization		497			355			448
Deferred income taxes and investment tax credits, net		39			6			14
Regulatory asset/liability establishment and amortization		(45	)		5			52
Other		10			14			50
Changes in:
Accounts receivable, net and other assets		(75	)		(129	)		71
Inventories		(48	)		(32	)		(39	)
Amounts due to/from affiliates - MEHC, net		20			(51	)		4
Amounts due to/from affiliates - ScottishPower, net		-			-			33
Accounts payable and other liabilities		(12	)		(2	)		(12	)

Net cash provided by operating activities		824			431			895

Cash flows from investing activities:
Capital expenditures		(1,519	)		(1,051	)		(1,049	)
Proceeds from sale of assets		9			-			-
Proceeds from available-for-sale securities		30			68			123
Purchases of available-for-sale securities		(25	)		(82	)		(85	)
Other		8			9			(13	)

Net cash used in investing activities		(1,497	)		(1,056	)		(1,024	)

Cash flows from financing activities:
Changes in short-term debt		(397	)		213			(284	)
Proceeds from long-term debt, net of issuance costs		1,193			348			296
Proceeds from equity contributions		200			215			485
Dividends paid		(2	)		(2	)		(177	)
Repayments and redemptions of long-term debt and capital lease obligations		(127	)		(211	)		(270	)
Redemptions of preferred stock subject to mandatory redemption		(38	)		(8	)		(8	)
Other		13			9			8

Net cash provided by financing activities		842			564			50

Net change in cash and cash equivalents		169			(61	)		(79	)

Cash and cash equivalents at beginning of period		59			120			199

Cash and cash equivalents at end of period	$	228		$	59		$	120

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

(Amounts in millions, except per share amounts)

									Accumulated
	Common								Other			Total
	Shareholder’s Capital					Retained			Comprehensive			Comprehensive
	Shares		Amounts			Earnings			Income (Loss)			Income
Balance at March 31, 2005		312	$	2,894		$	446		$	(5	)
Net income		-		-			361			-		$	361
Other comprehensive income (loss):
Unrealized loss on available-for-sale securities, net of tax of $(1)		-		-			-			(2	)		(2	)
Minimum pension liability, net of tax of $3		-		-			-			5			5
Common stock issuance		45		485			-			-			-
Tax benefit from stock option exercises		-		8			-			-			-
Separation of employee benefit plans		-		(4	)		-			-			-
Other		-		(1	)		-			-			-
Cash dividends declared:
Preferred stock		-		-			(2	)		-			-
Common stock ($0.53 per share)		-		-			(175	)		-			-
Balance at March 31, 2006		357		3,382			630			(2	)	$	364

Net income		-		-			161			-		$	161
Other comprehensive income (loss):
Unrealized gain on derivative contracts, net of tax of $1		-		-			-			2			2
Unrealized loss on available-for-sale securities, net of tax of $(2)		-		-			-			(3	)		(3	)
Minimum pension liability, net of tax of $-		-		-			-			-			-
Adjustment to initially apply SFAS 158, net of tax of $(1)		-		-			-			(1	)		-
Equity contributions		-		215			-			-			-
Tax benefit from stock option exercises		-		3			-			-			-
Cash dividends declared:
Preferred stock		-		-			(2	)		-			-
Balance at December 31, 2006		357		3,600			789			(4	)	$	160

Net income		-		-			439			-		$	439
Other comprehensive income (loss):
Unrecognized amounts on retirement benefits, net of tax of $2		-		-			-			2			2
Unrealized loss on derivative contracts, net of tax of $(1)		-		-			-			(2	)		(2	)
Adoption of FASB Interpretation No. 48		-		-			13			-			-
Equity contributions		-		200			-			-			-
Tax benefit from stock option exercises		-		4			-			-			-
Cash dividends declared:
Preferred stock		-		-			(2	)		-			-
Balance at December 31, 2007		357	$	3,804		$	1,239		$	(4	)	$	439

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

PACIFICORP AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Operations

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States regulated electricity company serving 1.7 million retail customers, including residential, commercial, industrial and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric and wind-powered generating plants, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with public and private utilities, energy marketing companies and incorporated municipalities. The regulatory commission in each state approves rates for retail electric sales within that state. PacifiCorp’s subsidiaries support its electric utility operations by providing coal-mining facilities and services 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 is a holding company based in Des Moines, Iowa, that owns subsidiaries that are principally engaged in energy businesses.

In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. As a result, the Consolidated Statements of Income include the audited nine-month transition period ended December 31, 2006. Summarized consolidated unaudited financial data for the comparative nine-month period ended December 31, 2005 is as follows (in millions):


Revenues	$	2,667
Income from operations		521
Income tax expense		129
Net income		214

(2) Summary of Significant Accounting Policies

Basis of Consolidation

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

Minority interest in Bridger Coal Company was $79 million at December 31, 2007 and $65 million at December 31, 2006 and is included in Deferred credits – Other in the Consolidated Balance Sheets.

In April 2007, PacifiCorp acquired the outstanding 10% minority interest in PacifiCorp Environmental Remediation Company (“PERCo”) for $150,000 and PERCo became a wholly owned subsidiary of PacifiCorp. PERCo provides environmental remediation services to PacifiCorp.

In August 2007, PacifiCorp’s steam delivery subsidiary, Intermountain Geothermal Company, was merged into PacifiCorp. PacifiCorp now has 95% of the steam rights associated with the geothermal field serving PacifiCorp’s Blundell geothermal plant.

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, regulatory and income tax matters; and certain assumptions made in accounting for pension and other 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 money market funds and in other investments with a maturity of three months or less when purchased.

Marketable Securities

PacifiCorp’s management determines the appropriate classifications 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 and unrealized gains and losses recognized in accumulated other comprehensive income, net of tax. Realized and unrealized gains and losses on the trust fund related to the final reclamation of leased coal-mining property are recorded as regulatory assets or liabilities 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.

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 income from operations.

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 ability of customers to pay the amounts owed to PacifiCorp and the outcome of pending disputes and arbitrations. At December 31, 2007 and 2006, the allowance for doubtful accounts totaled $7 million and $12 million, respectively.

Derivatives

PacifiCorp employs a number of different derivative instruments in connection with its electric, natural gas and foreign currency exchange rate 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 qualify for the normal purchases and normal sales exemption afforded by GAAP. Contracts that qualify as normal purchases or normal sales are not marked to market. Derivative contracts for commodities used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases and normal sales pursuant to the exemption. Recognition of these contracts in Revenues or Energy costs in the Consolidated Statements of Income occurs when the contracts settle.

For contracts designated in hedge relationships (“hedge contract”), PacifiCorp maintains formal documentation of the hedge. In addition, at inception and on a quarterly basis, PacifiCorp formally assesses whether 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 earnings. 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 current earnings.

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

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. The fair value of these instruments is a function of underlying forward commodity prices, related volatility, counterparty creditworthiness and duration of the contracts.

Inventories

Inventories consist mainly of materials and supplies, coal stocks, natural gas 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.

Generally when PacifiCorp retires or sells its regulated property, plant and equipment, it charges the original cost to accumulated depreciation. Any cost of removal is charged against the cost of removal regulatory liability established through depreciation rates. Salvage is recorded in the related accumulated depreciation and amortization accounts and any residual gain or loss is amortized through future depreciation expense.

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 8.3% for the year ended December 31, 2007, 7.5% for the nine-month period ended December 31, 2006 and 6.5% for the year ended March 31, 2006.

Intangible plant consists primarily of computer software costs that are originally recorded at cost. Accumulated amortization on Intangible plant was $378 million at December 31, 2007 and $358 million at December 31, 2006. Amortization expense on Intangible plant was $44 million during the year ended December 31, 2007; $35 million during the nine-month period ended December 31, 2006; and $46 million during the year ended March 31, 2006. The estimated aggregate amortization on Intangible plant for the years ending from December 31, 2008 through 2012 is $39 million in 2008, $31 million in 2009, $27 million in 2010, $26 million in 2011 and $24 million in 2012. Unamortized computer software costs were $149 million at December 31, 2007 and $177 million at December 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 million at December 31, 2007 and 2006, and accumulated depreciation of $85 million and $80 million at December 31, 2007 and 2006, respectively.

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 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 group method either over the life prescribed by PacifiCorp’s various regulatory jurisdictions for regulated assets or over the assets’ estimated useful lives. The composite depreciation rate of average depreciable assets on utility Property, plant and equipment was 3% for the year ended December 31, 2007, the nine-month period ended December 31, 2006 and the year ended March 31, 2006.

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

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

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

In August 2007, PacifiCorp filed applications with the regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation. Agreements have been reached in each of these states and are in various stages of approval. Based on the new depreciation study, PacifiCorp expects the depreciable lives of its Property, plant and equipment generally to be extended beyond the lives assumed as of December 31, 2007. The most significant change is expected to result in increasing the range of depreciable lives for steam plant from 20 – 43 years to 20 – 57 years. When approved by the state commissions, the agreements will make the new depreciation rates effective January 1, 2008.

Revenue Recognition

Revenue from customers is recognized as electricity is delivered and includes amounts for services rendered. Revenue recognized includes 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.

PacifiCorp records sales, franchise and excise taxes, which are collected directly from PacifiCorp’s customers and remitted directly to taxing authorities, on a net basis in the Consolidated Statements of Income.

Income Taxes

As a result of the sale of PacifiCorp to MEHC on March 21, 2006, Berkshire Hathaway Inc. commenced including PacifiCorp in its United States 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 United States 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. Changes in deferred income tax assets and liabilities that are associated with income tax benefits related to certain property-related basis differences and other various differences that PacifiCorp is required to pass on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as a net regulatory asset of $423 million at December 31, 2007, and will be included in rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense.

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

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 the 2000 tax year. In addition, open tax years related to a number of state jurisdictions remain subject to examination. 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 recognizes interest income, interest expense and penalties related to income taxes in income tax expense in the Consolidated Statements of Income.

Segment Information

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

New Accounting Pronouncements

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”). PacifiCorp adopted the provisions of FIN 48 on January 1, 2007. Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in PacifiCorp’s tax returns that do not meet these recognition and measurements standards. Refer to Note 10 for additional discussion.

SFAS No. 141(R)

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS No. 141(R)”). SFAS No. 141(R) applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the acquirer of a business should recognize, measure and disclose in its financial statements the identifiable assets and goodwill acquired, the liabilities assumed and any noncontrolling interest in the acquired business. SFAS No. 141(R) is applied prospectively for all business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impact on PacifiCorp’s historical Consolidated Financial Statements and will be applied to business combinations completed, if any, on or after January 1, 2009.

SFAS No. 160

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires entities to report noncontrolling interests as a separate component of shareholders’ equity in the consolidated financial statements. The amount of earnings attributable to the parent and to the noncontrolling interests should be clearly identified and presented on the face of the consolidated statements of operations. Additionally, SFAS No. 160 requires any changes in a parent’s ownership interest of its subsidiary, while retaining its control, to be accounted for as equity transactions. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. PacifiCorp is currently evaluating the impact of adopting SFAS No. 160 on it consolidated financial position and results of operations.

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 does not anticipate electing the fair value option for any existing eligible items. However, PacifiCorp will continue to evaluate items on a case-by-case basis for consideration under the fair value option.

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 or 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”). PacifiCorp adopted the recognition and related disclosure provisions of SFAS No. 158 as of December 31, 2006. 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. As of December 31, 2007, PacifiCorp had not yet adopted the measurement date provisions of the statement. 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.

(3) Regulatory Matters

PacifiCorp is subject to the jurisdiction of public utility regulatory authorities 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 and Liabilities

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

	Weighted
	Average
	Remaining	December 31,		December 31,
	Life	2007		2006

Deferred income taxes (a)	33 years	$	459	$	464
Pension and other postretirement liabilities (b)	11 years		227		566
Derivative contracts	9 years		256		230
Deferral of incurred power costs	(c)		31		3
Asset retirement obligation	25 years		25		24
Unamortized issuance expense on retired debt	12 years		21		25
Environmental costs	8 years		8		14
Various other costs	Various		64		71

Total		$	1,091	$	1,397

(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. Refer to Note 18 for further discussion.
(c)	Recovery period has not yet been determined.

PacifiCorp had regulatory assets not earning a return on investment of $945 million at December 31, 2007.

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

	Weighted
	Average
	Remaining	December 31,		December 31,
	Life	2007		2006

Cost of removal (a)(b)	33 years	$	707	$	698
Deferred income taxes	Various		36		48
Asset retirement obligation (a)	40 years		22		16
Various other costs	Various		34		60

Total		$	799	$	822

(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.

Rate Matters

In October 2007, PacifiCorp filed its 2006 tax report under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual tax report with the Oregon Public Utility Commission (the “OPUC”). PacifiCorp’s filing indicates that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposes to amortize $27 million of the surcharge over a one-year period, which would result in an average price increase of 3%. If the OPUC issues an order providing for recovery in excess of $27 million and allows the deferral of the excess, the portion not yet recovered will be tracked in a balancing account accruing interest at PacifiCorp’s weighted cost of capital. The deferred amount, if any, would be addressed in a subsequent SB 408 filing. The 2006 tax report is currently being challenged during the 180-day procedural schedule that follows the date of the filing, with rates potentially effective June 2008. PacifiCorp expects to file its 2007 tax report under SB 408 during the fourth quarter of 2008. PacifiCorp has not recorded any amounts related to either the 2006 tax report or the 2007 expected filing.

(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 are recorded at fair value and included in Deferred charges and other and Current assets – Other. Trust fund assets, which include the Idaho Power Company minority-interest portion and amounts invested in money market accounts not classified as available-for-sale, were $117 million at December 31, 2007 and $110 million at December 31, 2006. Net 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. Refer to Note 7 for information regarding asset retirement obligations.

The amortized cost and fair value of reclamation trust securities and other investments included in Deferred charges and other and Current assets – Other in the Consolidated Balance Sheets, which are classified as available-for-sale, were as follows (in millions):

			Gross		Gross
	Amortized		Unrealized		Unrealized			Estimated
	Cost		Gains		Losses			Fair Value

December 31, 2007:
Debt securities	$	53	$	1	$	-		$	54
Equity securities		51		10		(3	)		58

Total	$	104	$	11	$	(3	)	$	112

December 31, 2006:
Debt securities	$	47	$	-	$	-		$	47
Equity securities		54		8		(1	)		61

Total	$	101	$	8	$	(1	)	$	108

The quoted market prices of securities are used to estimate their fair value.

The amortized cost and estimated fair value of debt and equity securities by contractual maturities are shown below (in millions). 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, 2007				December 31, 2006
	Amortized		Estimated		Amortized		Estimated
	Cost		Fair Value		Cost		Fair Value

Debt securities:
Due in one year or less	$	26	$	27	$	1	$	1
Due after one year through five years		9		9		21		21
Due after five years through ten years		1		1		6		6
Due after ten years		17		17		19		19
Equity securities		51		58		54		61
Total	$	104	$	112	$	101	$	108

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

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,
	2007			2006			2006

Proceeds	$	30		$	68		$	123

Gross gains	$	3		$	5		$	17
Gross losses		-			(1	)		(2	)

Net gains		3			4			15
Less net gains included in Regulatory liabilities		(3	)		(2	)		(17	)

Net gains (losses) included in Net income	$	-		$	2		$	(2	)

(5) Short-Term Borrowings

Short-Term Debt

At December 31, 2007, PacifiCorp did not have any outstanding short-term debt borrowings. At December 31, 2006, PacifiCorp’s outstanding short-term borrowings consisted of commercial paper arrangements of $397 million at an average interest rate of 5.3%.

Revolving Credit Agreements

At December 31, 2007, PacifiCorp had $1.5 billion available under its unsecured revolving credit facilities. During the year ended December 31, 2007, PacifiCorp entered into an unsecured revolving credit facility with total bank commitments of $700 million available through October 23, 2012. Under PacifiCorp’s previously existing unsecured revolving credit facility, $800 million is available through July 6, 2011 and $760 million is available from July 7, 2011 through July 6, 2012. Each credit facility includes a variable interest rate borrowing option based on the London Interbank Offered Rate (“LIBOR”) plus a margin that is currently 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, 2007 and 2006, PacifiCorp had no borrowings outstanding under either credit 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, 2007, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

(6) Long-Term Debt and Capital Lease Obligations

PacifiCorp’s long-term debt and capital lease obligations were as follows (in millions):

	December 31, 2007						December 31, 2006
				Average						Average
				Interest						Interest
	Amount			Rate			Amount			Rate

First mortgage bonds:
4.3% to 9.2%, due through 2012	$	1,169			6.6	%	$	1,295			6.6	%
5.0% to 8.8%, due 2013 to 2017		442			5.5			442			5.5
8.1% to 8.5%, due 2018 to 2022		175			8.1			175			8.1
6.7% to 8.2%, due 2023 to 2026		249			7.0			249			7.0
7.7% due 2031		300			7.7			300			7.7
5.3% to 6.3%, due 2034 to 2037		2,050			5.9			850			5.8
Unamortized discount		(5	)					(5	)
Pollution-control revenue obligations:
Variable rates, due 2013 (a) (b)		41			3.8			41			4.0
Variable rates, due 2014 to 2025 (b)		325			3.5			325			3.9
Variable rates, due 2024 (a) (b)		176			3.8			176			4.0
3.4% to 5.7%, due 2014 to 2025 (a)		184			4.5			184			4.5
6.2% due 2030		13			6.2			13			6.2
Unamortized discount		(1	)					(1	)
Capital lease obligations:
10.4% to 14.8%, due through 2036		49			11.3			50			11.7

Total		5,167						4,094
Less current maturities		(414	)					(127	)
Total	$	4,753					$	3,967

(a)	Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution-control revenue bond obligations.
(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 PacifiCorp’s mortgage. Approximately $16 billion of the eligible assets (based on original cost) of PacifiCorp were subject to the lien of the mortgage at December 31, 2007.

In October 2007, PacifiCorp issued $600 million of its 6.25% First Mortgage bonds due October 15, 2037. In March 2007, PacifiCorp issued $600 million of it 5.75% First Mortgage Bonds due April 1, 2037.

As of December 31, 2007, $3.9 billion of first mortgage bonds were redeemable at PacifiCorp’s option at redemption prices dependent upon United States Treasury yields. As of December 31, 2007, $542 million of variable-rate pollution-control revenue bond obligations were redeemable at PacifiCorp’s option at par. As of December 31, 2007, $71 million of fixed-rate pollution-control revenue bond obligations were redeemable at PacifiCorp’s option at par and another $13 million at 101% of par. The remaining long-term debt was not redeemable at December 31, 2007.

At December 31, 2007, PacifiCorp had $518 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. These committed bank arrangements were all fully available at December 31, 2007 and expire periodically through May 2012.

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 1.0. PacifiCorp monitors these covenants on a regular basis in order to ensure that events of default will not occur and at December 31, 2007, 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. There were no non-cash capital lease additions to property, plant and equipment during the year ended December 31, 2007. Non-cash capital lease additions to property, plant and equipment were $17 million during the nine-month period ended December 31, 2006 and $12 million during the year ended March 31, 2006. Assets accounted for as capital leases of $49 million as of December 31, 2007 and 2006 were included in Property, plant and equipment – Other in the Consolidated Balance Sheets.

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

	Long-term			Capital Lease
	Debt			Obligations			Total

2008	$	412		$	7		$	419
2009		139			7			146
2010		15			7			22
2011		587			7			594
2012		17			7			24
Thereafter		3,954			85			4,039
Total		5,124			120			5,244
Unamortized discount		(6	)		-			(6	)
Amounts representing interest		-			(71	)		(71	)
Total	$	5,118		$	49		$	5,167

(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.

The following table describes the changes to PacifiCorp’s asset retirement obligation liability for the year ended December 31, 2007 and the nine-month period ended December 31, 2006 (in millions):

	December 31, 2007			December 31, 2006

Liability recognized at beginning of period	$	221		$	212
Liabilities incurred		2			4
Liabilities settled		(27	)		(4	)
Revisions in cash flow (a)		(22	)		1
Accretion expense		11			8

Asset retirement obligation		185			221

Less current portion (b)		30			20

Long-term asset retirement obligation at end of period (c)	$	155		$	201

(a)	Results from changes in the timing and amounts of estimated cash flows for certain plant and mine reclamation.
(b)	Amount included in Current liabilities – Other in the Consolidated Balance Sheets.
(c)	Amount included in Deferred credits – Other in the Consolidated Balance Sheets.

PacifiCorp had trust fund assets recorded at fair value, substantially relating to mine reclamation, that were included in Current assets – Other and Deferred charges and other of $119 million at December 31, 2007 and $112 million at December 31, 2006, including the minority-interest joint-owner portions.

(8) Preferred Stock Subject to Mandatory Redemption

In June 2007, PacifiCorp redeemed $38 million of outstanding preferred stock subject to mandatory redemption, representing all remaining outstanding shares of PacifiCorp’s $7.48 No Par Serial Preferred Stock Series. At December 31, 2006, PacifiCorp had 375,000 No Par Serial Preferred shares outstanding with a $100 stated value, totaling $38 million. During the nine-month period ended December 31, 2006, PacifiCorp redeemed $8 million of Preferred stock subject to mandatory and optional redemption.

(9) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. 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, assess, monitor, report, manage and mitigate 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, 2007 and 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2007 (in millions):

												Accumulated
												Other
									Net Regulatory			Comprehensive
	Derivative Net Assets (Liability)								Assets			(Income)
	Assets		Liabilities			Total			(Liabilities)			Loss (a)

Commodity	$	357	$	(614	)	$	(257	)	$	257		$	-
Foreign currency		1		-			1			(1	)		-
	$	358	$	(614	)	$	(256	)	$	256		$	-

Current	$	143	$	(117	)	$	26
Non-current		215		(497	)		(282	)
Total	$	358	$	(614	)	$	(256	)

(a)	Before income taxes.

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

												Accumulated
												Other
									Net Regulatory			Comprehensive
	Derivative Net Assets (Liability)								Assets			(Income)
	Assets		Liabilities			Total			(Liabilities)			Loss (a)

Commodity	$	383	$	(614	)	$	(231	)	$	233		$	(3	)
Foreign currency		3		-			3			(3	)		-
	$	386	$	(614	)	$	(228	)	$	230		$	(3	)

Current	$	151	$	(110	)	$	41
Non-current		235		(504	)		(269	)
Total	$	386	$	(614	)	$	(228	)

(a)	Before income taxes.

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 prices 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.

PacifiCorp 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 energy 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.

Derivative Instruments

Forward physical and financial swap energy contracts that do not qualify for the exemptions afforded by GAAP are accounted for as derivatives and are recorded in 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 Consolidated Balance Sheets. For those energy contracts that are probable of recovery in rates, the unrealized gains and losses on derivative instruments are recorded as a net regulatory 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.

Realized and 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 electricity and natural gas 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 swap energy contracts. 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 forward purchase and sale derivative contracts not held for trading purposes are presented on a net basis in the Consolidated Statements of Income as Revenues. Realized gains and losses on financial swap energy contracts are presented in the Consolidated Statements of Income as Energy costs and Operations and maintenance expense.

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 Accumulated 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. 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 swap energy contracts.

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:

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31, 2007			December 31, 2006 (a)			March 31, 2006

Revenues	$	(6	)	$	29		$	224
Operating expenses:
Energy costs		7			(133	)		(131	)
Operations and maintenance		-			-			(6	)

Total unrealized gain (loss) on derivative contracts	$	1		$	(104	)	$	87

(a)

During the nine-month period 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% 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 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 $44 million and a pre-tax increase to Accumulated other comprehensive income of $4 million.

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. Options components are valued using Black-Scholes-type option models, such as European option, Asian option, spread option and best-of option, with the appropriate forward price curve and other inputs.

Foreign Currency Derivatives

PacifiCorp has entered into an agreement with a turbine supplier related to a wind plant under construction that requires PacifiCorp to make certain payments in Euros. To mitigate the related exposure to fluctuations in foreign currency exchange rates, PacifiCorp entered into forward contracts to purchase Euros at a fixed price of United States Dollars. There is one remaining settlement date of March 31, 2008 that corresponds to the final payment to be made in Euros under the supply agreement. The forward contracts qualify as derivative instruments. As the cost of the associated wind plant is expected to be recovered in rates, the unrealized gain on this contract was recorded as a net regulatory asset. The unrealized gain was $1 million and $3 million at December 31, 2007 and 2006, respectively.

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 recognized a loss of $12 million during the nine-month period ended December 31, 2006 and a loss of $16 million during the year ended March 31, 2006. PacifiCorp currently has no streamflow or other weather derivative contracts.

(10) Income Taxes

Income tax expense (benefit) consists of the following (in millions):

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31, 2007			December 31, 2006			March 31, 2006

Current:
Federal	$	162		$	71		$	167
State		19			9			18
Total		181			80			185

Deferred:
Federal		41			11			20
State		6			1			2
Total		47			12			22

Investment tax credits		(8	)		(6	)		(8	)
Total income tax expense	$	220		$	86		$	199

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

				Nine-Month
	Year Ended			Period Ended			Year Ended
	December 31, 2007			December 31, 2006			March 31, 2006

Federal statutory rate		35	%		35	%		35	%
State taxes, net of federal benefit		3			4			3
Effect of regulatory treatment of depreciation differences		2			6			3
Tax reserves		(1	)		(5	)		1
Tax credits		(3	)		(4	)		(3	)
Other		(3	)		(1	)		(3	)
Effective income tax rate		33	%		35	%		36	%

The net deferred tax liability consists of the following (in millions):

	December 31, 2007			December 31, 2006

Deferred tax assets:
Regulatory liabilities	$	311		$	320
Employee benefits		138			295
Derivative contracts		107			102
Other deferred tax assets		167			128
		723			845
Deferred tax liabilities:
Property, plant and equipment		(1,641	)		(1,526	)
Regulatory assets		(598	)		(727	)
Derivative contract regulatory assets		(97	)		(87	)
Other deferred tax liabilities		(33	)		(118	)
		(2,369	)		(2,458	)
Net deferred tax liability	$	(1,646	)	$	(1,613	)

Reflected as:
Current assets – Deferred income taxes	$	55		$	28
Deferred credits – Deferred income taxes		(1,701	)		(1,641	)
	$	(1,646	)	$	(1,613	)

As of December 31, 2007 and December 31, 2006, PacifiCorp had no federal or state net operating loss carryforwards.

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.

PacifiCorp adopted FIN 48 effective January 1, 2007 and had a net asset of $22 million for uncertain tax positions. PacifiCorp recognized a net increase in the asset of $22 million as a cumulative effect of adopting FIN 48, which was offset by increases in beginning retained earnings of $13 million and deferred income tax liabilities of $9 million in the Consolidated Balance Sheets. The $22 million was included in Deferred credits – Other in the Consolidated Balance Sheets.

PacifiCorp had a net asset of $13 million for uncertain tax positions at December 31, 2007, including $15 million of tax positions that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect PacifiCorp’s effective tax rate. The current portion of uncertain tax positions is included in Current assets – Other and the non-current portion is included in Deferred credits – Other in the Consolidated Balance Sheets.

(11) Preferred Stock

PacifiCorp’s preferred stock, not subject to mandatory redemption, was as follows (shares in thousands, dollars in millions, except per share amounts):

		Redemption		December 31, 2007				December 31, 2006
		Price Per Share		Shares		Amount		Shares		Amount

Series:
Serial Preferred, $100 stated value, 3,500 shares authorized
	4.52%	$	103.5		2	$	-		2	$	-
	4.56		102.3		85		8		85		8
	4.72		103.5		70		7		70		7
	5.00		100.0		42		4		42		4
	5.40		101.0		66		6		66		6
	6.00	Non-redeemable			6		1		6		1
	7.00	Non-redeemable			18		2		18		2
5% Preferred, $100 stated value, 127 shares authorized			110.0		126		13		126		13
					415	$	41		415	$	41

Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. In the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp board of directors in the event dividends payable are in default in an amount equal to four full quarterly payments.

Dividends declared but unpaid on preferred stock were $1 million at December 31, 2007 and 2006.

(12) Common Shareholder’s Equity

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, 2007, 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, 2007, 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 Notes 5 and 6.

(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 gave the holders the right to acquire ScottishPower American Depository Shares, were required to be exercised by March 21, 2007 (12 months after the date of the sale of PacifiCorp) or 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 provided that all outstanding options, which gave the holders the right to acquire ScottishPower American Depository Shares, were 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 were not exercised within this time period were forfeited. Upon its sale, PacifiCorp ceased to participate in the plan. As of December 31, 2007, there were no remaining options outstanding and exercisable by PacifiCorp employees.

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

	PSIP					ExSOP
				Weighted					Weighted
	Number of			Average		Number of			Average
	Shares			Price		Shares			Price

ScottishPower American Depository Shares:

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

Exercised		(184,661	)		37.84		(31,316	)		27.20
Forfeited		(28,269	)		36.42		(3,540	)		26.45

Outstanding options at December 31, 2007		-		$	-		-		$	-

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

		Options Outstanding and Exercisable
				Weighted		Weighted
				Average		Average
				Exercise		Remaining
Range of Exercise Prices		Number of Shares		Price		Life (in years)

December 31, 2007

PSIP:	$ -		-	$	-		-
ESOP:	$ -		-		-		-

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

(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:

	December 31,			December 31,
	2007			2006


Unrealized gain on derivative contracts	$	-		$	2
Pension and other postretirement liabilities		(4	)		(6	)

Total accumulated other comprehensive loss, net	$	(4	)	$	(4	)

(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 consolidated 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 and are described below.

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 Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal 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 that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods 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. The court granted a motion to bifurcate the trial into separate liability and remedy phases. A five-day trial on the liability phase is scheduled to begin on April 21, 2008. The remedy-phase trail has not yet been set. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

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, 2007, 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 $29 million at December 31, 2007 and $40 million at December 31, 2006 and is included in Deferred credits – Other in the Consolidated Balance Sheets. The December 31, 2007 recorded liability included $18 million of discounted liabilities. Had none of the liabilities included in the $29 million balance recorded at December 31, 2007 been discounted, the total would have been $32 million. The expected undiscounted payments for each of the years ending December 31, 2008 through 2012 and thereafter are as follows: $9 million in 2008, $3 million in 2009, $2 million in 2010, $2 million in 2011, $1 million in 2012 and $15 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 $17 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 47 plants with an aggregate plant net owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of this portfolio through 16 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 and litigation 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 $89 million and $79 million in costs as of December 31, 2007 and 2006, respectively, for ongoing hydroelectric relicensing, which are reflected in Construction work-in-progress in the Consolidated Balance Sheets.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW (nameplate rating) 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 the 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 expects to 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.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $48 million and $42 million in costs at December 31, 2007 and 2006, respectively, which are reflected in Construction work-in-progress in the 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

In June 2007, the FERC approved PacifiCorp’s settlement and release of claims agreement (“Settlement”) with Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, the People of the State of California, ex rel. Edmund G. Brown Jr., Attorney General, the California Electricity Oversight Board, and the California Public Utilities Commission (collectively, the “California Parties”), certain of which purchased energy in the California Independent System Operator (“ISO”) and the California Power Exchange (“PX”) markets during past periods of high energy prices in 2000 and 2001. The Settlement, which was executed by PacifiCorp in April 2007, settles claims brought by the California Parties against PacifiCorp for refunds and remedies in numerous related proceedings (together, the “FERC Proceedings”), as well as certain potential civil claims, arising from events and transactions in Western United States energy markets during the period January 2000 through June 2001 (the “Refund Period”). Under the Settlement, PacifiCorp made cash payments to escrows controlled by the California Parties in the amount of $16 million in April 2007, and upon FERC approval of the agreement in June 2007, PacifiCorp allowed the PX to release an additional $12 million to such escrows, which represented PacifiCorp’s estimated unpaid receivable from the transactions in the PX and ISO markets during the Refund Period, plus interest. The monies held in escrow are for distribution to buyers from the ISO and PX markets that purchased power during the Refund Period. The agreement provides for the release of claims by the California Parties (as well as additional parties that join in the Settlement) against PacifiCorp for refunds, disgorgement of profits, or other monetary or non-monetary remedies in the FERC Proceedings, and provides a mutual release of claims for civil damages and equitable relief.

Northwest Refund Case

In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In November 2003, the FERC issued its final order denying rehearing. Several market participants filed petitions in the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) for review of the FERC’s final order. In August 2007, the Ninth Circuit issued its order on this appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy made by the California Energy Resources Scheduling (“CERS”) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and did not rule on the merits of the FERC’s November 2003 decision to deny refunds. Due to the remand, PacifiCorp cannot predict the impact of this ruling at this time.

(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, 2007.

PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning commitments require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation commitments 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 commitments.

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 million until October 2008 and a cap of $5 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 (in millions)

	Payments Due During the Year Ending December 31,
	2008		2009		2010		2011		2012		Thereafter		Total

Construction	$	342	$	6	$	1	$	-	$	-	$	-	$	349
Operating leases		9		4		4		3		3		35		58
Purchased electricity		734		487		414		256		182		1,874		3,947
Transmission		61		64		60		54		47		404		690
Fuel		607		531		445		276		118		1,104		3,081
Other		187		121		125		111		63		1,030		1,637

Total commitments	$	1,940	$	1,213	$	1,049	$	700	$	413	$	4,447	$	9,762

Construction

PacifiCorp has an ongoing construction program to meet increased electricity usage, customer growth and system reliability objectives. At December 31, 2007, PacifiCorp had estimated long-term unconditional purchase obligations related to the construction of five new wind plants.

Operating Leases

PacifiCorp leases offices, certain operating facilities, land and equipment under operating leases that expire at various dates through the year 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 $24 million during the year ended December 31, 2007; $19 million during the nine-month period ended December 31, 2006; and $29 million during the year ended March 31, 2006.

Minimum non-cancelable sublease rent payments expected to be received through the year ended December 31, 2018 total $21 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, 2007, PacifiCorp’s share of long-term arrangements with public utility districts was as follows (in millions):

	Year Contract	Nameplate		Percentage			Annual
	Expires	(MW)		of Output			Costs (a)
Generating Facility:
Wanapum	2009		194		19	%	$	10
Rocky Reach	2011		69		5			4
Priest Rapids	2045		63		7			3
Wells	2018		53		7			3
Total			379				$	20

(a)	Includes debt service totaling $11 million.

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

	Minimum		Operating
	Debt Service		Obligations

2008	$	11	$	12
2009		11		12
2010		5		6
2011		5		6
2012		3		4
Thereafter		64		122
	$	99	$	162

PacifiCorp has a 4% 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% entitlement of the Intermountain Power Project at a price equivalent to 4% 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. Also included are contributions expected to be made to the PacifiCorp Retirement Plan during the year ending December 31, 2008 as disclosed in Note 18 below.

(17) Variable-Interest Entities

PacifiCorp holds an undivided interest in 50% of the 474-MW Hermiston plant (refer to Note 21), procures 100% of the fuel input into the plant and subsequently receives 100% of the generated electricity, 50% of which is acquired through a long-term power purchase agreement. As a result, PacifiCorp holds a variable-interest in the joint owner of the remaining 50% of the 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 $36 million during the year ended December 31, 2007; $26 million during the nine-month period ended December 31, 2006; and $35 million during the year ended March 31, 2006. 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.

(18) Employee Benefit Plans

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides certain postretirement health care 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 $4 million reduction in Common shareholder’s equity during the year ended March 31, 2006.

Pension and Other Postretirement Plans

PacifiCorp’s pension plans include a non-contributory defined benefit pension plan, the PacifiCorp Retirement Plan (the “Retirement Plan”); the Supplemental Executive Retirement Plan (the “SERP”); and certain multi-employer and joint trust union plans to which PacifiCorp contributes on behalf of certain bargaining units. Benefits for union employees covered 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.

Effective June 1, 2007, PacifiCorp switched from a traditional final average pay formula for the Retirement Plan to a cash balance formula for its non-union employees. As a result of the change, benefits under the traditional final average pay formula were frozen as of May 31, 2007 for non-union employees, and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million. Non-union employees hired on or after January 1, 2008 will not be eligible to participate in PacifiCorp’s Retirement Plan. These non-union employees will be eligible to receive enhanced benefits under PacifiCorp’s defined contribution plan.

Effective December 31, 2007, Local Union No. 659 of the International Brotherhood of Electrical Workers (“Local 659”) elected to cease participation in the Retirement Plan and participate only in PacifiCorp’s defined contribution plan with enhanced benefits. As a result of this election, the Local 659 participants’ benefits were frozen as of December 31, 2007.

The cost of other postretirement benefits, including health care and life insurance benefits for eligible retirees, is accrued over the active service period of employees. PacifiCorp funds these other postretirement benefits through a combination of funding vehicles. PacifiCorp also contributes to joint trust union plans for postretirement benefits offered to certain bargaining units.

Plan assets and benefit obligations are measured three months prior to PacifiCorp’s fiscal year end. Accordingly, plan assets and benefit obligations were measured as of September 30. 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 after 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.

Net periodic benefit cost for the pension, including the SERP, and other postretirement benefit plans included the following components (in millions):

	Pension									Other Postretirement
				Nine-Month									Nine-Month
	Year Ended			Period Ended			Year Ended			Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,			December 31,			December 31,			March 31,
	2007			2006			2006			2007			2006			2006

Service cost (a)	$	29		$	22		$	31		$	7		$	7		$	9
Interest cost		71			56			74			33			25			30
Expected return on plan assets		(68	)		(54	)		(77	)		(26	)		(19	)		(26	)
Net amortization		23			23			31			19			15			17
Cost of termination benefits		1			2			3			-			-			-
Curtailment loss		-			1			-			-			-			-

Net periodic benefit cost	$	56		$	50		$	62		$	33		$	28		$	30

(a)	Service cost excludes $12 million of contributions to the multi-employer and joint trust union plans during the year ended December 31, 2007, $6 million during the nine-month period ended December 31, 2006 and $1 million during the year ended March 31, 2006.

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

	Pension						Other Postretirement
				Nine-Month						Nine-Month
	Year Ended			Period Ended			Year Ended			Period Ended
	December 31,			December 31,			December 31,			December 31,
	2007			2006			2007			2006

Plan assets at fair value, beginning of period	$	884		$	825		$	318		$	292
Employer contributions		80			79			46			30
Participant contributions		-			-			11			7
Actual return on plan assets		118			56			46			19
Benefits paid		(119	)		(76	)		(43	)		(30	)

Plan assets at fair value, end of period	$	963		$	884		$	378		$	318

The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $40 million and $39 million at December 31, 2007 and 2006, respectively. These assets are not included in the plan assets in the above table. The portion of the pension plans’ projected benefit obligation, included in the table below, related to the SERP was $52 million and $54 million at December 31, 2007 and 2006, respectively.

The following table is a reconciliation of the benefit obligations at the end of the period (in millions):

	Pension						Other Postretirement
				Nine-Month						Nine-Month
	Year Ended			Period Ended			Year Ended			Period Ended
	December 31,			December 31,			December 31,			December 31,
	2007			2006			2007			2006

Benefit obligation, beginning of period	$	1,333		$	1,342		$	566		$	582
Service cost		29			22			7			7
Interest cost		71			56			33			25
Participant contributions		-			-			11			7
Plan amendments		(130	)		-			-			-
Actuarial gain		(74	)		(13	)		(40	)		(25	)
Benefits paid		(119	)		(76	)		(43	)		(30	)
Cost of termination benefits		1			2			-			-
Medicare Part D subsidy		-			-			2			-
Benefit obligation, end of period	$	1,111		$	1,333		$	536		$	566

Accumulated benefit obligation as of the measurement date	$	1,061		$	1,165

The SERP’s accumulated benefit obligation totaled $52 million and $53 million at December 31, 2007 and 2006, respectively.

The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets are as follows (in millions):

	Pension						Other Postretirement
	December 31,			December 31,			December 31,			December 31,
	2007			2006			2007			2006

Plan assets at fair value, end of period	$	963		$	884		$	378		$	318
Less - Benefit obligation, end of period		1,111			1,333			536			566

Funded status		(148	)		(449	)		(158	)		(248	)

Contributions after the measurement date but before year-end		-			-			12			27

Amounts recognized in the Consolidated Balance Sheets	$	(148	)	$	(449	)	$	(146	)	$	(221	)

Amounts recognized in the Consolidated Balance Sheets:
Other current liabilities	$	(4	)	$	(4	)	$	-		$	-
Pension and other post employment liabilities		(144	)		(445	)		(146	)		(221	)

Amounts recognized	$	(148	)	$	(449	)	$	(146	)	$	(221	)

Amounts not yet recognized as components of net periodic benefit cost:
Net loss	$	250		$	400		$	45		$	109
Prior service cost (credit)		(115	)		9			17			20
Net transition obligation		3			5			60			72

Total	$	138		$	414		$	122		$	201

A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the year ended December 31, 2007 is as follows (in millions):

				Accumulated
				Other
	Regulatory			Comprehensive
	Asset			Income			Total
Pension
Balance, beginning of year	$	405		$	9		$	414
Prior service cost arising during the year		(129	)		(1	)		(130	)
Net gain arising during the year		(121	)		(2	)		(123	)
Net amortization		(23	)		-			(23	)
Total		(273	)		(3	)		(276	)
Balance, end of year	$	132		$	6		$	138

				Deferred
	Regulatory			Income
	Asset			Taxes			Total
Other Postretirement
Balance, beginning of year	$	161		$	40		$	201
Net gain arising during the year		(47	)		(13	)		(60	)
Net amortization		(19	)		-			(19	)
Total		(66	)		(13	)		(79	)
Balance, end of year	$	95		$	27		$	122

The net loss, prior service cost and net transition obligation that will be amortized in 2008 into net periodic benefit cost are estimated to be as follows (in millions):

	Net		Prior Service			Net Transition
	Loss		Cost			Obligation		Total

Pension benefits	$	17	$	(13	)	$	3	$	7
Other postretirement benefits		-		3			12		15

Total	$	17	$	(10	)	$	15	$	22

Plan Assumptions

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

	Pension									Other Postretirement
				Nine-Month									Nine-Month
	Year Ended			Period Ended			Year Ended			Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,			December 31,			December 31,			March 31,
	2007			2006			2006			2007			2006			2006

Benefit obligations as of the measurement date:
Discount rate		6.30	%		5.85	%		5.75	%		6.45	%		6.00	%		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		5.76	%		5.75	%		5.75	%		6.00	%		5.75	%		5.75	%
Expected return on plan assets		8.00			8.50			8.75			8.00			8.50			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-Month
	Year Ended			Period Ended			Year Ended
	December 31,			December 31,			March 31,
	2007			2006			2006

Health care cost trend rate assumed for next year - under 65		9	%		10	%		10	%
Health care cost trend rate assumed for next year - over 65		7			8			10
Rate that the cost trend rate gradually declines to		5			5			5
Year that rate reaches the rate it is assumed to remain at - under 65	2012			2012			2011
Year that rate reaches the rate it is assumed to remain at - over 65	2010			2010			2011

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 (in millions):

	Increase (Decrease) in Expense
	One Percentage-Point		One Percentage-Point
	Increase		Decrease

Effect on total service and interest cost	$	3	$	(2	)
Effect on other postretirement benefit obligation		40		(33	)

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement benefit plans are expected to be approximately $70 million and $27 million, respectively, for 2008. Also during 2008, PacifiCorp expects to contribute approximately $12 million to the joint trust union plans.

Retirement Plan costs are funded annually by at least the minimum required amount but by no more than the maximum amount that can be deducted for federal income tax purposes. The Pension Protection Act of 2006 changes funding rules beginning in 2008 and may have the effect of making minimum pension funding requirements more volatile than they have been historically. Accordingly, PacifiCorp continually evaluates its funding strategies. PacifiCorp’s policy is to contribute to its other postretirement benefit plan an amount equal to the net periodic cost.

PacifiCorp’s expected benefit payments to participants for its pension and other postretirement plans for 2008 through 2012 and for the five years thereafter are summarized below (in millions):

	Projected Benefit Payments
			Other Postretirement
	Pension		Gross		Medicare Subsidy		Net of Subsidy

2008	$	89	$	38	$	3	$	35
2009		86		39		4		35
2010		91		40		4		36
2011		92		42		4		38
2012		99		42		5		37
2013 – 2017		535		232		31		201

Investment Policy and Asset Allocation

The 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 foreign stocks, as well as growth and value companies, and small and large market capitalizations. Fixed-income investments are diversified across United States and foreign 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.

100

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 assets of the Retirement Plan. Each of the two Voluntary Employees’ Beneficiaries Association Trusts has its own investment allocation strategies.

PacifiCorp’s asset allocation was as follows:

										Voluntary Employees’
	Pension & Other Postretirement									Beneficiaries Association Trust
	December 31,			December 31,						December 31,			December 31,
	2007			2006			Target			2007			2006			Target

Equity securities		56	%		58	%		53 – 57	%		64	%		65	%		63 – 67	%
Debt securities		35			35			33 – 37			36			35			33 – 37
Other		9			7			8 – 12			-			-			-
		100	%		100	%					100	%		100	%

Defined Contribution Plan

PacifiCorp’s employee savings plan qualifies as a tax-deferred arrangement under the Internal Revenue Code and covers substantially all employees. PacifiCorp’s contributions to the employee savings plan were $19 million during the year ended December 31, 2007, $16 million during the nine-month period ended December 31, 2006 and $23 million during the year ended March 31, 2006.

Severance

PacifiCorp has undertaken a review of its organization and workforce. As a result of the review, PacifiCorp incurred severance expense of $4 million during the year ended December 31, 2007, $31 million during the nine-month period ended December 31, 2006 and $17 million during the year ended March 31, 2006.

(19) Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximate fair value because of the short-term maturity of these instruments. Derivative instruments are recorded at their fair values, which are based upon published market indexes as adjusted for other market factors such as location pricing differences or internally developed models. Substantially all investments are carried at their fair values, which are based on quoted market prices.

The fair value of PacifiCorp’s fixed-rate long-term debt, current maturities of long-term debt and preferred stock subject to mandatory redemption has been estimated based on quoted market prices. The carrying amount of variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying amount and estimated fair value of PacifiCorp’s long-term debt and preferred stock subject to mandatory redemption, including the current portion (in millions):

	December 31, 2007				December 31, 2006
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

Long-term debt	$	5,118	$	5,350	$	4,044	$	4,243
Preferred stock subject to mandatory redemption		-		-		38		38

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(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.

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 $- million at December 31, 2007 and $1 million at December 31, 2006. Services provided by affiliates and charged to PacifiCorp related primarily to the transport of natural gas, relocation services, and administrative services provided under the intercompany administrative services agreement among MEHC and its affiliates. These payables were $2 million at December 31, 2007 and $1 million at December 31, 2006. These expenses totaled $14 million during the year ended December 31, 2007 and $8 million during the nine-month period ended December 31, 2006.

PacifiCorp has long-term transportation contracts with the Burlington Northern Santa Fe Railway (“BNSF”), in which PacifiCorp’s ultimate parent company, Berkshire Hathaway, acquired a 17% ownership interest during 2007. At December 31, 2007, PacifiCorp had $2 million of accounts payable to BNSF outstanding under these contracts, including indirect payables related to a jointly owned plant. Transportation costs under these contracts were $31 million during the year ended December 31, 2007.

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, 2008. Prepayments to MISL were $2 million at December 31, 2007 and $2 million at December 31, 2006. Receivables for claims were $11 million at December 31, 2007 and $8 million at December 31, 2006. Premium expenses were $7 million during the year ended December 31, 2007, $6 million during the nine-month period ended December 31, 2006 and $- million during the period March 21, 2006 through March 31, 2006.

PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated tax return. As of December 31, 2007, Amounts due from affiliates included $23 million of income taxes receivable from PacifiCorp’s parent company. As of December 31, 2006, Amounts due from affiliates included $44 million of income taxes receivable from PacifiCorp’s parent company.

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 $8 million for the year ended March 31, 2006. 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 $14 million for the year ended March 31, 2006. 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 $45 million for the year ended March 31, 2006.

102

(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. Operating costs of each plant are assigned to joint owners based on ownership percentage or energy purchased, depending on the nature of the cost. Operating expenses in the Consolidated Statements of Income include PacifiCorp’s share of the expenses of these units.

The amounts shown in the table below represent PacifiCorp’s share in each jointly owned plant at December 31, 2007 (dollars in millions):

				Plant		Accumulated		Construction
	PacifiCorp			in		Depreciation/		Work-in-
	Share			Service		Amortization		Progress

Jim Bridger Nos. 1 - 4 (a)		67	%	$	965	$	482	$	13
Wyodak (a)		80			329		168		1
Hunter No. 1		94			304		146		1
Colstrip Nos. 3 and 4 (a)		10			243		118		1
Hunter No. 2		60			192		87		1
Hermiston (b)		50			170		37		2
Craig Nos. 1 and 2		19			167		77		1
Hayden No. 1		25			44		20		1
Foote Creek		79			37		13		-
Hayden No. 2		13			27		14		-
Other transmission and distribution plants	Various				80		20		2

Total				$	2,558	$	1,182	$	23

(a)	Includes transmission lines and substations.
(b)	Additionally, PacifiCorp has contracted to purchase the remaining 50% of the output of the Hermiston plant. Refer to Note 17 for further discussion.

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.

(22) Supplemental Cash Flow Information

A summary of supplemental cash flow information is presented in the following table (in millions):

			Nine-Month
	Year Ended		Period Ended		Year Ended
	December 31,		December 31,		March 31,
	2007		2006		2006

Income taxes paid	$	151	$	121	$	140
Interest paid, net of amounts capitalized	$	251	$	192	$	240

103

(23) Unaudited Quarterly Operating Results (in millions)


	Three-Month Periods Ended
	March 31,		June 30,		September 30,		December 31,
	2007		2007		2007		2007

Revenues	$	1,027	$	1,026	$	1,137	$	1,068
Income from operations		201		201		269		217
Net income		99		105		135		100

	Three-Month Periods Ended
	June 30,		September 30,		December 31,
	2006		2006		2006

Revenues	$	860	$	1,097	$	967
Income from operations		122		132		161
Net income		43		59		59

104

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T). CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

At the end of the period covered by this Annual Report Form 10-K, PacifiCorp carried out an evaluation, under the supervision and with the participation of PacifiCorp’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of PacifiCorp’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, PacifiCorp’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal 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. There has been no change in PacifiCorp’s internal control over financial reporting during the quarter ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Management of PacifiCorp is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act Rule 13a-15(f). Under the supervision and with the participation of PacifiCorp’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), PacifiCorp’s management conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2007 as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, PacifiCorp’s management used the criteria set forth in the framework in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in “Internal Control – Integrated Framework,” PacifiCorp’s management concluded that PacifiCorp's internal control over financial reporting was effective as of December 31, 2007.

This report does not include an attestation report of PacifiCorp’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PacifiCorp’s registered public accounting firm pursuant to temporary rules of the SEC that permit PacifiCorp to provide only management's report in this Annual Report on Form 10-K.

PacifiCorp

February 21, 2008

ITEM 9B. OTHER INFORMATION

None.

105

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Board of Directors appoints executive officers annually. There are no family relationships among the executive officers, nor any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of January 31, 2008, with respect to each of the current directors and executive officers of PacifiCorp:

Gregory E. Abel, 45, Chairman of the Board of Directors and Chief Executive Officer. 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, 49, 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 1993.

Brent E. Gale, 56, 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 legislative and strategic positions with MEHC and its predecessors since 1976.

Patrick J. Goodman, 41, 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.

Natalie L. Hocken, 38, Director. Ms. Hocken was elected director in August 2007. She has served as Vice President and General Counsel of Pacific Power, a division of PacifiCorp, since January 2007. Prior to that, she served as Assistant General Counsel and Senior Counsel for PacifiCorp. Ms. Hocken joined PacifiCorp in 2002.

A. Robert Lasich, 48, President, PacifiCorp Energy and Director. Mr. Lasich was elected President of PacifiCorp Energy, a division of PacifiCorp in August 2007. He 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 1997.

David J. Mendez, 40, Senior Vice President, Chief Financial Officer and Director. Mr. Mendez was appointed Senior Vice President and Chief Financial Officer in August 2006 and elected director in August 2007. He 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. On February 8, 2008, Mr. Mendez resigned as a director and officer of PacifiCorp effective February 29, 2008.

Mark C. Moench, 52, Director. Mr. Moench was named PacifiCorp General Counsel in February 2007. He joined PacifiCorp as Senior Vice President and General Counsel of Rocky Mountain Power, a division of PacifiCorp, 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.

R. Patrick Reiten, 46, 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.

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A. Richard Walje, 56, President, Rocky Mountain Power, and Director. Mr. Walje was elected President of Rocky Mountain Power in March 2006. 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.

Audit Committee and Audit Committee Financial Expert

During the year ended December 31, 2007, 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 officer, its principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is incorporated by reference in the exhibits to this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION COMMITTEE REPORT

Mr. Abel, our Chairman and Chief Executive Officer and sole member of our Compensation Committee, has reviewed and discussed the Compensation Discussion and Analysis with management and, based on this review and discussion, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Form 10-K.

COMPENSATION DISCUSSION AND ANALYSIS

Compensation Philosophy and Overall Objectives

We and our parent company, MidAmerican Energy Holdings Company, or MEHC, believe that the compensation paid to each of our Chief Executive Officer, or CEO, our Chief Financial Officer, or CFO, and our three other most highly compensated executive officers, to whom we refer collectively as our Named Executive Officers, or NEOs, should be closely aligned with our overall performance, and each NEO’s contribution to that 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 our NEOs meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and non-financial objectives that we believe contribute to our long-term success, and among which are financial strength, customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity.

How is Compensation Determined

Our Compensation Committee consists solely of the Chairman of our Board of Directors, Mr. Gregory E. Abel. Mr. Abel also serves as our CEO and as MEHC’s President and Chief Operating Officer. He is employed by MEHC and receives no direct compensation from us. Mr. Abel is responsible for the establishment and oversight of our compensation policy for our NEOs and for approving merit increases, incentive and performance awards, off-cycle pay changes, and participation in other employee benefit plans and programs.

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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. Given the uniqueness of each NEO’s duties, we do not specifically use companies as benchmarks when initially establishing our NEOs’ compensation.

Discussion and Analysis of Specific Compensation Elements

Base Salary

We determine base salaries for all of our NEOs, other than Mr. Abel, by reviewing our overall performance and each NEO’s 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 annual base salary adjustment for each NEO, other than Mr. Abel, is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. Annual merit increases are approved by Mr. Abel. In 2007, base salaries for all NEOs, other than Messrs. Abel and Lasich, increased on average by 3.5% and became effective December 26, 2006. Also effective December 26, 2006, Mr. Lasich, serving in his former role as Vice President and General Counsel of PacifiCorp Energy, received a base salary increase of 17.2%. Mr. Lasich was appointed President of PacifiCorp Energy in August 2007. An increase or decrease in base pay may also result from a promotion or other significant change in a NEO’s responsibilities during the year.

Short-Term Incentive Compensation

The objective of short-term incentive compensation is to reward the achievement of significant annual corporate goals while also providing NEOs with competitive total cash compensation.

Annual Incentive Plan

Under our Annual Incentive Plan, or AIP, all NEOs, other than Mr. Abel, are eligible to earn an annual discretionary cash incentive award, which is determined on a subjective basis and is not based on a specific formula or cap. Mr. Abel establishes a target bonus opportunity, expressed as a percentage of base salary and intended to reflect fully effective performance, for each of the other NEOs prior to the beginning of each year. Awards paid to a NEO under the AIP are based on a variety of measures linked to our overall performance and each NEO’s contribution to that performance. An individual NEO’s performance is measured against defined objectives that commonly include financial measures (e.g., net income and cash flow) and non-financial measures (e.g., customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity), as well as the NEO’s response to issues and opportunities that arise during the year.

Performance Awards

In addition to the annual awards under the AIP, 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. These awards are discretionary and approved by Mr. Abel. There were no awards granted in 2007.

Long-Term Incentive Compensation

The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. Our current long-term incentive compensation program is cash-based. Under MEHC ownership, we do not utilize equity-based compensation, such as stock option awards or equity incentive plan awards.

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Long-Term Incentive Partnership Plan

The MEHC Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align our interests and the interests of the participating employees. Messrs. Mendez, Walje, Reiten and Lasich participate in our LTIP, while Mr. Abel does not. Our LTIP provides for annual awards based upon significant accomplishments by the individual participants and the achievement of the financial and non-financial objectives previously described. 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 Mr. Abel. Except for limited situations of extraordinary performance, awards are capped at 1.5 times base salary. The value is finalized in the first quarter of the following year. These cash-based awards are subject to mandatory deferral and equal annual vesting over a five-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives, which are determined each year by a vote of all participants. Gains or losses may be incurred based on the investment performance. Participating NEOs may elect to defer all or part of the award or receive payment in cash after the five-year mandatory deferral and vesting period. Vested balances (including any investment profits or losses thereon) of terminating participants are paid at the time of termination.

Other Employee Benefits

Supplemental Executive Retirement Plan

The PacifiCorp Supplemental Executive Retirement Plan, or SERP, provides additional retirement benefits to participants. Mr. Walje was the only NEO who participated in our SERP during 2007, and the plan is currently closed to any new participants. The SERP provides monthly retirement benefits of 50% of final average pay plus 1% of final average pay for each fiscal year that we meet certain performance goals set for such fiscal year. The maximum benefit is 65% of final average pay. A participant’s final average pay equals the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose includes salary and annual incentive plan payments reflected in the Summary Compensation Table below.

Deferred Compensation Plan

Our Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs, other than Mr. Abel, to make voluntary deferrals of up to 50% of base salary and 100% of short-term incentive compensation awards. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of eight investment options offered under the DCP and selected by the participant and the plan allows participants to choose from three forms of distribution. While the plan allows us to make discretionary contributions, we have not made contributions to date. We include the DCP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.

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EXECUTIVE COMPENSATION

2007 Summary Compensation Table

The following table sets forth information regarding compensation earned by each of our NEOs during the years indicated:

						Change in
						Pension
						Value and
						Non-Qualified
						Deferred
		Base				Compensation		All Other
Name and Principal Position	Year	Salary		Bonus (b)		Earnings (c)		Compensation (d)		Total

Gregory E. Abel (a)	2007	$	-	$	-	$	-	$	-	$	-
Chairman and	2006		-		-		-		-		-
Chief Executive Officer

David J. Mendez (e)	2007		214,200		138,868		7,920		59,716		420,704
Senior Vice President and	2006		147,635		158,488		6,903		86,707		399,733
Chief Financial Officer

A. Richard Walje	2007		335,811		346,582		177,128		486,302		1,345,823
President, Rocky Mountain	2006		248,108		377,106		168,501		177,982		971,697
Power

R. Patrick Reiten	2007		250,000		330,838		3,484		2,083		586,405
President, Pacific Power	2006		-		-		-		-		-

A. Robert Lasich	2007		173,580		257,603		11,311		9,181		451,675
President, PacifiCorp Energy	2006		-		-		-		-		-

(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, 2007 (File No. 001-14881) for executive compensation information for Mr. Abel.
(b)	Consists of annual cash incentive awards earned pursuant to the AIP for our NEOs and the vesting of LTIP awards and associated earnings for Messrs. Mendez, Walje, Reiten and Lasich. The breakout for 2007 is as follows:

			AIP	LTIP
	David J. Mendez		$ 75,000	$ 63,868	($2,407 in investment profits)
	A. Richard Walje		170,000	176,582	($7,521 in investment profits)
	R. Patrick Reiten		170,000	160,838	($7,521 in investment profits)
	A. Robert Lasich (i)		170,000	87,603	($4,225 in investment profits)


	(i)	Includes amounts deferred pursuant to the Deferred Compensation Plan of $85,000 for Mr. Lasich.

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	LTIP awards are subject to mandatory deferral and equal annual vesting over a five–year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives, which are determined by a vote of all participants. Gains or losses may be incurred based on the investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the five-year mandatory deferral and vesting period. Vested balances (including any investment profits or losses thereon) of terminating participants are paid at the time of termination. Because the amounts to be paid out may increase or decrease depending on investment performance, the ultimate payouts are undeterminable. Net income, the net income target goal and the matrix below were used in determining the gross amount of the LTIP award available to Messrs. Mendez, Walje, Reiten, and Lasich. Net income is subject to discretionary adjustment by the CEO, President and Compensation Committee of MEHC. In 2007, the gross award and per-point value were adjusted to eliminate the earnings benefit of a reduction in the United Kingdom corporate income tax rate from 30% to 28% and for failing to achieve certain non-financial performance factors.
			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%

	A pool of up to 100,000 points in aggregate is allocated between plan participants either as initial points or year-end performance points. A nominating committee recommends the point allocation, subject to approval by the CEO and President of MEHC, based upon a discretionary evaluation of individual achievement of financial and non-financial goals previously described herein. A participant’s award equals their allocated points multiplied by the final per-point value, capped at 1.5 times base salary except in extraordinary circumstances.
(c)	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 assumptions consistent with those 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.
(d)	Amounts shown for the year ended December 31, 2007, include:
	(i)	Payment in the amount of $82,703 to Mr. Walje by Scottish Power plc, or ScottishPower, under the Transaction Incentive Program, a $6.0 million pool created by ScottishPower for retention incentives during the period of completion of ScottishPower’s sale of us to MEHC.
	(ii)	Performance-based retention payment in the amount of $50,000 to Mr. Mendez, representing the final installment under the May 2005 retention agreement entitling Mr. Mendez to a retention bonus (up to $100,000) for remaining employed at an acceptable level of performance in our corporate finance department through May 30, 2007 and developing a succession and risk mitigation plan for his position.
	(iii)	Mr. Walje participated in the ScottishPower Long-Term Incentive Plan while PacifiCorp was under ScottishPower ownership. Due to the sale of ScottishPower to Iberdrola, S.A., Mr. Walje’s stock award became fully vested and its value paid to him by ScottishPower in cash and shares in the amount of $392,869.
	(iv)	Company contributions to our Employee Savings and Stock Ownership Plan of $10,729 for Mr. Walje.
(e)	Mr. Mendez resigned on February 8, 2008 effective February 29, 2008.

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2007 Option Exercises and Stock Vested Table

The following table sets forth information regarding option exercises and stock vested by each of our NEOs during the year ended December 31, 2007. 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. All stock awards are for ScottishPower American Depository Shares and were granted under the ScottishPower Long-Term Incentive Plan.

	Option Awards				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		-	$	-		-	$	-
David J. Mendez		-		-		-		-
A. Richard Walje		38,332		941,852		3,923		392,869
R. Patrick Reiten		-		-		-		-
A. Robert Lasich		-		-		-		-

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 Mr. Walje. Mr. Walje participated in the ScottishPower Long-Term Incentive Plan while PacifiCorp was under ScottishPower ownership. Due to the sale of ScottishPower to Iberdrola, S.A., Mr. Walje’s stock award became fully vested and its value paid to him in cash and shares.

2007 Pension Benefits Table

We have adopted a non-contributory defined benefit retirement plan, or the Retirement Plan, for our employees, other than employees subject to collective bargaining agreements that do not provide for coverage. Mr. Walje also participates in our non-qualified SERP. Through May 31, 2007, participants earned benefits at retirement payable for life based on length of service through May 31, 2007 and average pay in the 60 consecutive months of highest pay out of the 120 months prior to May 31, 2007, and pay for this purpose included salary and annual incentive plan payments up to 10% of base salary, but were limited to the Internal Revenue Code amounts specified in §401(a)(17). Benefits were based on 1.3% of final average pay plus 0.65% of final average pay in excess of compensation subject to Federal Insurance Contributions Act (“FICA”) withholding times years of service.

The Retirement Plan was restated effective June 1, 2007 to change from a traditional average pay formula as described above to a cash balance formula for non-union participants. Benefits under the final average pay formula were frozen as of May 31, 2007, and no future benefits will accrue under that formula. Under the cash balance formula, benefits are based on 6.5% (5% for employees hired after July 1, 2006) of eligible compensation plus 4.0% of eligible compensation in excess of compensation subject to FICA withholding ($97,500 for 2007) to each participant’s account (where such salary and incentive amounts are reduced for Internal Revenue Code §401(a)(17) limits). Interest is also credited to each participant’s account. Employees who are age 40 or older will receive certain additional transition pay credits for five years from the effective date of the plan restatement.

Participants are entitled to receive full benefits upon retirement after age 65. Participants are also entitled to receive reduced benefits upon early retirement after age 55 with at least 5 years of service or when age plus years of service equals 75.

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The following table sets forth certain information regarding the Retirement Plan (and, in Mr. Walje’s case, the SERP) for each of our NEOs as of September 30, 2007:

Name	Plan Name	Number of Years of Service		Present Value of Accumulated Benefits

Gregory E. Abel			-	$	-
David J. Mendez	Retirement		5		37,045
A. Richard Walje	Retirement		22		603,881
	SERP		22		1,386,663
R. Patrick Reiten	Retirement		1		3,484
A. Robert Lasich	Retirement		2		15,249

Amounts are computed using the SFAS No. 158 assumptions used in preparing the applicable pension disclosures included in the Notes to the Consolidated Financial Statements and are as of September 30, 2007, 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 6.30%; 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 6.30%; an expected retirement age of 65; postretirement mortality using the RP-2000 tables; a lump sum interest rate of 6.05%; and lump sum mortality using the Internal Revenue Code §417(e)(3) Applicable Mortality Table for 2008.

The SERP provides monthly retirement benefits of 50% of final average pay plus 1% of final average pay for each fiscal year that we meet certain performance goals set for such fiscal year. The maximum benefit is 65% of final average pay. A participant’s final average pay equals the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose includes salary and annual incentive plan payments reflected in the Summary Compensation Table above. Mr. Walje has met the five-year participation requirement under the plan for early retirement eligibility. Mr. Walje’s SERP benefit will be reduced by a portion of his Social Security benefits, his regular retirement benefit under our Retirement Plan, and 0.25% for each month benefit commencement precedes age 60.

The above reference for the number of years of service and the present value of accumulated benefits for Mr. Lasich represents his service as a PacifiCorp employee only and does not include any vested benefits earned under MEHC.

2007 Non-Qualified Deferred Compensation Table

The following table sets forth certain information regarding the DCP accounts held by each of our NEOs as of December 31, 2007:

Name	Executive Contributions (a)		Aggregate Earnings		Aggregate Balance at Period-End

Gregory E. Abel	$	-	$	-	$	-
David J. Mendez		-		-		-
A. Richard Walje		-		75,053		1,524,255
R. Patrick Reiten		-		-		-
A. Robert Lasich		85,000		-		85,000

(a)	Mr. Lasich’s contribution is included within his “bonus” column total reported in the Summary Compensation Table.

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Eligibility for our DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow on a tax-deferred basis; thus, participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes due on that bonus or award. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of eight investment options offered by the plan and selected by the participant. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation elections. Participants can change their fund allocations as of the end of any calendar month.

The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement distribution, in-service distribution and education distribution. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments, except in the case of the four DCP transition accounts that allow for a grandfathered payout based on the previous deferred compensation plan distribution elections of lump sum, 5, 10, or 15 annual installments. Effective December 31, 2006, no new money may be deferred into the DCP Transition accounts. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55) all amounts in the participant’s account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.

Participants in our LTIP also have the option of deferring all or a part of those awards after the five-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.

Potential Payments Upon Termination or Change-in-Control

Our Executive Severance Plan was closed on May 24, 2007. The plan had provided severance benefits to only legacy participants previously designated by our Compensation Committee under ScottishPower ownership.

Our NEOs (excluding Mr. Abel) are not entitled to severance or enhanced benefits upon termination of employment or change-in-control. Please refer to MEHC’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-14881) for information about potential post-termination and change-in-control payments to Mr. Abel. However, upon any termination of employment, our other NEOs would be entitled to the Retirement Plan and SERP vested balances presented in the Pension Benefits and the balances presented in Non-Qualified Deferred Compensation Tables above.

Messrs. Mendez, Walje, Reiten, and Lasich are also entitled to full vesting of outstanding awards under the MEHC LTIP in the event of death or disability. As of December 31, 2007, the value of the unvested portions of outstanding awards under this plan were $227,595 for Mr. Mendez; $619,207 for Mr. Walje; $556,233 for Mr. Reiten; and $391,085 for Mr. Lasich. In the event of termination, Messrs. Mendez, Walje, Reiten, and Lasich would be entitled to the vested benefits under this plan included in the Summary Compensation Table.

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2007 Director Compensation Table

With the exception of Mr. Karras, all of our directors serving in 2007 were employees of PacifiCorp, or in the case of Messrs. Anderson and Goodman, employees of MEHC, and did not receive additional compensation for service as a director. The following table excludes Messrs. Mendez, Walje, Reiten and Lasich, for whom compensation information is reported in the Summary Compensation Table.

	Change in
	Pension Value and		All Other
	Non-Qualified		Compensation
Name	Compensation Earnings		(a)		Total

Douglas L. Anderson	$	-	$	-	$	-

William J. Fehrman		21,598		499,833		521,431

Brent E. Gale		24,034		559,127		583,161

Patrick J. Goodman		-		-		-

Natalie L. Hocken		3,589		288,000		291,589

Nolan Karras		-		-		-

Mark C. Moench		18,526		433,365		451,891

Stanley K. Watters		1,057,860		1,012,340		2,070,200

(a)	Amounts shown for the year ended December 31, 2007, include:
	(i)	Base salary in the amounts of $205,682 for Mr. Fehrman; $273,000 for Mr. Gale; $160,000 for Ms. Hocken; $205,200 for Mr. Moench; and $63,021 for Mr. Watters.
	(ii)	Awards earned pursuant to the AIP in the amounts of $140,000 for Mr. Gale; $80,000 for Ms. Hocken; and $100,000 for Mr. Moench.
	(iii)	Relocation expenses for Mr. Fehrman in the amount of $21,825.
	(iv)	Severance payments to Mr. Watters in the amount of $333,688.
	(v)	Personal time payout at termination of $55,768 for Mr. Watters.
	(vi)	Tax gross-up for Mr. Fehrman in the amount of $10,261 for relocation expenses and Mr. Watters in the amount of $547,239 for severance payments.
	(vii)	The vested portion of awards earned, (including earnings on previously earned awards) pursuant to the MEHC LTIP in the amounts of $255,986 (including earnings of $13,486) to Mr. Fehrman; $146,127 (including earnings of $7,054) to Mr. Gale; $48,000 to Ms. Hocken; and $128,165 (including earnings of $6,605) to Mr. Moench.

Mr. Watters resigned as a director and officer of PacifiCorp on March 16, 2007 and Mr. Fehrman resigned as a director and officer of PacifiCorp on August 30, 2007. Mr. Karras resigned as a Director of PacifiCorp on July 25, 2007 and did not receive compensation from PacifiCorp in 2007.

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Amounts included in change in pension value and non-qualified deferred compensation earnings 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 assumptions consistent with those 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.

Compensation Committee Interlocks and Insider Participation

Mr. Abel is our Chairman of the Board of Directors and Chief Executive Officer and also the President and Chief Operating Officer of MEHC. 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 of this Form 10-K.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

All outstanding shares of our common stock are indirectly owned by MEHC, 666 Grand Avenue, Des Moines, Iowa 50309. MEHC is a consolidated subsidiary of Berkshire Hathaway, that, as of January 31, 2008, owns approximately 88.2% of MEHC’s common stock (87.4% on a diluted basis). The remainder 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.

None of our executive officers or directors owns shares of our preferred stock. The following table sets forth certain information as of January 31, 2008 regarding the beneficial ownership of common stock of MEHC and the Class A and Class B common stock of Berkshire Hathaway held by each of our directors, executive officers and all of our directors and executive officers as a group as of January 31, 2008.

	MEHC					Berkshire Hathaway
	Common Stock					Class A Common Stock				Class B Common Stock
Beneficial Owner	Number of Shares Beneficially Owned (a)		Percentage of Class (a)			Number of Shares Beneficially Owned (a)		Percentage of Class (a)		Number of Shares Beneficially Owned (a)		Percentage of Class (a)

Gregory E. Abel (b)(c)		749,992		1.0	%		-		-		6		*
Douglas L. Anderson		-		-			3		*		-		-
Brent E. Gale		-		-			-		-		-		-
Patrick J. Goodman		-		-			2		*		3		*
Natalie L. Hocken		-		-			-		-		-		-
A. Robert Lasich		-		-			-		-		-		-
David J. Mendez		-		-			-		-		-		-
Mark C. Moench		-		-			1		*		-		-
R. Patrick Reiten		-		-			-		-		-		-
A. Richard Walje		-		-			-		-		-		-
All executive officers and directors as a group (10 persons)		749,992		1.0	%		6		*		9		*

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*	Indicates beneficial ownership of less than one percent of all outstanding shares.
(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)	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, 2008, 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 1,158 shares of Berkshire Hathaway Class A stock or 34,615 shares of Berkshire Hathaway Class B stock. Assuming an exchange of all available MEHC shares into either Berkshire Hathaway Class A shares or Berkshire Hathaway Class B shares, Mr. Abel would beneficially own less than 1% of the outstanding shares of either class of stock.
(c)	Includes options to purchase 154,052 shares of common stock that are presently exercisable or become exercisable within 60 days.

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.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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, or 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 five percent 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.

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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 determined that Nolan Karras was our only director serving during the year ended December 31, 2007 who was “independent.” Our remaining directors would not be considered independent because of their employment by MEHC or PacifiCorp. In making the determination that Mr. Karras was independent, our Board of Directors affirmatively determined that he had 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 paid Mr. Karras in prior years for service on one of our regional advisory boards, as described in “Executive Compensation – Director Compensation” included in Item 11 of this Form 10-K. Our Board of Directors considered no other transactions, relationships or arrangements involving Mr. Karras not disclosed in this Annual Report on Form 10-K. Mr. Karras resigned as a director of PacifiCorp in July 2007.

Refer to Note 20 of Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information regarding related-party transactions.

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 (“MEHC”). 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

The following table shows PacifiCorp’s fees paid or accrued for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively the “Deloitte Entities”), for the year ended December 31, 2007 and the nine-month period ended December 31, 2006 (in millions):

			Nine-Month
	Year Ended		Period Ended
	December 31,		December 31,
	2007		2006

Audit fees (1)	$	2.1	$	1.8
Audit-related fees (2)		0.2		0.2
Tax fees (3)		-		-
All other fees		-		-

Total aggregate fees billed	$	2.3	$	2.0

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(1)	Audit fees include fees for the audit and review of PacifiCorp’s consolidated financial statements and interim review of PacifiCorp’s quarterly financial statements, audit services provided in connection with required statutory audits, and comfort letters, statutory and regulatory audits, consents and services related to SEC matters.

(2)	Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain employee benefit plans and consultations on various accounting and reporting matters.

(3)	Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal and state tax compliance, tax return preparation and tax audits.

The audit committee of MEHC reviewed and approved the services rendered by the Deloitte Entities in and for fiscal 2007 as set forth in the above table and concluded that the non-audit services were compatible with maintaining the principal accountant’s independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit services performed by the principal accountant require approval in advance by the audit committee in order to assure that such services do not impair the principal accountant’s independence from other affiliated entities. Accordingly, the 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 principal 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. If not pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being performed by the principal 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 Policy does not delegate the audit committee’s responsibilities to pre-approve services performed by the principal accountant to management.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	1.	The list of all financial statements filed as a part of this report is included in Item 8 of this Form 10-K.

	2.	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.”

	3.	Exhibits:
Exhibit
Number		Exhibit Title

3.1*		Third Restated Articles of Incorporation of PacifiCorp (Exhibit (3)b, Annual Report on Form 10-K for the year ended December 31, 1996, filed March 21, 1997, File No. 1-5152).
3.2*		Bylaws of PacifiCorp, as amended May 23, 2005 (Exhibit 3.2, on Annual Report on Form 10-K for the year ended March 31, 2006, filed May 30, 2006, File No. 1-5152).
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 21 Supplemental Indentures as follows:


Exhibit Number	File Type	File Date	File Number
(4)(b)	SE	November 2, 1989	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
4.2	8-K	August 14, 2006	1-5152
4	8-K	March 14, 2007	1-5152
4.1	8-K	October 3, 2007	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% 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.

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4.3*	$700,000,000 Credit Agreement dated as of October 23, 2007 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and Union Bank of California, N.A., as Administrative Agent. (Exhibit 99, Quarterly Report on Form 10-Q, filed November 2, 2007, File No. 1-5152).

10.1	Summary of Key Terms of Named Executive Officer and Employee Director 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	PacifiCorp Executive Voluntary Deferred Compensation Plan

10.4*	Supplemental Executive Retirement Plan (Exhibit 10.7, Annual Report on Form 10-K, for the year ended March 31, 2005, 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*	David Mendez Retention Agreement (Exhibit 10.14, Transition Report on Form 10-K for the nine-month period ended December 31, 2006, filed March 2, 2007, 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 Preference Dividends.

14.1*	Code of Ethics (Exhibit 14.1, Transition Report on Form 10-K for the nine-month period ended December 31, 2006, filed March 2, 2007, File No. 1-5152).

23.1	Consent of Deloitte & Touche LLP.

23.2	Consent of PricewaterhouseCoopers LLP.

31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*Incorporated herein by reference.

(b)	See (a) 3. above.
(c)	See (a) 2. above.

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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 on this 29th day of February 2008.

	PACIFICORP

	/s/ David J. Mendez
	David J. Mendez
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

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

/s/ Gregory E. Abel	Chairman of the Board of Directors	February 29, 2008
Gregory E. Abel	and Chief Executive Officer
	(principal executive officer)

/s/ David J. Mendez	Senior Vice President, Chief	February 29, 2008
David J. Mendez	Financial Officer and Director
	(principal financial and accounting officer)


/s/ Douglas L. Anderson	Director	February 29, 2008
Douglas L. Anderson

/s/ Brent E. Gale	Director	February 29, 2008
Brent E. Gale

/s/ Patrick J. Goodman	Director	February 29, 2008
Patrick J. Goodman

/s/ Natalie L. Hocken	Director	February 29, 2008
Natalie L. Hocken

/s/ A. Robert Lasich	Director	February 29, 2008
A. Robert Lasich

/s/ Mark C. Moench	Director	February 29, 2008
Mark C. Moench

/s/ R. Patrick Reiten	Director	February 29, 2008
R. Patrick Reiten

/s/ A. Richard Walje	Director	February 29, 2008
A. Richard Walje

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