PACIFICORP /OR/ - Quarter Report: 2007 September (Form 10-Q)

pacificorp0930200710q.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 September 30, 2007

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

For the transition period from ______ to _______

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

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

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

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, or a non-accelerated filer. See the definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer T

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

Yes ¨ No T

As of October 31, 2007, all 357,060,915 outstanding shares of PacifiCorp’s common stock were indirectly owned by MidAmerican Energy Holdings Company.

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	16

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31

Item 4.	Controls and Procedures	31

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	32

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32

Item 3.	Defaults Upon Senior Securities	32

Item 4.	Submission of Matters to a Vote of Security Holders	32

Item 5.	Other Information	32

Item 6.	Exhibits	32

Signature		33

Exhibit Index		34

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and its subsidiaries (“PacifiCorp”) as of September 30, 2007, and the related consolidated statements of income for the three-month and nine-month periods ended September 30, 2007 and 2006, and the related consolidated statements of cash flows for the nine-month periods ended September 30, 2007 and 2006. 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 its subsidiaries as of December 31, 2006, and the related consolidated statements of income, common shareholder’s equity and comprehensive income, and of cash flows for the nine-month period then ended (not presented herein); and in our report dated February 27, 2007, 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). In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2006, 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

November 2, 2007

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006

Revenues	$	1,137		$	1,097		$	3,190		$	3,187

Operating expenses:
Energy costs		487			567			1,327			1,451
Operations and maintenance		230			253			747			787
Depreciation and amortization		125			118			368			347
Taxes, other than income taxes		26			27			77			77
Total		868			965			2,519			2,662

Income from operations		269			132			671			525

Interest and other expense (income):
Interest expense		76			72			230			210
Interest income		(3	)		(3	)		(10	)		(7	)
Allowance for borrowed funds		(8	)		(6	)		(24	)		(16	)
Allowance for equity funds		(11	)		(6	)		(28	)		(18	)
Other		2			(1	)		-			(3	)
Total		56			56			168			166

Income before income tax expense		213			76			503			359
Income tax expense		78			17			164			110
Net income	$	135		$	59		$	339		$	249

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,			December 31,
	2007			2006

ASSETS

Current assets:
Cash and cash equivalents	$	56		$	59
Accounts receivable, net		406			342
Unbilled revenue		182			178
Amounts due from affiliates		15			53
Inventories at average costs:
Materials and supplies		162			140
Fuel		127			104
Derivative contracts		140			151
Deferred income taxes		75			28
Other		124			57
Total current assets		1,287			1,112

Property, plant and equipment		16,866			15,843
Accumulated depreciation and amortization		(6,081	)		(5,842	)
		10,785			10,001
Construction work-in-progress		787			809
Total property, plant and equipment, net		11,572			10,810

Other assets:
Regulatory assets		1,318			1,397
Derivative contracts		178			235
Deferred charges and other		282			298
Total other assets		1,778			1,930

Total assets	$	14,637		$	13,852

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,			December 31,
	2007			2006

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	401		$	385
Amounts due to affiliates		2			1
Accrued employee expenses		118			85
Taxes payable, other than income taxes		63			30
Interest payable		78			57
Derivative contracts		160			110
Long-term debt and capital lease obligations, currently maturing		413			127
Preferred stock subject to mandatory redemption, currently maturing		-			38
Short-term debt		206			397
Other		136			135
Total current liabilities		1,577			1,365

Deferred credits:
Deferred income taxes		1,665			1,641
Investment tax credits		56			62
Regulatory liabilities		794			822
Derivative contracts		459			504
Pension and other post employment liabilities		513			691
Other		427			374
Total deferred credits		3,914			4,094

Long-term debt and capital lease obligations, net of current maturities		4,166			3,967
Total liabilities		9,657			9,426

Commitments and contingencies (Note 5)

Shareholders’ equity:
Preferred stock		41			41
Common equity:
Common shareholder’s capital - 750 shares authorized, no par value, 357 shares issued and outstanding		3,804			3,600
Retained earnings		1,139			789
Accumulated other comprehensive loss, net		(4	)		(4	)
Total common equity		4,939			4,385
Total shareholders’ equity		4,980			4,426

Total liabilities and shareholders’ equity	$	14,637		$	13,852

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2007			2006

Cash flows from operating activities:
Net income	$	339		$	249
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized loss (gain) on derivative contracts, net		(4	)		45
Depreciation and amortization		368			347
Deferred income taxes and investment tax credits, net		17			(32	)
Regulatory asset/liability establishment and amortization		(37	)		22
Other		11			33
Changes in:
Accounts receivable, net and other assets		(76	)		(67	)
Inventories		(45	)		(38	)
Amounts due to/from affiliates - MEHC, net		39			-
Accounts payable and other liabilities		38			117
Net cash provided by operating activities		650			676

Cash flows from investing activities:
Capital expenditures		(1,136	)		(1,113	)
Proceeds from sale of assets		9			-
Proceeds from available-for-sale securities		22			78
Purchases of available-for-sale securities		(19	)		(80	)
Other		12			(7	)
Net cash used in investing activities		(1,112	)		(1,122	)

Cash flows from financing activities:
Changes in short-term debt		(191	)		(135	)
Proceeds from long-term debt, net of issuance costs		599			346
Proceeds from equity contributions		200			255
Dividends paid		(2	)		(18	)
Repayments and redemptions on long-term debt, preferred stock subject to mandatory redemption and capital lease obligations		(153	)		(108	)
Other		6			10
Net cash provided by financing activities		459			350

Change in cash and cash equivalents		(3	)		(96	)
Cash and cash equivalents at beginning of period		59			164
Cash and cash equivalents at end of period	$	56		$	68

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 electric utility company serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and also engages in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services and environmental remediation. 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 accompanying 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 include all adjustments (consisting only of normal recurring adjustments) considered necessary for fair presentation of the financial statements as of September 30, 2007, and for the three- and nine-month periods ended September 30, 2007 and 2006. A portion of PacifiCorp’s business is of a seasonal nature and, therefore, results of operations for the three- and nine-month periods ended September 30, 2007, are not necessarily indicative of the results to be expected for the full year.

The accompanying 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 Transition Report on Form 10-K for the nine-month period ended December 31, 2006, 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 nine months of 2007, except as described in Note 2.

(2) New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”). PacifiCorp adopted the provisions of FIN 48 effective January 1, 2007. Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in PacifiCorp’s tax returns that do not meet these recognition and measurements standards.

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

Included in the asset of $22 million is $14 million of net uncertain tax positions that, if recognized, would have an impact on the effective tax rate. The remaining amounts relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax positions, other than applicable interest and penalties, would not affect PacifiCorp’s effective tax rate. PacifiCorp recognizes interest and penalties accrued related to uncertain tax positions in income tax expense. As of January 1, 2007, PacifiCorp had $7 million accrued for the receipt of interest, which is included in the asset for uncertain tax positions.

Prior to 2006, PacifiCorp filed income tax returns in the U.S. federal jurisdiction and various state jurisdictions. The U.S. Internal Revenue Service has closed examination of PacifiCorp’s income tax returns through its tax year ended March 31, 2000. In addition, open tax years related to a number of state jurisdictions remain subject to examination. As a result of the sale of PacifiCorp to MEHC on March 21, 2006, Berkshire Hathaway commenced including PacifiCorp in its U.S. federal income tax returns.

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

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

(3) Recent Debt Transactions

In October 2007, PacifiCorp issued $600 million of its 6.25% First Mortgage Bonds due October 15, 2037. The proceeds will be used to repay short-term debt and for general corporate purposes.

In June 2007, PacifiCorp redeemed $38 million of outstanding preferred stock subject to mandatory redemption, representing the remaining outstanding shares of PacifiCorp’s $7.48 No Par Serial Preferred Stock series.

In March 2007, PacifiCorp issued $600 million of its 5.75% First Mortgage Bonds due April 1, 2037. The proceeds were used to repay short-term debt and for general corporate purposes.

(4) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. PacifiCorp employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, swaps and options. The risk management process established by PacifiCorp is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes. As of September 30, 2007 and December 31, 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.

The following table summarizes the various derivative mark-to-market positions included in the accompanying Consolidated Balance Sheet as of September 30, 2007 (in millions):

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

Commodity	$	314	$	(619	)	$	(305	)	$	311		$	(3	)
Foreign currency		4		-			4			(4	)		-
Total	$	318	$	(619	)	$	(301	)	$	307		$	(3	)

Current	$	140	$	(160	)	$	(20	)
Non-current		178		(459	)		(281	)
Total	$	318	$	(619	)	$	(301	)

(1)	Before income taxes.

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

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

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

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

(1)	Before income taxes.

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

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006

Revenues	$	(3	)	$	81		$	22		$	333
Operating expenses:
Energy costs		9			(146	)		(18	)		(376	)
Operations and maintenance		-			(1	)		-			(2	)
Total unrealized gain (loss) on derivative contracts	$	6		$	(66	)	$	4		$	(45	)

(5) Commitments and Contingencies

Environmental Matters

PacifiCorp is subject to numerous federal, state and local environmental laws and regulations, including the Clean Air Act, related air quality standards promulgated by the Environmental Protection Agency (“EPA”) and various state air quality laws; the Endangered Species Act; the Comprehensive Environmental Response, Compensation and Liability Act, 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 to impact PacifiCorp’s current and future operations. Current and future Clean Air Act and associated requirements will impact the operations of PacifiCorp’s generating facilities and will require PacifiCorp to reduce sulfur dioxide, nitrogen oxides and mercury emissions from current levels through the installation of additional or improved emission controls, the purchase of additional emission allowances, or some combination thereof. PacifiCorp is also subject to various state renewables portfolio standards. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to PacifiCorp’s generation facilities. Additionally, the adoption of stringent limits on greenhouse emissions could significantly impact PacifiCorp’s fossil-fueled facilities, and, therefore, its financial results. 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 expense is 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 September 30, 2007 and December 31, 2006 was $23 million and $40 million, respectively, and is included in other liabilities and other deferred credits on the accompanying 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 48 plants with an aggregate plant net owned capacity of 1,158 megawatts (“MW”). The Federal Energy Regulatory Commission (the “FERC”) regulates 98% of the net capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $86 million and $79 million in costs at September 30, 2007 and December 31, 2006, respectively, for ongoing hydroelectric relicensing, which are reflected in construction work-in-progress on the Consolidated Balance Sheets.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW nameplate-rated Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. In January 2007, as part of the relicensing process, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with the March 2006 filings, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. 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. The FERC did not issue its final environmental impact statement in the summer of 2007 as scheduled, and it has provided no new issuance date. Other federal agencies are also working to complete their endangered species analyses by December 1, 2007. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $46 million and $42 million in costs at September 30, 2007 and December 31, 2006, respectively, which are reflected in construction work-in-progress in the accompanying Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

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 Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. A five-day trial on the liability phase is scheduled to begin on April 21, 2008. The remedy-phase trial has not yet been set. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

FERC Issues

California Refund Case

On June 21, 2007, the FERC approved PacifiCorp’s settlement and release of claims agreement (“Settlement”) with Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, the People of the State of California, ex rel. Edmund G. Brown Jr., Attorney General, the California Electricity Oversight Board, and the California Public Utilities Commission (collectively, the “California Parties”), certain of which purchased energy in the California Independent System Operator (“ISO”) and the California Power Exchange (“PX”) markets during past periods of high energy prices in 2000 and 2001. The Settlement, which was executed by PacifiCorp on April 11, 2007, settles claims brought by the California Parties against PacifiCorp for refunds and remedies in numerous related proceedings (together, the “FERC Proceedings”), as well as certain potential civil claims, arising from events and transactions in Western United States energy markets during the period January 1, 2000 through June 20, 2001 (the “Refund Period”). Under the Settlement, PacifiCorp made cash payments to escrows controlled by the California Parties in the amount of $16 million in April 2007, and upon FERC approval of the agreement in June 2007, PacifiCorp allowed the PX to release an additional $12 million to such escrows, which represented PacifiCorp’s estimated unpaid receivable from the transactions in the PX and ISO markets during the Refund Period, plus interest. The monies held in escrow are for distribution to buyers from the ISO and PX markets that purchased power during the Refund Period. The agreement provides for the release of claims by the California Parties (as well as additional parties that join in the Settlement) against PacifiCorp for refunds, disgorgement of profits, or other monetary or non-monetary remedies in the FERC Proceedings, and provides a mutual release of claims for civil damages and equitable relief.

Northwest Refund Case

In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In November 2003, the FERC issued its final order denying rehearing. Several market participants filed petitions in the United States Ninth Circuit Court of Appeals (the “Ninth Circuit”) for review of the FERC’s final order. On August 24, 2007, the Ninth Circuit issued its order on this appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy made by the California Energy Resources Scheduling (“CERS”) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and did not rule on the merits of the FERC’s November 2003 decision to deny refunds. Due to the remand, PacifiCorp cannot predict the impact of this ruling at this time.

(6) Employee Benefit Plans

In December 2006, non-bargaining employees were notified that PacifiCorp would switch from a traditional final average pay formula for the PacifiCorp Retirement Plan to a cash balance formula effective June 1, 2007. As a result of the change, benefits under the traditional final average pay formula were frozen as of May 31, 2007, and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million.

The components of net periodic benefit cost for PacifiCorp’s pension and other postretirement benefit plans were as follows (in millions):

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006

Pension:
Service cost	$	7		$	8		$	21		$	23
Interest cost		17			19			55			57
Expected return on plan assets		(18	)		(18	)		(52	)		(55	)
Net amortization and other costs		6			7			20			25
Net periodic benefit cost	$	12		$	16		$	44		$	50


Other postretirement:
Service cost	$	1		$	2		$	5		$	6
Interest cost		8			8			25			24
Expected return on plan assets		(7	)		(6	)		(20	)		(19	)
Net amortization and other costs		6			5			15			15
Net periodic benefit cost	$	8		$	9		$	25		$	26

Excluded from the tables above are contributions to certain multi-employer and joint trust union plans of $3 million for each of the three-month periods ended September 30, 2007 and 2006, and $9 million and $7 million for the nine-month periods ended September 30, 2007 and 2006, respectively.

Employer Contributions

Employer contributions to the pension and other postretirement plans are expected to be $88 million and $34 million, respectively, in 2007. As of September 30, 2007, $85 million and $21 million of contributions had been made to the pension and other postretirement plans, respectively.

Severance

PacifiCorp has reviewed its organization and workforce requirements. As a result, PacifiCorp incurred severance expense of $- million and $15 million during the three-month periods ended September 30, 2007 and 2006, respectively; and $7 million and $35 million during the nine-month periods ended September 30, 2007 and 2006, respectively.

(7) Comprehensive Income and Components of Accumulated Other Comprehensive Loss

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

	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2007			2006		2007		2006

Net income	$	135		$	59	$	339	$	249
Other comprehensive income (loss):
Unrecognized amounts on retirement benefits, net of tax of $-; $-; $-; and $-		(1	)		-		-		-
Fair value adjustment on cash flow hedges, net of tax of $(1); $14; $-; and $11		(1	)		22		-		18
Minimum pension liability, net of tax of $-; $-; $-; and $3		-			-		-		5
Unrealized gains (losses) on marketable securities, net of tax of $-; $1; $-; and $-		-			2		-		(1	)
Total other comprehensive income (loss)		(2	)		24		-		22

Comprehensive income	$	133		$	83	$	339	$	271

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

	As of
	September 30,			December 31,
	2007			2006

Unrecognized amounts on retirement benefits, net of tax of $(4) and $(4)	$	(6	)	$	(6	)
Fair value adjustment on cash flow hedges, net of tax of $1 and $1		2			2
Total accumulated other comprehensive loss, net	$	(4	)	$	(4	)

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 thereto included elsewhere in Item 1. 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 are typically identified by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast,” “intend,” and similar terms. These statements are based on PacifiCorp’s current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside PacifiCorp’s control and could cause actual results to differ materially from those expressed or implied by PacifiCorp’s forward-looking statements. These factors include, among others:

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

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

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

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

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

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

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

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

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

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

Availability, terms and deployment of capital;

Financial condition and creditworthiness of significant customers and suppliers;

The impact of 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;

Changes in PacifiCorp’s credit ratings;

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

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

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

Further details of the potential risks and uncertainties affecting PacifiCorp are described in PacifiCorp’s filings with the SEC, including 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 $90 million during the nine-month period ended September 30, 2007, to $339 million compared to $249 million for the nine-month period ended September 30, 2006, primarily due to higher retail revenues and higher net wholesale sales and purchases, partially offset by higher fuel costs.

Retail revenues increased due to higher retail prices approved by regulators, as well as continued growth in the number of retail customers and usage. Net margin on wholesale activities increased primarily due to higher average prices on wholesale sales and lower purchased electricity volumes. PacifiCorp’s financial results were further improved by higher output at PacifiCorp’s thermal and wind plants serving the higher retail load. These improvements were partially offset by higher prices of coal, natural gas and purchased electricity, as well as lower hydroelectric generation.

Output from PacifiCorp’s thermal plants for the nine-month period ended September 30, 2007, increased by 3,135,182 megawatt-hours (“MWh”), or 9%, compared to the nine-month period ended September 30, 2006, primarily due to the Currant Creek plant becoming fully operational at the end of March 2006. Output from PacifiCorp’s wind plants increased by 261,137 MWh, or 314%, during the nine-month period ended September 30, 2007, compared to the nine-month period ended September 30, 2006, primarily due to the Leaning Juniper plant being placed into service in September 2006 and the Marengo plant being placed into service in August 2007. Output from PacifiCorp’s hydroelectric facilities decreased by 621,155 MWh, or 18%, during the nine-month period ended September 30, 2007, compared to the nine-month period ended September 30, 2006, primarily due to drier than normal conditions in the current period.

Three-Month Periods Ended September 30, 2007 and 2006

Revenues (dollars in millions)

	Three-Month Periods
	Ended September 30,				Favorable/(Unfavorable)
	2007		2006		$ Change			% Change


Retail	$	904	$	803	$	101			13	%
Wholesale sales and other		233		294		(61	)		(21	)
Total revenues	$	1,137	$	1,097	$	40			4

Retail energy sales (gigawatt - hours)		14,188		13,704		484			4
Wholesale energy sales (gigawatt - hours)		3,129		3,401		(272	)		(8	)
Average retail customers (in thousands)		1,688		1,655		33			2

Retail revenues increased $101 million, or 13%, primarily due to:

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

$28 million of increases due to higher average customer usage resulting primarily from warmer weather; and

$14 million of increases due to growth in the number of customers.

Wholesale sales and other revenues decreased $61 million, or 21%, primarily due to:

$84 million of decreases due to changes in the fair value of derivative contracts; partially offset by,

$20 million of increases in wholesale electric sales primarily due to higher average prices, partially offset by lower volumes.

Operating Expenses (in millions)

	Three-Month Periods
	Ended September 30,				Favorable/(Unfavorable)
	2007		2006		$ Change			% Change


Energy costs	$	487	$	567	$	80			14	%
Operations and maintenance		230		253		23			9
Depreciation and amortization		125		118		(7	)		(6	)
Taxes, other than income taxes		26		27		1			4
Total operating expenses	$	868	$	965	$	97			10

Energy costs decreased $80 million, or 14%, primarily due to:

$155 million of decreases due to changes in the fair value of derivative contracts;

$15 million of decreases primarily due to the deferral of incurred power costs in accordance with established adjustment mechanisms; and

$3 million of decreases due to the prior period loss on the streamflow weather derivative contract; partially offset by,

$54 million of increases due to higher volumes of natural gas consumed at higher average prices;

$18 million of increases in the cost of coal primarily due to higher average prices; and

$17 million of increases in purchased electricity due to higher average prices, partially offset by lower volumes.

Operations and maintenance expense decreased $23 million, or 9%, primarily due to:

$15 million of decreases in employee severance costs;

$5 million of decreases in employee expenses, primarily due to reduced workforce; and

$5 million of decreases primarily due to asset write-offs in the prior year; partially offset by,

$3 million of increases in maintenance costs and related contracts, primarily associated with generation plant overhauls.

Depreciation and amortization expense increased $7 million, or 6%, primarily due to higher plant in service.

Interest and Other Expense (Income) (in millions)

	Three-Month Periods
	Ended September 30,						Favorable/(Unfavorable)
	2007			2006			$ Change			% Change


Interest expense	$	76		$	72		$	(4	)		(6	)%
Interest income		(3	)		(3	)		-			-
Allowance for borrowed funds		(8	)		(6	)		2			33
Allowance for equity funds		(11	)		(6	)		5			83
Other		2			(1	)		(3	)		(300	)
Total	$	56		$	56		$	-			-

Interest expense increased $4 million, or 6%, primarily due to higher average debt balances during the three-month period ended September 30, 2007.

Allowance for borrowed and equity funds increased $7 million, primarily due to higher average qualified construction work-in-progress balances during the three-month period ended September 30, 2007.

Income Tax Expense

Income tax expense for the three-month period ended September 30, 2007, increased $61 million to $78 million from the comparable period in 2006, primarily due to higher pre-tax earnings and income tax accruals for uncertain tax positions in the current period, compared to prior period benefits attributed to the resolution of certain matters previously outstanding with the Internal Revenue Service. The effective tax rates were 37% and 22% for the three-month periods ended September 30, 2007 and 2006, respectively.

Nine-Month Periods Ended September 30, 2007 and 2006

Revenues (dollars in millions)

	Nine-Month Periods
	Ended September 30,				Favorable/(Unfavorable)
	2007		2006		$ Change			% Change


Retail	$	2,455	$	2,212	$	243			11	%
Wholesale sales and other		735		975		(240	)		(25	)
Total revenues	$	3,190	$	3,187	$	3			-

Retail energy sales (gigawatt - hours)		40,054		38,637		1,417			4
Wholesale energy sales (gigawatt - hours)		10,117		10,083		34			-
Average retail customers (in thousands)		1,680		1,645		35			2

Retail revenues increased $243 million, or 11%, primarily due to:

$145 million of increases from higher retail prices approved by regulators;

$61 million of increases due to higher average customer usage, primarily as a result of more extreme weather conditions and an earlier start to the irrigation season in the current period as compared to the prior period; and

$38 million of increases due to growth in the number of customers.

Wholesale sales and other revenues decreased $240 million, or 25%, primarily due to:

$311 million of decreases due to changes in the fair value of derivative contracts; and

$7 million of decreases resulting from higher sales of sulfur dioxide emission allowances in the prior period; partially offset by,

$80 million of increases substantially due to higher margins on non-physically settled system-balancing transactions and higher average prices on wholesale electric sales.

Operating Expenses (in millions)

	Nine-Month Periods
	Ended September 30,				Favorable/(Unfavorable)
	2007		2006		$ Change			% Change


Energy costs	$	1,327	$	1,451	$	124			9	%
Operations and maintenance		747		787		40			5
Depreciation and amortization		368		347		(21	)		(6	)
Taxes, other than income taxes		77		77		-			-
Total operating expenses	$	2,519	$	2,662	$	143			5

Energy costs decreased $124 million, or 9%, primarily due to:

$358 million of decreases due to changes in the fair value of derivative contracts;

$27 million of decreases primarily due to the deferral of incurred power costs in accordance with established adjustment mechanisms; and

$12 million of decreases due to the prior period loss on the streamflow weather derivative contract; partially offset by,

$150 million of increases due to higher volumes of natural gas consumed at higher average prices;

$62 million of increases in the cost of coal substantially due to higher average prices; and

$54 million of increases in purchased electricity primarily due to higher average prices, partially offset by lower volumes.

Operations and maintenance expense decreased $40 million, or 5%, primarily due to:

$28 million of decreases in employee severance costs;

$18 million of decreases in employee expenses, primarily due to reduced workforce;

$8 million of decreases due to changes in environmental accruals; and

$4 million of decreases due to the initial assessment of penalties related to compliance with the FERC standards of conduct for transmission in the prior period; partially offset by,

$22 million of increases in maintenance costs and related contracts, primarily associated with generation plant overhauls.

Depreciation and amortization expense increased $21 million, or 6%, primarily due to higher plant in service.

Interest and Other Expense (Income) (in millions)

	Nine-Month Periods
	Ended September 30,						Favorable/(Unfavorable)
	2007			2006			$ Change			% Change


Interest expense	$	230		$	210		$	(20	)		(10	)%
Interest income		(10	)		(7	)		3			43
Allowance for borrowed funds		(24	)		(16	)		8			50
Allowance for equity funds		(28	)		(18	)		10			56
Other		-			(3	)		(3	)		(100	)
Total	$	168		$	166		$	(2	)		(1	)

Interest expense increased $20 million, or 10%, primarily due to higher average debt balances during the nine-month period ended September 30, 2007.

Allowance for borrowed and equity funds increased $18 million, primarily due to higher average qualified construction work-in-progress balances during the nine-month period ended September 30, 2007.

Income Tax Expense

Income tax expense for the nine-month period ended September 30, 2007, increased $54 million to $164 million from the comparable period in 2006, primarily due to higher pre-tax earnings. The effective tax rates were 33% and 31% for the nine-month periods ended September 30, 2007 and 2006, 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. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through long-term debt issuances and through cash capital contributions from PacifiCorp’s direct parent company, PPW Holdings LLC (“PPW”). PacifiCorp expects it will need additional periodic equity contributions from its parent over the next several years. Issuance of long-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash flows provided by operating activities decreased $26 million to $650 million for the nine-month period ended September 30, 2007, compared to $676 million for the nine-month period ended September 30, 2006, primarily due to the timing of payments and cash collections and higher fuel costs, partially offset by higher retail revenues and higher net wholesale sales and purchases.

Investing Activities

Net cash used in investing activities decreased $10 million to $1,112 million for the nine-month period ended September 30, 2007, compared to $1,122 million for the nine-month period ended September 30, 2006. Capital expenditures totaled $1,136 million for the nine-month period ended September 30, 2007, compared to $1,113 million for the nine-month period ended September 30, 2006. Capital spending increased primarily due to wind generation investments. Additional increases resulted from the construction and installation of emission control equipment and various capital projects related to transmission, distribution and other generation facilities. PacifiCorp spent approximately $89 million and $73 million, excluding non-cash allowance for equity funds used during construction, on emission control environmental projects during the nine-month periods ended September 30, 2007 and 2006, respectively. These increases were partially offset by decreases in expenditures, as compared to the previous period, for the construction of the Currant Creek plant, which commenced full combined-cycle operation in March 2006, and decreases in expenditures for the construction of the 534-megawatt (“MW”) Lake Side plant, which commenced full combined-cycle operation in September 2007.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt decreased by $191 million during the nine-month period ended September 30, 2007, primarily due to the proceeds from the issuance of long-term debt and the capital contributions received during the period, partially offset by capital expenditures and maturities of long-term securities in excess of net cash provided by operating activities.

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which an aggregate principal amount of $206 million of commercial paper was outstanding at September 30, 2007, with a weighted-average interest rate of 5.3%.

Revolving Credit and Other Financing Agreements

In October 2007, PacifiCorp entered into a new unsecured revolving credit facility with total bank commitments of $700 million. The facility will support PacifiCorp's commercial paper program and terminates on October 23, 2012. Terms and conditions, including borrowing rates, are substantially similar to PacifiCorp's existing revolving credit facility. Under PacifiCorp’s existing unsecured revolving credit facility, total bank commitments of $800 million are available through July 2011 and $760 million for the subsequent year ending July 2012. The credit facility supports PacifiCorp’s commercial paper program and includes a variable-rate borrowing option based on the London Interbank Offered Rate (LIBOR) plus 0.195%, which varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities. As of September 30, 2007, there were no borrowings outstanding under this credit facility.

At September 30, 2007, PacifiCorp had $518 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $21 million of standby letters of credit available to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available at September 30, 2007 and expire periodically through May 2012.

PacifiCorp’s revolving credit and other financing agreements contain customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1. At September 30, 2007, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Long-Term Debt

In October 2007, PacifiCorp issued $600 million of its 6.25% First Mortgage Bonds due October 15, 2037. The proceeds will be used to repay short-term debt and for general corporate purposes.

In March 2007, PacifiCorp issued $600 million of its 5.75% First Mortgage Bonds due April 1, 2037, and used the proceeds to repay short-term debt and for general corporate purposes.

During the nine-month period ending September 30, 2007, PacifiCorp made scheduled long-term debt repayments of $114 million.

As a result of the October and March 2007 long-term debt issuances, PacifiCorp has $300 million available under currently effective SEC shelf registration statements covering future first mortgage bond and unsecured debt issuances. PacifiCorp currently has available state regulatory authority from the Oregon Public Utility Commission (“OPUC”) and the Idaho Public Utility Commission (“IPUC”) to issue up to an additional $300 million of long-term debt. An additional filing would be required with the Washington Utilities and Transportation Commission (“WUTC”) prior to any future issuances. In May 2007, PacifiCorp was granted an exemption from obtaining prior written approval from the Utah Public Service Commission (“UPSC”) for additional long-term debt issuances. The exemption generally remains in effect as long as PacifiCorp’s senior secured debt maintains investment grade ratings.

Common Shareholder’s Capital

During the nine-month period ended September 30, 2007, PacifiCorp received capital contributions from PPW of $200 million.

Preferred Stock Redemptions

In June 2007, PacifiCorp redeemed $38 million of outstanding preferred stock subject to mandatory redemption, representing all remaining outstanding shares of PacifiCorp’s $7.48 No Par Serial Preferred Stock series.

Future Uses of Cash

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, 2007.

Capital Expenditure Program

Estimated capital expenditures, which exclude non-cash allowances for equity funds used during construction, for the year ending December 31, 2007, are expected to be approximately $1,644 million, which includes $797 million for ongoing operations projects, including new connections related to customer growth, $737 million for generation development and the related transmission projects, and $110 million for emission control equipment to address current and anticipated air quality regulations.

The capital expenditures estimate for generation development projects for the year ending December 31, 2007, includes the 140-MW Marengo I wind plant that was placed into service in August 2007. The estimate also includes construction costs for the development of additional wind generation projects that are expected to increase PacifiCorp’s renewable generation portfolio by 362 MW. These wind generation projects are expected to be placed into service through December 31, 2008. PacifiCorp continues to pursue additional cost-effective wind-powered generation.

The estimated capital expenditures for generation development projects also includes costs to complete the 534-MW Lake Side plant, which was placed into service in September 2007, as well as upgrades of other generation plant equipment. Total costs for the Lake Side plant are expected to be approximately $347 million, including non-cash allowance for equity funds used during construction. As of September 30, 2007, $339 million, including $17 million in non-cash allowance for equity funds used during construction, had been incurred.

In funding its capital expenditure program, PacifiCorp expects to obtain funds required for construction and other purposes from sources similar to those used in the past, including cash provided by operating activities, the issuance of new long-term debt and cash capital contributions from PPW. The availability of capital will influence actual expenditures.

The capital expenditure estimates are subject to a high degree of variability based on several factors, including, among others highlighted in “Forward-Looking Statements” above, future decisions arising from PacifiCorp’s Integrated Resource Plan process, changes in regulations, laws and market conditions, as well as the outcomes of rate-making proceedings. Additionally, capital expenditure needs are regularly reviewed by management and may change significantly as a result of such reviews.

Integrated Resource Plans

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

In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for approximately 3,171 MW of additional resources by summer 2016, to be met with a combination of thermal generation, combined heat and power and load control programs. PacifiCorp also plans to procure economic renewable resources, implement energy conservation programs and to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources. PacifiCorp is currently seeking acknowledgement of its 2007 IRP from state regulators and expects the acknowledgement process to be complete in 2008.

Transmission Investment

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new transmission lines originating in Wyoming and connecting into Utah, Idaho, Oregon and the desert Southwest. The estimated $4 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the western region. These transmission lines are expected to be placed into service beginning 2010 through 2014.

Credit Ratings

PacifiCorp’s credit ratings at September 30, 2007, 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. At September 30, 2007, PacifiCorp’s credit ratings from Standard & Poor’s and Moody’s were investment grade; however, if the ratings fell more than one rating below investment grade, PacifiCorp’s estimated potential collateral requirements would total approximately $419 million. PacifiCorp’s potential collateral requirements could fluctuate considerably due to seasonality, market prices and their volatility, a loss of key PacifiCorp generating facilities or other related factors.

For a further discussion of PacifiCorp’s credit ratings and their effect on PacifiCorp’s business, refer to Item 7 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006.

Contractual Obligations and Commercial Commitments

Subsequent to December 31, 2006, 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 Transition Report on Form 10-K for the nine-month period ended December 31, 2006, other than PacifiCorp’s March 2007 issuance of $600 million of its 5.75% First Mortgage Bonds due April 1, 2037 and October 2007 issuance of $600 million of its 6.25% First Mortgage Bonds due October 15, 2037.

Regulatory Matters

In addition to the discussion contained herein regarding updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2006, refer to Note 5 of Notes to Consolidated Financial Statements included in Item 1 for additional regulatory matter updates.

Federal Regulatory Matters

The Bonneville Power Administration Residential Exchange Program

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

Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Ninth Circuit Court of Appeals (the “Ninth Circuit”) seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. In May 2007, the Ninth Circuit issued two decisions. The first decision sets aside the October 2000 Residential Exchange Program settlement agreement as being inconsistent with the BPA’s settlement authority. The second decision holds, among other things, that the BPA acted contrary to law when it allocated to its preference customers, which include public utilities, cooperatives and federal agencies, part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. As a result of the ruling, in May 2007, the BPA notified the Pacific Northwest’s six utilities, including PacifiCorp, that it was immediately suspending payments. This has resulted in increases to PacifiCorp’s residential and small farm customers’ electric bills in Oregon, Washington and Idaho. 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. In October 2007, the Ninth Circuit issued one published decision and three unpublished decisions. The published decision remanded the May 2004 agreements modifying the October 2000 and May 2001 agreements to the BPA for further action consistent with the Ninth Circuit’s May 2007 decisions. The other three unpublished decisions dismiss cases in which the publicly owned utilities sought review of the BPA’s decision to implement the reduction of risk discount provision and make the full cash payment to PacifiCorp.

Hydroelectric Decommissioning

Powerdale Hydroelectric Project – (Hood River, Oregon)

In June 2003, PacifiCorp entered into a settlement agreement to remove the 6-MW nameplate-rated Powerdale plant rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale plant and associated project features, which is subject to the FERC and other regulatory approvals, is projected to cost $6 million excluding inflation. Removal of the plant is scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale plant and rendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp’s request to cease generation at the project until decommissioning activities begin. Also in February 2007, PacifiCorp submitted a request to the FERC to allow it to defer the remaining net book value and any additional removal costs of this project as a regulatory asset. In May 2007, the FERC issued an order which approved PacifiCorp’s proposed accounting entries, thereby allowing PacifiCorp to reclassify the net book value and the estimated removal costs to a regulatory asset. PacifiCorp has filed with its state commissions to recover these costs.

State Regulatory Actions

The following discussion provides a state-by-state update based upon significant changes that occurred subsequent to December 31, 2006.

Utah

In June 2007, the second phase of PacifiCorp’s general rate case filed in March 2006 became effective, adjusting the rate increase from $85 million to $115 million. Under the terms of the stipulation in the case, PacifiCorp has agreed not to file another rate case before December 11, 2007, with new rates to become effective no earlier than August 2008.

Oregon

In July 2007, as part of PacifiCorp’s annual compliance filing with the OPUC to update forecasted net power costs, PacifiCorp requested an increase of approximately $30 million, or an average price increase of 3%, to take effect January 1, 2008. The annual filing, called the transition adjustment mechanism (“TAM”), will be adjusted for new contracts through October 2007 and for other changes to forecasted net power costs, such as coal and natural gas prices, through November 2007. The OPUC issued an order on October 17, 2007, which is expected to reduce the requested increase by approximately $9 million. The final net power cost increase under the TAM will be determined in November 2007, after PacifiCorp’s annual filing is updated for the changes to forecasted net power costs.

In August 2007, PacifiCorp filed a renewable cost adjustment clause that will allow for timely recovery of the costs to implement Oregon’s Renewable Portfolio Standard (“RPS”) between rate cases. The RPS requires the OPUC to approve an automatic adjustment clause for timely recovery of these costs by January 1, 2008.

In October 2007, PacifiCorp filed its first tax report under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. The filing indicates that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was reflected in rates to its retail customers. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual tax report with the OPUC. The filing will be subject to a 180-day procedural schedule with rates potentially effective June 2008.

Wyoming

In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (“WPSC”) requesting an increase of $36 million annually, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. PacifiCorp expects the new rates to become effective by May 2008.

Washington

In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23 million, or 10%. As part of the filing, PacifiCorp proposed a Washington-only cost-allocation methodology, which is based on PacifiCorp’s western resources. The rate case included a five-year pilot period on the proposed allocation methodology and a power cost adjustment mechanism (“PCAM”). On June 21, 2007, the WUTC issued an order approving a rate increase of $14 million, or an average price increase of 6%, effective June 27, 2007, and accepted PacifiCorp’s proposed allocation methodology for a five-year pilot period. The WUTC found that PacifiCorp demonstrated the need for a PCAM, but it did not approve the design of the proposal in this case. The order authorized PacifiCorp to file a revised PCAM proposal, with or without a request to file power cost-only rate cases, outside the context of a general rate case within 12 months of the order.

Idaho

In June 2007, PacifiCorp filed a general rate case with the IPUC for an annual increase of $18 million, or an average price increase of 10%, with a request for an effective date of January 1, 2008. A hearing on the general rate case has been scheduled for November 6, 2007.

California

In August 2007, PacifiCorp filed an energy cost adjustment clause application with the California Public Utilities Commission (“CPUC”) to update actual and forecasted net variable power costs, requesting a rate increase of $6 million, or 8% overall, with an effective date of January 1, 2008.

In October 2007, PacifiCorp filed two advice letter filings requesting authority to implement components of the post test-year adjustment mechanism. The combined requested increase would total $2 million, or 2%, and would be effective January 1, 2008.

Depreciation Rate Changes

In August 2007, PacifiCorp filed applications with the respective regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation, based on a new depreciation study. PacifiCorp expects that the state regulatory commissions will make the results of the new depreciation study effective beginning January 1, 2008.

Environmental Matters

In addition to the discussion contained herein, refer to Note 5 of Notes to Consolidated Financial Statements included in Item 1 of this report and Item 1 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006, for additional information regarding certain environmental matters affecting PacifiCorp’s operations.

Renewable Portfolio Standards

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

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

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

California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance from the CPUC on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in 2007. Absent further direction from the CPUC on treatment of SMJUs, PacifiCorp cannot predict the impact of the California RPS on its financial results.

Climate Change

As a result of increased attention to climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority, and many congressional observers expect to see the passage of climate change legislation within the next several years. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the Environmental Protection Agency (“EPA”) has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. In addition, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired plants are expected to become active. Furthermore, while debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions, including Oregon, Washington, California and several Northeastern states, and individual state actions to regulate greenhouse gas emissions are likely to increase. The impact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact PacifiCorp’s current and future fossil-fueled facilities, and, therefore, its financial results.

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

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

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.

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 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 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 Transition Report on Form 10-K for the nine-month period ended December 31, 2006. PacifiCorp’s critical accounting policies have not changed materially since December 31, 2006, other than the adoption of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.”

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 Transition Report on Form 10-K for the nine-month period ended December 31, 2006. PacifiCorp’s exposure to market risk has not changed materially since December 31, 2006, except as described below.

Commodity Price Risk

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk ("VaR") approach and other measurements of net position. VaR represents an estimate of possible changes at a given level of confidence in fair value that would be measured on its portfolio assuming hypothetical movements in forward market prices and is not necessarily indicative of actual results that may occur. One of the key assumptions utilized in the VaR computations is expected retail load levels. In May 2007, PacifiCorp completed its periodic update of its estimated long-term retail load levels, which affected the VaR computation. The updated estimate indicates an increase in PacifiCorp’s long-term retail loads due to higher levels of industrial activity, primarily in the natural resource development and manufacturing industries, in several states. The increase also reflects accelerated expected growth rates in the number of retail customers and usage in Oregon and Utah.

As of September 30, 2007, PacifiCorp’s estimated potential one-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 48 months was $8 million, as measured by the VaR computations described above, compared to $16 million as of December 31, 2006. The minimum, average and maximum daily VaR (one-day holding periods) are as follows (in millions):

	Three-Month Period		Nine-Month Period
	Ended September 30, 2007		Ended September 30, 2007

Minimum VaR (measured)	$	8	$	8
Average VaR (calculated)		9		13
Maximum VaR (measured)		11		20

PacifiCorp maintained compliance with its VaR limit procedures during the nine-month period ended September 30, 2007. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Item 4. Controls and Procedures.

An evaluation was performed under the supervision and with the participation of PacifiCorp’s management, including the chief executive officer and chief financial officer, regarding 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) as of September 30, 2007. Based on that evaluation, PacifiCorp’s management, including the chief executive officer and chief financial officer, concluded that PacifiCorp’s disclosure controls and procedures were effective. There have been no changes during the quarter covered by this report in PacifiCorp’s internal control over financial reporting 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 Transition Report on Form 10-K for the nine-month period ended December 31, 2006. Material developments to these proceedings during the nine-month period ended September 30, 2007, are included in Note 5 of Notes to Consolidated Financial Statements included in Item 1.

Item 1A. Risk Factors.

There has been no material change to PacifiCorp’s risk factors from those disclosed in Item 1A of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006.

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.

SIGNATURE

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: November 2, 2007	/s/ David J. Mendez
	David J. Mendez
	Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit No.	Description

15	Letter Re: Unaudited Interim Financial Information.
31.1	Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	$700,000,000 Credit Agreement dated as of October 23, 2007 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and Union Bank of California, N.A., as Administrative Agent.