PACIFICORP /OR/ - Quarter Report: 2010 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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)
	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 October 31, 2010, 357,060,915 shares of common stock were outstanding.

TABLE OF CONTENTS


PART I

Item 1.	Financial Statements	3

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41

Item 4.	Controls and Procedures	41

PART II

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3.	Defaults Upon Senior Securities	43

Item 4.	(Removed and Reserved)	43

Item 5.	Other Information	44

Item 6.	Exhibits	44

Signatures		45

Exhibit Index		46

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2010, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2010 and 2009, and of cash flows and changes in equity for the nine-month periods ended September 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 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

November 5, 2010

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30, 2010		December 31, 2009
ASSETS

Current assets:
Cash and cash equivalents	$	32	$	117
Accounts receivable, net	604		619
Income taxes receivable from affiliates	328		249
Inventories:
Materials and supplies	183		192
Fuel	183		187
Derivative contracts	148		108
Deferred income taxes	61		39
Other current assets	42		61
Total current assets	1,581		1,572

Property, plant and equipment, net	16,148		15,537
Regulatory assets	1,637		1,539
Derivative contracts	24		43
Investments and other assets	389		275

Total assets	$	19,779	$	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
	September 30, 2010		December 31, 2009
LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	492	$	553
Accrued employee expenses	114		76
Accrued interest	105		111
Accrued property and other taxes	111		67
Derivative contracts	104		85
Short-term debt	34		—
Current portion of long-term debt and capital lease obligations	89		16
Other current liabilities	91		105
Total current liabilities	1,140		1,013

Regulatory liabilities	836		838
Derivative contracts	389		410
Long-term debt and capital lease obligations	6,326		6,400
Deferred income taxes	3,149		2,625
Other long-term liabilities	745		948
Total liabilities	12,585		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	2,674		2,234
Accumulated other comprehensive loss, net	—		(6		)
Total common equity	7,153		6,607
Total PacifiCorp shareholders' equity	7,194		6,648
Noncontrolling interest	—		84
Total equity	7,194		6,732

Total liabilities and equity	$	19,779	$	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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Operating revenue	$	1,165		$	1,146		$	3,323		$	3,278

Operating costs and expenses:
Energy costs	450			435			1,213			1,231
Operations and maintenance	264			247			798			761
Depreciation and amortization	137			138			414			408
Taxes, other than income taxes	34			33			98			98
Total operating costs and expenses	885			853			2,523			2,498

Operating income	280			293			800			780

Other income (expense):
Interest expense	(97		)	(97		)	(291		)	(296		)
Allowance for borrowed funds	11			10			35			25
Allowance for equity funds	21			18			63			45
Interest income	1			5			4			17
Other, net	—			1			(2		)	—
Total other income (expense)	(64		)	(63		)	(191		)	(209		)

Income before income tax expense	216			230			609			571
Income tax expense	60			64			167			169
Net income	156			166			442			402
Net income attributable to noncontrolling interest	—			4			—			7
Net income attributable to PacifiCorp	$	156		$	162		$	442		$	395

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2010			2009

Cash flows from operating activities:
Net income	$	442		$	402
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	414			408
Provision for deferred income taxes	435			276
Changes in regulatory assets and liabilities	14			15
Other, net	(53		)	(26		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	33			63
Derivative collateral, net	(107		)	81
Inventories	(17		)	(24		)
Income taxes - affiliates, net	(79		)	(109		)
Accounts payable and other liabilities	(38		)	(7		)
Net cash flows from operating activities	1,044			1,079

Cash flows from investing activities:
Capital expenditures	(1,250		)	(1,766		)
Purchases of available-for-sale securities	—			(18		)
Proceeds from sales of available-for-sale securities	—			33
Other, net	(9		)	3
Net cash flows from investing activities	(1,259		)	(1,748		)

Cash flows from financing activities:
Net proceeds from (repayments of) short-term debt	34			(85		)
Proceeds from long-term debt	—			992
Proceeds from equity contributions	100			—
Preferred stock dividends	(2		)	(2		)
Repayments and redemptions of long-term debt and capital lease obligations	(1		)	(129		)
Other, net	(1		)	(17		)
Net cash flows from financing activities	130			759

Net change in cash and cash equivalents	(85		)	90
Cash and cash equivalents at beginning of period	117			59
Cash and cash equivalents at end of period	$	32		$	149

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	—		—		—		395			—			7			402
Other comprehensive loss	—		—		—		—			(3		)	—			(3		)
Contributions	—		—		—		—			—			23			23
Distributions	—		—		—		—			—			(31		)	(31		)
Preferred stock dividends
declared	—		—		—		(2		)	—			—			(2		)
Other equity transactions	—		—		—		—			—			6			6
Balance, September 30, 2009	$	41	$	—	$	4,254	$	2,087		$	(5	)	$	85		$	6,462

Balance, January 1, 2010	$	41	$	—	$	4,379	$	2,234		$	(6	)	$	84		$	6,732
Deconsolidation of
Bridger Coal	—		—		—		—			—			(84		)	(84		)
Net income	—		—		—		442			—			—			442
Other comprehensive
income	—		—		—		—			6			—			6
Contributions	—		—		100		—			—			—			100
Preferred stock dividends
declared	—		—		—		(2		)	—			—			(2		)
Balance, September 30, 2010	$	41	$	—	$	4,479	$	2,674		$	—		$	—		$	7,194

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					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009

Net income	$	156	$	166		$	442	$	402
Other comprehensive income (loss), net of tax -
Fair value adjustment on cash flow hedges, net of
tax of $-, $(1), $3 and $(1)	1		(2		)	6		(3		)
Comprehensive income	157		164			448		399
Comprehensive income attributable to noncontrolling interest	—		4			—		7
Comprehensive income attributable to PacifiCorp	$	157	$	160		$	448	$	392

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 principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the Consolidated Financial Statements as of September 30, 2010 and for the three- and nine-month periods ended September 30, 2010 and 2009. The results of operations for the three- and nine-month periods ended September 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 nine-month period ended September 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 on 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, enterprises 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 ("Bridger Coal"), was deconsolidated and is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. The deconsolidation of Bridger Coal 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 deconsolidation 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 Bridger Coal 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	September 30, 2010			December 31, 2009

Property, plant and equipment in service	5-80 years	$	20,837		$	20,330
Accumulated depreciation and amortization		(6,589		)	(6,623		)
Net property, plant and equipment in service		14,248			13,707
Construction work-in-progress		1,900			1,830
Total property, plant and equipment, net		$	16,148		$	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 Commission ("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 Oregon Court of Appeals held oral arguments on the matter. A decision is not expected until 2011, which could impact PacifiCorp's 2006 through 2009 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 for a surcharge of $38 million in its 2008 tax report under SB 408. In January 2010, PacifiCorp entered into a stipulation with OPUC staff and the Citizens' Utility Board of Oregon, agreeing to a lower surcharge totaling $2 million, including interest. In April 2010, the OPUC issued an order adopting the stipulation in its entirety, at which time PacifiCorp recorded the $2 million in earnings.

In October 2010, PacifiCorp filed for a surcharge of $29 million, plus interest, in its 2009 tax report under SB 408. No amounts have been recorded in relation to the 2009 tax report.


(5)	Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates 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 September 30, 2010
Assets:
Investments in available-for-sale securities -
Money market mutual funds⁽²⁾	$	31	$	—		$	—		$	—		$	31
Investments in trading securities -
Investment funds⁽³⁾	9		—			—			—			9
Commodity derivatives	—		386			5			(219		)	172
	$	40	$	386		$	5		$	(219	)	$	212
Liabilities:
Commodity derivatives	$	—	$	(487	)	$	(357	)	$	351		$	(493	)

As of December 31, 2009
Assets:
Investments in available-for-sale securities:
Money market mutual funds⁽²⁾	$	123	$	—		$	—		$	—		$	123
Debt securities	1		33			—			—			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)	Represents a net cash collateral receivable of $132 million and $25 million as of September 30, 2010 and December 31, 2009, respectively, and netting under master netting arrangements.


(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 38% United States government obligations, 29% corporate obligations, 21% United States equity securities and 12% international equity securities.

PacifiCorp's investments in money market mutual funds, investment 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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Beginning balance	$	(406	)	$	(389	)	$	(380	)	$	(408	)
Changes in fair value recognized in regulatory assets	14			(6		)	(38		)	23
Purchases, sales, issuances and settlements	40			43			66			56
Net transfers (to) from Level 2	—			—			—			(23		)
Ending balance	$	(352	)	$	(352	)	$	(352	)	$	(352	)

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 variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):


	As of September 30, 2010				As of December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	6,358	$	7,401	$	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 purchased 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 contracts, 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 related 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 September 30, 2010
Not Designated as Hedging Contracts⁽¹⁾⁽²⁾:
Commodity assets	$	251		$	35		$	25		$	68		$	379
Commodity liabilities	(79		)	(11		)	(238		)	(513		)	(841		)
Total	172			24			(213		)	(445		)	(462		)

Designated as Cash Flow Hedging Contracts⁽¹⁾:
Commodity assets	11			—			1			—			12
Commodity liabilities	(3		)	—			—			—			(3		)
Total	8			—			1			—			9

Total derivatives	180			24			(212		)	(445		)	(453		)
Cash collateral (payable) receivable	(32		)	—			108			56			132
Total derivatives - net basis	$	148		$	24		$	(104	)	$	(389	)	$	(321	)

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 September 30, 2010 and December 31, 2009, net regulatory assets of $463 million and $367 million, respectively, were recorded related to the net derivative liabilities not designated as hedging contracts of $462 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 recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):


	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Beginning balance	$	482		$	302		$	367		$	442
Changes in fair value recognized in net regulatory assets	10			30			83			(132		)
Net gains reclassified to earnings - operating revenue	11			53			52			191
Net losses reclassified to earnings - energy costs	(40		)	(98		)	(39		)	(214		)
Ending balance	$	463		$	287		$	463		$	287

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 Operations 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					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2010		2009			2010			2009
Commodity derivatives:
Operating revenue	$	2	$	—		$	3		$	5
Energy costs	1		3			(4		)	4
Operations and maintenance	—		(1		)	(1		)	—
Total	$	3	$	2		$	(2	)	$	9

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 derivative 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					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2010			2009		2010			2009

Beginning balance	$	(8	)	$	1	$	—		$	—
Net (gains) losses recognized in OCI	(3		)	3		(13		)	4
Net losses reclassified to earnings - revenue	(2		)	—		—			—
Net gains reclassified to earnings - cost of sales	4			—		4			—
Ending balance	$	(9	)	$	4	$	(9	)	$	4

Realized gains and losses and hedge ineffectiveness are recognized in income as operating revenue or energy costs depending upon the nature of the item being hedged. For the three- and nine-month periods ended September 30, 2010 and 2009, hedge ineffectiveness was insignificant. As of September 30, 2010, PacifiCorp had cash flow hedges with expiration dates extending through December 31, 2010 and $9 million of pre-tax net unrealized gains are forecasted to be reclassified from accumulated other comprehensive income into earnings as the contracts settle through December 31, 2010.

Derivative Contract Volumes

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


	Unit of Measure	2010		2009
Commodity contracts:
Electricity sales	Megawatt hours	(16	)	(22	)
Natural gas purchases	Decatherms	165		205
Fuel purchases	Gallons	4		2

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 participants that have a direct or indirect relationship with the counterparty.

PacifiCorp analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and 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 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 September 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 $534 million and $353 million as of September 30, 2010 and December 31, 2009, respectively, for which PacifiCorp had posted collateral of $164 million and $80 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2010 and December 31, 2009, PacifiCorp would have been required to post $125 million and $159 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, 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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
Pension:
Service cost⁽¹⁾	$	3		$	4		$	9		$	12
Interest cost	16			18			49			53
Expected return on plan assets	(19		)	(18		)	(56		)	(53		)
Net amortization	5			3			17			8
Net amortization of regulatory deferrals	(2		)	(2		)	(7		)	(6		)
Net periodic benefit cost	$	3		$	5		$	12		$	14


	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
Other postretirement:
Service cost⁽¹⁾	$	1		$	2		$	4		$	4
Interest cost	7			9			23			25
Expected return on plan assets	(7		)	(8		)	(22		)	(22		)
Net amortization	4			3			11			9
Net amortization of regulatory deferrals	1			—			1			1
Net periodic benefit cost	$	6		$	6		$	17		$	17


(1)	Service cost excludes $3 million of contributions to the joint trust union plans during each of the three-month periods ended September 30, 2010 and 2009. Service cost excludes $9 million of contributions to the joint trust union plans during each of the nine-month periods ended September 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 September 30, 2010, $116 million, $18 million and $9 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 substantial amounts and are described below.

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp's Jim Bridger 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 reviewed by the United States Environmental Protection Agency ("EPA") and approved by the court. This matter is now concluded and 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 increase in annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event it is determined that PacifiCorp's historical projects did not meet all regulatory requirements. The impact of these additional emissions controls, costs and penalties, if any, on PacifiCorp's consolidated financial results cannot be determined at this time.

Accrued Environmental Costs

PacifiCorp is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of PacifiCorp's operations and sites owned by third parties. PacifiCorp accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, PacifiCorp's proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of September 30, 2010 and December 31, 2009 was $15 million and $18 million, respectively, and is included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are legal obligations associated with the retirement of those assets are separately accounted for as asset retirement obligations.

Hydroelectric Relicensing

PacifiCorp's hydroelectric portfolio consists of 46 generating facilities with an aggregate facility net owned capacity of 1,157 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 Klamath 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 system in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until the relicensing process is complete 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 mainstem 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 on dam removal, and California issued a resolution in October 2010, holding the certification process in abeyance until May 2011.

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 between the parties continued with an expanded group of stakeholders. The parties to the Klamath Hydroelectric Settlement Agreement ("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. PacifiCorp expects that federal legislation will be introduced in the United States Congress in 2011 to endorse and enact provisions of the KHSA.

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, local 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 activities. 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 PacifiCorp's contribution to dam removal costs exceeds $200 million or 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 ("CPUC") 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. In September 2010, the OPUC issued an order approving dam removal surcharges for Oregon customers. The CPUC is expected to issue an order on PacifiCorp's California surcharge filing in April 2011.

As of September 30, 2010 and December 31, 2009, PacifiCorp had $73 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 general rate case recommended recovery of relicensing costs effective January 1, 2011. As of September 30, 2010, PacifiCorp's Klamath hydroelectric system generating facilities had a net book value of $60 million with an average remaining depreciable life of 36 years. In August 2010, PacifiCorp received an order from the OPUC approving a change to depreciation rates for certain of the Klamath hydroelectric system generating facilities. The depreciation rate change will be effective January 1, 2011 and will allow for full depreciation of the assets by December 31, 2019. PacifiCorp has made a similar filing in California and plans to include a similar request in upcoming rate cases in the rest of the states comprising its service territory.

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 investigation into the February 2008 outage. Also in November 2008, in conjunction with the reliability standards review, the FERC assumed control of certain aspects of the WECC's 2007 audit. PacifiCorp has engaged in discussions with FERC staff regarding findings related to the WECC audit and the non-public investigation. However, PacifiCorp cannot predict the impact of the audit or the non-public investigation 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 made by the California Energy Resources Scheduling ("CERS") division of the California Department of Water Resources. Without issuing the mandate order, the Ninth Circuit remanded the case to the FERC to (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.

Purchase Obligations

In September 2010, PacifiCorp amended an existing coal supply agreement and entered into a new coal supply agreement, each establishing annual minimum purchases of coal to supply one of PacifiCorp's coal-fired generating facilities. Prior to the amendment, the existing agreement did not require a minimum level of purchases. The coal supply agreements result in minimum future purchases for the years ending December 31 of approximately $90 million in 2011, $93 million in 2012, $99 million in 2013, $101 million in 2014, $109 million in 2015 and $731 million thereafter.


(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
	September 30, 2010			December 31, 2009

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


(10)	Related-Party Transactions

PacifiCorp has an intercompany administrative services agreement with its indirect parent company, MEHC and its subsidiaries. Expenses charged to PacifiCorp under this agreement totaled $2 million during each of the three-month periods ended September 30, 2010 and 2009, and $6 million during each of the nine-month periods ended September 30, 2010 and 2009.

PacifiCorp also engages in various transactions with several subsidiaries of MEHC in the ordinary course of business. Services provided by these affiliates in the ordinary course of business and charged to PacifiCorp relate to the transportation of natural gas and relocation services. These expenses totaled $1 million during each of the three-month periods ended September 30, 2010 and 2009, and $3 million and $2 million during the nine-month periods ended September 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 equity 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 $1 million during each of the three-month periods ended September 30, 2010 and 2009, and $5 million during each of the nine-month periods ended September 30, 2010 and 2009. Prepayments to MISL were $3 million and $2 million as of September 30, 2010 and December 31, 2009, respectively. Receivables for claims were $20 million and $10 million as of September 30, 2010 and December 31, 2009, respectively.

PacifiCorp has long-term transportation contracts with BNSF Railway Company, which became an indirect wholly owned subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company, in February 2010. Transportation costs under these contracts were $6 million and $7 million during the three-month periods ended September 30, 2010 and 2009, respectively, and $21 million during each of the nine-month periods ended September 30, 2010 and 2009.

PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. As of September 30, 2010 and December 31, 2009, income taxes receivable from MEHC were $328 million and $249 million, respectively.

PacifiCorp transacts with its equity investees, Bridger Coal and Trapper Mining, Inc. Refer to Note 2 for additional information regarding Bridger Coal. Services provided by PacifiCorp and charged to Bridger Coal relate primarily to management services, income taxes and labor. Receivables for these services were $4 million as of September 30, 2010. Services provided by equity investees and charged to PacifiCorp primarily relate to coal purchases; for Bridger Coal these purchases are under a long-term contract that ends on December 31, 2024. These payables were $21 million as of September 30, 2010. During the three- and nine-month periods ended September 30, 2010, coal purchases totaled $39 million and $107 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 significant 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 PacifiCorp's forward-looking statements. These factors include, among others:


•	general economic, political and business conditions in the jurisdictions in which PacifiCorp's facilities operate;


•	changes in 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 PacifiCorp'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 business 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 impact 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 affect 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


•	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 forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

Results of Operations for the Third Quarter and First Nine Months of 2010 and 2009

Overview

Net income attributable to PacifiCorp for the third quarter was $156 million, a decrease of $6 million, or 4%, and for the first nine months of 2010 was $442 million, an increase of $47 million, or 12%, as compared to 2009. Net income attributable to PacifiCorp for the third quarter decreased due to lower net wholesale electricity activities, higher operations and maintenance expense, higher depreciation on higher plant placed-in-service and the favorable settlement of certain tax contingencies in the prior year, partially offset by higher prices approved by regulators and higher production tax credits. Net income attributable to PacifiCorp for the first nine months of 2010 increased due to higher prices approved by regulators, higher revenue from sales of renewable energy credits mainly during the first six months of 2010, higher allowances for funds used during construction and higher production tax credits, partially offset by lower net wholesale electricity activities, higher operations and maintenance expense, higher depreciation on higher plant placed-in-service, the favorable settlement of certain tax contingencies in 2009 and the benefits in 2009 associated with Oregon Senate Bill 408 ("SB 408").

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 ("Bridger Coal").

Operating revenue 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 third quarter were as follows:


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

Gross margin (in millions):
Operating revenue	$	1,165	$	1,146	$	19		2	%
Energy costs	450		435		(15		)	(3	)
Gross margin	$	715	$	711	$	4		1

Volumes of electricity sold (in gigawatt hours ("GWh")):
Residential	3,969		4,014		(45		)	(1	)%
Commercial	4,302		4,362		(60		)	(1	)
Industrial	5,604		5,222		382			7
Other	160		156		4			3
Total retail electricity sales	14,035		13,754		281			2
Wholesale electricity sales	2,453		3,038		(585		)	(19	)
Total electricity sales	16,488		16,792		(304		)	(2	)

Retail electricity sales:
Average retail customers (in thousands)	1,733		1,718		15			1	%
Average revenue per megawatt hour ("MWh")	$	73.38	$	70.03	$	3.35		5	%

Wholesale electricity sales:
Average revenue per MWh	$	37.84	$	44.61	$	(6.77	)	(15	)%

Volumes of electricity generated (in GWh):
Coal-fired generation	11,089		11,839		(750		)	(6	)%
Natural gas-fired generation	2,384		2,441		(57		)	(2	)
Hydroelectric generation	573		499		74			15
Other	593		480		113			24
Total PacifiCorp generated volumes	14,639		15,259		(620		)	(4	)

Volumes of electricity purchased (in GWh):
Wholesale electricity purchases	3,187		2,639		(548		)	(21	)%

Cost of wholesale electricity purchased:
Average cost per MWh	$	41.70	$	42.01	$	0.31		1	%

Gross margin increased $4 million, or 1%, for 2010 compared to 2009 primarily due to:


•	$53 million from higher retail prices approved by regulators, including $13 million of increases in demand-side management ("DSM") revenues primarily associated with Utah DSM programs;


•	$10 million due to higher customer usage in the eastern side of PacifiCorp's service territory in substantially all customer classes, partially offset by lower residential and commercial usage in the western side of PacifiCorp's service territory primarily due to unfavorable weather;


•	$7 million of changes in the fair value of energy sales and purchase contracts accounted for as derivatives;


•	$6 million of higher deferrals of incurred power costs and lower amortization of previous deferrals in accordance with established adjustment mechanisms;


•	$5 million of decreased fuel costs due to lower average prices paid for natural gas and lower volumes of coal and natural gas consumed, partially offset by increased coal prices; and


•	$3 million of higher revenue from sales of renewable energy credits.

The increase in gross margin was partially offset by:


•	$64 million resulting from net wholesale electricity activities due to $30 million of lower volumes of wholesale electricity sales and $12 million of lower prices on wholesale electricity sales, as well as $23 million of higher volumes of wholesale electricity purchases;


•	$17 million of lower revenue related to the deconsolidation of Bridger Coal; and


•	$7 million resulting from higher transmission expense due to higher contract rates.

Operations and maintenance increased $17 million, or 7%, for 2010 compared to 2009 primarily due to higher Utah DSM expenses, partially offset by lower costs related to the deconsolidation of Bridger Coal.

Depreciation and amortization decreased $1 million, or 1%, for 2010 compared to 2009 due to revised depreciation rates in California and $3 million of lower depreciation related to the deconsolidation of Bridger Coal, partially offset by higher plant placed-in-service.

Allowances for borrowed and equity funds increased $4 million, or 14%, for 2010 compared to 2009 primarily due to higher qualified construction work-in-progress balances.

Interest income decreased $4 million, or 80%, for 2010 compared to 2009 primarily due to higher interest recognized on certain receivables in the prior year.

Income tax expense decreased $4 million to $60 million for 2010 compared to 2009, primarily due to regulatory treatment of certain deferred income taxes, higher production tax credits associated with PacifiCorp's wind-powered generating facilities, and lower pre-tax book income, substantially offset by prior year favorable settlement of certain tax contingencies. The effective tax rate was 28% for each of the three-month periods ended September 30, 2010 and 2009.

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


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

Gross margin (in millions):
Operating revenue	$	3,323	$	3,278	$	45		1	%
Energy costs	1,213		1,231		18			1
Gross margin	$	2,110	$	2,047	$	63		3

Volumes of electricity sold (in GWh):
Residential	11,621		11,678		(57		)	(0	)%
Commercial	11,877		12,088		(211		)	(2	)
Industrial	15,552		14,851		701			5
Other	438		450		(12		)	(3	)
Total retail electricity sales	39,488		39,067		421			1
Wholesale electricity sales	8,427		9,159		(732		)	(8	)
Total electricity sales	47,915		48,226		(311		)	(1	)

Retail electricity sales:
Average retail customers (in thousands)	1,731		1,717		14			1	%
Average revenue per MWh	$	70.62	$	67.72	$	2.90		4	%

Wholesale electricity sales:
Average revenue per MWh	$	44.43	$	52.05	$	(7.62	)	(15	)%

Volumes of electricity generated (in GWh):
Coal-fired generation	32,066		32,440		(374		)	(1	)%
Natural gas-fired generation	6,302		6,467		(165		)	(3	)
Hydroelectric generation	2,720		2,804		(84		)	(3	)
Other	2,043		1,662		381			23
Total PacifiCorp generated volumes	43,131		43,373		(242		)	(1	)

Volumes of electricity purchased (in GWh):
Wholesale electricity purchases	8,168		8,137		(31		)	(0	)%

Cost of wholesale electricity purchased:
Average cost per MWh	$	40.54	$	42.55	$	2.01		5	%

Gross margin increased $63 million, or 3%, for 2010 compared to 2009 primarily due to:


•	$122 million from higher retail prices approved by regulators, including $36 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;


•	$49 million of higher revenue from sales of renewable energy credits;


•	$26 million of higher deferrals of incurred power costs and lower amortization of previous deferrals in accordance with established adjustment mechanisms;


•	$14 million primarily due to the elimination of certain regulatory liabilities resulting from the Utah DSM settlement in 2009 and the Utah general rate case order in 2010;


•	$7 million due to higher customer usage in the eastern side of PacifiCorp's service territory in substantially all customer classes, partially offset by lower residential and commercial usage in the western side of PacifiCorp's service territory primarily due to unfavorable weather; and


•	$3 million of decreased fuel costs due to lower average prices paid for natural gas and lower volumes of natural gas and coal consumed, substantially offset by increased coal prices.

The increase in gross margin was partially offset by:


•	$87 million resulting from net wholesale electricity activities due to $64 million of lower average prices on wholesale electricity sales and $38 million of lower wholesale sales volumes, partially offset by $15 million of lower costs of wholesale electricity purchases substantially due to lower average prices;


•	$49 million of lower revenue related to the deconsolidation of Bridger Coal;


•	$17 million resulting from higher transmission expense due to higher contract rates; and


•	$4 million of changes in the fair value of energy sales and purchase contracts accounted for as derivatives.

Operations and maintenance increased $37 million, or 5%, for 2010 compared to 2009 primarily due to higher Utah DSM expenses , the write-off of a portion of the Utah DSM regulatory asset resulting from the Utah DSM settlement in 2009 and the Utah general rate case order in 2010, and higher costs associated with jointly owned generating facilities primarily due to increased overhauls, partially offset by lower costs related to the deconsolidation of Bridger Coal.

Depreciation and amortization increased $6 million, or 1%, for 2010 compared to 2009 primarily due to higher plant placed-in-service, partially offset by revised depreciation rates in California and $7 million of lower depreciation related to the deconsolidation of Bridger Coal.

Allowances for borrowed and equity funds increased $28 million, or 40%, for 2010 compared to 2009 primarily due to higher qualified construction work-in-progress balances.

Interest income decreased $13 million, or 76%, for 2010 compared to 2009 primarily due to interest recognized in the prior year associated with SB 408.

Income tax expense decreased $2 million to $167 million for 2010 compared to 2009 primarily due to regulatory treatment of certain deferred income taxes, and higher production tax credits associated with PacifiCorp's wind-powered generating facilities, substantially offset by higher pre-tax book income and prior year favorable settlement of certain tax contingencies. The effective tax rate was 27% for the nine-month period ended September 30, 2010 compared to 30% for 2009.

Liquidity and Capital Resources

As of September 30, 2010, PacifiCorp's total net liquidity available was $1.089 billion. The components of total net liquidity available are as follows (in millions):


Cash and cash equivalents	$	32

Available revolving credit facilities	$	1,395
Less:
Short-term borrowings and issuances of commercial paper	(34		)
Letters of credit and tax-exempt bond support	(304		)
Net revolving credit facilities available	$	1,057

Total net liquidity available	$	1,089

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 nine-month periods ended September 30, 2010 and 2009 were $1.044 billion and $1.079 billion, respectively. The $35 million decrease was primarily due to changes in collateral posted for derivative contracts, lower net wholesale electricity activities and higher contributions to PacifiCorp's pension plan, partially offset by higher income tax receipts in the current year primarily related to the prior year repairs deduction and bonus depreciation and higher prices approved by regulators.

In September 2010, the President signed the Small Business Jobs Act into law, extending retroactively to January 1, 2010, the 50% depreciation bonus for qualifying property purchased and placed in service in 2010. As a result of the new law, PacifiCorp's third quarter tax provision reflected bonus depreciation on qualifying assets placed in service during 2010. Accordingly, PacifiCorp's receivable for income taxes increased to $328 million as of September 30, 2010.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2010 and 2009 were $(1.259) billion and $(1.748) billion, respectively. Capital expenditures decreased $516 million. Capital expenditures consisted mainly of the following during the nine-month periods ended September 30:

2010:

•

Transmission system investments totaling $317 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 substantially complete in the fourth quarter of 2010.


•	Emissions control equipment totaling $304 million, including costs for the Dave Johnston generating facility Unit 3, which includes a sulfur dioxide scrubber that was placed in 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 $144 million for the 111-megawatt ("MW") Dunlap Ranch I wind project near Medicine Bow, Wyoming, which was placed in service in October 2010.


•	Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $485 million.

2009:


•	Transmission system investments totaling $553 million, including construction costs for the Populus-to-Terminal segment of the Energy Gateway Transmission Expansion Program.


•	The development and construction of wind-powered generating facilities totaling $373 million.


•	Emissions control equipment totaling $229 million.


•	Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $611 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2010 were $130 million. Sources of cash consisted of $100 million of cash capital contributions from PacifiCorp's indirect parent company, MidAmerican Energy Holdings Company, as well as $34 million of net borrowings of short-term debt. Uses of cash totaled $4 million and consisted substantially of preferred stock dividends paid, the purchase at a discount to the stated value and cancellation of 7,302 shares of preferred stock, and the repayment of capital lease obligations.

Net cash flows from financing activities for the nine-month period ended September 30, 2009 were $759 million. Sources of cash consisted of $992 million of proceeds from the issuance of long-term debt. Uses of cash totaled $233 million and consisted substantially of $125 million for scheduled repayments of long-term debt and $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. As of September 30, 2010, PacifiCorp had $34 million of short-term debt outstanding at a weighted average interest rate of 0.4%. PacifiCorp had no outstanding short-term debt as of 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 June 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. In September 2010, PacifiCorp completed a re-offering of variable-rate tax-exempt bond obligations totaling $38 million. Letters of credit totaling $39 million were issued under one of PacifiCorp's unsecured revolving credit facilities to provide credit enhancement and liquidity support for these previously unenhanced obligations.

As of September 30, 2010, PacifiCorp had $601 million of letters of credit available to provide credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $587 million plus interest. These committed bank arrangements were fully available as of September 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, replacement 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:


•	$459 million for transmission system investments, including $206 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.


•	$355 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 oxides and particulate matter emissions.


•	$155 million for construction and development of the 111-MW Dunlap Ranch I wind-powered generating facility that was placed in service in October 2010.


•	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 electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts, 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 the 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 with 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 200-MW Top of the World wind-powered generating facility located in Wyoming and the associated renewable energy credits. The generating facility reached commercial operation in October 2010 and the power purchase agreement will 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 constructed and placed in service in October 2010.

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, evaluations have been completed and negotiations with the final shortlist bidders have been initiated.

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. The UPSC completed the phase one hearings in January 2010. In February 2010, the UPSC issued an order to proceed to the second phase, concluding that the public interest determination is dependent on evidence to be provided in phase two. Additionally, in February 2010, PacifiCorp filed an application 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 that would establish deferred accounts for both net power costs and renewable energy credit revenues in excess of the levels currently included in rates, subject to the UPSC's final determination of the ratemaking treatment of the deferrals. In November 2010, a final hearing on the ECAM was held with the UPSC. A final decision as to whether all or any of the net power costs and renewable energy credit revenues in excess of the levels currently included in rates will be collected from or passed through to customers is under consideration by the UPSC.

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 UPSC 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. Collection of a one-time $16 million surcharge for the portion of the $31 million increase related to the period from July 2010 to December 2010 is expected to begin effective January 1, 2011.

Oregon

In February 2010, PacifiCorp made its initial filing for the annual transition adjustment mechanism 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 OPUC approved the all-party stipulation in September 2010, subject to updates for anticipated net power costs through November 2010. In July 2010, PacifiCorp filed the first of three net power cost updates, requesting a revised increase of $61 million. The final rates 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 net power costs in November 2010 and collection through March 2012. In November 2010, the WPSC approved effective December 1, 2010, the deferral of net power costs incurred above or below base net power costs currently provided for in rates until the WPSC issues an order on PacifiCorp's application for the ECAM.

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 annual 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%, and includes the establishment of revised depreciation rates on California distribution assets. In September 2010, the CPUC approved the settlement agreement with an effective date of 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 requested recovery of $1 million to be collected over a one-year period beginning January 1, 2011. In August 2010, an all-party settlement agreement providing for a $1 million recovery was filed with the CPUC. In October 2010, the CPUC approved the settlement agreement.

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.

Hydroelectric Decommissioning

Powerdale Hydroelectric Facility - Hood River, Oregon

In June 2003, PacifiCorp entered into a settlement agreement to decommission the 6-MW Powerdale hydroelectric facility rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale dam and associated system features is projected to cost $6 million, excluding inflation. In November 2006, flooding damaged the Powerdale facility and rendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp's request to cease generation at the facility; however, removal was still scheduled for 2010. Also in February 2007, PacifiCorp submitted a request to the FERC to allow PacifiCorp to defer the remaining net book value and any additional removal costs of the system as a regulatory asset. In May 2007, the FERC issued an order that approved PacifiCorp's proposed accounting entries, thereby allowing PacifiCorp to reclassify the net book value and the estimated removal costs to a regulatory asset. PacifiCorp received approval from its state regulatory commissions to defer and recover these costs. In April 2010, PacifiCorp initiated removal of the Powerdale dam and associated system features as stipulated in the FERC Surrender Order. As of September 30, 2010, the dam has been removed and all work within the river channel has been completed. Final decommissioning activities, including site restoration, are expected to be completed by the end of 2010.

Condit Hydroelectric Facility - White Salmon River, Washington

In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectric facility was signed by PacifiCorp, state and federal agencies and non-governmental organizations. Under the original settlement agreement, removal was expected to begin in October 2006, with a total cost to decommission not to exceed $17 million, excluding inflation. In early February 2005, the parties agreed to modify the settlement agreement so that removal would not begin until October 2008, with a total cost to decommission not to exceed $21 million, excluding inflation. In March 2008, the United States Army Corps of Engineers requested PacifiCorp complete an additional study of expected decommissioning impacts on aquatic resources. In January 2009, the study work was completed and the results were provided to the United States Army Corps of Engineers and the Washington Department of Ecology. In January 2010, the Washington Department of Ecology released the Final Second Supplemental Environmental Impact Statement which formally considered this additional information, and in October 2010, the Washington Department of Ecology issued a Clean Water Act 401 certificate. Remaining permitting includes a 404 permit from the United States Army Corps of Engineers and a surrender order from the FERC. The settlement agreement is contingent upon receiving a FERC surrender order and other regulatory approvals that are not materially inconsistent with the amended settlement agreement. PacifiCorp is in the process of acquiring all necessary permits within the terms and conditions of the amended settlement agreement. Given the ongoing permitting process and the time needed for system removal and to evaluate impacts on natural resources, decommissioning is now expected to begin no earlier than October 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 interpretation, 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 regulations 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 storage 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 surface 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 November 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 credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

PacifiCorp 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 rating agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 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 September 30, 2010, PacifiCorp would have been required to post $228 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, 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, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act ("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 subject 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. 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-counter 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 Statements in Item 1 of this Form 10-Q for disclosure of PacifiCorp's derivative positions as of September 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 reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and is accumulated and communicated to management, including PacifiCorp's Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in PacifiCorp's internal control over financial reporting during the quarter ended September 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 developments 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 motion 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 mutual 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. Williams 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

Not applicable.


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	(Removed and Reserved)


Item 5.	Other Information

Coal Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

The operation of PacifiCorp's coal mines and coal processing facilities is regulated by the Federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 ("Mine Safety Act"). MSHA inspects PacifiCorp's coal mines and coal processing facilities on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act. For citations, monetary penalties are assessed by MSHA. Citations, notices and orders can be contested and appealed and the severity and assessment of penalties may be reduced or, in some cases, dismissed through the appeal process.

The table below summarizes the total number of citations, notices and orders issued and penalties assessed by MSHA for each coal mine or coal processing facility operated by PacifiCorp under the indicated provisions of the Mine Safety Act during the three-month period ended September 30, 2010. Closed or idled mines have been excluded from the table below as no citations, orders or notices were issued for such mines during the three-month period ended September 30, 2010. In addition, there were no fatalities at PacifiCorp's coal mines or coal processing facilities during the three-month period ended September 30, 2010.


	Mine Safety Act
Coal Mine or Coal Processing Facility	Section 104(a) Significant & Substantial Citations⁽¹⁾	Section 104(b) Orders⁽²⁾	Section 104(d) Citations & Orders⁽³⁾	Section 110(b)(2) Citations⁽⁴⁾	Section 107(a) Imminent Danger Orders⁽⁵⁾	Section 104(e) Notice⁽⁶⁾	Total Value of Proposed MSHA Assessments (in thousands)		Legal Actions Pending⁽⁷⁾

Deer Creek	10	—	1	—	—	—	$	40	15
Bridger (surface)	2	—	—	—	—	—	4		6
Bridger (underground)	9	—	—	—	1	—	42		17
Cottonwood Preparatory Plant	—	—	—	—	—	—	—		—
Wyodak Coal Crushing Facility	—	—	—	—	—	—	—		—


(1)	For alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.


(2)	For alleged failure to totally abate the subject matter of a Mine Safety Act section 104(a) citation within the period specified in the citation.


(3)	For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.


(4)	For alleged flagrant violations (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation of a mandatory health or safety standard that substantially and proximately caused, or reasonably caused, or reasonably could have been expected to cause, death or serious bodily injury).


(5)	The total number of imminent danger orders (i.e. the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated).


(6)	For a pattern, or the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards.


(7)	Represents the total number of legal actions pending before the Federal Mine Safety and Health Review Commission, which is not exclusive to citations, notices, orders and penalties assessed by MSHA.


Item 6.	Exhibits

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

SIGNATURES

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


	PACIFICORP
	(Registrant)



Date: November 5, 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.

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