PACIFICORP /OR/ - Quarter Report: 2009 June (Form 10-Q)

pacificorp10q_06302009.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, 2009

[ ] 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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, 2009, there were 357,060,915 shares of common stock outstanding.

TABLE OF CONTENTS

PART I

Item 1.	Financial Statements	3

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	36

PART II

Item 1.	Legal Proceedings	37

Item 1A.	Risk Factors	37

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37

Item 3.	Defaults Upon Senior Securities	37

Item 4.	Submission of Matters to a Vote of Security Holders	37

Item 5.	Other Information	37

Item 6.	Exhibits	37

Signatures		38

Exhibit Index		39

PART I

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, 2009, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2009 and 2008, and of cash flows and changes in equity for the six-month periods ended June 30, 2009 and 2008. 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, 2008, and the related consolidated statements of operations, cash flows, and of changes in common shareholder’s equity and comprehensive income for the year then ended prior to retrospective adjustment for the adoption of FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (not presented herein); and in our report dated February 27, 2009, we expressed an unqualified opinion on those consolidated financial statements. We also audited the adjustments described in Note 2 that were applied to retrospectively adjust the December 31, 2008 consolidated balance sheet of PacifiCorp (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying retrospectively adjusted consolidated balance sheet as of December 31, 2008.

/s/ Deloitte & Touche LLP

Portland, Oregon

August 7, 2009

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2009		2008
ASSETS

Current assets:
Cash and cash equivalents	$	552	$	59
Accounts receivable, net		514		609
Income taxes receivable from affiliates		50		43
Inventories:
Materials and supplies		193		184
Fuel		162		155
Derivative contracts		128		174
Deferred income taxes		73		74
Other current assets		67		78
Total current assets		1,739		1,376

Property, plant and equipment, net		14,636		13,824
Regulatory assets		1,476		1,624
Derivative contracts		75		86
Investments and other assets		267		257

Total assets	$	18,193	$	17,167

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

	As of
	June 30,			December 31,
	2009			2008

LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	580		$	757
Accrued employee expenses		112			77
Accrued interest		116			89
Accrued taxes		99			73
Derivative contracts		75			130
Short-term debt		-			85
Current portion of long-term debt and capital lease obligations		143			144
Other current liabilities		112			111
Total current liabilities		1,237			1,466

Regulatory liabilities		827			821
Derivative contracts		405			490
Long-term debt and capital lease obligations		6,415			5,424
Deferred income taxes		2,173			2,025
Other long-term liabilities		836			874
Total liabilities		11,893			11,100

Commitments and contingencies (Note 10)

Equity:
PacifiCorp shareholders’ equity:
Preferred stock		41			41
Common equity:
Common stock – 750 shares authorized, no par value, 357 shares issued and outstanding		-			-
Additional paid-in capital		4,254			4,254
Retained earnings		1,926			1,694
Accumulated other comprehensive loss, net		(3	)		(2	)
Total common equity		6,177			5,946
Total PacifiCorp shareholders’ equity		6,218			5,987
Noncontrolling interest		82			80
Total equity		6,300			6,067

Total liabilities and equity	$	18,193		$	17,167

The accompanying notes are an integral part of these consolidated 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,
	2009			2008			2009			2008

Operating revenue	$	1,016		$	1,055		$	2,132		$	2,150

Operating costs and expenses:
Energy costs		360			437			796			912
Operations and maintenance		261			254			514			499
Depreciation and amortization		136			124			270			241
Taxes, other than income taxes		31			27			65			56
Total operating costs and expenses		788			842			1,645			1,708

Operating income		228			213			487			442

Other income (expense):
Interest expense		(100	)		(80	)		(199	)		(164	)
Allowance for borrowed funds		8			8			15			16
Allowance for equity funds		14			11			27			21
Interest income		9			2			12			5
Other, net		-			-			(1	)		(1	)
Total other income (expense)		(69	)		(59	)		(146	)		(123	)

Income before income tax expense		159			154			341			319
Income tax expense		49			58			105			116
Net income		110			96			236			203
Net income (loss) attributable to noncontrolling interest		-			(3	)		3			(4	)
Net income attributable to PacifiCorp	$	110		$	99		$	233		$	207

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2009			2008

Cash flows from operating activities:
Net income	$	236		$	203
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		270			241
Provision for deferred income taxes		145			159
Changes in regulatory assets and liabilities		(1	)		(52	)
Other, net		(22	)		4
Changes in other operating assets and liabilities:
Accounts receivable and other assets		97			77
Derivative collateral, net		66			(65	)
Inventories		(16	)		(32	)
Income taxes - affiliates, net		(7	)		(17	)
Accounts payable and other liabilities		(25	)		(30	)
Net cash flows from operating activities		743			488

Cash flows from investing activities:
Capital expenditures		(1,148	)		(710	)
Purchases of available-for-sale securities		(13	)		(44	)
Proceeds from sales of available-for-sale securities		24			50
Other, net		-			4
Net cash flows from investing activities		(1,137	)		(700	)

Cash flows from financing activities:
Net (repayments) borrowings of short-term debt		(85	)		35
Proceeds from long-term debt		992			-
Proceeds from equity contributions		-			200
Preferred stock dividends paid		(1	)		(1	)
Repayments and redemptions of long-term debt and capital lease obligations		(3	)		(201	)
Other, net		(16	)		9
Net cash flows from financing activities		887			42

Net change in cash and cash equivalents		493			(170	)
Cash and cash equivalents at beginning of period		59			228
Cash and cash equivalents at end of period	$	552		$	58

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

	PacifiCorp Shareholders’ Equity
										Accumulated
					Additional					Other
	Preferred		Common		Paid-in		Retained			Comprehensive			Noncontrolling
	Stock		Stock		Capital		Earnings			Loss, Net			Interest			Total

Balance, January 1, 2008	$	41	$	-	$	3,804	$	1,239		$	(4	)	$	79		$	5,159
Net income (loss)		-		-		-		207			-			(4	)		203
Other comprehensive loss		-		-		-		-			(9	)		-			(9	)
Contributions		-		-		200		-			-			21			221
Distributions		-		-		-		(1	)		-			(12	)		(13	)
Other equity transactions		-		-		-		-			-			(2	)		(2	)
Balance, June 30, 2008	$	41	$	-	$	4,004	$	1,445		$	(13	)	$	82		$	5,559

Balance, January 1, 2009	$	41	$	-	$	4,254	$	1,694		$	(2	)	$	80		$	6,067
Net income		-		-		-		233			-			3			236
Other comprehensive loss		-		-		-		-			(1	)		-			(1	)
Contributions		-		-		-		-			-			17			17
Distributions		-		-		-		(1	)		-			(24	)		(25	)
Other equity transactions		-		-		-		-			-			6			6
Balance, June 30, 2009	$	41	$	-	$	4,254	$	1,926		$	(3	)	$	82		$	6,300

The accompanying notes are an integral part of these consolidated 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 facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with public and private utilities, energy marketing companies and incorporated municipalities. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp’s subsidiaries support its electric utility operations by providing coal-mining 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 that owns subsidiaries principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc.

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 United States Securities and Exchange Commission’s 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 Consolidated Financial Statements as of June 30, 2009 and for the three- and six-month periods ended June 30, 2009 and 2008. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income attributable to PacifiCorp or retained earnings. The results of operations for the three- and six-month periods ended June 30, 2009 are not necessarily indicative of the results to be expected for the full year. PacifiCorp has evaluated subsequent events through August 7, 2009, which is the date the unaudited Consolidated Financial Statements were issued.

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 revenue 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, 2008 describes the most significant accounting policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in PacifiCorp’s assumptions regarding significant accounting estimates and policies during the six-month period ended June 30, 2009.

(2)	New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS No. 167”). SFAS No. 167 amends FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities – an interpretation of ARB No. 51” (“FIN 46(R)”), to require a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable interest entity. This analysis should be based on whether the enterprise has (i) the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. In addition, SFAS No. 167 requires enterprises to more frequently reassess whether an entity is a variable interest entity and whether the enterprise is the primary beneficiary of the variable interest entity. Finally, SFAS No. 167 amends guidance for consolidation or deconsolidation of a variable interest entity and enhances disclosure requirements about an enterprise’s involvement with a variable interest entity. SFAS No. 167 is effective as of the beginning of the first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter, with early application prohibited. PacifiCorp is currently evaluating the impact of adopting SFAS No. 167 on its consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued Staff Positions (“FSP”) No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1”). FSP FAS 107-1 requires publicly traded companies to include the annual fair value disclosures required for all financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” in interim financial statements. PacifiCorp adopted FSP FAS 107-1 on April 1, 2009 and included the required disclosures within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2”). FSP FAS 115-2 amends current other-than-temporary impairment guidance for debt securities to require a new other-than-temporary impairment model that shifts the focus from an entity’s intent to hold the debt security until recovery to its intent or expected requirement to sell the debt security. The existing other-than-temporary impairment models for equity securities will continue to apply. In addition, FSP FAS 115-2 addresses whether an other-than-temporary impairment should be recognized in earnings, other comprehensive income or some combination thereof. FSP FAS 115-2 also expands the already required annual disclosures about other-than-temporary impairment for debt and equity securities and requires companies to include these expanded disclosures in interim financial statements. PacifiCorp adopted FSP FAS 115-2 on April 1, 2009. The adoption did not have a material impact on PacifiCorp’s consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”). FSP FAS 157-4 clarifies the application of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), in determining when a market is not active and if a transaction is not orderly. In addition, FSP FAS 157-4 amends SFAS No. 157 to require disclosures in interim and annual periods of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period. FSP FAS 157-4 also amends SFAS No. 157 to define “major categories” to be consistent with those described in SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” PacifiCorp adopted FSP FAS 157-4 on April 1, 2009. The adoption did not have a material impact on PacifiCorp’s consolidated financial results and disclosures included within Notes to Consolidated Financial Statements.

In December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP FAS 132(R)-1”). FSP FAS 132(R)-1 is intended to improve financial reporting about plan assets of defined benefit pension and other postretirement plans by requiring enhanced disclosures to enable investors to better understand how investment allocation decisions are made and the major categories of plan assets. FSP FAS 132(R)-1 also requires disclosure of the inputs and valuation techniques used to measure fair value and the effect of fair value measurements using significant unobservable inputs on changes in plan assets. In addition, FSP FAS 132(R)-1 establishes disclosure requirements for significant concentrations of risk within plan assets. FSP FAS 132(R)-1 is effective for financial statements issued after December 15, 2009, with early application permitted. PacifiCorp is currently evaluating the impact of adopting FSP FAS 132(R)-1 on its disclosures included within Notes to Consolidated Financial Statements.

In March 2008, the FASB issued 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 results. PacifiCorp adopted SFAS No. 161 on January 1, 2009 and included the required disclosures within Notes to Consolidated Financial Statements.

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. PacifiCorp adopted SFAS No. 160 on January 1, 2009. As a result, PacifiCorp has presented noncontrolling interest as a separate component of equity on the Consolidated Balance Sheets. Previously, this amount was reported in other long-term liabilities on the Consolidated Balance Sheets. Also, PacifiCorp has presented net income attributable to noncontrolling interest separately on the Consolidated Statements of Operations. Previously, this amount was included in operating income on the Consolidated Statements of Operations.

(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consist of the following (in millions):

		As of
		June 30,			December 31,
	Depreciation Life	2009			2008

Property, plant and equipment	5-80 years	$	19,613		$	18,879
Accumulated depreciation and amortization			(6,472	)		(6,275	)
Net property, plant and equipment			13,141			12,604
Construction work-in-progress			1,495			1,220
Total property, plant and equipment, net		$	14,636		$	13,824

(4)	Regulatory Matters

The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2008.

Rate Matters

Oregon Senate Bill 408 (“SB 408”)

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 report each October with the Oregon Public Utility Commission (the “OPUC”) comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. PacifiCorp’s amended filing for the 2006 tax year indicated that PacifiCorp paid $35 million more in income taxes than was collected in rates from its retail customers. In April 2008, the OPUC approved $27 million of the deficiency associated with PacifiCorp’s 2006 tax report 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 April 2009, the OPUC approved recovery of the remaining balance, including interest, associated with PacifiCorp’s 2006 tax report and approved recovery of the under collected income tax balance, including interest, associated with PacifiCorp’s 2007 tax report. In April 2009, PacifiCorp recorded a $20 million regulatory asset representing the balance to be collected from its Oregon retail customers for its 2006 and 2007 tax reports. The amounts are being collected over a one-year period beginning June 1, 2009.

The OPUC’s April 2008 order on PacifiCorp’s 2006 tax report is being challenged by the Industrial Customers of Northwest Utilities (“ICNU”), which filed a petition in May 2008 with the Court of Appeals of the State of Oregon (“Court of Appeals”) seeking judicial review of the April 2008 order. In December 2008, ICNU filed their opening brief. In March 2009, a notice of withdrawal of the April 2008 order in judicial review was filed in the Court of Appeals by the OPUC. In May 2009, the OPUC issued an order on reconsideration, which supplemented and affirmed its April 2008 order. In June 2009, ICNU continued their challenge of the April 2008 order by filing an amended petition for judicial review with the Court of Appeals. PacifiCorp believes the outcome of these proceedings will not have a material impact on its consolidated financial results.

(5)	Fair Value Measurements

The carrying amounts of PacifiCorp’s cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximate fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value in the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

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

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

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

The following table presents PacifiCorp’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of June 30, 2009 (in millions):

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

Assets(2):
Investments in available-for-sale securities:
Money market mutual funds(3)	$	550	$	-		$	-		$	-		$	550
Debt securities		3		33			-			-			36
Equity securities		31		7			-			-			38
Commodity derivatives		-		542			8			(347	)		203
	$	584	$	582		$	8		$	(347	)	$	827

Liabilities:
Commodity derivatives	$	-	$	(446	)	$	(397	)	$	363		$	(480	)

(1)	Primarily represents a net cash collateral receivable of $16 million and netting under master netting arrangements.

(2)	Does not include investments in either pension or other postretirement benefit plan assets.

(3)	Amounts are included in cash and cash equivalents, other current assets and investments and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

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 December 31, 2008 (in millions):

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

Assets(2):
Investments in available-for-sale securities:
Money market mutual funds(3)	$	51	$	-		$	-		$	-		$	51
Debt securities		-		42			-			-			42
Equity securities		30		6			-			-			36
Commodity derivatives		-		474			88			(302	)		260
	$	81	$	522		$	88		$	(302	)	$	389

Liabilities:
Commodity derivatives	$	-	$	(485	)	$	(496	)	$	361		$	(620	)

(1)	Primarily represents a net cash collateral receivable of $82 million and netting under master netting arrangements.

(2)	Does not include investments in either pension or other postretirement benefit plan assets.

(3)	Amounts are included in cash and cash equivalents, other current assets and investments and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

PacifiCorp’s investments in debt and equity securities, including certain cash equivalents, are accounted for as available-for-sale securities and are 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 or net asset value in a readily observable and active market, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

The fair value of derivative instruments is determined using unadjusted quoted prices for identical instruments on the applicable exchange in which PacifiCorp transacts. When quoted prices for identical instruments are not available, PacifiCorp uses 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; 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 if 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 significant unobservable inputs. Refer to Note 6 for further discussion regarding PacifiCorp’s risk management and hedging activities.

Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap and option components. Forward and swap components are valued against the appropriate forward price curve. Options components are valued using Black-Scholes-type option models, such as European option, Asian option, spread option and best-of option, with the appropriate forward price curve and other inputs.

The following table reconciles the beginning and ending balance of PacifiCorp’s commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the three-month periods ended June 30 (in millions):

	2009			2008

Beginning balance	$	(452	)	$	(312	)
Unrealized or realized gains included in regulatory assets		46			127
Purchases, sales, issuances and settlements		19			(23	)
Net transfers into or out of Level 3		(2	)		-
Ending balance	$	(389	)	$	(208	)

	2009			2008

Beginning balance	$	(408	)	$	(311	)
Unrealized or realized gains included in regulatory assets		29			145
Purchases, sales, issuances and settlements		13			(42	)
Net transfers into or out of Level 3		(23	)		-
Ending balance	$	(389	)	$	(208	)

PacifiCorp’s long-term debt is carried at cost in the Consolidated Financial Statements. The fair value of PacifiCorp’s long-term debt has been estimated based on quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar risks. The carrying amount of PacifiCorp’s variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying amount and estimated fair value of PacifiCorp’s long-term debt (in millions):

	As of
	June 30, 2009		December 31, 2008
	Carrying	Fair	Carrying	Fair
	Amount	Value	Amount	Value

Long-term debt	$ 6,495	$ 6,982	$ 5,503	$ 5,769

(6)	Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity and natural gas commodity price risk. PacifiCorp’s load and generation assets represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of wholesale electricity that is purchased and sold and fuel costs to generate electricity. Electricity and natural gas prices are subject to wide price swings as supply and demand for these commodities are impacted by, among many other unpredictable items, changing weather, market liquidity, generation plant availability, customer usage, storage and transmission and transportation constraints. Interest rate risk exists on variable-rate debt, commercial paper and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in PacifiCorp’s business. To mitigate a portion of its commodity risk, PacifiCorp uses commodity derivative contracts, including forward contracts, futures, options, fixed price and basis swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. To manage its interest rate risk on existing or future debt, PacifiCorp may from time to time enter into interest rate derivatives, such as interest rate swaps or locks. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to the risks and benefits of spot-market price movements.

There have been no significant changes in PacifiCorp’s significant accounting policies related to derivatives. Refer to Notes 2 and 5 of Notes to Consolidated Financial Statements for additional information on derivative contracts.

The following table, which excludes contracts that qualify for the normal purchase or normal sales exemption afforded by GAAP, summarizes the fair value of PacifiCorp’s derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis included in the Consolidated Balance Sheet as of June 30, 2009 (in millions):

	Balance Sheet Locations
	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Total

Not Designated as Hedging Contracts (1)(2):
Commodity assets	$	377		$	115		$	25		$	30		$	547
Commodity liabilities		(134	)		(31	)		(202	)		(474	)		(841	)
Total		243			84			(177	)		(444	)		(294	)

Designated as Cash Flow Hedging Contracts (1):
Commodity assets		3			-			-			-			3
Commodity liabilities		(2	)		-			-			-			(2	)
Total		1			-			-			-			1

Total derivatives		244			84			(177	)		(444	)		(293	)
Cash collateral receivable (payable)		(116	)		(9	)		102			39			16
Total derivatives – net basis	$	128		$	75		$	(75	)	$	(405	)	$	(277	)

(1)	Derivative contracts within these categories are subject to master netting arrangements and are presented on a net basis in the Consolidated Balance Sheet.

(2)	The majority of PacifiCorp’s commodity derivatives not designated as hedging contracts are recoverable from customers in regulated rates and as of June 30, 2009, a net regulatory asset of $302 million was recorded related to the net derivative liabilities of $294 million.

Not Designated as Hedging Contracts

For PacifiCorp’s commodity derivatives not designated as hedging contracts, the settled amount is generally recovered from customers in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of recovery in rates are recorded as net regulatory assets. The following table reconciles the beginning and ending balances of PacifiCorp’s net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):

	Three-Month			Six-Month
	Period Ended			Period Ended
	June 30, 2009			June 30, 2009

Beginning balance	$	385		$	442
Changes in fair value recognized in net regulatory assets		(89	)		(162	)
Gains reclassified to earnings – operating revenue		59			138
Losses reclassified to earnings – energy costs		(53	)		(116	)
Ending balance	$	302		$	302

For PacifiCorp’s commodity derivatives not designated as hedging contracts and not recorded as a net regulatory asset, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts and as energy costs and operations and maintenance expense for purchase contracts and electricity and natural gas swap contracts. The following table summarizes the pre-tax gains included within the Consolidated Statement of Operations associated with PacifiCorp’s derivative contracts not designated as hedging contracts and not recorded as a net regulatory asset (in millions):

	Three-Month		Six-Month
	Period Ended		Period Ended
	June 30, 2009		June 30, 2009
Commodity derivatives:
Operating revenue	$	2	$	5
Energy costs		1		1
Operations and maintenance		2		1
Total	$	5	$	7

Designated as Hedging Contracts

PacifiCorp uses derivative contracts accounted for as cash flow hedges to hedge commodity prices. The gains and losses on these derivative contracts are recognized in other comprehensive income. Derivative contracts accounted for as cash flow hedges were not material for the three- and six-month periods ended June 30, 2009. The impact of hedge ineffectiveness was also not material. Hedge ineffectiveness is recognized in income as operating revenue, energy costs or operation and maintenance expense depending on the nature of the item being hedged.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contract volumes with fixed price terms that comprise the mark-to-market values (in millions):

	Unit of	As of
	Measure	June 30, 2009
Commodity contracts:
Electricity sales	Megawatt hours		(21	)
Natural gas purchases	Decatherms		215
Fuel purchases	Gallons		4

Credit Risk

PacifiCorp extends unsecured credit to other utilities, energy marketers, financial institutions and other market participants in conjunction with wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.

PacifiCorp analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed payments. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty’s credit support arrangement. Based on PacifiCorp’s policies and risk exposures related to credit, PacifiCorp does not anticipate a material adverse effect on its consolidated financial results as a result of counterparty nonperformance.

Collateral and Contingent Features

In accordance with industry practice, certain derivative contracts contain provisions that require PacifiCorp to maintain specific credit ratings from one or more of the major credit rating agencies on its unsecured debt. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels (“credit-risk-related contingent features”) or provide the right for counterparties to demand “adequate assurance” in the event of a material adverse change in PacifiCorp’s creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2009, PacifiCorp’s credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp’s derivative contracts in liability positions with specific credit-risk-related contingent features totaled $535 million as of June 30, 2009, for which PacifiCorp had posted collateral of $141 million. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of June 30, 2009, PacifiCorp would have been required to post $170 million of additional collateral. PacifiCorp’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors.

(7)	Recent Debt Transactions

In January 2009, PacifiCorp issued $350 million of its 5.5% First Mortgage Bonds due January 15, 2019 and $650 million of its 6.0% First Mortgage Bonds due January 15, 2039. The net proceeds were used to repay short-term debt and are being used to fund capital expenditures and for general corporate purposes.

(8)	Employee Benefit Plans

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

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Pension
Service cost(1)	$	4		$	7		$	8		$	14
Interest cost		17			17			35			33
Expected return on plan assets		(17	)		(17	)		(35	)		(35	)
Net amortization		2			1			5			3
Net amortization of regulatory deferrals		(2	)		-			(4	)		-
Net periodic benefit cost	$	4		$	8		$	9		$	15

	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
Other Postretirement
Service cost(1)	$	1		$	1		$	2		$	3
Interest cost		8			9			16			17
Expected return on plan assets		(7	)		(7	)		(14	)		(14	)
Net amortization		3			4			6			8
Net amortization of regulatory deferrals		-			-			1			-
Net periodic benefit cost	$	5		$	7		$	11		$	14

(1)

Service cost excludes $2 million and $4 million of contributions to the joint trust union plans during the three-month periods ended June 30, 2009 and 2008, respectively. Service cost excludes $6 million and $7 million of contributions to the joint trust union plans during the six-month periods ended June 30, 2009 and 2008, respectively.

Employer contributions to the pension, other postretirement benefit and joint trust union plans are expected to be $54 million, $25 million and $13 million, respectively, during 2009. As of June 30, 2009, $39 million, $12 million and $6 million of contributions had been made to the pension, other postretirement benefit and joint trust union plans, respectively.

(9)

Taxes

The effective tax rates were 31% and 38% for the three-month periods ended June 30, 2009 and 2008, respectively, and 31% and 36% for the six-month periods ended June 30, 2009 and 2008, respectively. The decrease in the effective tax rate was primarily due to the benefit of additional production tax credits associated with increased production at wind-powered generating facilities combined with lower income tax expense associated with the regulatory treatment of certain deferred income taxes.

(10)	Commitments and Contingencies

Legal Matters

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material 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 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. 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.

Environmental Matters

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp’s current and future operations. PacifiCorp believes it is in material compliance with current environmental requirements.

New Source Review

As part of an industry-wide investigation to assess compliance with the New Source Review (“NSR”) and Prevention of Significant Deterioration (“PSD”) provisions, the United States Environmental Protection Agency (the “EPA”) has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating facilities. Between 2001 and 2003, PacifiCorp responded to requests for information relating to its capital projects at its generating facilities, and it has been engaged in periodic discussions with the EPA over several years regarding its historical projects and their compliance with NSR and PSD provisions. An NSR enforcement case against another utility has been decided by the United States Supreme Court, holding that an increase in annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event it is determined that PacifiCorp’s historical projects did not meet all regulatory requirements. The impact of these additional emissions controls, costs and penalties, if any, on PacifiCorp’s consolidated financial results cannot be determined at this time.

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, 2009 and as of December 31, 2008 was $22 million and $26 million, respectively, and is included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and legal obligations associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Climate Change

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009, (“Waxman-Markey bill”), introduced by Representatives Henry Waxman and Edward Markey. In addition to a federal renewable portfolio standard, which would require utilities to obtain a portion of their energy from certain qualifying renewable sources, and energy efficiency measures, the bill requires a reduction in greenhouse gas emissions beginning in 2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a “cap and trade” program. Similar bills seeking to create “cap and trade” systems for greenhouse gas emissions have also been introduced in the United States Senate. If the Waxman-Markey bill or some other federal comprehensive climate change bill were to pass both Houses of Congress and be signed into law by the President, the impact on PacifiCorp’s financial performance could be material and would depend on a number of factors, including the required timing and level of greenhouse gas reductions, the price and availability of offsets and allowances used for compliance and the ability of PacifiCorp to receive revenue from customers for increased costs. The new law would likely result in increased operating costs and expenses, additional capital expenditures and asset retirements and may negatively impact demand for electricity. PacifiCorp expects it will be allowed to recover the costs to comply with climate change requirements.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 47 generating facilities with an aggregate facility 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 16 individual licenses, which typically have terms of 30 to 50 years. PacifiCorp is currently actively engaged in the relicensing process with the FERC for its Klamath hydroelectric system.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW Klamath hydroelectric system 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 operating under annual licenses until the relicensing process is complete. As part of the relicensing process, the FERC is required to perform an environmental review, and 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 Klamath hydroelectric system’s impact on endangered species under a new FERC license consistent with the FERC staff’s recommended license alternative and terms and conditions issued by the United States Departments of the Interior and Commerce. These terms and conditions include construction of upstream and downstream fish passage facilities at the Klamath hydroelectric system’s four mainstem dams. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has water quality applications pending in Oregon and California.

In November 2008, PacifiCorp signed a non-binding agreement in principle (the “AIP”) that lays out a framework for the disposition of PacifiCorp’s Klamath hydroelectric system relicensing process, including a path toward dam transfer and removal by an entity other than PacifiCorp no earlier than 2020. Parties to the AIP are PacifiCorp, the United States Department of the Interior, the State of Oregon and the State of California. Any transfer of facilities and subsequent removal are contingent on PacifiCorp reaching a comprehensive final settlement with the AIP signatories and other stakeholders. Negotiations have begun and a final agreement is expected in September 2009. As provided in the AIP, PacifiCorp’s support for a definitive settlement will depend on a variety of factors, including the protection for PacifiCorp and its customers from uncapped dam removal costs and liabilities.

The AIP includes provisions to:

Perform studies and implement certain measures designed to benefit aquatic species and their habitat in the Klamath Basin;

Support and implement legislation in Oregon authorizing a customer surcharge intended to cover potential dam removal; and

Require parties to support proposed federal legislation introduced to facilitate a final agreement.

Assuming a final agreement is reached, the United States government will conduct scientific and engineering studies and consult with state, local and tribal governments and other stakeholders, as appropriate, to determine by March 31, 2012 whether the benefits of dam removal will justify the costs.

In addition to signing the AIP, PacifiCorp provided both the United States Fish and Wildlife Service and the National Marine Fisheries Service an interim conservation plan aimed at providing additional protections for endangered species in the Klamath Basin. PacifiCorp is currently collaborating with both agencies to implement the plan.

In July 2009, Oregon’s governor signed a bill authorizing PacifiCorp to collect surcharges from its Oregon customers for Oregon’s share of the customer contribution identified in the AIP for the cost of removing the Klamath River dams. According to the AIP, the total amount to be collected from PacifiCorp’s customers is capped at $200 million. Of this amount, approximately $180 million is to be collected from PacifiCorp’s Oregon customers with the remainder to be collected from PacifiCorp’s California customers.

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, as well as ongoing operations and maintenance expense and capital expenditures required by its hydroelectric licenses. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $62 million and $57 million in costs, included in construction work-in-progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets, as of June 30, 2009 and December 31, 2008, respectively, for ongoing hydroelectric relicensing. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

FERC Issues

FERC Investigation

During 2007, the Western Electricity Coordinating Council (the “WECC”) audited PacifiCorp’s compliance with several of the reliability standards developed by the North American Electric Reliability Corporation (the “NERC”). In April 2008, PacifiCorp received notice of a preliminary non-public investigation from the FERC and the NERC to determine whether an outage that occurred in PacifiCorp’s transmission system in February 2008 involved any violations of reliability standards. In November 2008, PacifiCorp received preliminary findings from the FERC staff regarding its non-public investigation into the February 2008 outage. Also in November 2008, in conjunction with the reliability standards review, the FERC assumed control of certain aspects of the WECC’s 2007 audit. PacifiCorp has engaged in discussions with FERC staff regarding findings related to the WECC audit and the non-public investigation. However, PacifiCorp cannot predict the impact of the audit or the non-public investigation, if any, on its consolidated financial results at this time.

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 in the Pacific Northwest spot market made by the California Energy Resources Scheduling (“CERS”) division of the California Department of Water Resources. Without issuing the mandate order, the Ninth Circuit remanded the case to the FERC to (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. In April 2009, the Ninth Circuit issued a formal mandate order, completing the remand of the case to the FERC, which has not yet undertaken further action. PacifiCorp cannot predict the future course of this proceeding and its impact on its consolidated financial results, if any, at this time.

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

Comprehensive income attributable to PacifiCorp consists of the following components (in millions):

	Three-Month Periods					Six-Month Periods
	Ended June 30,					Ended June 30,
	2009		2008			2009			2008

Net income attributable to PacifiCorp	$	110	$	99		$	233		$	207
Other comprehensive loss attributable to PacifiCorp:
Fair value adjustment on cash flow hedges, net of tax of $-, $(5), $- and $(5)		-		(9	)		(1	)		(9	)

Comprehensive income attributable to PacifiCorp	$	110	$	90		$	232		$	198

Accumulated other comprehensive loss attributable to PacifiCorp, net consists of the following components (in millions):

	As of
	June 30,			December 31,
	2009			2008

Unrecognized amounts on retirement benefits, net of tax of $(2) and $(2)	$	(2	)	$	(2	)
Fair value adjustment on cash flow hedges, net of tax of $- and $-		(1	)		-
Total accumulated other comprehensive loss attributable to PacifiCorp, net	$	(3	)	$	(2	)

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 Notes to Consolidated Financial Statements included 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 operate;

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 (“SB 408”);

changes in, and compliance with, environmental laws, regulations, decisions and policies, including those addressing climate change, that could increase operating and capital costs, reduce plant output 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 or PacifiCorp’s ability to obtain long-term contracts with customers and suppliers;

a high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and costs to balance electricity and load 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 PacifiCorp’s ability to generate electricity;

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

the financial condition and creditworthiness of PacifiCorp’s significant customers and suppliers;

changes in business strategy or development plans;

availability, terms and deployment of capital, including severe reductions in demand for investment grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for PacifiCorp’s credit facilities;

changes in PacifiCorp’s credit ratings;

performance of PacifiCorp’s generating facilities, including unscheduled outages or repairs;

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

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

unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities 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, wars, the effects of terrorism, embargoes and other catastrophic events; and

other business or investment considerations that may be disclosed from time to time in PacifiCorp’s 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 for the Three- and Six-Month Periods Ended June 30, 2009 and 2008

Overview

Net income attributable to PacifiCorp during the three-month period ended June 30, 2009 was $110 million, an increase of $11 million, or 11%, and for the six-month period ended June 30, 2009 was $233 million, an increase of $26 million, or 13%, as compared to 2008. Net income attributable to PacifiCorp increased in both periods primarily due to lower prices on wholesale electricity purchases and higher prices approved by regulators on retail electricity sales, partially offset by lower retail customer usage, lower average prices on wholesale electricity sales, higher depreciation and amortization and higher interest expense. Retail energy sales volumes decreased 7% and 5% during the three- and six-month periods ended June 30, 2009, respectively, primarily due to the impacts of the current economic conditions, as well as cooler than normal weather conditions in Utah during the second quarter.

The September 2008 acquisition of the 520-megawatt (“MW”) natural gas-fired Chehalis plant and the addition of 520 MWs of wind-powered generating facilities placed in service from May 2008 through January 2009 provided more flexibility in balancing PacifiCorp’s system requirements during the three- and six-month periods ended June 30, 2009. This additional owned generating capacity and lower retail demand reduced PacifiCorp’s reliance on purchased electricity. Significantly lower average market prices for wholesale electricity sales in the open market limited PacifiCorp’s ability to economically utilize excess thermal generating capacity.

Operating Revenue (Dollars in Millions)

	Three-Month Periods Ended June 30,				Favorable/(Unfavorable)
	2009		2008		Change

Retail	$	816	$	840	$	(24	)	(3	)%
Wholesale and other		200		215		(15	)	(7	)
Total operating revenue	$	1,016	$	1,055	$	(39	)	(4	)

Average retail customers (in thousands)		1,716		1,704		12		1

Volumes Gigawatt hours (“GWh”):
Retail energy sales		12,046		12,891		(845	)	(7	)
Wholesale energy sales		2,621		2,756		(135	)	(5	)
Total energy sales		14,667		15,647		(980	)	(6	)

Retail revenues decreased $24 million, or 3%, primarily due to:

$46 million of decreases due to lower average customer usage, primarily due to the effects of the current economic conditions on customer usage in Oregon and on industrial customer usage in Utah and Idaho, and including a $13 million decrease due to cooler than normal weather in Utah; and

$15 million of lower revenue related to SB 408; partially offset by,

$28 million of increases from higher prices approved by regulators; and

$7 million of increases due to growth in the average number of commercial customers.

Wholesale sales and other revenue decreased $15 million, or 7%, primarily due to:

$42 million of decreases in wholesale sales due to $32 million from lower average prices and $10 million from lower volumes; partially offset by,

$18 million of increases due to changes in the fair value of energy sales contracts accounted for as derivatives; and

$14 million of increases due to revenue attributable to PacifiCorp’s majority owned coal mining operations.

Operating Costs and Expenses (Dollars in Millions)

	Three-Month Periods Ended June 30,				Favorable/(Unfavorable)
	2009		2008		Change

Energy costs	$	360	$	437	$	77		18	%
Operations and maintenance		261		254		(7	)	(3	)
Depreciation and amortization		136		124		(12	)	(10	)
Taxes, other than income taxes		31		27		(4	)	(15	)
Total operating costs and expenses	$	788	$	842	$	54		6

Volumes (GWh):
Coal-fired generation		9,441		10,207		(766	)	(8	)
Natural gas-fired generation		1,523		1,798		(275	)	(15	)
Hydroelectric generation		1,267		1,278		(11	)	(1	)
Other		568		372		196		53
Total PacifiCorp generated volumes		12,799		13,655		(856	)	(6	)
Purchased electricity		2,838		3,037		199		7

Energy costs decreased $77 million, or 18%, primarily due to:

$100 million of decreases in purchased electricity due to $87 million from lower average prices and $13 million from lower volumes; and

$5 million of decreases in the cost of coal consumed at PacifiCorp’s coal-fired generating facilities due to $12 million from lower volumes, partially offset by $7 million from higher average prices; partially offset by,

$16 million of increases primarily due to lower deferrals of incurred power costs in accordance with established adjustment mechanisms in the current period; and

$13 million of increases due to changes in the fair value of energy purchase contracts accounted for as derivatives.

Operations and maintenance expense increased $7 million, or 3%, primarily due to costs attributable to PacifiCorp’s majority owned coal mining operations.

Depreciation and amortization expense increased $12 million, or 10%, primarily due to higher plant-in-service in the current period.

Other Income (Expense) (in Millions)

	Three-Month Periods Ended June 30,						Favorable/(Unfavorable)
	2009			2008			Change

Interest expense	$	(100	)	$	(80	)	$	(20	)	(25	)%
Allowance for borrowed funds		8			8			-		-
Allowance for equity funds		14			11			3		27
Interest income		9			2			7		350
Total other income (expense)	$	(69	)	$	(59	)	$	(10	)	(17	)

Interest expense increased $20 million, or 25%, primarily due to higher average debt outstanding, partially offset by lower average rates on variable-rate debt.

Interest income increased $7 million, substantially due to interest associated with PacifiCorp’s 2006 and 2007 tax reports pursuant to SB 408.

Income tax expense decreased $9 million to $49 million for the three-month period ended June 30, 2009 as compared to 2008, primarily due to higher production tax credits associated with increased production at wind-powered generating facilities combined with lower tax expense associated with the regulatory treatment of certain deferred income taxes, partially offset by higher pre-tax earnings. The effective tax rate was 31% for the three-month period ended June 30, 2009 compared to 38% for 2008.

Operating Revenue (Dollars in Millions)

	Six-Month Periods Ended June 30,				Favorable/(Unfavorable)
	2009		2008		Change

Retail	$	1,664	$	1,674	$	(10	)	(1	)%
Wholesale and other		468		476		(8	)	(2	)
Total operating revenue	$	2,132	$	2,150	$	(18	)	(1	)

Average retail customers (in thousands)		1,716		1,703		13		1

Volumes (GWh):
Retail energy sales		25,313		26,602		(1,289	)	(5	)
Wholesale energy sales		6,121		6,027		94		2
Total energy sales		31,434		32,629		(1,195	)	(4	)

Retail revenues decreased $10 million, or 1%, primarily due to:

$67 million of decreases due to lower average customer usage, primarily due to the effects of the current economic conditions mainly in Oregon and on industrial customer usage in Utah and Idaho; and

$15 million of lower revenue related to SB 408; partially offset by,

$56 million of increases from higher prices approved by regulators; and

$14 million of increases due to growth in the average number of commercial and residential customers.

Wholesale sales and other revenue decreased $8 million, or 2%, primarily due to:

$74 million of decreases in wholesale sales due to $81 million from lower average prices, partially offset by $7 million from higher volumes; partially offset by,

$38 million of increases due to changes in the fair value of energy sales contracts accounted for as derivatives; and

$32 million of increases due to revenue attributable to PacifiCorp’s majority owned coal mining operations.

Operating Costs and Expenses (Dollars in Millions)

	Six-Month Periods Ended June 30,				Favorable/(Unfavorable)
	2009		2008		Change

Energy costs	$	796	$	912	$	116		13	%
Operations and maintenance		514		499		(15	)	(3	)
Depreciation and amortization		270		241		(29	)	(12	)
Taxes, other than income taxes		65		56		(9	)	(16	)
Total operating costs and expenses	$	1,645	$	1,708	$	63		4

Volumes (GWh):
Coal-fired generation		20,601		22,010		(1,409	)	(6	)
Natural gas-fired generation		4,026		3,974		52		1
Hydroelectric generation		2,305		2,311		(6	)	-
Other		1,182		679		503		74
Total PacifiCorp generated volumes		28,114		28,974		(860	)	(3	)
Purchased electricity		5,498		6,010		512		9

Energy costs decreased $116 million, or 13%, primarily due to:

$167 million of decreases in purchased electricity due to $133 million from lower average prices and $34 million from lower volumes; and

$12 million of decreases in the cost of coal consumed at PacifiCorp’s coal-fired generating facilities due to $20 million from lower volumes, partially offset by $8 million from higher average prices; partially offset by,

$31 million of increases primarily due to lower deferrals of incurred power costs in accordance with established adjustment mechanisms;

$22 million of increases due to changes in the fair value of energy purchase contracts accounted for as derivatives; and

$11 million of increases in the cost of natural gas consumed at PacifiCorp’s natural gas-fired generating facilities due to $10 million from higher volumes primarily due to the addition of the 520-MW Chehalis plant in September 2008, which was partially offset by the May 2008 termination of the West Valley lease.

Operations and maintenance expense increased $15 million, or 3%, primarily due to costs attributable to PacifiCorp’s majority owned coal mining operations.

Depreciation and amortization expense increased $29 million, or 12%, primarily due to higher plant-in-service in the current period.

Other Income (Expense) (in Millions)

	Six-Month Periods Ended June 30,						Favorable/(Unfavorable)
	2009			2008			Change

Interest expense	$	(199	)	$	(164	)	$	(35	)	(21	)%
Allowance for borrowed funds		15			16			(1	)	(6	)
Allowance for equity funds		27			21			6		29
Interest income		12			5			7		140
Other, net		(1	)		(1	)		-		-
Total other income (expense)	$	(146	)	$	(123	)	$	(23	)	(19	)

Interest expense increased $35 million, or 21%, primarily due to higher average debt outstanding, partially offset by lower average rates on variable-rate debt.

Interest income increased $7 million, substantially due to interest associated with PacifiCorp’s 2006 and 2007 tax reports pursuant to SB 408.

Income tax expense decreased $11 million to $105 million for the six-month period ended June 30, 2009 as compared to 2008, primarily due to higher production tax credits associated with increased production at wind-powered generating facilities combined with lower tax expense associated with the regulatory treatment of certain deferred income taxes, partially offset by higher pre-tax earnings. The effective tax rate was 31% for the six-month period ended June 30, 2009 compared to 36% for 2008.

Liquidity and Capital Resources

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 or canceled and operating income may be reduced. Short-term cash requirements not met by net cash flows 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 by PacifiCorp’s indirect parent company, MidAmerican Energy Holdings Company (“MEHC”). PacifiCorp expects it will need additional periodic equity contributions from MEHC over the next several years. Issuance of long-term securities is influenced by the levels of short-term debt, net cash flows from operating activities, capital expenditures, market conditions, regulatory approvals and other considerations.

As of June 30, 2009, PacifiCorp’s total net liquidity available was $1.689 billion. The components of total net liquidity available are as follows (in millions):

Cash and cash equivalents	$	552

Available revolving credit facilities	$	1,395

Less –Tax-exempt bond support and letters of credit		(258	)
Net revolving credit facilities available	$	1,137

Total net liquidity available	$	1,689

Unsecured revolving credit facilities:
Maturity date		2012-2013
Largest single bank commitment as a % of total(1)		15	%

(1)	An inability of financial institutions to honor their commitments could adversely affect PacifiCorp’s short-term liquidity and ability to meet long-term commitments.

PacifiCorp’s cash and cash equivalents were $552 million as of June 30, 2009, compared to $59 million as of December 31, 2008. PacifiCorp has restricted cash and investments included in other current assets and investments and other assets on the Consolidated Balance Sheets totaling $88 million and $93 million as of June 30, 2009 and December 31, 2008, respectively, that principally relate to trust funds held for coal mine reclamation.

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2009 and 2008 were $743 million and $488 million, respectively. The $255 million increase was due primarily to lower average prices on wholesale electricity purchases and a net receipt of cash collateral on derivative contracts in the current period, partially offset by lower average prices on wholesale electricity sales.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2009 and 2008 were $(1.137) billion and $(700) million, respectively. Capital expenditures increased $438 million primarily due to wind-powered generating facilities, transmission expansion and reliability investments and generation overhauls.

Capital expenditures consisted mainly of the following during the six-month periods ended June 30, 2009 and 2008, respectively:

2009:

The development and construction of wind-powered generating facilities totaling $308 million, including payments for wind-powered generating facilities placed in service in December 2008. In January 2009, 138 MW of additional wind-powered generating facilities were placed in service. An additional 127.5 MW of wind-powered generating facilities are expected to be placed in service by December 31, 2009.

Emission control equipment totaling $143 million.

Transmission system expansion and upgrades totaling $269 million, including the Energy Gateway Transmission Expansion Project.

Distribution, generation, mining and other infrastructure needed to serve existing and expected growing demand totaling $428 million.

2008:

The development and construction of wind-powered generating facilities totaling $190 million.

Emission control equipment totaling $87 million.

Transmission system expansion and upgrades totaling $73 million, including the Energy Gateway Transmission Expansion Project.

Distribution, generation, mining and other infrastructure needed to serve existing and growing demand totaling $360 million.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2009 were $887 million. Sources of cash totaled $992 million and consisted of proceeds from the issuance of long-term debt. Uses of cash totaled $105 million and consisted primarily of $85 million for net repayments of short-term debt.

Net cash flows from financing activities for the six-month period ended June 30, 2008 were $42 million. Sources of cash totaled $244 million and consisted primarily of $200 million of proceeds from equity contributions from MEHC. Uses of cash totaled $202 million and consisted substantially of repayments of long-term debt.

Short-term Debt and Revolving Credit Facilities

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which an aggregate principal amount of $85 million was outstanding at December 31, 2008 with a weighted average interest rate of 1.0%. In January 2009, PacifiCorp repaid its outstanding short-term debt with proceeds from its January 2009 long-term debt issuance discussed below. PacifiCorp had no outstanding short-term debt as of June 30, 2009.

PacifiCorp had no outstanding borrowings under its unsecured revolving credit facilities as of June 30, 2009 or December 31, 2008. In April 2009, PacifiCorp’s commitments with Lehman Brothers Bank, FSB and Lehman Commercial Paper, Inc. were terminated, reducing the total committed facilities to $1.395 billion. See Note 8 of Notes to Consolidated Financial Statements included in PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2008 for further discussion.

Long-term Debt

Future Uses of Cash

PacifiCorp expects to have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depend on a variety of factors, including PacifiCorp’s credit ratings, investors’ judgment of risk and conditions in the overall capital markets, including the condition of the utility industry in general.

Integrated Resource Plan

As required by certain state regulations, PacifiCorp uses an Integrated Resource Plan (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. PacifiCorp files its IRP on a biennial basis. In May 2009, PacifiCorp filed its 2008 IRP with each of its state commissions.

Requests for Proposals

PacifiCorp has issued a series of separate requests for proposals (“RFPs”), each of which focuses on a specific category of resources consistent with the IRP. The IRP and the RFPs provide for the identification and staged procurement of resources in future years to achieve a balance of load requirements and resources. As required by applicable laws and regulations, PacifiCorp files draft RFPs with the Utah Public Service Commission (the “UPSC”), the Oregon Public Utility Commission (the “OPUC”) and the Washington Utilities and Transportation Commission (the “WUTC”) prior to issuance to the market.

In June 2009, PacifiCorp filed its draft 2009R renewable resources RFP (the “2009R RFP”) with the OPUC. The 2009R RFP seeks up to 600 MW of cost-effective renewable generation projects, with no single resource greater than 300 MW and on-line dates no later than December 31, 2012. The 2009R RFP was approved by the OPUC in July 2009. Renewable resource RFPs for resources under 300 MW do not require approval from the UPSC. 2009R RFP bids are due September 2009.

Capital Expenditures

PacifiCorp has significant future capital requirements. Forecasted capital expenditures for 2009, which exclude non-cash allowance for equity funds used during construction, are approximately $2.4 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews, which may consider, among other factors: changes in rules and regulations, including environmental; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; and the cost and availability of capital.

Forecasted capital expenditures for 2009 include the following:

$515 million for the Energy Gateway Transmission Expansion Project, which 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, one of the first major segments of the project.

$411 million for wind-powered generation development, primarily construction costs for the 99-MW High Plains and 28.5-MW McFadden Ridge I wind-powered generating facilities that are expected to be placed in service during 2009, a 111-MW wind-powered generating facility that is expected to be placed in service in 2010 and the remaining project costs related to the wind-powered generating facilities placed in service during the year ended December 31, 2008 and those placed in service during January 2009.

$370 million for emission control equipment at certain coal-fired generating facilities to meet anticipated air quality and visibility targets, reduction of sulfur dioxide, particulate matter, nitrogen oxide and mercury emissions.

Remaining amounts are for transmission, distribution and generation overhauls needed to serve existing and expected growing demand.

PacifiCorp is subject to federal, state, local and foreign laws and regulations with regard to air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp’s current and future operations. The future costs (beyond existing planned capital expenditures) of complying with applicable environmental laws, regulations and rules cannot yet be reasonably estimated but could be material to PacifiCorp. PacifiCorp is not aware of any proven, commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and natural gas-fired generating facilities, and PacifiCorp is uncertain when, or if, such technology will be commercially available. Refer to the “Environmental Regulation” section of Item 1 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2008, Note 10 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q and the “Environmental Regulation” section of this Form 10-Q for a detailed discussion of environmental matters affecting PacifiCorp.

Contractual Obligations

Subsequent to December 31, 2008, there were no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp’s Annual Report on Form 10-K for the year ended December 31, 2008, other than the January 2009 debt issuance previously discussed. Additionally, refer to the “Capital Expenditures” discussions included in “Liquidity and Capital Resources.”

Regulatory Matters

In addition to the updates contained herein regarding updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2008, refer to Notes 4 and 10 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, 2008 for an additional discussion of regulatory matters affecting PacifiCorp.

Utah

In July 2008, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million, or an average price increase of 11%, prior to any consideration for the UPSC’s order in the 2007 general rate case. In September 2008, PacifiCorp filed supplemental testimony that reflected then-current revenues and other adjustments based on the August 2008 order in the 2007 general rate case. The supplemental filing reduced PacifiCorp’s request to $115 million. In October 2008, the UPSC issued an order changing the test period from the twelve months ending June 2009 using end-of-period rate base to the forecast calendar year 2009 using average rate base. In December 2008, PacifiCorp updated its filing to reflect the change in the test period. The updated filing proposed an increase of $116 million, or an average price increase of 8%. In March 2009, a settlement agreement was filed with the UPSC resolving all remaining revenue requirement issues resulting in parties agreeing, among other settlement terms, on a $45 million, or 3%, rate increase effective May 8, 2009. In April 2009, the UPSC issued its final order approving the revenue requirement settlement agreement without modification.

In March 2009, Utah’s governor signed Senate Bill 75 that provides additional regulatory tools for the UPSC to use in the ratemaking process. The additional tools provided in the legislation allow for single item cost recovery of major capital investments outside of the general rate case process and allow for, but do not require, the use of a power cost mechanism. In March 2009, PacifiCorp filed for an energy cost adjustment mechanism (“ECAM”) with the UPSC. The filing recommends that the UPSC adopt the ECAM to recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. The UPSC has separated the application into two phases to first address whether the mechanism is in the public interest, and then if it is found to be in the public interest, determine the type of mechanism that should be implemented. The public interest phase is scheduled for completion in December 2009 and the design phase is scheduled for completion in March 2010, shortly after the conclusion of the 2009 general rate case.

In June 2009, PacifiCorp filed a general rate case for an increase of $67 million, or an average price increase of 5%. If approved, rates will be effective February 18, 2010. The forecasted test period is the twelve months ending June 30, 2010.

Oregon

In March 2009, PacifiCorp made the initial filing for the annual transition adjustment mechanism (“TAM”) with the OPUC for an annual increase of $21 million, or 2%, to recover the anticipated net power costs for the year beginning January 1, 2010. The expected effective date for the TAM is January 1, 2010. In April 2009, PacifiCorp filed a general rate case for an increase of $92 million, or 9%. If approved, rates will be effective no later than February 3, 2010.

Wyoming

In July 2008, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (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 were excluded from the filing and were addressed separately in PacifiCorp’s annual power cost adjustment mechanism (“PCAM”) application filed in February 2009. In October 2008, the general rate case request was reduced by $5 million, to $29 million, to reflect a change in the in-service date of the High Plains wind-powered generating plant. In March 2009, a settlement agreement was filed with the WPSC requesting an increase in Wyoming rates of $18 million annually, beginning May 24, 2009, for an average overall increase of 4%. The WPSC held and completed public hearings on the 2008 general rate case in March 2009. In May 2009, the final order was issued by the WPSC approving the stipulation agreement.

In February 2009, PacifiCorp filed its annual PCAM application with the WPSC. The PCAM application requests recovery of the difference between actual net power costs and the amount included in base rates, subject to certain limitations, for the period December 1, 2007 through November 30, 2008, and establishes for the first time, an adjustment for the difference between forecasted net power costs and the amount included in base rates for the period December 1, 2008 through November 30, 2009. In the 2009 PCAM docket, PacifiCorp is requesting a $2 million reduction to the current annual surcharge rate based on the results for the twelve-month period ending November 30, 2008, as well as a $16 million increase to the annual surcharge rate for the forecasted twelve-month period ending November 30, 2009, resulting in a net increase to the annual surcharge rate of $14 million, or 3%, on a combined basis. In March 2009, the WPSC approved PacifiCorp’s motion to implement an interim rate increase of $7 million effective April 1, 2009 consistent with the interim PCAM increase agreed to in the 2008 general rate case settlement agreement. In July 2009, a stipulation agreement was signed by the major participants in the case requesting that the interim rate increase implemented in April 2009 be made permanent. A public hearing to consider the stipulation agreement is scheduled for August 2009.

Idaho

In September 2008, PacifiCorp filed a general rate case with the Idaho Public Utilities Commission (the “IPUC”) for an annual increase of $6 million, or an average price increase of 4%. In February 2009, a settlement signed by PacifiCorp, the IPUC staff and intervening parties was filed with the IPUC resolving all issues in the 2008 general rate case. The agreement stipulates a $4 million increase, or 3% average rate increase, for non-contract retail customers in Idaho. As part of the stipulation, intervening parties acknowledged that PacifiCorp’s acquisition of the 520-MW natural gas-fired Chehalis plant was prudent and the investment should be included in PacifiCorp’s revenue requirement, and that PacifiCorp has demonstrated that its demand-side management programs are prudent. The parties also agreed on a base level of net power costs for any future ECAM calculations if a mechanism is adopted in Idaho. In February 2009, parties to the stipulation filed supporting testimony recommending the IPUC approve the stipulation as filed. Public hearings were held in March 2009 for the IPUC to hear evidence in support of the settlement and associated price increase. In April 2009, the IPUC issued an order approving the stipulation effective April 18, 2009.

In June 2009, an agreement was reached with parties to the ECAM docket allowing for the implementation of an ECAM to recover the difference between power costs recovered in rates and actual costs incurred, subject to the calculation methodology of the mechanism. The stipulation is subject to review and approval by the IPUC. An order from the IPUC on the stipulation is expected in August 2009.

California

In February 2009, PacifiCorp filed a post-test-year adjustment mechanism (“PTAM”) with the California Public Utilities Commission (the “CPUC”) for major capital additions amounting to a California rate adjustment of $1 million, or 2%. The filing included the addition of four major renewable resources: the 99-MW Seven Mile Hill, the 99-MW Glenrock, the 39-MW Glenrock III and the 99-MW Rolling Hills wind-powered generating facilities. The rates became effective March 19, 2009.

In February 2009, PacifiCorp filed an application to extend its PTAM attrition adjustment (an adjustment for inflation) through 2010 and to delay filing its next general rate case by one year. The application was approved by the CPUC in April 2009.

In July 2009, PacifiCorp made its annual filing under the energy cost adjustment clause requesting a rate reduction of $5 million, or 5%, due to a decrease in net power costs. If approved by the CPUC, the new rates will be effective January 1, 2010.

Federal Energy Regulatory Commission (“FERC”) Reliability Standards

The FERC has approved 88 reliability standards developed by the North American Electric Reliability Corporation (the “NERC”) and eight regional variations developed by the Western Electricity Coordinating Council (the “WECC”). Responsibility for compliance and enforcement of these standards has been given to the WECC. The 88 standards comprise over 600 requirements and sub-requirements with which PacifiCorp must comply. In January 2008, the FERC approved eight additional cyber security and critical infrastructure protection standards proposed by the NERC. The additional standards became mandatory and enforceable in April 2008. During 2007, the WECC audited PacifiCorp’s compliance with several of the approved reliability standards, and in November 2008, the FERC assumed control of certain aspects of the WECC’s audit. In May 2009, PacifiCorp received a notice of alleged violation and proposed sanctions related to the portions of the WECC’s 2007 audit that remained with the WECC. In July 2009, PacifiCorp reached a settlement in principle with the WECC. The results of settlement will not have a material impact on PacifiCorp’s consolidated financial results. Refer to Note 10 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional information regarding certain aspects of the WECC’s 2007 audit currently under the FERC’s authority.

Environmental Regulation

In addition to the updates contained herein, refer to Note 10 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, 2008 for additional information regarding certain environmental matters affecting PacifiCorp’s operations.

Climate Change

In April 2009, the United States Environmental Protection Agency (the “EPA”) issued a proposed finding, in response to the United States Supreme Court’s 2007 decision in the case of Massachusetts v. EPA, that under Section 202(a) of the Clean Air Act six greenhouse gases – carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride – threaten the public health and welfare of current and future generations. The finding does not include any proposed regulations regarding greenhouse gas emissions; however, such regulatory or legislative action could have a significant adverse impact on PacifiCorp’s current and future fossil-fueled generating facilities.

Credit Ratings

Debt and preferred securities of PacifiCorp are rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of PacifiCorp’s ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. PacifiCorp’s credit ratings are as follows:

	Fitch	Moody’s	Standard and Poor’s
Issuer/Corporate	BBB	Baa1	A-
Senior secured debt	A-	A2	A
Senior unsecured debt	B+	Baa1	A-
Preferred stock	BB	Baa3	BBB
Commercial paper	F2	P-2	A-2
Outlook	Stable	Stable	Stable

PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp’s unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.

In accordance with industry practice, certain agreements, including derivative contracts, contain provisions that require PacifiCorp to maintain specific credit ratings on its unsecured debt from one or more of the major credit rating agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels (“credit-risk-related contingent features”) or provide the right for counterparties to demand “adequate assurance” in the event of a material adverse change in PacifiCorp’s creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2009, PacifiCorp’s credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements, including derivative contracts, had been triggered as of June 30, 2009, PacifiCorp would have been required to post $239 million of additional collateral. PacifiCorp’s collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for a discussion of PacifiCorp’s collateral requirements specific to PacifiCorp’s derivative contracts.

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 several years 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 other postretirement benefits, 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, 2008. PacifiCorp’s critical accounting policies have not changed materially since December 31, 2008.

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, 2008. PacifiCorp’s exposure to market risk and its management of such risk has not changed materially since December 31, 2008. Refer to Note 6 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, 2009 and December 31, 2008.

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, 2009 that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

PART II

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, 2008. Refer to Note 10 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q for material developments since December 31, 2008.

Item 1A.

Risk Factors

Except as discussed below, 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, 2008.

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

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009 (“Waxman-Markey bill”), introduced by Representatives Henry Waxman and Edward Markey. In addition to a federal renewable portfolio standard, which would require utilities to obtain a portion of their energy from certain qualifying renewable sources, and energy efficiency measures, the bill requires a reduction in greenhouse gas emissions beginning in 2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a “cap and trade” program. Similar bills seeking to create “cap and trade” systems for greenhouse gas emissions have also been introduced in the United States Senate. If the Waxman-Markey bill or some other federal comprehensive climate change bill were to pass both Houses of Congress and be signed into law by the President, the impact on our financial performance could be material and would depend on a number of factors, including the required timing and level of greenhouse gas reductions, the price and availability of offsets and allowances used for compliance and our ability to receive revenue from customers for increased costs. The new law would likely result in increased operating costs and expenses, additional capital expenditures and asset retirements and may negatively impact demand for electricity. To the extent that we are not allowed by our regulators to recover or cannot otherwise recover the costs to comply with climate change requirements, these requirements could have a material adverse impact on our consolidated financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse impact on our consolidated financial results.

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 7, 2009	/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.