PACIFICORP /OR/ - Quarter Report: 2008 August (Form 10-Q)

pacificorp630200810q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

[ ] 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)

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 ¨

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer T

Smaller reporting company ¨

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

Yes ¨ No T

All shares of outstanding common stock are indirectly owned by MidAmerican Energy Holdings Company, 666 Grand Avenue, Des Moines, Iowa. As of July 31, 2008, there were 357,060,915 shares of common stock outstanding.

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	3

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	33

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	35

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35

Item 3.	Defaults Upon Senior Securities	35

Item 4.	Submission of Matters to a Vote of Security Holders	35

Item 5.	Other Information	35

Item 6.	Exhibits	35

Signatures		36

Exhibit Index		37

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

PacifiCorp

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries (“PacifiCorp”) as of June 30, 2008, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2008 and 2007, and of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of PacifiCorp’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2007, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income, and of cash flows for the year then ended (not presented herein); and in our report dated February 27, 2008, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of 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. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Portland, Oregon

August 8, 2008

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,			December 31,
	2008			2007

ASSETS

Current assets:
Cash and cash equivalents	$	58		$	228
Accounts receivable, net		528			594
Income taxes receivable from affiliates		40			23
Inventories at average cost:
Materials and supplies		179			163
Fuel		138			129
Derivative contracts		286			143
Other current assets		131			141
Deferred income taxes		78			55
Total current assets		1,438			1,476

Property, plant and equipment, net:
Property, plant and equipment		17,758			17,014
Accumulated depreciation and amortization		(6,213	)		(6,125	)
Net property, plant and equipment		11,545			10,889
Construction work-in-progress		820			960
Total property, plant and equipment, net		12,365			11,849

Other assets:
Regulatory assets		1,186			1,091
Derivative contracts		347			215
Deferred charges, investments and other		275			276
Total other assets		1,808			1,582

Total assets	$	15,611		$	14,907

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,			December 31,
	2008			2007

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	469		$	451
Accrued employee expenses		110			80
Accrued interest		71			74
Taxes payable, other than income taxes		63			28
Derivative contracts		274			117
Other current liabilities		138			149
Short-term debt		35			-
Current portion of long-term debt and capital lease obligations		215			414
Total current liabilities		1,375			1,313

Long-term liabilities:
Regulatory liabilities		808			799
Derivative contracts		660			497
Other long-term liabilities		612			710
Long-term debt and capital lease obligations		4,763			4,753
Investment tax credits		52			54
Deferred income taxes		1,864			1,701
Total liabilities		10,134			9,827

Commitments and contingencies (Notes 3 and 6)

Shareholders’ equity:
Preferred stock		41			41
Common equity:
Common shareholder’s capital - 750 shares authorized, no par value, 357 shares issued and outstanding		4,004			3,804
Retained earnings		1,445			1,239
Accumulated other comprehensive loss, net		(13	)		(4	)
Total common equity		5,436			5,039
Total shareholders’ equity		5,477			5,080

Total liabilities and shareholders’ equity	$	15,611		$	14,907

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007

Operating revenue	$	1,055		$	1,026		$	2,150		$	2,053

Operating costs and expenses:
Energy costs		437			425			912			840
Operations and maintenance		251			255			495			517
Depreciation and amortization		124			122			241			243
Taxes, other than income taxes		27			23			56			51
Total operating costs and expenses		839			825			1,704			1,651

Operating income		216			201			446			402

Other income (expense):
Interest expense		(80	)		(79	)		(164	)		(154	)
Allowance for borrowed funds		8			9			16			16
Allowance for equity funds		11			10			21			17
Interest income		2			4			5			7
Other		-			2			(1	)		2
Total other income (expense)		(59	)		(54	)		(123	)		(112	)

Income before income tax expense		157			147			323			290
Income tax expense		58			42			116			86
Net income	$	99		$	105		$	207		$	204

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2008			2007

Cash flows from operating activities:
Net income	$	207		$	204
Adjustments to reconcile net income to net cash flows from operations:
Depreciation and amortization		241			243
Regulatory asset/liability establishment and amortization		(52	)		(24	)
Provision for deferred income taxes and investment tax credits, net		159			(1	)
Other		-			13
Changes in other items:
Accounts receivable and other assets		77			(1	)
Derivative contract assets/liabilities, net		(65	)		1
Inventories		(32	)		(52	)
Income taxes receivable/payable from/to affiliates, net		(17	)		43
Accounts payable and other liabilities		(30	)		35
Net cash flows from operating activities		488			461

Cash flows from investing activities:
Capital expenditures		(710	)		(731	)
Purchases of available-for-sale securities		(44	)		(17	)
Proceeds from available-for-sale securities		50			19
Other		4			24
Net cash flows from investing activities		(700	)		(705	)

Cash flows from financing activities:
Changes in short-term debt		35			(367	)
Proceeds from long-term debt, net of issuance costs		-			600
Proceeds from equity contributions		200			150
Preferred dividends paid		(1	)		(1	)
Repayments of long-term debt and capital lease obligations		(201	)		(107	)
Redemptions of preferred stock subject to mandatory redemption		-			(38	)
Other		9			4
Net cash flows from financing activities		42			241

Net change in cash and cash equivalents		(170	)		(3	)
Cash and cash equivalents at beginning of period		228			59
Cash and cash equivalents at end of period	$	58		$	56

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

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States regulated electric company serving 1.7 million retail customers, including residential, commercial, industrial and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating 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. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company (“MEHC”), a holding company based in Des Moines, Iowa, owning subsidiaries that are principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”).

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the U.S. Securities and Exchange Commission’s (the “SEC”) rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the financial statements as of June 30, 2008, and for the three- and six-month periods ended June 30, 2008 and 2007. A portion of PacifiCorp’s business is of a seasonal nature and, therefore, the results of operations for the three- and six-month periods ended June 30, 2008 are not necessarily indicative of the results to be expected for the full year.

The unaudited 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.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007 describes the most significant accounting estimates and policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in PacifiCorp’s assumptions regarding significant accounting policies during the first six months of 2008.

(2) Change in Estimate and New Accounting Pronouncements

Change in Estimate

In August 2007, PacifiCorp filed applications with the regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change its rates of depreciation prospectively. PacifiCorp received approval to change the depreciation rates effective January 1, 2008. The Oregon Public Utility Commission (the “OPUC”) order required additional modifications related to the depreciation lives of coal-fired generation assets. In July 2008, PacifiCorp filed the modified depreciation rates with the OPUC. The revised depreciation rates generally reflect an extension of the lives of PacifiCorp’s assets and resulted in a benefit to pre-tax income during the three- and six-month periods ended June 30, 2008 of approximately $9 million and $23 million, respectively. Depreciation expense for the six-month period ended June 30, 2008 includes the year-to-date impact of the modified coal-fired generation asset depreciation rates submitted to the OPUC.

New Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand how and why an entity uses derivative instruments and their effects on an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 with early application encouraged. PacifiCorp is currently evaluating the impact of adopting SFAS No. 161 on its disclosures included within the notes to its Consolidated Financial Statements.

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.

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 its consolidated financial position and results of operations.

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 literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. PacifiCorp adopted SFAS No. 159 effective January 1, 2008 and did not elect the fair value option for any existing eligible items.

In September 2006, 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. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. PacifiCorp adopted the provisions of SFAS No. 157 for assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. The partial adoption of SFAS No. 157 did not have a material impact on PacifiCorp’s Consolidated Financial Statements. Refer to Note 9 for additional discussion.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”). SFAS No. 158 requires 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 June 30, 2008, 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 an immaterial 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

Oregon

In October 2007, PacifiCorp filed its tax report for 2006 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 a report annually with the OPUC comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. PacifiCorp’s filing indicated that for the 2006 tax year, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposed to recover $27 million of the deficiency over a one-year period starting June 1, 2008 and to defer any excess into a balancing account for future disposition. During the review process, PacifiCorp updated its filing to address the OPUC staff recommendations, which increased the initial request by $2 million for a total of $35 million. In April 2008, the OPUC approved PacifiCorp’s revised request with $27 million to be recovered over a one-year period beginning June 1, 2008, and the remainder to be deferred until a later period, with interest to accrue at PacifiCorp’s authorized rate of return. In June 2008, PacifiCorp recorded a $27 million regulatory asset and associated revenues representing the amount that PacifiCorp will collect from its Oregon retail customers over the one-year period that began on June 1, 2008. In May 2008, the Industrial Customers of Northwest Utilities filed a petition for judicial review in the Court of Appeals of the State of Oregon challenging the OPUC order. Briefs are anticipated to be filed in late 2008. PacifiCorp believes the outcome of the judicial review will not have a material impact on its consolidated financial results. 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 the expected filing for 2007.

Wyoming

In February 2008, PacifiCorp filed its annual power cost adjustment mechanism (“PCAM”) application with the Wyoming Public Service Commission (the “WPSC”) for costs incurred during the period December 1, 2006 through November 30, 2007. In March 2008, the WPSC approved PacifiCorp’s request on an interim basis effective April 1, 2008, resulting in a rate increase of $31 million, or an average price increase of 8%, to recover deferred power costs over a one-year period. In April 2008, PacifiCorp began collecting this interim surcharge from its Wyoming customers and will continue until the matter is either settled through negotiation with the parties or is litigated in a contested hearing, which has been scheduled for September 2008. In either case, the WPSC must approve the final surcharge and tariff. PacifiCorp believes the outcome of the negotiations or potential litigation will not have a material impact on its consolidated financial results.

(4) Recent Transactions

Debt Issuance

In July 2008, PacifiCorp issued $500 million of 5.65% First Mortgage Bonds due July 15, 2018 and $300 million of 6.35% First Mortgage Bonds due July 15, 2038. The net proceeds are being used for general corporate purposes.

Acquisition

In April 2008, PacifiCorp entered into a purchase agreement with TNA Merchant Projects, Inc., an affiliate of Suez Energy North America, Inc., to acquire 100% of the equity interests of an entity owning a 520-megawatt (“MW”) natural gas-fired facility located in Chehalis, Washington. PacifiCorp has obtained all necessary federal and state regulatory approvals and expects to close the transaction during the third quarter of 2008.

(5) 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, options, swaps and other over-the-counter agreements. 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.

In January 2008, PacifiCorp adopted FASB Staff Position No. FIN 39-1 (“FSP FIN 39-1”), which amends FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts. FSP FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions by requiring entities that net derivatives to offset the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral or the obligation to return cash collateral under those arrangements against the derivative values.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of June 30, 2008 (in millions):

											Accumulated
									Regulatory		Other
	Derivative Net Assets (Liabilities)								Net Assets		Comprehensive
	Assets(1)		Liabilities(1)			Net			(Liabilities)		(Income) Loss(2)

Commodity	$	633	$	(934	)	$	(301	)	$	344	$	14

Current	$	286	$	(274	)	$	12
Non-current		347		(660	)		(313	)
Total	$	633	$	(934	)	$	(301	)

(1)	Derivative assets (liabilities) include $65 million of a net asset for cash collateral.
(2)	Before income taxes.

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
									Regulatory			Other
	Derivative Net Assets (Liabilities)								Net Assets			Comprehensive
	Assets		Liabilities			Net			(Liabilities)			(Income) Loss(1)

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

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

(1)	Before income taxes.

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

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007

Operating revenue	$	(18	)	$	19		$	(35	)	$	25
Energy costs		16			(24	)		27			(27	)
Total unrealized loss on derivative contracts	$	(2	)	$	(5	)	$	(8	)	$	(2	)

(6) Commitments and Contingencies

Environmental Matters

PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act, related air quality standards promulgated by the United States 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 operation 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 June 30, 2008, PacifiCorp’s environmental contingencies principally consisted of air quality matters. PacifiCorp believes it is in material compliance with current environmental requirements.

Accrued Environmental Costs

PacifiCorp is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of PacifiCorp’s operations and sites owned by third parties. PacifiCorp accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, PacifiCorp’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of June 30, 2008 and December 31, 2007 was $29 million and is included in other current liabilities and other long-term liabilities in the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 plants with an aggregate plant net owned capacity of 1,158 MW. The Federal Energy Regulatory Commission (the “FERC”) regulates 98% of the net capacity of this portfolio through 16 individual licenses. During the six-month period ended June 30, 2008, the FERC issued new licenses for the Prospect and the Lewis River hydroelectric projects as described below. PacifiCorp’s Klamath hydroelectric project is currently undergoing 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 will 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 $87 million and $89 million in costs as of June 30, 2008 and December 31, 2007, respectively, for ongoing hydroelectric relicensing projects, which are reflected in construction work-in-progress in the Consolidated Balance Sheets.

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 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.

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 a new FERC license consistent with the FERC staff’s recommended alternative and modified terms and conditions issued by the Departments of Interior and Commerce. 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 that consultation on annual FERC licenses is not required. PacifiCorp is currently working with the United States Fish and Wildlife Service to resolve any endangered species issues. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has an application pending in Oregon. In July 2008, PacifiCorp withdrew its application for water quality certification in California to facilitate settlement negotiations. PacifiCorp intends to resubmit its application in the near future.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $52 million and $48 million in costs at June 30, 2008 and December 31, 2007, 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.

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, with total nameplate ratings of 37 MW. The Oregon Department of Environmental Quality issued a 401 Water Quality certificate for the project in April 2007. In April 2008, the FERC issued a new license for a period of 30 years effective April 1, 2008. In the relicensing of the Prospect hydroelectric project, PacifiCorp had incurred $7 million in costs as of June 30, 2008 and December 31, 2007. As of June 30, 2008, the costs to relicense the Prospect Hydroelectric Project were reflected in property, plant and equipment in the Consolidated Balance Sheet.

Lewis River Hydroelectric Project – (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. These commitments were 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. In June 2008, the FERC issued new individual project licenses for the Merwin, Swift No. 1 and Yale hydroelectric projects, each for a period of 50 years, effective June 1, 2008. In July 2008, PacifiCorp filed a motion of request for clarification or rehearing on certain items. By filing the request for rehearing, PacifiCorp has deferred acceptance of the licenses. However, each FERC license order states that filing a request for rehearing does not operate as a stay of the effective date of the license or any other date specified in the license order. To remain compliant during this period, PacifiCorp is acting upon the terms and conditions of each new license. In the relicensing of these projects, PacifiCorp had incurred $35 million in costs as of June 30, 2008 and $34 million as of December 31, 2007, which are reflected in construction work-in-progress in the Consolidated Balance Sheets.

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 complaint 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 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. In March 2008, the court indefinitely postponed the date for the liability-phase trial. The remedy-phase trial has not yet been scheduled. The court also has before it a number of motions on which it has not yet ruled. 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.

FERC Issues

Northwest Refund Case

In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In November 2003, the FERC issued its final order denying rehearing. Several market participants, excluding PacifiCorp, filed petitions in the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) for review of the FERC’s final order. In August 2007, the Ninth Circuit concluded that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest, and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy 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.

(7) Employee Benefit Plans

Net periodic benefit cost for PacifiCorp’s pension plans, including its supplemental executive retirement plan, and other postretirement benefit plans included the following components (in millions):

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007

Pension:
Service cost	$	7		$	6		$	14		$	14
Interest cost		17			19			33			38
Expected return on plan assets		(17	)		(17	)		(35	)		(34	)
Net amortization and other costs		1			6			3			14
Net periodic benefit cost	$	8		$	14		$	15		$	32


Other postretirement:
Service cost	$	1		$	2		$	3		$	4
Interest cost		9			9			17			17
Expected return on plan assets		(7	)		(7	)		(14	)		(13	)
Net amortization and other costs		4			4			8			9
Net periodic benefit cost	$	7		$	8		$	14		$	17

Employer contributions to the pension and other postretirement plans are expected to be approximately $70 million and $27 million, respectively, in 2008. As of June 30, 2008, $60 million and $14 million of contributions had been made to the pension and other postretirement plans, respectively. Also during 2008, PacifiCorp expects to contribute approximately $12 million to the joint trust union plans, which are excluded from the tables above. During the three-month periods ended June 30, 2008 and 2007, $4 million and $3 million, respectively, of contributions were made to the joint trust union plans. During the six-month periods ended June 30, 2008 and 2007, $7 million and $6 million, respectively, of contributions were made to the joint trust union plans.

(8) Comprehensive Income and Components of Accumulated Other Comprehensive Loss, Net

The components of comprehensive income are as follows (in millions):

	Three-Month Periods					Six-Month Periods
	Ended June 30,					Ended June 30,
	2008			2007		2008			2007

Net income	$	99		$	105	$	207		$	204
Other comprehensive income (loss):
Unrecognized amounts on retirement benefits, net of tax of $-, $-, $- and $-		-			1		-			1
Fair value adjustment on cash flow hedges, net of tax of $(5), $3, $(5) and $1		(9	)		5		(9	)		1
Total other comprehensive income (loss)		(9	)		6		(9	)		2

Comprehensive income	$	90		$	111	$	198		$	206

Accumulated other comprehensive loss, net is included in the Consolidated Balance Sheets in common equity, and consists of the following components (in millions):

	As of
	June 30,			December 31,
	2008			2007

Unrecognized amounts on retirement benefits, net of tax of $(2) and $(2)	$	(4	)	$	(4	)
Fair value adjustment on cash flow hedges, net of tax of $(5) and $-		(9	)		-
Total accumulated other comprehensive loss, net	$	(13	)	$	(4	)

(9) Fair Value Measurements

PacifiCorp has various financial instruments that are measured at fair value in the Consolidated Financial Statements, including marketable debt and equity securities and commodity derivatives. PacifiCorp’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 – Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 – Unobservable inputs reflect PacifiCorp’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including PacifiCorp’s own data.

The following table presents PacifiCorp’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of June 30, 2008 (in millions):

	Input Levels for Fair Value Measurements
Description	Level 1		Level 2			Level 3			Other(1)			Total

Assets(2):
Available-for-sale securities	$	42	$	64		$	-		$	-		$	106
Commodity derivatives		-		536			508			(411	)		633
	$	42	$	600		$	508		$	(411	)	$	739

Liabilities:
Commodity derivatives	$	-	$	(669	)	$	(716	)	$	451		$	(934	)

(1)	Primarily represents netting under master netting arrangements and cash collateral requirements.
(2)	Does not include investments in either pension or other postretirement plan assets.

PacifiCorp’s investments in debt and equity securities are classified as available-for-sale and stated at fair value. When available, the quoted market price or net asset value of an identical security in the principal market is used to record the fair value. In the absence of a quoted market price in a readily observable market, the fair value is determined using pricing models based on observable market inputs and quoted market prices of securities with similar characteristics.

PacifiCorp uses various commodity derivative instruments, including forward contracts, options, swaps and other over-the-counter agreements. The fair value of commodity derivatives is determined using forward price curves derived from market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years, and therefore PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first six years or the instrument is not actively traded. Given that limited market data exists for these instruments, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs.

The following table reconciles the beginning and ending balance of PacifiCorp’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):

	Commodity Derivatives
	Three-Month Period			Six-Month Period
	Ended June 30, 2008			Ended June 30, 2008

Beginning Balance	$	(312	)	$	(311	)
Unrealized gains (losses) included in regulatory assets		104			103
Ending Balance	$	(208	)	$	(208	)

Item 2. 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 and its subsidiaries (collectively, “PacifiCorp”) during the periods included herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with PacifiCorp’s historical unaudited Consolidated Financial Statements and the notes included elsewhere in Item 1 of this Form 10-Q. PacifiCorp’s actual results in the future could differ significantly from the historical results.

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 can typically be identified by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “intend,” “potential,” “plan,” “forecast,” 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 Part II, Item 1A and other discussions contained in this Form 10-Q. 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.

Results of Operations

Overview

PacifiCorp’s net income increased $3 million during the six-month period ended June 30, 2008 to $207 million compared to $204 million for the six-month period ended June 30, 2007, primarily as a result of higher retail revenues and lower operations and maintenance expenses, which were substantially offset by higher fuel costs and an increase in the effective income tax rate.

Retail revenues increased due to the recognition of revenues related to Oregon Senate Bill 408 (“SB 408”), higher prices approved by regulators, and continued growth in the average number of customers and usage. Fuel costs increased at PacifiCorp’s natural gas-fired generation plants due to higher generation levels primarily attributable to the addition of the 548-megawatt (“MW”) Lake Side plant in September 2007. Fuel costs also increased due to improved thermal resource availability at PacifiCorp’s coal-fired generation plants and increases in the cost of purchased and mined coal. Wind generation levels also increased due to the addition of the 140-MW Marengo wind plant in August 2007, the 94-MW Goodnoe Hills wind plant in May 2008 and the 70-MW Marengo II wind plant in June 2008. These generation increases more than offset increases in retail loads, resulting in a decrease in net wholesale purchases. However, net wholesale costs were largely unchanged due to higher purchased electricity prices. Operations and maintenance expense decreased primarily due to lower pension expenses resulting from the May 2007 change to a cash balance formula for PacifiCorp’s non-union employees. PacifiCorp’s effective income tax rate increased due to lower tax benefits associated with the regulatory treatment of certain deferred income tax items and tax benefits associated with tax years under examination by the Internal Revenue Service in the prior year.

Output from PacifiCorp’s thermal plants during the six-month period ended June 30, 2008 increased by 1,245,642 megawatt-hours (“MWh”), or 5%, compared to the six-month period ended June 30, 2007, primarily due to the addition of the 548-MW Lake Side plant. Output from PacifiCorp’s hydroelectric facilities increased by 70,833 MWh, or 3%, during the six-month period ended June 30, 2008 compared to the six-month period ended June 30, 2007, with unfavorable conditions in the first three months of 2008 due to cold temperatures more than offset by snow melt in May and June.

Three-Month Periods Ended June 30, 2008 and 2007

Operating Revenue (dollars in millions)

	Three-Month Periods
	Ended June 30,				Favorable/(Unfavorable)
	2008		2007		Change			% Change


Retail	$	840	$	774	$	66			9	%
Wholesale revenues and other		215		252		(37	)		(15	)
Total operating revenue	$	1,055	$	1,026	$	29			3

Retail energy sales (gigawatt - hours)		12,891		12,790		101			1
Average retail customers (in thousands)		1,704		1,679		25			1
Wholesale energy sales (gigawatt - hours)		2,756		3,492		(736	)		(21	)

Retail revenues increased $66 million, or 9%, primarily due to:

$27 million of increases due to the recognition of revenues as a result of approval from the Oregon Public Utility Commission (the “OPUC”) to collect previously under-collected income taxes pursuant to SB 408;

$18 million of increases from higher prices approved by regulators;

$13 million of increases due to growth in the average number of customers; and

$9 million of increases due to higher average customer usage.

Wholesale revenues and other revenues decreased $37 million, or 15%, primarily due to:

$38 million of decreases due to lower volumes of wholesale electric sales;

$37 million of decreases due to changes in the fair value of energy sales contracts accounted for as derivatives; and

$3 million of decreases primarily due to lower margins on non-physically settled wholesale transactions; partially offset by,

$38 million of increases due to higher average prices on wholesale electric sales; and

$5 million of increases in transmission revenue.

Operating Costs and Expenses (in millions)

	Three-Month Periods
	Ended June 30,				Favorable/(Unfavorable)
	2008		2007		$ Change			% Change


Energy costs	$	437	$	425	$	(12	)		(3	)%
Operations and maintenance		251		255		4			2
Depreciation and amortization		124		122		(2	)		(2	)
Taxes, other than income taxes		27		23		(4	)		(17	)
Total operating costs and expenses	$	839	$	825	$	(14	)		(2	)

Energy costs increased $12 million, or 3%, primarily due to:

$56 million of increases due to higher average prices of purchased electricity;

$24 million of increases primarily due to higher average prices of natural gas consumed;

$6 million of increases in transmission costs primarily due to new contracts and higher volumes;

$5 million of increases primarily due to the higher deferral in the prior year of incurred power costs in accordance with established adjustment mechanisms; and

$2 million of increases in coal costs due to higher average prices, substantially offset by lower volumes consumed; partially offset by,

$40 million of decreases due to changes in the fair value of energy purchase contracts accounted for as derivatives; and

$39 million of decreases due to lower volumes of purchased electricity.

Operations and maintenance decreased $4 million, or 2%, primarily due to decreases in employee expenses primarily as a result of lower pension and other postretirement benefit expenses.

Depreciation and amortization increased $2 million, or 2%, primarily due to higher plant-in-service in the current period, partially offset by a $9 million reduction resulting from the extension of the depreciable lives of certain property, plant and equipment as a result of PacifiCorp’s recent depreciation study.

Other Income (Expense) (in millions)

	Three-Month Periods
	Ended June 30,						Favorable/(Unfavorable)
	2008			2007			$ Change			% Change


Interest expense	$	(80	)	$	(79	)	$	(1	)		(1	)%
Allowance for borrowed funds		8			9			(1	)		(11	)
Allowance for equity funds		11			10			1			10
Interest income		2			4			(2	)		(50	)
Other		-			2			(2	)		(100	)
Total other income (expense)	$	(59	)	$	(54	)	$	(5	)		(9	)

Interest expense increased $1 million, or 1%, primarily due to higher average debt outstanding, partially offset by lower average rates during the three-month period ended June 30, 2008.

Income Tax Expense

Income tax expense for the three-month period ended June 30, 2008 increased $16 million to $58 million from the comparable period in 2007, primarily due to higher pre-tax earnings, as well as lower tax benefits associated with both the regulatory treatment of certain deferred income taxes and tax years under examination by the Internal Revenue Service, partially offset by higher production tax credits associated with increased wind generation production. The effective tax rates were 37% and 29% for the three-month periods ended June 30, 2008 and 2007, respectively.

Six-Month Periods Ended June 30, 2008 and 2007

Operating Revenue (dollars in millions)

	Six-Month Periods
	Ended June 30,				Favorable/(Unfavorable)
	2008		2007		Change			% Change


Retail	$	1,674	$	1,551	$	123			8	%
Wholesale revenues and other		476		502		(26	)		(5	)
Total operating revenue	$	2,150	$	2,053	$	97			5

Retail energy sales (gigawatt - hours)		26,602		25,866		736			3
Average retail customers (in thousands)		1,703		1,677		26			2
Wholesale energy sales (gigawatt - hours)		6,027		6,985		(958	)		(14	)

Retail revenues increased $123 million, or 8%, primarily due to:

$42 million of increases from higher prices approved by regulators;

$27 million of increases due to the recognition of revenues as a result of approval from the OPUC to collect previously under-collected income taxes pursuant to SB 408;

$27 million of increases due to growth in the average number of customers; and

$27 million of increases due to higher average customer usage primarily attributable to weather.

Wholesale revenues and other revenues decreased $26 million, or 5%, primarily due to:

$60 million of decreases due to changes in the fair value of energy sales contracts accounted for as derivatives;

$58 million of decreases due to lower volumes of wholesale electric sales; and

$15 million of decreases primarily due to lower margins on non-physically settled wholesale transactions; partially offset by,

$97 million of increases due to higher average prices on wholesale electric sales; and

$10 million of increases in transmission revenue.

Operating Costs and Expenses (in millions)

	Six-Month Periods
	Ended June 30,				Favorable/(Unfavorable)
	2008		2007		$ Change			% Change


Energy costs	$	912	$	840	$	(72	)		(9	)%
Operations and maintenance		495		517		22			4
Depreciation and amortization		241		243		2			1
Taxes, other than income taxes		56		51		(5	)		(10	)
Total operating costs and expenses	$	1,704	$	1,651	$	(53	)		(3	)

Energy costs increased $72 million, or 9%, primarily due to:

$103 million of increases due to higher average prices of purchased electricity;

$78 million of increases primarily due to higher volumes of natural gas consumed at higher average prices;

$24 million of increases primarily due to higher average coal prices; and

$7 million of increases in transmission costs primarily due to new contracts and higher volumes; partially offset by,

$82 million of decreases due to lower volumes of purchased electricity;

$54 million of decreases due to changes in the fair value of energy purchase contracts accounted for as derivatives; and

$2 million of decreases primarily due to the deferral of incurred power costs in accordance with established adjustment mechanisms, partially offset by prior-year deferrals.

Operations and maintenance decreased $22 million, or 4%, primarily due to decreases in employee expenses primarily as a result of lower pension and other postretirement benefit expenses.

Depreciation and amortization decreased $2 million, or 1%, primarily due to a $23 million reduction resulting from the extension of the depreciable lives of certain property, plant and equipment as a result of PacifiCorp’s recent depreciation study, partially offset by higher plant-in-service in the current period.

Other Income (Expense) (in millions)

	Six-Month Periods
	Ended June 30,						Favorable/(Unfavorable)
	2008			2007			$ Change			% Change


Interest expense	$	(164	)	$	(154	)	$	(10	)		(6	)%
Allowance for borrowed funds		16			16			-			-
Allowance for equity funds		21			17			4			24
Interest income		5			7			(2	)		(29	)
Other		(1	)		2			(3	)		(150	)
Total other income (expense)	$	(123	)	$	(112	)	$	(11	)		(10	)

Interest expense increased $10 million, or 6%, primarily due to higher average debt outstanding during the six-month period ended June 30, 2008.

Allowance for borrowed and equity funds increased $4 million, or 12%, primarily due to higher qualified construction work-in-progress balances during the six-month period ended June 30, 2008.

Income Tax Expense

Income tax expense for the six-month period ended June 30, 2008 increased $30 million to $116 million from the comparable period in 2007, primarily due to higher pre-tax earnings, as well as lower tax benefits associated with both the regulatory treatment of certain deferred income taxes and tax years under examination by the Internal Revenue Service, partially offset by higher production tax credits associated with increased wind generation production. The effective tax rates were 36% and 30% for the six-month periods ended June 30, 2008 and 2007, respectively.

Liquidity and Capital Resources

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. 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 from 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 equity 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 from operating activities, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash flows from operating activities increased $27 million to $488 million for the six-month period ended June 30, 2008 compared to $461 million for the six-month period ended June 30, 2007, primarily due to higher retail revenues, lower income tax payments and the timing of cash collections and payments, substantially offset by higher fuel costs and higher net margin deposits with third parties.

Investing Activities

Net cash used in investing activities decreased $5 million to $700 million for the six-month period ended June 30, 2008 compared to $705 million for the six-month period ended June 30, 2007. Capital expenditures totaled $710 million for the six-month period ended June 30, 2008 compared to $731 million for the six-month period ended June 30, 2007. Capital spending decreased $21 million primarily due to higher spending in the prior year to complete the 140-MW Marengo wind plant, which was placed in service in August 2007, partially offset by additional spending in the current year on wind projects expected to be completed in 2008 and 2009 and an increase in spending on emission control environmental projects during the current year. Emission control environmental project expenditures, excluding non-cash allowance for equity funds used during construction, were $87 million and $63 million during the six-month periods ended June 30, 2008 and 2007, respectively.

Financing Activities

Short-Term Debt and Revolving Credit Agreements

PacifiCorp’s short-term debt increased $35 million during the six-month period ended June 30, 2008, primarily due to capital expenditures and maturities of long-term debt in excess of net cash from operating activities, the utilization of temporary cash investments, and a $200 million capital contribution received during the period.

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which an aggregate principal amount of $35 million of commercial paper was outstanding at June 30, 2008, with a weighted-average interest rate of 2.65%.

As of June 30, 2008, PacifiCorp had $1.5 billion of total bank commitments available under two unsecured revolving credit facilities. The first credit facility has $800 million of bank commitments available through July 6, 2011. The commitments reduce over time and are $670 million for the year ending July 6, 2013. The second credit facility has $700 million of total bank commitments available through October 23, 2012. Each credit facility includes a variable interest rate borrowing option based on the London Interbank Offered Rate, plus a margin that is currently 0.195% and varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities. These credit facilities support PacifiCorp’s commercial paper program. As of June 30, 2008, PacifiCorp had no borrowings outstanding under either 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. As of June 30, 2008, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Long-Term Debt

During the six-month period ended June 30, 2008, PacifiCorp made scheduled long-term debt repayments of $200 million.

As of June 30, 2008, 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.

PacifiCorp has $216 million of insured variable-rate pollution-control revenue bond obligations. Due to the significant reduction in market liquidity for insured variable-rate obligations, $199 million of these obligations are unable to be re-marketed and are held by banks under the terms of standby bond purchase agreements. PacifiCorp is evaluating alternatives for these obligations.

Capital Contributions

In May 2008, PacifiCorp received capital contributions of $200 million in cash from its direct parent company, PPW Holdings LLC.

Future Uses of Cash

PacifiCorp may from time to time seek to acquire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases, if any, may be temporary, and will depend on prevailing market conditions, interest rates on securities, PacifiCorp’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Dividends

PacifiCorp does not currently anticipate that it will declare or pay dividends on common stock during the remainder of the year ending December 31, 2008.

Investing Activities

Estimated capital expenditures for the year ending December 31, 2008 are expected to be approximately $2.1 billion, excluding non-cash allowance for equity funds used during construction.

The capital expenditure estimate for operations for the year ending December 31, 2008 is approximately $971 million for ongoing operations projects, including new connections related to customer growth and generation plant overhauls.

The capital expenditure estimate for generation development projects for the year ending December 31, 2008 is approximately $787 million and includes the remaining costs for the 94-MW Goodnoe Hills wind plant, which was placed in service in May 2008, and the 70-MW Marengo II wind plant, which was placed in service in June 2008. The estimate also includes the remaining construction costs for the development of the 99-MW Glenrock, 39-MW Glenrock III, 99-MW Rolling Hills, 99-MW Seven Mile Hill and 19.5-MW Seven Mile Hill II wind plant projects, which are expected to be placed in service during 2008.

The capital expenditure estimate for transmission system expansion and upgrades for the year ending December 31, 2008 is approximately $89 million and includes the construction of a 135-mile, double-circuit, 345-kilovolt transmission line to be built between the Populus substation located in southern Idaho and the Terminal substation located in the Salt Lake City area. This transmission 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 emission control equipment projects for the year ending December 31, 2008 is approximately $219 million and includes the remaining installation costs for emission control equipment placed in service at the Cholla plant in May 2008, as well as estimated capital expenditures related to 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.

In April 2008, PacifiCorp entered into a purchase agreement with TNA Merchant Projects, Inc., an affiliate of Suez Energy North America, Inc., to acquire 100% of the equity interests of an entity owning a 520-MW natural gas-fired facility located in Chehalis, Washington. PacifiCorp has obtained all necessary federal and state regulatory approvals and expects to close the transaction during the third quarter of 2008.

PacifiCorp is subject to federal, state and local laws and regulations with regard to air and water quality, renewable portfolio standards, 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, including those associated with addressing the issue of global climate change, may impact the operation of PacifiCorp’s generating facilities and may require PacifiCorp to reduce emissions at its 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 proven commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and gas-fired facilities, and PacifiCorp is uncertain when, or if, such technology will be commercially available.

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 above, changes in regulations, laws, the economy and market conditions, as well as the outcomes of rate-making proceedings. Future decisions arising from the Integrated Resource Plan (“IRP”) process may impact future estimated capital expenditures. Additionally, capital expenditure needs are regularly reviewed by management and may change significantly as a result of such reviews.

Requests for Proposal

PacifiCorp has issued a series of separate RFPs, each of which focuses on a specific category of resources as provided in the IRP. The IRP and the RFPs 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 RFPs with the UPSC, the OPUC and the Washington Utilities and Transportation Commission (the “WUTC”) prior to issuance to the market.

In January 2008, PacifiCorp issued to the market a 2008 renewable resources 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 no later than December 2009. Bids from the market were received in March 2008 and are currently under evaluation.

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 to be 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. PacifiCorp expects to issue the all-source 2008 RFP to the market in the third quarter of 2008.

In April 2008, PacifiCorp filed its draft new renewable resources RFP with the OPUC and the WUTC. This filing seeks approval of a solicitation for new renewable resources targeting up to 500 MW that will be in operation by December 2011.

Credit Ratings

PacifiCorp’s credit ratings at June 30, 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

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 one rating below investment grade, PacifiCorp’s estimated potential collateral requirements as of June 30, 2008 would have totaled approximately $474 million. Additional collateral requirements would be necessary if ratings fell further than one rating below investment grade. 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.

For a further discussion of PacifiCorp’s credit ratings and their effect on PacifiCorp’s business, refer to Item 7 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007.

Contractual Obligations and Commercial Commitments

Subsequent to December 31, 2007, there were no material changes outside the normal course of business in the contractual obligations and commercial commitments from the information provided in Item 7 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007, other than the 2008 debt issuance previously discussed. Additionally, refer to the “Future Uses of Cash” discussion included in “Liquidity and Capital Resources.”

Regulatory Matters

Federal Regulatory Matters

In addition to the discussion contained herein regarding updates to federal regulatory matters based upon material changes that occurred subsequent to December 31, 2007, refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for further information regarding federal regulatory matters.

Transmission Investment

In July 2008, PacifiCorp filed with the FERC a petition for declaratory order to confirm incentive rate treatment for the Energy Gateway Transmission Expansion Project. The Energy Gateway Transmission Expansion Project is an investment plan to build in excess of 1,900 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The plan, with an estimated cost of approximately $6 billion, 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. Major transmission segments associated with this plan are expected to be placed in service beginning 2010 with major segments in service by 2014 depending on siting, permitting and construction timeframes.

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.

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 that resulted in the BPA suspending payments to the Pacific Northwest’s six utilities, including PacifiCorp. This resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho.

In February 2008, the BPA initiated a rate proceeding under 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. Also in February 2008, the BPA offered PacifiCorp and other investor-owned utilities an interim agreement intended to resume customer benefits pending the outcome of the rate proceeding. In March 2008, the OPUC ordered PacifiCorp to not execute the interim agreement offered by the BPA because the benefits offered were subject to true-up and acceptance of the benefits before the conclusion of the rate proceeding was not in the best interest of customers. In March and May 2008, PacifiCorp and other parties submitted testimony in the BPA rate proceeding and initial legal briefing was completed in June 2008. 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.

Hydroelectric Relicensing

For a discussion of hydroelectric relicensing, refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.

Hydroelectric Decommissioning

Condit Hydroelectric Project – (White Salmon River, Washington)

In September 1999, a settlement agreement to remove the 14-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 would not begin until October 2008 with 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. The permitting process is ongoing and will not be completed in time to allow the decommissioning of the project to begin by the October 2008 target date under the settlement agreement. Given the time needed for project removal and impacts to natural resources, completion of decommissioning is now expected by October 2009.

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 based upon significant changes that occurred subsequent to December 31, 2007.

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%, with a test period for the forecasted twelve months ended June 2009. 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 test period should end December 2008. In March 2008, PacifiCorp filed supplemental testimony reducing the requested rate increase to $100 million. The change in the test period accounts for $40 million of the reduction. The supplemental filing also reflects an additional $21 million of reductions associated with recent UPSC orders on depreciation rate changes and two deferred accounting requests that were pending when the original case was filed. In May 2008, PacifiCorp filed rebuttal testimony that reduced the requested rate increase by an additional $15 million to $85 million. Hearings on the revenue requirement portion of the case were held in June 2008. Additional adjustments adopted at the hearings reduced the requested increase to $75 million. The rate-design phase of the case is scheduled for October 2008. PacifiCorp expects that initial rates, if approved, will become effective no later than August 13, 2008.

In July 2008, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million over PacifiCorp’s current rates, or an average price increase of 11%. This represents an increase of $86 million over the December 2007 pending rate request described above, or an additional average price increase of 6%. The new rates, if approved, are expected to become effective in March 2009.

Oregon

In April 2008, PacifiCorp filed its first annual renewable adjustment clause to recover the revenue requirement related to new renewable resources and associated transmission that are eligible under the Oregon Renewable Energy Act and are not reflected in general rates. PacifiCorp requested an annual increase of $39 million on an Oregon-allocated basis, or an average price increase of 4%. The OPUC is expected to issue a decision by November 2008, with rates effective January 1, 2009.

In July 2008, as part of its annual transition adjustment mechanism, PacifiCorp filed updated forecasted net power costs for 2009. PacifiCorp proposed a net power cost increase of $57 million on an Oregon-allocated basis, or an average price increase of 6%. The forecasted net power costs will be updated again in early November 2008 for OPUC ordered changes, changes to the forward price curve and new wholesale sales and purchases. A final update for changes in the forward price curve will be filed in November 2008. The OPUC is expected to issue a decision by November 2008, with rates effective January 1, 2009.

For a discussion of SB 408, refer to Note 3 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.

Wyoming

In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (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 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 modify the current power cost adjustment mechanism (“PCAM”) to use forecasted power costs in the future and to terminate the 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 approved by the WPSC in March 2008. The new rates were effective May 1, 2008.

In February 2008, PacifiCorp filed its annual PCAM application with the WPSC for costs incurred during the period December 1, 2006 through November 30, 2007. In March 2008, the WPSC approved PacifiCorp’s request on an interim basis effective April 1, 2008, resulting in a rate increase of $31 million, or an average price increase of 8%, to recover deferred power costs over a one-year period. In April 2008, PacifiCorp began collecting this interim surcharge from its Wyoming customers and will continue until the matter is either settled through negotiation with the parties or is litigated in a contested hearing, which has been scheduled for September 2008. In either case, the WPSC must approve the final surcharge and tariff.

In July 2008, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $34 million, or an average price increase of 7%, with an effective date of May 24, 2009. Power costs have been excluded from the filing and will be addressed separately in PacifiCorp’s annual PCAM application in February 2009.

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%. In August 2008, PacifiCorp filed with the WUTC an all-party settlement agreement with WUTC staff, Public Counsel, Industrial Customers of Northwest Utilities, and the Energy Project. Pursuant to the terms of the settlement, parties agreed to an overall rate increase of $20 million or 9%. If the WUTC approves the settlement, the increase will be composed of an $18 million increase to base rates and a $2 million annual surcharge for approximately three years related to recovery of higher power costs incurred in 2005 due to poor hydroelectric conditions. Recovery of these higher power costs was originally requested by PacifiCorp as a separate deferred cost filing in March 2005. The total recovery of these higher power costs will be $6 million plus interest collected over a three-year period. PacifiCorp agreed to drop the current proposal for a generation cost adjustment mechanism (“GCAM”) and further committed that PacifiCorp would not propose a GCAM in the next general rate case. A hearing on the settlement agreement is scheduled for September 2008. The new rates will be effective October 15, 2008, subject to WUTC approval.

Idaho

In June 2008, PacifiCorp filed a notice of intent to file a general rate case with the Idaho Public Utilities Commission (the “IPUC”). A notice of intent must be filed with the IPUC at least 60 days before a general rate case can be filed.

Depreciation Rate Changes

For a discussion of PacifiCorp’s depreciation rate changes, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.

Environmental Matters

In addition to the discussion contained herein, refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q and Item 1 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007 for additional information regarding certain environmental matters affecting PacifiCorp’s operations.

Renewable Portfolio Standards

In March 2008, Utah’s governor signed Utah Senate Bill 202, Energy Resource and Carbon Emission Reduction Initiative. Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and demand-side management programs. Qualifying renewable energy sources can be located anywhere in the Western Electricity Coordinating Council areas, and renewable energy credits can be used. The costs of complying with the law will be a system cost and are expected to be recovered in retail rates in all states served, either through rate cases or adjustment mechanisms.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and postretirement obligations, income taxes and revenue recognition - unbilled revenue. For additional discussion of PacifiCorp’s critical accounting policies, see Item 7 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007. PacifiCorp’s critical accounting policies have not changed materially since December 31, 2007.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting PacifiCorp, see Item 7A of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007. PacifiCorp’s exposure to market risk and its management of such risk has not changed materially since December 31, 2007. Refer to Note 5 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for disclosure of PacifiCorp’s derivative positions as of June 30, 2008 and December 31, 2007.

Item 4. Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, 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 were effective to ensure that information required to be disclosed by PacifiCorp in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management, including PacifiCorp’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in PacifiCorp’s internal control over financial reporting during the quarter ended June 30, 2008 that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

For a description of certain legal proceedings affecting PacifiCorp, refer to Item 3 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007 and Part II, Item 1 of PacifiCorp’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008. In addition to the discussion contained herein regarding material developments to legal proceedings, refer to Note 6 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q.

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 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 United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) and briefing was completed in March 2006. In February 2008, the Ninth Circuit affirmed the District Court’s 2005 decisions dismissing the case. In May 2008, the plaintiffs filed a petition requesting review by the U.S. Supreme Court. PacifiCorp filed a brief in opposition to the petition in June 2008. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial results.

Item 1A. Risk Factors

There has been no material change to PacifiCorp’s risk factors from those disclosed in Item 1A of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2007.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PACIFICORP
	(Registrant)



Date: August 8, 2008	/s/ Douglas K. Stuver
	Douglas K. Stuver
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

EXHIBIT INDEX

Exhibit No.	Description

15	Awareness Letter of Independent Registered Public Accounting Firm.

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.