PacifiCorp 10Q 2010 Q2 Quarterly report

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, 2010

[ ] 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)	&nbs p;
	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 x No o

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 o No o

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 o	Accelerated filer o	Non - -accelerated filer x	Smaller reporting company o

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

Yes o No x

All of the shares of outstanding common stock are indirectly owned by MidAmerican Energy Holdings Company, 666 Grand Avenue, Des Moines, Iowa. As of July 31, 2010, 357,060,915 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I

Item 1.

Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FI RM

To the Board of Directors and Shareholders of

PacifiCorp

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("Pacif iCorp") as of June 30, 2010, and the related consolidated statements of operations and comprehensive income for the three-month and six-month periods ended June 30, 2010 and 2009, and of cash flows and changes in equity for the six-month periods ended June 30, 2010 and 2009. 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&nb sp;31, 2009, and the related consolidated statements of operations, cash flows, changes in equity and comprehensive income for the year then ended (not presented herein); and in our report dated March 1, 2010, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Portland, Oregon

August 6, 2010

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30, 2010		December 31, 2009
ASSETS

Current assets:
Cash and cash equivalents	$	110	$	117
Accounts receivable, net	539		619
Income taxes receivable from affiliates	—		249
Inventories:
Materials and supplies	184		192
Fuel	188		187
Derivative contracts	117		108
Deferred income taxes	48		39
Other current assets	46		61
Total current assets	1,232		1,572

Property, plant and equipment, net	15,865		15,537
Regulatory assets	1,655		1,539
Derivative contracts	22		43
Investments and other assets	373		275

Total assets	$	19,147	$	18,966

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	June 30, 2010				December 31, 2009
LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	424			$	553
Income taxes payable to affiliate	4				—
Accrued employee expenses	110				76
Accrued interest	110				111
Accrued property and other taxes	80				67
Derivative contracts	80				85
Current portion of long-term debt and capital lease obligations	16				16
Other current liabilities	87				105
Total current liabilities	911				1,013

Regulatory liabilities	835				838
Derivative contracts	453			&n bsp;	410
Long-term debt and capital lease obligations	6,399				6,400
Deferred income taxes	2,768				2,625
Other long-term liabilities	743				948
Total liabilities	12,109				12,234

Commitments and contingencies (Note 8)

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	4,479				4,379
Retained earnings	2,519				2,234
Accumulated other comprehensive loss, net	(1		)		(6		)
Total common equity	6,997				6,607
Total PacifiCorp shareholders' equity	7,038				6,648
Noncontrolling interest	—				84
Total equity	7,038			&n bsp;	6,732

Total liabilities and equity	$	19,147			$	18,966

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,
	2010			2009				2010				2009

Operating revenue	$	1,052		$	1,016			$	2,158			$	2,132

Operating costs and expenses:
Energy costs	348			360				763				796
Operations and maintenance	264			261				534				514
Depreciation and amortization	139			136				277				270
Taxes, other than income taxes	32			31				64				65
Total operating costs and expenses	783			788				1,638				1,645

Operating income	269			228				520				487

Other income (expense):
Interest expense	(97		)	(100		)		(194		)		(199		)
All owance for borrowed funds	12			8				24				15
Allowance for equity funds	20			14			42				27
Interest income	2			9				3				12
Other, net	(2		)	—				(2		)		(1		)
Total other income (expense)	(65		)	(69		)		(127		)		(146		)

Income before income tax expense	204			159				393				341
Income tax expense	54			49				107			105
Net income	150			110				286				236
Net income attributable to noncontrolling interest	—			—				—				3
Net income attributable to PacifiCorp	$	150		$	110			$	286			$	233

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,
	2010			2009

Cash flows from operating activities:
Net income	$	286		$	236
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	277			270
Provision for deferred income taxes	75			145
Changes in regulatory assets and liabilities	15			(1		)
Other, net	(29		)	(22		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	101			97
Derivative collateral, net	(60		)	66
Inventories	(23		)	(16		)
Income taxes - affiliates, net	253			(7		)
Accounts payable and other liabilities	(116		)	(25		)
Net cash flows from operating activities	779			743

Cash flows from investing activities:
Capital expenditures	(876		)	(1,148		)
Purchases of available-for-sale securities	—			(13		)
Proceeds from sales of available-for-sale securities	—			24
Other, net	(7		)	—
Net cash flows from investing activities	(883		)	(1,137		)

Cash flows from financing activities:
Net repayments of short-term debt	—			(85		)
Proceeds from long-term debt	—			992
Proceeds from equity contributions	100			—
Preferred stock dividends	(1		)	(1		)
Repayments and redemptions of long-term debt and capital lease obligations	(1		)	(3		)
Other, net	(1		)	(16		)
Net cash flows from financing activities	97			887

Net change in cash and cash equivalents	(7		)	493
Cash and cash equivalents at beginning of period	117			59
Cash and cash equivalents at end of period	$	110		$	552

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
												Other
							Additional					Comprehensive
	Preferred			Common			Paid-in		Retained			Income (Loss),			Noncontrolling
	Stock			Stock			Capital		Earnings			Net			Interest			Total

Balance, January 1, 2009	$	41		$	—		$	4,254	$	1,694		$	(2	)	$	80		$	6,067
Net income	—			—			—		2 33			—			3			236
Other comprehensive loss	—			—			—		—			(1		)	—			(1		)
Contributions	—			—			—		—			&md ash;			17			17
Distributions	—			—			—		—			—			(24		)	(24		)
Preferred stock dividends
declared	—			—			—		(1		)	—			—			(1		)
Other equity transactions	—			—			—		—			—			6			6
Balance, June 30, 2009	$	41		$	—		$	4,254	$	1,926		$	(3	)	$	82		$	6,300

Balance, January 1, 2010	$	41		$	—		$	4,379	$	2,234		$	(6	)	$	84		$	6,732
Deconsolidation of BCC	—			—			—		—			—			(84		)	(84		)
Net income	—			—			—		286			—			—			286
Other comprehensive
income	—			—			—		—			5			—			5
Contributions	—			—			100		—			—			—			100
Preferred stock dividends
declared	—			—		&nb sp;	—		(1		)	—			—			(1		)
Balance, June 30, 2010	$	41	;	$	—		$	4,479	$	2,519		$	(1	)	$	—		$	7,038

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods					Six-Month Periods
	Ended June 30,					Ended June 30,
	2010			2009		2010		2009

Net income	$	150		$	110	$	286	$	236
Other comprehensive income (loss), net of tax -
Fair value adjustment on cash flow hedges, net of
tax of $(1), $-, $3 and $-	(1		)	—		5		(1		)

Comprehensive income	149			110		291		235
Comprehensive income attributable to noncontrolling interest	—			—		—		3
Comprehensive income attributable to PacifiCorp	$	149		$	110	$	291	$	232

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 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 principall y 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, 2010 and for the three- and six-month periods ended June 30, 2010 and 2009. The results of operations for the three- and six-month periods ended June 30, 2010 are not necessarily indicative of the results to be expected for the full year.

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 Consolidated 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, 2009 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, 2010.

(2)

New Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2010-06 ("ASU No. 2010-06"), which amends FASB Accounting Standards Codification ("ASC") Topic 820, "Fair Value Measurements and Disclosures." ASU No. 2010-06 requires disclosure of (a) the amount of significant transfers into and out of Levels 1 and 2 of the fair value hierarchy and the reasons for those transfers and (b) gross presentation of purchases, sales, issuances and settlements in the Level 3 fair value measurement rollforward. This guidance clarifies that existing fair value measurement disclosures should be presented for each class of assets and liabilities. The existing disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements have also been clarified to ensure such disclosures are presented for the Levels 2 and 3 fair value measurements. PacifiCorp adopted this guidance as of January 1, 2010, with the exception of the disclosure requirement to present purchases, sales, issuances and settlements gross in the Level 3 fair value measurement rollforward, which is effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption did not have a material impact o n PacifiCorp's disclosures included within Notes to Consolidated Financial Statements.

In June 2009, the FASB issued authoritative guidance (which was codified into ASC Topic 810, "Consolidation," with the issuance of ASU No. 2009-17) that requires a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable interest entity. This analysis is based on whether the enterprise has (a) the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance and (b) 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, enterp rises are required 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, the guidance for consolidation or deconsolidation of a variable interest entity is amended and disclosure requirements about an enterprise's involvement with a variable interest entity are enhanced. PacifiCorp adopted this guidance as of January 1, 2010 on a prospective basis. As a result, PacifiCorp's coal mining joint venture, Bridger Coal Company ("BCC"), was deconsolidated and is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact BCC's economic performance are shared with the joint venture partner. The deconsolidation of BCC resulted in a decrease in assets, liabilities and noncontrolling interest equity as of January 1, 2010 of $192 million, $108 million and $84 million, respectively. These changes included the decon solidation of: (a) mine reclamation trust funds totaling $79 million; (b) property, plant and equipment, net totaling $249 million; and (c) asset retirement obligation liabilities totaling $79 million. Additionally, as a result of PacifiCorp's investment in BCC being accounted for under the equity method, an investment of $168 million was recorded on January 1, 2010.

(3)

Property, Plant and Equipment, Net

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


		As of
	Depreciable Life	June 30, 2010				December 31, 2009
					&n bsp;
Property, plant and equipment in service	5-80 years	$	20,731			$	20,330
Accumulated depreciation and amortization		(6,539		)		(6,623		)
Net property, plant and equipment in service		14,192				13,707
Construction work-in-progress		1,673				1,830
Total property, plant and equipment, net		$	15,865			$	15,537

(4)

Regulatory Matters

Rate Matters

Oregon Senate Bill 408

Oregon Senate Bill 408 ("SB 408") requires PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers to file an annual report each October with the Oregon Public Utility Commissio n ("OPUC") comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. If after its review, the OPUC determines the amount of income taxes collected differs from the amount of income taxes paid by more than $100,000, the OPUC must require the public utility to establish an automatic adjustment clause to account for the difference.

The OPUC's April 2008 order approving the recovery of $35 million, plus interest, related to PacifiCorp's 2006 tax report is being challenged by the Industrial Customers of Northwest Utilities, which has petitioned the Oregon Court of Appeals for judicial review of, among other things, the application of certain administrative rules considered in the April 2008 order. In July 2010, the Or egon Court of Appeals held oral arguments on the matter. A decision is not expected until 2011, which could impact PacifiCorp's 2006 through 2008 tax reports filed under SB 408. PacifiCorp believes the outcome of these proceedings will not have a material impact on its consolidated financial results. The $35 million, plus interest, was previously recorded in earnings.

In October 2009, PacifiCorp filed its 2008 tax report under SB 408. PacifiCorp's filing for the 2008 tax year indicated that PacifiCorp paid $38 million more in income taxes than was collected in rates from its retail customers. In January 2010, PacifiCorp entered into a stipulation with OPUC staff and the Citizens' Utility Board of Oregon, agreeing to a lower recovery totaling $2 million, including in terest. In April 2010, the OPUC issued an order adopting the stipulation in its entirety.

(5)

Fair Value Measurements

The carrying value 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 on 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 on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):


	Input Levels for Fair Value Measurements
	Level 1		Level 2				Level 3			Other⁽¹⁾			Total
As of June 30, 2010
Assets:
Investments in available-for-sale securities -						&nbs p;
Money market mutual funds⁽²⁾	$	105	$	—			$	—		$	—		$	105
Investments in trading securities -
Investment funds⁽³⁾	9		—				—			—			9
Commodity derivatives	—		347				4			(212		)	139
	$	114	$	347			$	4		$	(212	)	$	253
Liabilities:
Commodity derivatives	$	—	$	(420	)		$	(410	)	$	297		$	(533	)

As of December 31, 2009
Assets:
Investments in available-for-sale securities:
Money market mutual funds⁽²⁾	$	123	$	—			$	—		$	—		$	123
Debt securities	1		33				—			&md ash;			34
Equity securities	36		8				—			—			44
Commodity derivatives	—		285				6			(140		)	151
	$	160	$	326			$	6		$	(140	)	$	352
Liabilities:
Commodity derivatives	$	—	$	(274	)		$	(386	)	$	165		$	(495	)

(1)

Primarily represents netting under master netting arrangements and a net cash collatera l receivable of $85 million and $25 million as of June 30, 2010 and December 31, 2009, respectively.

(2)

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.

(3)

Investment funds are comprised of 40% United States government obligations, 29% corporate obligations, 20% Unite d States equity securities and 11% international equity securities.

PacifiCorp's investments in money market mutual funds and debt and equity securities are accounted for as either available-for-sale or as trading securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, 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.

When available, the fair value of derivative contracts is determined using unadjusted quoted prices for identical contracts. When quoted prices for identical contracts 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. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, 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. Option components are valued using Black-Scholes-type 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 balances of PacifiCorp's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


	Three-Month Periods						Si x-Month Periods
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009

Beginning balance	$	(409	)	$	(452	)	$	(380	)	$	(408	)
Changes in fair value recognized in regulatory assets	(21		)	46			(52		)	29
Purchases, sales, issuances and settlements	24			19			26			13
Net transfers (to) from Level 2	—			(2		)	—			(23		)
Ending balance	$	(406	)	$	(389	)	$	(406	)	$	(389	)

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


	As of June 30, 2010				As of December 31, 2009
	Carryi ng		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	6,357	$	7,312	$	6,357	$	6,843

(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 as it has an obligation to serve retail customer load in its regulated service territories. PacifiCorp's load and generation assets represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is pur chased and sold. 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, generating facility 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 its business. To mitigate a portion of its commodity risk, PacifiCorp uses commodity derivative contr acts, including forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates and by monitoring market changes in interest rates. PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks to mitigate PacifiCorp's exposure to interest rate risk. 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 changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies rel ated to derivatives. Refer to Note 5 for additional information on derivative contracts.

The following table, which excludes contracts that qualify for the normal purchases or normal sales exception 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 on the Consolidated Balance Sheets (in millions):


	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent				Total

As of June 30, 2010:
Not Designated as Hedging Contracts^(1) (2):
Commodity assets	$	215		$	30		$	41		$	55			$	341
Commodity liabilities	(56		)	(8		)	(206		)	(558	)		(828		)
Total	159			22			(165		)	(503		)		(487		)

Designated as Cash Flow Hedging Contracts ⁽¹⁾:
Commodity assets	9			—			1			—				10
Commodity liabilities	(2		)	—			—			—				(2		)
Total	7			—			1			—				8
														& nbsp;
Total derivatives	166			22			(164		)	(503		)		(479		)
Cash collateral (payable) receivable	(49		)	—			84			50				85
Total derivatives - net basis	$	117		$	22		$	(80	)	$	(453	)		$	(394	)

As of December 31, 2009:
Not Designated as Hedging Contracts^(1) (2):
Commodity assets	$	191		$	61		$	8		$	31			$	291
Commodity liabilities	(29		)	(17		)	(142		)	(472		)		(660		)
Total	162			44			(134		)	(441		)		(369		)

Designated as Cash Flow Hedging Contracts ⁽¹⁾:
Commodity assets	—			—			—			—				—
Commodity liabilities	—			—			—			—				—
Total	—			—			—			—				—

Total derivatives	162			44			(134		)	(441		)		(369		)
Cash collateral (payable) receivable	(54		)	(1		)	49			31				25
Total derivatives - net basis	$	108		$	43		$	(85	)	$	(410	)		$	(344	)

(1)

Derivative contracts within these categories subject to master netting arrangements are presented on a net basis on the Consolidated Balance Sheets.

(2)

PacifiCorp's commodity derivatives not designated as hedging contracts are generally included in regulated rates and as of June 30, 2010 and December 31, 2009, net regulatory assets of $482 million and $367 million, respectively, were recorded related to the net derivative liabilities of $487 million and $369 million, respectively.

Not Designated as Hedging Contracts

For PacifiCorp's commodity derivatives not designated as hedging contracts, the settled amount is generally included 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 inclusion in regulated 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 recogniz ed in net regulatory assets, as well as amounts reclassified to earnings (in millions):


	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2010			2009			2010		2009

B eginning balance	$	429		$	385		$	367	$	442
Chan ges in fair value recognized in net regulatory assets	41			(89		)	73		(162		)
Gains reclassified to earnings - operating revenue	20			59			41		138
Gains (losses) reclassified to earnings - energy costs	(8		)	(53		)	1		(116		)
Ending balance	$	482		$	302		$	482	$	302

For PacifiCorp's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as a net regulatory asset or liability, unrealized gains and losses are recognized on the Consolidated Statements of Operatio ns as operating revenue for sales contracts, energy costs and operations and maintenance for purchase contracts and electricity and natural gas swap contracts and interest expense for interest rate derivatives. The following table summarizes the pre-tax gains (losses) included on the Consolidated Statements of Operations associated with PacifiCorp's derivative contracts not designated as hedging contracts and not recorded as a net regulatory asset or liability (in millions):


	Three-Month Periods					Six-Month Periods
	Ended June 30,					Ended June 30,
	2010			2009		2010			2009
Commodity derivatives:
Operating revenue	$	1		$	2	$	1		$	5
Energy costs	(4		)	1		(5		)	1
Operations and maintenance	(2		)	2		(1		)	1
Total	$	(5	)	$	5	$	(5	)	$	7

Designated as Cash Flow Hedging Contracts

PacifiCorp uses derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices. The following table reconciles the beginning and ending balances of PacifiCorp's accumulated other comprehensive (income) loss (pre-tax) and summarizes pre-tax gains and losses on commodity de rivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income ("OCI"), as well as amounts reclassified to earnings (in millions):


	Three-Month Periods					Six-Month Periods
	Ended June 30,					Ended June 30,
	2010			2009		2010			2009
&n bsp;
Beginning balance	$	(10	)	$	1	$	—		$	—
(Gains) losses recognized in OCI	—			—		(10		)	1
Gains reclassified to earnings - revenue	2			—		2			—
Ending balance	$	(8	)	$	1	$	(8	)	$	1

Hedge ineffectiveness is recognized in income as operating revenue or energy costs depending upon the nature of the item being hedged. For the three- and six-month periods ended June 30, 2010 and 2009, hedge ineffectiveness was insignificant. As of June 30, 2010, PacifiCorp had cash flow hedges with expiration dates extending through December 31, 2010 and $8 million of pre-tax net unrealized gains forecasted to be reclassified from accumulated other comprehensive income into earnings as the contracts settle through December 31, 2010.

Derivative Contract Volumes

The following ta ble summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of June 30 (in millions):


	Unit of
	Measure	2010		2009
Commodity contracts:
Electricity sales	Megawatt hours	(18	)	(21	)
Natural gas purchases	Decatherms	180		215
Fuel purchases	Gallons	7		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 on 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 par ticipants 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 obtains 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.

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 spe cified 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, 2010, 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 $480 million and $353 million as of June 30, 2010 and December 31, 2009, respectively, for which PacifiCorp had posted collateral of $134 million and $80 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of June 30, 2010 and December 31, 2009, PacifiCorp would have been required to post $148 million and $159 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings or other factors.

(7)

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,
	2010			2 009			2010			2009
Pension:
Service cost⁽¹⁾	$	3		$	4		$	6		$	8
Interest cost	16			17			33			35
Expected return on plan assets	(19		)	(17		)	(37		)	(35		)
Net amortization	6			2			12			5
Net amortization of regulatory assets	(2		)	(2		)	(5		)	(4		)
Net periodic benefit cost	$	4		$	4		$	9		$	9


	Three-Month Periods						Six-Month Periods
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
Other postretirement:
Service cost⁽¹⁾	$	2		$	1		$	3		$	2
Interest cost	8			8			16			16
Expected return on plan assets	(8		)	(7		)	(15		)	(14		)
Net amortization	3			3			7			6
Net amortization of regulatory assets	—			&md ash;			—			1
Net periodic benefit cost	$	5		$	5		$	11		$	11

(1)

Service cost excludes $3 million and $2 million of contributions to the joint trust union plans during the three-month periods ended June 30, 2010 and 2009, respectively. Service cost excludes $6 million of contributions to the joint trust union plans during each of the six-month periods ended June 30, 2010 and 2009.

Employer contributions to the pension, other postretirement benefit and joint trust union plans are expected to be $117 million, $25 million and $12 million, respectively, during 2010. As of June 30, 2010, $115 million, $12 million and $6 million of contributions had been made to the pension, other postretirement benefit and joint trust union plans, respectively.

In March 2010, the President signed into law healthcare reform legislation that included provisions to eliminate the tax deductibility of other postretirement costs to the extent of retiree drug subsidies received from the federal government beginning after December 31, 2012. Accordingly, PacifiCorp increased deferred income tax liabilities and regulatory assets by $39 million. PacifiCorp filed applications with various state regulatory commissions for recovery of the $16 million of the adjustment that related to income tax benefits associated with amounts previously recognized as net periodic benefit costs. The remaining $23 million of the adjustment relates to income tax benefits that will no longer be realized in the future when the net periodic benefit cost is recognized and for which recovery of the resulting higher future income tax expense will be addressed through on-going ratemaking proceedings.

(8)

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 impact 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, penalties and other costs in substan tial 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 generating facility in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger generating facility'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 alleged thousands of violations of asserted six-minute compliance periods and sought an injunction ordering the Jim Bridger generating facility's compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs' costs of litigation. In February 2010, PacifiCorp, the Sierra Club and the Wyoming Outdoor Council reached an agreement in principle to settle all outstanding claims in the action. The settlement was memorialized in a consent decree and filed with the United States Environmental Protection Agency ("EPA") for review and also with the court for review and approval. In June 2010, the court approved the consent decree filed by the parties. The settlement did not have a material impact on PacifiCorp's consolidated financial results.

Environmental Laws and Regulations

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 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 has been engaged in periodic discussions with the EPA over several years regarding its historical projects and their compliance with NSR and PSD provisions. A NSR enforcement case against another utility has been decided by the United States Supreme Court, holding that an inc rease 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, 2010 and December 31, 2009 was $15 million and $18 million, re spectively, 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 that are legal obligations associated with the retirement of those assets are separately accounted for as asset retirement obligations.

&nbs p;

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 ("FERC") regulates 98% of the net capacity of this portfolio through 16 individual licenses, which typically have terms of 30 to 50 years. PacifiCorp expects to incur ongoing operating and maintenance expense and capital expenditures associated with the terms of its renewed hydroelectric licenses and settlement agreements, including natural resource enhancements. PacifiCorp's K lamath hydroelectric system is currently operating under annual licenses. Substantially all of PacifiCorp's remaining hydroelectric generating facilities are operating under licenses that expire between 2030 and 2058.

Klamath Hydroelectric System - Klamath River, Oregon and California

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 170-MW Klamath hydroelectric sy stem 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 or the system's four mainstem dams are removed. 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 m ainstem dams. Prior to the FERC issuing a final license, PacifiCorp is required to obtain water quality certifications from Oregon and California. PacifiCorp currently has water quality applications pending in Oregon and California; however, Oregon issued a letter in March 2010, holding the certification process in abeyance during the United States Secretary of the Interior's public interest determination.

In November 2008, PacifiCorp signed a non-binding agreement in principle ("AIP") that laid out a framework for the disposition of PacifiCorp's Klamath hydroelectric system relicensing process, including a path toward potential dam transfer and removal by an entity other than PacifiCorp no earlier than 2020. Subsequent to release of the AIP, negotiations betwee n the parties continued with an expanded group of stakeholders. A final draft of the Klamath Hydroelectric Settlement Agreement ("KHSA") was released in January 2010 for public review. The parties to the KHSA, which include PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the State of California, the State of Oregon and various other governmental and non-governmental settlement parties, signed the KHSA in February 2010. Federal legislation to endorse and enact provisions of the KHSA is planned to be introduced in the United States Congress in 2010.

Under the terms of the KHSA, the United States Departments of the Interior and Commerce will conduct scientific and engineering studies and consult with state, l ocal and tribal governments and other stakeholders, as appropriate, to determine by March 31, 2012 whether removal of the Klamath hydroelectric system's four mainstem dams will advance restoration of the salmonid fisheries of the Klamath Basin and is in the public interest. This determination will be made by the United States Secretary of the Interior. If it is determined that dam removal should proceed, dam removal is expected to commence no earlier than 2020.

Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. For dam removal to occur, federal legislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from all liabilities associated with dam removal acti vities. In addition, the KHSA limits PacifiCorp's contribution to dam removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. An additional $250 million for dam removal costs is expected to be raised through a California bond measure. If dam removal costs exceed $200 million and if the State of California is unable to raise the funds necessary for dam removal costs, sufficient funds would need to be obtained elsewhere in order for the KHSA and dam removal to proceed.

Actual removal of a facility would occur only after all permits for removal are obtained and the facility and associated land are transferred to a dam removal entity. Prior to potential removal of a facility, the facility will generally continue to operate as it does currently. However, PacifiCorp is responsible for implementing interim measures to provide additional resource protections, water quality improvements, habitat enhancement for aquatic species and increased funding for hatchery operations in the Klamath River Basin.

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 for the cost of removing the Klamath hydroelectric system's four mainstem dams. In March 2010, PacifiCorp filed with the OPUC to begin collecting the surcharge from Oregon customers, as of that date, subject to refund based on the OPUC's determination that the surcharges result in rates that are fair, just and reasonable. Also, in March 2010, PacifiCorp filed with the California Public Utilities Commission to collect a surcharge from PacifiCorp's California customers beginning January 1, 2011. The proceeds from the surcharges will be deposited in trust accounts to be established by each of the respective utility commissions.

As of June 30, 2010 and December 31, 2009, PacifiCorp had $71 million and $67 million, respectively, in costs related to the relicensing of the Klamath hydroelectric system included in construction work-in-progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets. Recovery of relicensing costs is anticipated through traditional rate proceedings. The all-party settlement proposed in the Oregon rate case recommended recovery of relicensing costs effective January 1, 2011.

FERC Issues

FERC Investigation

During 2007, the Western Electricity Coordinating Council ("WECC") audited PacifiCorp's compliance with several of the reliability standards developed by the North American Electric Reliability Corporation ("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 investi gation 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 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 ("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 m ade 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 (a) 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; (b) include sales to CERS in its analysis; and (c) 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.

(9)

Components of Accumulated Other Comprehensive Loss, Net

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


	As of
	June 30, 2010			December 31, 2009

Unrecognized retirement costs, net of tax of $(3) and $(3)	$	(6	)	$	(6	)
Fair value adjustment of cash flow hedges, net of tax of $3 and $-	5			—
Total accumulated other comprehensive loss attributable to PacifiCorp, net	$	(1	)	$	(6	)

(10)

Related-Party Transactions

PacifiCorp has an intercompany administrative services agreement with its indirect parent company, MEHC. Services provided by PacifiCorp and charged to affiliates relate primarily to administrative services, financial statement preparation and direct-assigned employees. Services provided by affiliates and charged to PacifiCorp relate p rimarily to the administrative services provided under the intercompany administrative services agreement among MEHC and its affiliates. These expenses totaled $2 million during each of the three-month periods ended June 30, 2010 and 2009, and $4 million during each of the six-month periods ended June 30, 2010 and 2009.

PacifiCorp engages in various transactions with several of its affiliated companies in the ordinary course of business. Services provided by af filiates in the ordinary course of business and charged to PacifiCorp relate primarily to the transportation of natural gas and relocation services. These expenses totaled $1 million and $- million during the three-month periods ended June 30, 2010 and 2009, respectively, and $2 million and $1 million during the six-month periods ended June 30, 2010 and 2009, respectively.

PacifiCorp has long-term transportation contracts with BNSF Railway Company, which becam e an indirect wholly owned subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company, in February 2010. Transportation costs under these contracts were $7 million and $6 million during the three-month periods ended June 30, 2010 and 2009, respectively, and $15 million and $14 million during the six-month periods ended June 30, 2010 and 2009, respectively.

PacifiCorp participates in a captive insurance program provided by MEHC Insurance Services Ltd. ("MISL"), a wholly owned subsidiary of MEHC. MISL covers all or significant portions of the property damage and liability insurance deductibles in many of PacifiCorp's current policies, as well as overhead distribution and transmission line property damage. PacifiCorp has no equ ity interest in MISL and has no obligation to contribute equity or loan funds to MISL. Premium amounts were established in March 2006 based on a combination of actuarial assessments and market rates to cover loss claims, administrative expenses and appropriate reserves, but as a result of regulatory commitments are capped through December 31, 2010. Certain costs associated with the program are prepaid and amortized over the policy coverage period expiring March 20, 2011. Premium expenses were $2 million during each of the three-month periods ended June 30, 2010 and 2009, and $4 million during each of the six-month periods ended June 30, 2010 and 2009. Prepayments to MISL were $5 million and $2 million as of June 30, 2010 and December 31, 2009, respectively. Receivables for claims were $16 million and $10 million as of June 30, 2010 and December 31, 2009, respectively.

PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. As of June 30, 2010, income taxes payable to MEHC were $4 million and as of December 31, 2009, income taxes receivable from MEHC were $249 million.

PacifiCorp transacts with its equity investees, BCC and Trapper Mining, Inc. Refer to Note 2 for additional information regarding BCC. Service s provided by PacifiCorp and charged to BCC relate primarily to management services, income taxes and labor. Receivables for these services were $4 million as of June 30, 2010. Services provided by equity investees and charged to PacifiCorp primarily relate to coal purchases; for BCC these purchases are under a long-term contract that ends on December 31, 2024. These payables were $9 million as of June 30, 2010. During the three- and six-month periods ended June 30, 2010, coal purchases totaled $27 million and $68 million, respectively.

Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain signi ficant factors that have affected the consolidated 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 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 Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. 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 PacifiCo rp'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 federal, state and local governmental, legislative or regulatory requirements affecting PacifiCorp or the electric utility industry;

•

changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce plant output, accelerate plant retirements 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 Paci fiCorp's ability to obtain long-term contracts with customers;

•

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, availability and demand 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 bu siness strategy or development plans;

•

availability, terms and deployment of capital, including 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 contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of derivative contracts;

•

increases in employee healthcare costs;

•

the im pact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity 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 af fect future generating facilities and infrastructure additions;

•

the impact of new accounting guidance or changes in current accounting estimates and assumptions on consolidated financial results;

•

other risks or unforeseen events, including litigation, wars, the effects of terrorism, embargoes and other catastrophic events; and

• &nbs p;

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 ("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 forw ard-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 Second Quarter and First Six Months of 2010 and 2009

Overview

Net income attributable to PacifiCorp for the second quarter was $150 million, an increase of $40 million, or 36%, and for the first six months of 2010 was $286 million, an increase of $53 million, or 23%, as compared to 2009. Net income attributable to PacifiCorp increased due to higher prices approved by regulators, higher revenue from sales of renewable energy credits, higher industrial customer usage in the eastern side of PacifiCorp's service territory during the second quarter, lower purchased electricity and higher allowanc es for funds used during construction, partially offset by lower wholesale sales, despite higher volumes during the second quarter, as well as benefits associated with Oregon Senate Bill 408 ("SB 408") in the prior year.

As discussed in Note 2 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q, PacifiCorp adopted authoritative guidance as of January 1, 2010 that requires equity method accounting treatment of its coal mining joint venture, Bridger Coal Company ("BCC").

Operating rev enue and energy costs are the key drivers of PacifiCorp's results of operations as they encompass retail and wholesale electricity sales and the direct costs associated with providing electricity to our customers. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore useful.

A comparison of PacifiCorp's key operating results for the second quarter were as follows:


	Second Quarter					Favorable/(Unfavorable)
	2010		2009			Change			% Change

Gross margin (in millions):
Operating revenue	$	1,052	$	1,016		$	36		4	%
Energy costs	348		360			12			3
Gross margin	$	704	$	656		$	48		7

Volumes of electricity sold (in gigawatt hours ("GWh")):
Residential	3,329		3,238			91			3	%
Commercial	3,801		3,811			(10		)	(0	)
Industrial	5,149		4,848			301			6
Other	141		149		&n bsp;	(8		)	(5	)
Total retail electricity sales	12,420		12,046			374			3
Wholesale electricity sales	2,973		2,621			352			13
Total electricity sales	15,393		14,667			726			5

Retail electricity sales:
Average retail customers (in thousands)	1,731		1,716			15			1	%
Average revenue per megawatt hour ("MWh")	$	69.93	$	68.57		$	1.36		2	%

Wholesale electricity sales:
Average revenue per MWh	$	41.30	$	52.39		$	(11.09	)	(21	)%

Volumes of electricity generated (in GW h):
Coal-fired generation	10,065		9,441			624			7	%
Natural gas-fired generation	1,731		1,523			208			14
Hydroelectric generation	1,093		1,267			(174		)	(14	)
Other	797		568			229			40
Total PacifiCorp generated volumes	13,686		12,799			887			7

Volumes of electricity purchased (in GWh):
Wholesale electricity purchases	2,598		2,838			240			8	%

Cost of wholesale electricity purchased:
Average cost per MWh	$	31.68	$	35.43		$	3.75		11	%

Gross margin increased $48 million, or 7%, for 2010 compared to 2009 primarily due to:

•

$24& nbsp;million of higher revenue from sales of renewable energy credits;

•

$23 million from higher retail prices approved by regulators, including $12 million of increases in DSM revenues primarily associated with Utah DSM programs, partially offset by a $10 million decrease in revenue associated with SB 408;

•

$20 million of higher revenue from higher average customer usage driven by industrial customers on the eastern side of PacifiCorp's service territory;

•

$10 million of higher deferrals of incurred power costs and lower amortization of previous deferrals in accordance with established adjustment mechanisms; and

•

$3 million resulting from net wholesale electricity activities due to $10 million of lower purchase prices and $8 million of lower volumes of wholesale electricity purchases and $21 million of higher volumes of wholesale electricity sales, partially offset by $36 million of lower prices on wholesale electricity sales.

These increases in gross margin were partially offset by:

•

$14 million of lower revenue related to the deconsolidation of BCC;

•

$7 million of increased fuel costs due to higher volumes of coal consumed, partially offset by decreases in natural gas prices;

•

$5 million of changes in the fair value of energy sales and purchase contracts accounted for as derivatives; and

•

$2 million resulting from higher transmission expense due to higher contract rates.

Operations and maintenance increased $3 million, or 1%, for 2010 compared to 2009 primarily due to:

•

$12 million of higher DSM expenses primarily attributable to recognition of costs associated with Utah DSM programs; partially offset by,

•

$10 million of lower costs related to the deconsolidation of BCC.

Depreciation and amortization increased $3 million, or 2%, for 2010 compared to 2009 primarily due to higher plant-in-service.

Allowances for borrowed and equity funds increased $10 million, or 45%, for 2010 compared to 2009 primarily due to higher qualified construction work-in-progress balances.

Interest income decreased $7 million for 2010 compared to 2009 substantially due to interest recognized in the prior year associated with SB 408.

Income tax expense increased $5 million to $54 million for 2010 compared to 2009, primarily due to increased pre-tax book income, partially offset by higher production tax credits associated with PacifiCorp's wind-powered generating facilities and regulatory treatment of certain deferred income taxes. The effective tax rate was 27% for the three-month period ended June 30, 2010 compared to 31% for 2009.

A comparison of PacifiCorp's key operating results for the first six months were as follows:


	First Six Months				Favorable/(Unfavorable)
	2010		2009		Change			% Change

Gross margin (in millions):
Operating revenue	$	2,158	$	2,132	$	26		1	%
Energy costs	763		796		33			4
Gross margin	$	1,395	$	1,336	$	59		4

Volumes of electricity sold (in GWh):
Residential	7,652		7,664		(12		)	(0	)%
Commercial	7,575		7,726		(151		)	(2	)
Industrial	9,948		9,629		319			3
Other	278		294		(16		)	(5	)
Total retail electricity sales	25,453		25,313		140			1
Wholesale electricity sales	5,974		6,121		(147		)	(2	)
Total electricity sales	31,427		31,434		(7		)	(0	)

Retail electricity sales:
Average retail customers (in thousands)	1,730		1,716		14			1	%
Average revenue per MWh	$	69.10	$	66.46	$	2.64		4	%

Wholesale electricity sales:
Average revenue per MWh	$	47.13	$	55.74	$	(8.61	)	(15	)%

Volumes of electricity generated (in GWh):
Coal-fired generation	20,977		20,601		376			2	%
Natural gas-fired generation	3,918		4,026		(108		)	(3	)
Hydroelectric generation	2,147		2,305		(158		)	(7	)
Other	1,450		1,182		268			23
Total PacifiCorp generated volumes	28,492		28,114		378			1

Volumes of electricity purchased (in GWh):
Wholesale electricity purchases	4,981		5,498		517			9	%

Cost of wholesale electricity purchased:
Average cost per MWh	$	39.80	$	42.80	$	3.00		7	%

Gross margin increased $59 million, or 4%, for 2010 compared to 2009 primarily due to:

•

$69 million from higher retail prices approved by regulators, including $23 million of increases in DSM revenues primarily associated with Utah DSM programs, partially offset by a $10 million decrease in revenue associated with SB 408;

•

$46 million of higher revenue from sales of renewable energy credits;

•

$20 million of higher deferrals of incurred power costs and lower amortization of previous deferrals in accordance with established adjustment mechanisms; and

• &nbs p;

$11 million due to the elimination of certain regulatory liabilities resulting from the settlement of the Utah DSM tariff filing in the first quarter.

These increases in gross margin were partially offset by:

•

$32 million of lower revenue related to the deconsolidation of BCC;

•

$23 million resulting from net wholesale electricity activities due to $52 mill ion of lower average prices on wholesale electricity sales and $8 million of lower wholesale sales volumes, partially offset by $22 million of lower volumes and $15 million of lower average prices on wholesale electricity purchases;

•

$11 million of changes in the fair value of energy sales and purchase contracts accounted for as derivatives;

•

$10 million resulting from higher transmission expense due to higher contract rates;

•

$3 million due to lower average commercial and industrial customer usage in the western side of PacifiCorp's service territory, partially offset by higher average industrial customer usage in the eastern side of PacifiCorp's service territory; and

•

$2 million of increased fuel costs due to higher volumes and prices of coal consumed, partially offset by decreases in natural gas prices and lower volumes of natural gas consumed.

Operations and maintenance increased $20 million, or 4%, for 2010 compared to 2009 primarily due to:

&bul l;

$23 million of higher DSM expense primarily attributable to recognition of costs associated with Utah DSM programs;

•

$11 million due to the settlement of a portion of the Utah DSM regulatory asset related to the Utah DSM tariff filing in the first quarter;

•

$7 million of higher costs associated with jointly owned generating facilities primarily due to increased overhauls; partially offset by,

•

$18 million of lower costs related to the deconsolidation of BCC.

Depreciation and amortization increased $7 million, or 3%, for 2010 compared to 2009 primarily due to higher plant-in-service.

Allowances for borrowed and equity funds increased $24 million, or 57%, for 2010 compared to 2009 primarily due to higher qualified construction work-in-progress balances.

Interest income decreased $9 million for 2010 compared to 2009 substantially due to interest recognized in the prior year associated with SB 408.

Income tax expense increased $2 million to $107 million for 2010 compared to 2009 primarily due to increased pre-tax book income, partially offset by higher production tax credits associated with PacifiCorp's wind-powered generating facilities and regulatory treatment of certain deferred income taxes. The effective tax rate was 27% for the six-month period ended June 30, 2010 compared to 31% for 2009.

Liquidity and Capital Resources

As of June 30, 2010, PacifiCorp's total net liquidity available was $1.201 billion. The components of total net liquidity available are as follows (in millions):


Cash and cash equivalents	$	110

Available revolving credit facilities	$	1,395
Less:
Short-term borrowings and issuances of commercial paper	—
Tax-exempt bond support and letters of credit	(304		)
Net revolving credit facilities available	$	1,091

Total net liquidity available	$	1,201

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.

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2010 and 2009 were $779 million and $743 million, respectively. The $36 million increase was primarily due to significantly higher income tax receipts related to the repairs deduction and bonus depreciation in the prior year and higher prices approved by regulators, partially offset by changes in collateral posted for derivative contracts, the increase and acceleration of contributions to PacifiCorp's pension plan in the current year and lower net wholesale electricity activities.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2010 and 2009 were $(883) million and $(1.137) billion, respectively. Capital expenditures decreased $ 272 million. Capital expenditures consisted mainly of the following during the six-month periods ended June 30:

2010:

•

Transmission system investments totaling $239 million, including construction costs for the first major segment of the Energy Gateway Transmission Expansion Program, a 135-mile, double-circuit, 345-kilovolt transmission line being built between the Populus substation in southern Idaho and the Terminal substation near Salt Lake City, Utah, which is expected to be completed during 2010.

•

Emissions control equipment totaling $182 million, including costs for the Dave Johnston generating facility Unit 3, which includes a sulfur dioxide scrubber that was placed into service in May 2010, as well as low nitrogen oxide burners, and costs for installation or upgrade of sulfur dioxide scrubbers on various other generating facilities.

•

The development and construction of wind-powered generating facilities totaling $105 million, substantially for the 111-megawatt ("MW") Dunlap Ranch I wind project under construction near Medicine Bow, Wyoming, which is expected to be placed in service in the second half of 2010.

•

Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $350 million.

2009:

•

The development and construction of wind-powered generating facilities totaling $308 million.

•

Transmission system investments totaling $269 million, including construction costs for the Populus-to-Terminal segment of the Energy Gateway Transmission Expansion Program.

•

Emissions control equipment totaling $143 million.

•

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

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2010 were $97 million. Sources of cash consisted of $100 million of capital contributions. Uses of cash totaled $3 million and consisted primarily of preferred stock dividends paid, as we ll as the purchase at a discount to the stated value and cancellation of 7,302 shares of preferred stock.

Net cash flows from financing activities for the six-month period ended June 30, 2009 were $887 million. Sources of cash consisted of $992 million 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.

Short-term Debt and Revolving Credit Facilities

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. PacifiCorp had no outstanding short-term debt as of June 30, 2010 and December 31, 2009.

Long-term Debt

PacifiCorp has regulatory authority from the Oregon Public Utility Commission ("OPUC") and the Idaho Public Utilities Commission ("IPUC") to issue an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission ("WUTC") prior to any future issuance.

In Jun e 2010, PacifiCorp completed a re-offering of a $45 million series of tax-exempt bond obligations. The interest rate for this obligation was previously fixed for a term which, upon scheduled expiration, was converted to a variable-rate with credit enhancement and liquidity support provided by a $46 million letter of credit issued under one of PacifiCorp's unsecured revolving credit facilities.

As of June 30, 2010, PacifiCorp had $562 million of letters of credit available to provide credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $549 million plus interest. These committed bank arrangements were fully available as of June 30, 2010 and expire periodically through May 2012.

Future Uses of Cash

PacifiCorp has 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 depends on a variety of factors, including PacifiCorp's credit rating, investors' judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general.

Capital Expenditures

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these 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. Expenditures for compliance-related items, such as pollution-control technologies, r eplacement generation, hydroelectric relicensing and decommissioning, and associated operating costs are generally incorporated into PacifiCorp's retail rates.

Forecasted capital expenditures, which exclude non-cash equity allowance for funds used during construction, are approximately $1.7 billion for 2010 and include the following:

•

$461 million for transmission system investments, including $218 million for the Energy Gateway Transmission Expansion Program, which includes costs for completion of the first major segment of the program, the Populus to Terminal transmission line.

•

$360 million for environmental projects to install and upgrade emissions control equipment at certain coal-fired generating facilities to meet anticipated air quality and visibility targets through reductions of sulfur dioxide, nitrogen oxide and particulate matter emissions.

•

$158 million for construction and development of wind-powered generating facilities, primarily constr uction costs for the 111-MW Dunlap Ranch I wind-powered generating facility that is expected to be placed in service in the second half of 2010 and the remaining project costs related to the wind-powered generating facilities placed in service during the year ended December 31, 2009.

•

Remaining amounts are for ongoing investments in distribution, generation, mining and other infrastructure needed to serve existing and expected demand.

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 electri c 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, state energy policies 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, and for four of its six state jurisdictions, receives a formal notification as to whether the IRP meets the commission's IRP standards and guidelines. In May 2009, PacifiCorp filed its 2008 IRP with each of its state commissions. During 2009, PacifiCorp received orders from the WUTC and the IPUC acknowledging that the 2008 IRP met their applicable standards and guidelines. During 2010, the OPUC and the Utah Public Service Commission ("UPSC") issued orders acknowledging the 2008 IRP. Preparation of PacifiCorp's next IRP is underway, and it is expected to be filed with t he state commissions in March 2011.

Requests for Proposals

PacifiCorp has issued a series of individual Requests for Proposals ("RFPs"), each of which focuses on a specific category of electric generation 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 wit h the UPSC, the OPUC and the WUTC prior to issuance to the market. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.

In August 2009, under PacifiCorp's 2008R-1 renewable resources RFP (approved by the OPUC in September 2008), PacifiCorp executed a power purchase agreement to purchase the entire output of the proposed 200-MW Top of the World wind-powered generating facility located in Wyoming. The generation of the energy and associated renewable energy credits under this agreement are expected to commence by the fourth quarter of 2010 and continue for a period of 20 years. PacifiCorp's 2009R renewable resources RFP (approved by the OPUC with modification in July 2009) seeks additional cost-effective renewable generation projects with no single resource greater than 300 MW, combined total resources of no more than 400 MW and on-line dates no later than December 31, 2012. As a result of the 2009R renewable resources RFP, PacifiCorp's 111-MW Dunlap Ranch I wind-powered generating facility located in Wyoming was selected and construction has commenced. Negotiations were also initiated with the remaining final shortlist bidder under the 2009R renewable resources RFP.

In October 2009, PacifiCorp filed a request for approval with the UPSC to re-issue the All Source RFP, which was previously suspended in April 2009. In October 2009 and November 2009, respectively, the UPSC and the OPUC approved resumption of the All Source RFP. The All Source RFP seeks up to 1,500 MW on a system wide basis from projects with in-service dates from 2014 through 2016. In December 2009, the All Source RFP was issued to the market. Proposals have been received under the All Source RFP and evaluations are currently underway.

Contractual Obligations

There have been 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, 2009. Additionally, refer to the "Capital Expenditures" discussion included in "Liquidity and Capital Resources."

Regulatory Matters

In addition to the discussion contained herein regarding updates to regulatory matters based upon changes that occurred subsequent to those disclosed in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2009, refer to Notes 4 and 8 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for additional regulatory matter updates.

Utah

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, to determine the type of mechanism that should be implemented. Hearings on the public interest phase were completed in January 2010. In February 2010, the UPSC issued an order to proceed to the second phase to address design considerations in the development of an ECAM. Additionally, in February 2010, PacifiCorp filed an applicat ion with the UPSC seeking approval to defer the difference between the net power costs allowed by the UPSC's final order in PacifiCorp's 2009 general rate case and the actual net power costs incurred. Also in February 2010, the Utah Association of Energy Users filed a motion with the UPSC seeking approval to defer incremental renewable energy credit revenue in excess of the renewable energy credit value utilized in Utah rates established by the 2009 general rate case. In July 2010, the UPSC issued an order approving a stipulation to establish deferrals for both net power costs and renewable energy credit revenues in excess of the level currently included in rates. Whether all or any of the deferred costs and revenues will be passed through to customers will be determined in the final order in the case.

In February 2010, PacifiCorp filed an application with the UPSC requesting an increase of $34 million associated with two major construction projects that were completed and in service by June 2010. The application requests recovery in conjunction with a future rate change. In March 2010, PacifiCorp updated its application to reflect the cost of capital decisions from the February 2010 general rate case order, reducing the amount requested for recovery to $33 million. In May 2010, a multi-party stipulation was filed with the UPSC agreeing to recovery of $31 million. In June 2010, the stipulation was approved by the UPSC.

In August 2010, PacifiCorp filed an application with the UPS C requesting an increase of $39 million associated with two major construction projects expected to be complete and in service by December 2010. The application requests a 5% increase in rates effective January 2011 encompassing both the $39 million requested increase and the $31 million increase approved by the UPSC in June 2010. The application also requests to begin collecting effective January 2011 a one-time $16 million surcharge for the portion of the $31 million increase related to the period from July 2010 to December 2010.

Oregon

In February 2010, PacifiCorp made the initial filing for the annual transition adjustment mechanism ("TAM") with the OPUC for an annual increase of $69 million to recover the anticipated net power costs forecasted for calendar year 2011. In July 2010, an all-party stipulation was filed with the OPUC agreeing to an increase of $58 million, or an average price increase of 6%. The rates, which are subject to updates for anticipated net power costs through November 2010, will be effective January 1, 2011.

In March 2010, PacifiCorp filed a general rate case with the OPUC requesting an increase of $131 million, or an average price increase of 13%. In July 2010, a multi-party stipulation was filed with the OPUC agreeing to an annual increase of $85 million, or an average price increase of 8%. If approved by the OPUC, the rates will be effective January 1, 2011.

Wyoming

In October 2009, PacifiCorp filed a general rate case with the Wyoming Public Service Commission ("WPSC") requesting a rate increase of $71 million with an effective date of August 1, 2010. Power costs were included in the general rate case, reflecting increased coal costs and the expiration of low cost long-term power purchase contracts. The application was based on a test period ending December 31, 2010. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to an overall rate increase of $36 million, or an average price increase of 7%, to be implemented in two phases. In May 2010, the WPSC approved the settlement agreement. The first phase of the rate increase, consisting of a $26 million increase, became effective July 1, 2010 and the second phase, consisting of the remaining $10 million increase, will be effective February 1, 2011.

In January 2010, PacifiCorp filed its annual power cost adjustment mechanism ("PCAM") application with the WPSC requesting recovery of $8 million in deferred net power costs. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to reduce the requested recovery to $4 million. In May 2010, the WPSC approved the settlement agreement allowing for the change in the PCAM surcharge rate effective April 1, 2010.

In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The PCAM will sunset with the final deferral of power costs in November 2010 and collection through March 2012.

Washington

In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price increase of 21%. If approved by the WUTC, the rates will be effective in April 2011.

Idaho

In February 2010, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $2 million in deferred net power costs. In March 2010, the IPUC issued an order approving PacifiCorp's ECAM application effective April 1, 2010.

In May 2010, PacifiCorp filed a general rate case with the IPUC requesting an ann ual increase of $28 million, or an average price increase of 14%. If approved by the IPUC, the rates will be effective by January 1, 2011.

In June 2010, the IPUC approved an increase to PacifiCorp's energy efficiency rider to fund DSM programs of $1 million, or an average price increase of 1%, with an effective date of July 1, 2010. As a result of the 1% increase, the energy efficiency rider in Idaho is now 5%.

California

In November 2009, PacifiCorp filed a general rate case with the California Public Utilities Commission ("CPUC") requesting an annual increase of $8 million, or an average price increase of 10%. In June 2010, PacifiCorp filed with the CPUC an all-party joint motion for commission approval and adoption of the settlement agreement. The agreement reflects an annual increase of $4 million, or an average price increase of 5%. If approved by the CPUC, the rates will be effective January 1, 2011.

In March 2010, PacifiCorp filed an advice filing with the CPUC that would allow PacifiCorp to complete the transition of certain Klamath irrigation customers from contract rates to full tariff rates as agreed to as part of the 2005 California general rate case. The change was approved by the CPUC resulting in an annual rate increase of $1 million effective April 17, 2010.

In April 2010, PacifiCorp filed a post-test-year adjustment mechanism for major capital additions ("PTAM") with the CPUC amounting to a rate increase of $1 million, or an average price increase of 1%. The filing requests recovery of costs associated with the Ben Lomond to Terminal transmission line. In May 2010, the CPUC approved the PTAM with an effective date of May 29, 2010.

In May 2010, PacifiCorp filed an application under a storm damage deferral mechanism to recover costs related to damage caused by the severe winter storms in Siskiyou County, California in January 2010. The application requests recovery of $1 m illion to be collected over a one-year period beginning January 1, 2011.

In August 2010, PacifiCorp filed an application with the CPUC to increase rates pursuant to the energy cost adjustment clause. In the application, PacifiCorp requested a rate increase of $9 million, or an average price increase of 11%. If approved by the CPUC, the rates will be effective January 1, 2011.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, climate change, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the United States Environmental Protection Agency ("EPA") and various other state and local agencies. All such laws and regulations are subject to a range of interpretat ion, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. PacifiCorp believes it is in material compliance with all applicable laws and regulations. Refer to "Future Uses of Cash" for discussion of PacifiCorp's forecasted environmental-related capital expenditures and Note 8 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information regarding certain environmental laws and regulation affecting PacifiCorp. The discussion below contains material developments since those disclosed in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2009.

National Ambient Air Quality Standards

In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide ("SO₂"). Under the new rule, the existing 24-hour and annual standards for SO₂, which were 140 parts per billion measured over 24 hours and 30 parts per billion measured over an entire year, were replaced with a new one-hour standard of 75 parts per billion. The new rule will utilize a 3-year average to determine attainment. The rule will utilize source modeling, in addition to the installation of ambient monitors where SO₂ emissions impact populated areas, with new monitors required to be in-service no later than January 2013. Attainment designations are due by June 2012, with state implementation plans due by 2014 and final attainment demonstrations by August 2017.

Under the new standard, the number of counties designated as nonattainment areas is likely to increase. Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of facilities that are sources of emissions could become more difficult in nonattainment areas. Until additional monitoring and modeling is conducted, the impacts on PacifiCorp cannot be determined.

Coal Combustion Byproduct Disposal

In December 2008, an ash impoundment dike at the Tennessee Valley Authority's Kingston power plant collapsed after heavy rain, releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surrounding area. In light of this incident, federal and state officials have called for greater regulation of coal combustion sto rage and disposal. In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the Resource Conservation and Recovery Act ("RCRA"). Under the first option, coal combustion byproducts would be regulated as special waste under RCRA Subtitle C and the EPA would establish requirements for coal combustion byproducts from the point of generation to disposition, including the closure of disposal units. Alternatively, the EPA is considering regulation under RCRA Subtitle D under which it would establish minimum nationwide standards for the disposal of coal combustion byproducts. Under both options, surface impoundments utilized for coal combustion byproducts would have to be cleaned and closed unless they could meet more stringent regulatory requirements; in addition, more stringent requirements would be implemented for new ash landfills and expansions of existing ash landfills. PacifiCorp operates 16 s urface impoundments and six landfills that contain coal combustion byproducts. These ash impoundments and landfills may be impacted by the newly proposed regulation, particularly if the materials are regulated as hazardous or special waste under RCRA Subtitle C, and could pose significant additional costs associated with ash management and disposal activities at PacifiCorp's coal-fired generating facilities. Public comments on the proposed rule are due in September 2010. The impact of the proposed regulations on coal combustion byproducts cannot be determined at this time.

Collateral and Contingent Features

PacifiCorp's senior secured and senior unsecured debt credit ratings are as follows:


	Fitch	Moody's	Standard & Poor's

Senior secured debt	A-	A2	A
Senior unsecured debt	BBB+	Baa1	A-
Outlook	Stable	Stable	Stable

Debt and preferred securities of PacifiCorp are rated by the 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 iss ued 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 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 three recognized credit ratings 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, 2010, 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, 2010, PacifiCorp would have been required to post $253 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 in Item 1 of this Form 10-Q for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.

In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Reform Act"). The Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms and providing new enforcement powers to regulators. Virtually all major areas of the Reform Act, including collateral requirements on derivative contracts, will be the s ubject of regulatory interpretation and implementation rules requiring rulemaking proceedings that may take several years to complete.

PacifiCorp is a party to derivative contracts, including over-the-counter derivative contracts. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts. The Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing, exchange trading, capital and margin requirements for "swap dealers" and "major swap participants." Although PacifiCorp generally does not enter into over-the-counte r derivative contracts for purposes unrelated to hedging of commercial risk and does not believe it will be considered a swap dealer or major swap participant, the outcome of the rulemaking proceedings cannot be predicted and, therefore, the impact of the Reform Act on PacifiCorp's consolidated financial results cannot be determined at this time.

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected on the Consolidated Financial Statements will likely change 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 estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2009. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2009.

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, 2009. PacifiCorp's exposure to market risk and its management of such risk has not changed materially since December 31, 2009. Refer to Note 6 of Notes to Consolidated Financial Stateme nts in Item 1 of this Form 10-Q for disclosure of PacifiCorp's derivative positions as of June 30, 2010.

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 repo rts 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, 2010 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, 2009. Refer to Note 8 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for material deve lopments since those disclosed in Item 3 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2009.

In December 2000, Wah Chang, a large industrial customer of PacifiCorp that operates a reactive and refractory metals manufacturing facility in Millersburg, Oregon, filed an action before the OPUC asserting that the rates set by a special tariff with PacifiCorp and approved by the OPUC were not just and reasonable. In October 2001, the OPUC dismissed Wah Chang's petition and found that Wah Chang assumed the risk of price increases under the special tariff. Wah Chang petitioned the Circuit Court for Marion County, Oregon for review of the OPUC's order. In June 2002, the Circuit Court for Marion County, Oregon, granted Wah Chang's mot ion and ordered the OPUC to reopen the record to allow Wah Chang the opportunity to present new evidence of alleged market manipulation during the energy crisis. In September 2009, the OPUC dismissed Wah Chang's petition and reaffirmed that the rates set by the special tariff were just and reasonable. In October 2009, Wah Chang filed with the Oregon Court of Appeals a petition for judicial review of the OPUC's September 2009 order denying Wah Chang relief. In July 2010, the Oregon Court of Appeals accepted judicial review.

In a separate but related proceeding, in December 2000, Wah Chang filed a complaint in the Circuit Court for Linn County, Oregon, asserting that the special tariff with PacifiCorp is subject to rescission based on theories of mu tual mistake of fact, frustration of purpose and impracticability. In August 2002, the Circuit Court for Linn County, Oregon, granted PacifiCorp's motion for summary judgment dismissing Wah Chang's complaint. In February 2004, the Circuit Court for Linn County, Oregon, granted Wah Chang's motion to reopen the case to present additional evidence of alleged market manipulation. In December 2007, Wah Chang filed a second amended complaint seeking recovery of a portion of the costs paid under the special tariff based on various theories of legal relief, including partial rescission, unjust enrichment, and breach of duty of good faith and fair dealing. In August 2009, the Circuit Court for Linn County, Oregon, granted Wah Chang's request to file a third amended complaint containing a claim for punitive damages. In December 2009, PacifiCorp's motion for summary judgment based on the OPUC's September 2009 order was denied by the Circuit Court for Linn County, Oregon. The trial date has been set for April 2011. Wah Chang is seeking $37 million (less the amount Wah Chang would have paid for electricity absent the special tariff) in compensatory damages and $200 million in punitive damages. PacifiCorp intends to vigorously defend these claims and believes that the outcome of these proceedings will not have a material impact on its consolidated financial results.

In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in the Third District Court for Salt Lake County, Utah ("Third District Court") by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon Energy, LLC (collectively, "USA Power"), against Utah attorney Jody L. Will iams and the law firm Holme, Roberts & Owen, LLP, who represent PacifiCorp on various matters from time to time. USA Power was the developer of a planned generation project in Mona, Utah called Spring Canyon, which PacifiCorp, as part of its resource procurement process, at one time considered as an alternative to the Currant Creek generating facility. USA Power's complaint alleged that PacifiCorp misappropriated confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and related claims. USA Power seeks $250 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys' fees. The statutory doubling of damages only applies to the plaintiffs' trade secret claim and could increase the total damages sought to $500 million. After considering various motions for summary judgment, the court ruled in October 2007 in favor of PacifiCorp on all counts and dismissed the plaintiffs' claims in their entirety. In February 2008, the plaintiffs filed a petition requesting consideration by the Utah Supreme Court of two of their five claims. The plaintiffs' request was granted and they filed a brief in November 2008 with the Utah Supreme Court. In January 2009, PacifiCorp filed its reply brief. In May 2010, the Utah Supreme Court reversed and remanded the case back to the Third District Court for further consideration. The Third District Court set an eight-week trial for June and July, 2011, and also ordered the parties to engage in mediation to try and resolve the case before December 31, 2010. PacifiCorp cannot predict the outcome of these proceedings, but believes that the outcome will not have a material impact on its consolidated financial results.

Item 1A.

Risk Factors

There has been no material change to PacifiCorp's risk factors from those disclosed in Item 1A of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2009.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

In May 2010, PacifiCorp received an unsolicited offer to repurchase certain shares of PacifiCorp's preferred stock. As a result, PacifiCorp purchased and canceled 4,036 shares of its $100 stated value 4.72% Serial Preferred Stock for $318,844, at an average price per share of $79, and 3,266 shares of its $100 stated value 4.56% Serial Preferred Stock for $241,684, at an average price per share of $74.

Item 3.

Defaults Upon Senior Securities

Not applicable.

Item 4.

(Removed and Reserved)

Item 5.

Other Information

Not applicable.

Item 6.

Exhibits

Th e 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 6, 2010	/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.

3 2.2		Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

PacifiCorp (PPWLM) 10-Q2010 Q2 Quarterly report

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