PacifiCorp (PPWLM) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

or

[  ] 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
	503-813-5608
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  x  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 50309. As of October 31, 2011, 357,060,915 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	32
PART II
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	33
Item 4.	(Removed and Reserved)	33
Item 5.	Other Information	34
Item 6.	Exhibits	34
Signatures		35
Exhibit Index		36

i

Definition of Abbreviations and Industry Terms

When used in Part I, Items 2 through 4, and Part II, Items 1 through 6, the following terms have the definitions indicated.

PacifiCorp and Related Entities
MEHC	MidAmerican Energy Holdings Company
PacifiCorp	PacifiCorp and its subsidiaries
PPW Holdings	PPW Holdings LLC, a wholly owned subsidiary of MEHC and PacifiCorp's direct parent company
Certain Industry Terms
AFUDC	Allowance for Funds Used During Construction
CPUC	California Public Utilities Commission
DSM	Demand-side Management
EBA	Energy Balancing Account
ECAC	Energy Cost Adjustment Clause
ECAM	Energy Cost Adjustment Mechanism
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GHG	Greenhouse Gases
GHG Reporting	Greenhouse Gases Reporting
GWh	Gigawatt hour
IPUC	Idaho Public Utilities Commission
IRP	Integrated Resource Plan
kV	Kilovolt
Mine Safety Act	Federal Mine Safety and Health Act of 1977
MSHA	Federal Mine Safety and Health Administration
MW	Megawatt
MWh	Megawatt hour
OPUC	Oregon Public Utility Commission
PCAM	Power Cost Adjustment Mechanism
PTAM	Post Test-year Adjustment Mechanism
RCRA	Resource Conservation and Recovery Act
REC	Renewable Energy Credit
RFPs	Requests for Proposals
RPS	Renewable Portfolio Standards
SIP	State Implementation Plans
TAM	Transition Adjustment Mechanism
UPSC	Utah Public Service Commission
WPSC	Wyoming Public Service Commission
WUTC	Washington Utilities and Transportation Commission

ii

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 "will," "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 the control of PacifiCorp and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:

• general economic, political and business conditions, as well as changes in laws and regulations affecting PacifiCorp's operations or related industries;

• changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;

• 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, electricity supply or PacifiCorp's ability to obtain long-term contracts with wholesale customers and suppliers;

• a high degree of variance between actual and forecasted load that could impact PacifiCorp's hedging strategy and the cost of balancing its generation resources and wholesale activities with its retail load obligations;

• performance and availability of PacifiCorp's generating facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions;

• hydroelectric conditions, as well as the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings, that could have a significant impact on electricity 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 generating 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;

• 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;

• the impact of inflation on costs and our ability to recover such costs in rates;

• increases in employee healthcare costs;

• the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on expense and funding requirements associated with PacifiCorp's pension and other postretirement benefits plans and the joint trust plans to which PacifiCorp contributes;

iii

• 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 PacifiCorp's consolidated financial results;

• other risks or unforeseen events, including the effects of storms, floods, litigation, wars, 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 or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting PacifiCorp are described in its filings with the United States Securities and Exchange Commission, 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.

iv

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, 2011, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2011 and 2010, and of cash flows and changes in equity for the nine-month periods ended September 30, 2011 and 2010. 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, 2010, 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 February 28, 2011, 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, 2010 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 4, 2011

1

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30, 2011		December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	151	$	31
Accounts receivable, net	661		628
Income taxes receivable	12		345
Inventories:
Materials and supplies	193		186
Fuel	215		188
Derivative contracts	32		114
Deferred income taxes	107		83
Other current assets	30		59
Total current assets	1,401		1,634
Property, plant and equipment, net	17,045		16,392
Regulatory assets	1,717		1,715
Derivative contracts	6		9
Other assets	401		396
Total assets	$	20,570	$	20,146

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

2

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30, 2011			December 31, 2010
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	495		$	479
Accrued employee expenses	95			81
Accrued interest	110			110
Accrued property and other taxes	119			63
Derivative contracts	112			84
Short-term debt	—			36
Current portion of long-term debt and capital lease obligations	521			588
Other current liabilities	113			97
Total current liabilities	1,565			1,538
Regulatory liabilities	898			849
Derivative contracts	266			399
Long-term debt and capital lease obligations	6,206			5,813
Deferred income taxes	3,733			3,448
Other long-term liabilities	718			788
Total liabilities	13,386			12,835
Commitments and contingencies (Note 8)
Shareholders' equity:
Preferred stock	41			41
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—			—
Additional paid-in capital	4,479			4,479
Retained earnings	2,671			2,798
Accumulated other comprehensive loss, net	(7		)	(7		)
Total shareholders' equity	7,184			7,311
Total liabilities and shareholders' equity	$	20,570		$	20,146

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

3

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
Operating revenue	$	1,198		$	1,165		$	3,408		$	3,323
Operating costs and expenses:
Energy costs	428			450			1,182			1,213
Operations and maintenance	263			264			811			798
Depreciation and amortization	151			137			456			414
Taxes, other than income taxes	40			34			113			98
Total operating costs and expenses	882			885			2,562			2,523
Operating income	316			280			846			800
Other income (expense):
Interest expense	(102		)	(97		)	(297		)	(291		)
Allowance for borrowed funds	7			11			18			35
Allowance for equity funds	12			21			34			63
Interest income	1			1			5			4
Other, net	(2		)	—			(3		)	(2		)
Total other income (expense)	(84		)	(64		)	(243		)	(191		)
Income before income tax expense	232			216			603			609
Income tax expense	63			60			178			167
Net income	$	169		$	156		$	425		$	442

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

4

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	425		$	442
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	456			414
Deferred income taxes and amortization of investment tax credits	274			435
Changes in regulatory assets and liabilities	(23		)	14
Other, net	(21		)	(53		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(8		)	33
Derivative collateral, net	44			(107		)
Inventories	(34		)	(17		)
Income taxes receivable, net	333			(79		)
Accounts payable and other liabilities	6			(38		)
Net cash flows from operating activities	1,452			1,044
Cash flows from investing activities:
Capital expenditures	(1,069		)	(1,250		)
Other, net	2			(9		)
Net cash flows from investing activities	(1,067		)	(1,259		)
Cash flows from financing activities:
Net (repayments of) proceeds from short-term debt	(36		)	34
Proceeds from long-term debt	399			—
Proceeds from equity contributions	—			100
Repayments and redemptions of long-term debt and capital lease obligations	(74		)	(1		)
Preferred stock dividends	(2		)	(2		)
Common stock dividends	(550		)	—
Other, net	(2		)	(1		)
Net cash flows from financing activities	(265		)	130
Net change in cash and cash equivalents	120			(85		)
Cash and cash equivalents at beginning of period	31			117
Cash and cash equivalents at end of period	$	151		$	32

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

5

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, December 31, 2009	$	41	$	—	$	4,379	$	2,234		$	(6	)	$	84		$	6,732
Deconsolidation of Bridger Coal Company	—		—		—		—			—			(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
Balance, December 31, 2010	$	41	$	—	$	4,479	$	2,798		$	(7	)	$	—		$	7,311
Net income	—		—		—		425			—			—			425
Preferred stock dividends declared	—		—		—		(2		)	—			—			(2		)
Common stock dividends declared	—		—		—		(550		)	—			—			(550		)
Balance, September 30, 2011	$	41	$	—	$	4,479	$	2,671		$	(7	)	$	—		$	7,184

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

6

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2011		2010		2011		2010
Net income	$	169	$	156	$	425	$	442
Other comprehensive income (loss), net of tax -
Unrealized gains on cash flow hedges, net of tax of $-, $-, $- and $3	—		1		—		6
Comprehensive income	$	169	$	157	$	425	$	448

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

7

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, financial institutions 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. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the 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, 2011 and for the three- and nine-month periods ended September 30, 2011 and 2010. The results of operations for the three- and nine-month periods ended September 30, 2011 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, 2010 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, 2011.

(2) New Accounting Pronouncements

In September 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2011-09, which amends FASB Accounting Standards Codification ("ASC") Subtopic 715-80, "Compensation-Retirement Benefits-Multiemployer Plans." The amendments in this guidance require additional disclosures regarding an entity's participation in multiemployer pension plans and other postretirement benefit plans, as well as certain qualitative and quantitative disclosures regarding individually significant multiemployer pension plans. This guidance is effective for annual reporting periods ending after December 15, 2011. PacifiCorp is currently evaluating the impact of adopting this guidance on its disclosures included within Notes to Consolidated Financial Statements.

In June 2011, the FASB issued ASU No. 2011-05, which amends FASB ASC Topic 220, "Comprehensive Income." ASU No. 2011-05 provides an entity with the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Regardless of the option chosen, this guidance also requires presentation of items on the face of the financial statements that are reclassified from other comprehensive income to net income. This guidance does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income or how tax effects of each item of other comprehensive income are presented. This guidance is effective for interim and annual reporting periods beginning after December 15, 2011. PacifiCorp is currently evaluating which presentation option will be implemented.

8

In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC Topic 820, "Fair Value Measurements and Disclosures." The amendments in this guidance are not intended to result in a change in current accounting. ASU No. 2011-04 requires additional disclosures relating to fair value measurements categorized within Level 3 of the fair value hierarchy, including quantitative information about unobservable inputs, the valuation process used by the entity and the sensitivity of unobservable input measurements. Additionally, entities are required to disclose the level of the fair value hierarchy for assets and liabilities that are not measured at fair value in the balance sheet, but for which disclosure of the fair value is required. This guidance is effective for interim and annual reporting periods beginning after December 15, 2011. PacifiCorp is currently evaluating the impact of adopting this guidance on its disclosures included within Notes to Consolidated Financial Statements.

In January 2010, the FASB issued ASU No. 2010-06, which amends FASB 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 PacifiCorp adopted as of January 1, 2011. The adoption of this guidance did not have a material impact on PacifiCorp's disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

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

		As of
	Depreciable Life	September 30, 2011			December 31, 2010
Property, plant and equipment	5-80 years	$	22,614		$	22,034
Accumulated depreciation and amortization		(6,815		)	(6,646		)
Net property, plant and equipment		15,799			15,388
Construction work-in-progress		1,246			1,004
Total property, plant and equipment, net		$	17,045		$	16,392

(4) 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.

9

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, 2011
Assets:
Commodity derivatives	$	—	$	160		$	1		$	(123	)	$	38
Investments in available-for-sale securities -
Money market mutual funds(2)	143		—			—			—			143
	$	143	$	160		$	1		$	(123	)	$	181
Liabilities - Commodity derivatives	$	—	$	(366	)	$	(218	)	$	206		$	(378	)
As of December 31, 2010
Assets:
Commodity derivatives	$	—	$	263		$	5		$	(145	)	$	123
Investments in available-for-sale securities -
Money market mutual funds(2)	29		—			—			—			29
	$	29	$	263		$	5		$	(145	)	$	152
Liabilities - Commodity derivatives	$	—	$	(405	)	$	(350	)	$	272		$	(483	)

(1) Represents netting under master netting arrangements and a net cash collateral receivable of $83 million and $127 million as of September 30, 2011 and December 31, 2010, respectively.

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

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon 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 unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 5 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, spread option and best-of option, with the appropriate forward price curve and other inputs.

PacifiCorp's investments in money market mutual funds are accounted for as available-for-sale securities and are stated at fair value. PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value.

10

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,
	2011			2010			2011			2010
Beginning balance	$	(240	)	$	(406	)	$	(345	)	$	(380	)
Changes in fair value recognized in net regulatory assets	5			14			84			(38		)
Settlements	18			40			44			66
Ending balance	$	(217	)	$	(352	)	$	(217	)	$	(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, 2011				As of December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	6,670	$	8,000	$	6,344	$	7,086

(5)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, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territories. PacifiCorp's load and generating facilities 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. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt 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 price 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 primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, 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 4 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, 2011
Not designated as hedging contracts(1)(2):
Commodity assets	$	78		$	9		$	61		$	13		$	161
Commodity liabilities	(43		)	(3		)	(248		)	(290		)	(584		)
Total	35			6			(187		)	(277		)	(423		)
Total derivatives	35			6			(187		)	(277		)	(423		)
Cash collateral (payable) receivable	(3		)	—			75			11			83
Total derivatives - net basis	$	32		$	6		$	(112	)	$	(266	)	$	(340	)
As of December 31, 2010
Not designated as hedging contracts(1)(2):
Commodity assets	$	185		$	13		$	34		$	36		$	268
Commodity liabilities	(62		)	(4		)	(213		)	(476		)	(755		)
Total	123			9			(179		)	(440		)	(487		)
Total derivatives	123			9			(179		)	(440		)	(487		)
Cash collateral (payable) receivable	(9		)	—			95			41			127
Total derivatives - net basis	$	114		$	9		$	(84	)	$	(399	)	$	(360	)

(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 are generally included in rates and as of September 30, 2011 and December 31, 2010, a net regulatory asset of $423 million and $487 million, respectively, was recorded related to the net derivative liability of $423 million and $487 million, respectively.

For PacifiCorp's commodity derivatives, the settled amount is generally included in 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 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,
	2011			2010			2011			2010
Beginning balance	$	438		$	482		$	487		$	367
Changes in fair value recognized in net regulatory assets	42			10			(24		)	83
Net (losses) gains reclassified to operating revenue	(3		)	11			7			52
Net losses reclassified to energy costs	(54		)	(40		)	(47		)	(39		)
Ending balance	$	423		$	463		$	423		$	463

For PacifiCorp's derivatives for which changes in fair value are not recorded as a net regulatory asset, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts and energy costs and operations and maintenance for purchase contracts and electricity, natural gas and fuel oil swap contracts. During the three- and nine-month periods ended September 30, 2011 and 2010, these amounts were insignificant.

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 (in millions):

	Unit of Measure	September 30, 2011		December 31, 2010
Commodity contracts:
Electricity sales	Megawatt hours	(8	)	(13	)
Natural gas purchases	Decatherms	109		159
Fuel oil purchases	Gallons	4		16

Credit Risk

PacifiCorp extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with its 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 fees for delayed payments. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

11

Collateral and Contingent Features

In accordance with industry practice, certain wholesale 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, 2011, 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 $398 million and $448 million as of September 30, 2011 and December 31, 2010, respectively, for which PacifiCorp had posted collateral of $86 million and $136 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2011 and December 31, 2010, PacifiCorp would have been required to post $183 million and $129 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.

(6) Recent Debt Transactions

In May 2011, PacifiCorp issued $400 million of 3.85% First Mortgage Bonds due June 15, 2021. The net proceeds were used to fund capital expenditures, repay short-term debt and for general corporate purposes.

(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,
	2011			2010			2011			2010
Pension:
Service cost(1)	$	2		$	3		$	7		$	9
Interest cost	16			16			48			49
Expected return on plan assets	(19		)	(19		)	(56		)	(56		)
Net amortization	8			5			22			17
Net amortization of regulatory deferrals	(2		)	(2		)	(7		)	(7		)
Net periodic benefit cost	$	5		$	3		$	14		$	12
Other postretirement:
Service cost(1)	$	2		$	1		$	5		$	4
Interest cost	7			7			23			23
Expected return on plan assets	(8		)	(7		)	(23		)	(22		)
Net amortization	4			4			13			11
Net amortization of regulatory deferrals	1			1			1			1
Net periodic benefit cost	$	6		$	6		$	19		$	17

(1) Service cost excludes $5 million and $3 million of contributions to joint trust union plans during the three-month periods ended September 30, 2011 and 2010, respectively. Service cost excludes $11 million and $9 million of contributions to joint trust union plans during the nine-month periods ended September 30, 2011 and 2010, respectively.

Employer contributions to the pension, other postretirement benefit and joint trust union plans are expected to be $71 million, $28 million and $13 million, respectively, during 2011. As of September 30, 2011, $70 million, $21 million and $11 million of contributions had been made to the pension, other postretirement benefit and joint trust union plans, respectively.

(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.

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 Federal Energy Regulatory Commission ("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 non-public investigation, which includes the WECC's findings that are now being processed by the FERC. PacifiCorp does not believe that the outcome of the non-public investigation will have a material impact on its consolidated financial results. 

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Hydroelectric Relicensing

PacifiCorp's hydroelectric portfolio consists of 44 generating facilities with an aggregate facility net owned capacity of 1,145 megawatts. The FERC regulates 98% of the net capacity of this portfolio through 15 individual licenses, which 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 2010, 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 Klamath Hydroelectric Settlement Agreement ("KHSA"). Among other things, the KHSA provides that the United States Department of the Interior conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's four mainstem dams is in the public interest and will advance restoration of the Klamath Basin's salmonid fisheries. 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. If Congress does not enact legislation, then PacifiCorp will resume relicensing at the FERC. 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 or other appropriate State of California financing mechanism. If dam removal costs exceed $200 million and if the State of California is unable to raise the additional funds necessary for dam removal costs, sufficient funds would need to be provided by an entity other than PacifiCorp in order for the KHSA and dam removal to proceed.

12

PacifiCorp has begun collection of surcharges from Oregon customers for their share of dam removal costs, as approved by the Oregon Public Utility Commission ("OPUC") and is depositing the proceeds in a trust account maintained by the OPUC. PacifiCorp will begin collection of surcharges from California customers for their share of dam removal costs, as approved by the California Public Utilities Commission ("CPUC"), upon the establishment of two trust accounts.

As of September 30, 2011 and December 31, 2010, PacifiCorp's property, plant and equipment, net included $120 million and $125 million, respectively, of costs associated with the Klamath hydroelectric system's four mainstem dams and the associated relicensing and settlement costs. During 2010 and 2011, PacifiCorp received approvals from the OPUC, the CPUC and the Wyoming Public Service Commission to depreciate the Klamath hydroelectric system's four mainstem dams and the associated relicensing and settlement costs through the expected dam removal date. The depreciation rate changes were effective January 1, 2011 and will allow for full depreciation of the assets by December 2019 for those jurisdictions. PacifiCorp is seeking similar approval in Idaho and expects to seek approval in the next Washington general rate case. As part of the July 2011 Utah general rate case settlement that was approved by the UPSC in August 2011, PacifiCorp and the other parties to the settlement agreed to defer a decision regarding the acceleration of the depreciation rates for the Klamath hydroelectric system's four mainstem dams to a future rate proceeding, at which time the associated relicensing and settlement costs would be addressed.

FERC Issues

Northwest Refund Case

In October 2011, the FERC issued an order on remand by the United States Court of Appeals for the Ninth Circuit in which it determined that additional procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest wholesale spot market during the period from December 2000 through June 2001. PacifiCorp was a participant in the Pacific Northwest wholesale spot market during this period. The FERC ordered an evidentiary trial-type hearing before an administrative law judge to permit parties to present evidence of alleged unlawful market activity. However, the FERC held the hearing in abeyance pending settlement discussions with all parties, which will be the subject of a November 16, 2011 status conference with the appointed settlement judge. Because, among other things, the scope of the proceeding has not been defined, PacifiCorp cannot predict the outcome of this proceeding and any impact on PacifiCorp's consolidated financial results, if any.

Purchase Obligations

In May 2011, PacifiCorp issued a notice to proceed with the engineering, procurement and construction contract for the 637-MW Lake Side 2 combined-cycle combustion turbine natural gas-fired generating facility. The notice to proceed resulted in purchase obligations for the years ending December 31 of approximately $181 million in 2011, $206 million in 2012, $126 million in 2013 and $8 million in 2014.

(9) Common Equity

In March 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC, a direct wholly owned subsidiary of MEHC and PacifiCorp's direct parent company, on April 20, 2011.

In January 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC on February 28, 2011.

(10) Components of Accumulated Other Comprehensive Loss, Net

Accumulated other comprehensive loss, net is included in shareholders' equity on the Consolidated Balance Sheets and consisted of unrecognized amounts on retirement benefits of $7 million, net of tax of $4 million, as of September 30, 2011 and December 31, 2010.

13

(11) Related-Party Transactions

PacifiCorp has an intercompany administrative services agreement with MEHC and its subsidiaries. Amounts charged to PacifiCorp under this agreement totaled $2 million during each of the three-month periods ended September 30, 2011 and 2010, and $7 million and $6 million during the nine-month periods ended September 30, 2011 and 2010, respectively.

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, 2011 and 2010, and $4 million and $3 million during the nine-month periods ended September 30, 2011 and 2010, respectively.

PacifiCorp has long-term transportation contracts with BNSF Railway Company, an indirect wholly owned subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company. Transportation costs under these contracts were $9 million and $6 million during the three-month periods ended September 30, 2011 and 2010, respectively, and $25 million and $21 million during the nine-month periods ended September 30, 2011 and 2010, respectively.

PacifiCorp participated in a captive insurance program provided by MEHC Insurance Services Ltd. ("MEISL"), a wholly owned subsidiary of MEHC. MEISL covered significant portions of the property damage and liability insurance deductibles in many of PacifiCorp's policies, as well as overhead distribution and transmission line property damage. The policy coverage period expired in March 2011 and will not be renewed. Premium expenses were $- million and $1 million during the three-month periods ended September 30, 2011 and 2010, respectively, and $2 million and $5 million during the nine-month periods ended September 30, 2011 and 2010, respectively. Receivables for claims were $21 million and $12 million as of September 30, 2011 and December 31, 2010, respectively.

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, 2011 and December 31, 2010, income taxes receivable from MEHC were $12 million and $345 million, respectively. For the nine-month periods ended September 30, 2011 and 2010, cash received for income taxes from MEHC totaled $426 million and $183 million, respectively.

PacifiCorp transacts with its equity investees, Bridger Coal Company and Trapper Mining Inc. Services provided by equity investees and charged to PacifiCorp primarily relate to coal purchases. During the three-month periods ended September 30, 2011 and 2010, coal purchases totaled $26 million and $39 million, respectively. During the nine-month periods ended September 30, 2011 and 2010, coal purchases totaled $92 million and $107 million, respectively. Payables to PacifiCorp's equity investees were $13 million and $17 million as of September 30, 2011 and December 31, 2010, respectively.

14

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 during the periods included herein. Explanations include management's best estimate of the impacts 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.

Results of Operations for the Third Quarter and First Nine Months of 2011 and 2010

Overview

Net income attributable to PacifiCorp for the three-month period ended September 30, 2011 was $169 million, an increase of $13 million, or 8%, compared to 2010. Net income attributable to PacifiCorp increased due to higher retail prices approved by regulators, the net impact of the Utah general rate case settlement and higher retail customer load, partially offset by higher purchased electricity costs, higher depreciation expense on higher plant in service and lower AFUDC due to lower construction work-in-progress.

Net income attributable to PacifiCorp for the nine-month period ended September 30, 2011 was $425 million, a decrease of $17 million, or 4%, compared to 2010. Net income attributable to PacifiCorp for the first nine months decreased as higher retail prices approved by regulators, higher retail customer load, the net impact of the Utah general rate case settlement and lower fuel costs were more than offset by lower revenue from wholesale electricity sales, higher purchased electricity costs, higher depreciation and property tax expense on higher plant in service, lower AFUDC due to lower construction work-in-progress and higher operations and maintenance expense.

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 customers, which include the costs of fuel, wholesale electricity purchases and transmission. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore useful.

15

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

	Third Quarter				Favorable/(Unfavorable)
	2011		2010		Change			% Change
Gross margin (in millions):
Operating revenue	$	1,198	$	1,165	$	33		3	%
Energy costs	428		450		22			5
Gross margin	$	770	$	715	$	55		8
Volumes of electricity sold (in GWh):
Residential	3,937		3,969		(32		)	(1	)%
Commercial	4,478		4,302		176			4
Industrial and irrigation	5,670		5,604		66			1
Other	128		160		(32		)	(20	)
Total retail electricity sales	14,213		14,035		178			1
Wholesale electricity sales	2,799		2,453		346			14
Total electricity sales	17,012		16,488		524			3
Retail electricity sales:
Average retail customers (in thousands)	1,741		1,733		8			—	%
Average revenue per MWh	$	76.71	$	73.38	$	3.33		5	%
Wholesale electricity sales:
Average revenue per MWh	$	33.77	$	37.84	$	(4.07	)	(11	)%
Volumes of electricity generated (in GWh):
Coal-fired generation	11,212		11,089		123			1	%
Natural gas-fired generation	1,784		2,384		(600		)	(25	)
Hydroelectric generation	794		573		221			39
Other	608		593		15			3
Total PacifiCorp generated volumes	14,398		14,639		(241		)	(2	)
Volumes of electricity purchased (in GWh):
Wholesale electricity purchases	3,699		3,187		(512		)	(16	)%
Cost of wholesale electricity purchased:
Average cost per MWh	$	43.92	$	41.70	$	(2.22	)	(5	)%

16

Gross margin increased $55 million, or 8%, for 2011 compared to 2010 primarily due to:

• $60 million of increases resulting from the Utah general rate case settlement in the current quarter for the recovery of incurred power costs;

• $49 million of increases from higher retail prices approved by regulators; and

• $11 million of increases primarily due to higher commercial customer load in Utah and Oregon.

The increase in gross margin was partially offset by:

• $28 million of decreases in net wholesale electricity activities primarily due to higher volumes of purchased electricity;

• $30 million of decreases resulting from the Utah general rate case settlement in the current quarter for return to customers of past renewable energy credit sales in excess of base rates; and

• $5 million of decreases resulting from higher fuel costs due to $20 million of higher coal prices, partially offset by $16 million of lower volumes of natural gas consumed.

Depreciation and amortization increased $14 million, or 10%, for 2011 compared to 2010 primarily due to higher plant in service.

Taxes, other than income taxes increased $6 million, or 18%, for 2011 compared to 2010 primarily due to increased property taxes driven by higher plant in service.

Allowances for borrowed and equity funds decreased $13 million, or 41%, for 2011 compared to 2010 primarily due to lower qualified construction work-in-progress balances.

Income tax expense increased $3 million to $63 million for 2011 compared to 2010 and the effective tax rates were 27% and 28% for 2011 and 2010, respectively. The decrease in PacifiCorp's effective tax rate was primarily due to higher production tax credits associated with PacifiCorp's wind-powered generating facilities, partially offset by the regulatory treatment of certain deferred income taxes.

17

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

		First Nine Months				Favorable/(Unfavorable)
		2011		2010		Change			% Change
Gross margin (in millions):
Operating revenue		$	3,408	$	3,323	$	85		3	%
Energy costs		1,182		1,213		31			3
Gross margin		$	2,226	$	2,110	$	116		5
Volumes of electricity sold (in GWh):
Residential		11,798		11,621		177			2	%
Commercial		12,366		11,877		489			4
Industrial and irrigation		15,925		15,552		373			2
Other		399		438		(39		)	(9	)
Total retail electricity sales		40,488		39,488		1,000			3
Wholesale electricity sales		7,806		8,427		(621		)	(7	)
Total electricity sales		48,294		47,915		379			1
Retail electricity sales:
Average retail customers (in thousands)		1,741		1,731		10			1	%
Average revenue per MWh		$	74.71	$	70.62	$	4.09		6	%
Wholesale electricity sales:
Average revenue per MWh		$	32.49	$	44.43	$	(11.94	)	(27	)%
Volumes of electricity generated (in GWh):
Coal-fired generation		30,637		32,066		(1,429		)	(4	)%
Natural gas-fired generation		4,456		6,302		(1,846		)	(29	)
Hydroelectric generation		3,770		2,720		1,050			39
Other		2,663		2,043		620			30
Total PacifiCorp generated volumes		41,526		43,131		(1,605		)	(4	)
Volumes of electricity purchased (in GWh):
Wholesale electricity purchases	��	10,064		8,168		(1,896		)	(23	)%
Cost of wholesale electricity purchased:
Average cost per MWh		$	37.68	$	40.54	$	2.86		7	%

18

Gross margin increased $116 million, or 5%, for 2011 compared to 2010 primarily due to:

• $183 million of increases from higher retail prices approved by regulators;

• $60 million of increases resulting from the Utah general rate case settlement in the current quarter for the recovery of incurred power costs;

• $64 million of increases due to higher commercial customer load primarily in Utah and Oregon, higher industrial customer load in Utah and the impacts of cooler weather on residential customer load in Oregon;

• $10 million of increases resulting from lower fuel costs primarily due to $65 million of lower volumes of natural gas and $22 million of lower coal consumed, partially offset by $79 million of higher coal prices; and

• $8 million of increases due to net higher deferrals of incurred power costs in accordance with established adjustment mechanisms.

The increase in gross margin was partially offset by:

• $169 million of decreases resulting from higher volumes of purchased electricity and lower volumes of wholesale electricity sales, both at lower average market prices;

• $30 million of decreases resulting from the Utah general rate case settlement in the current quarter for return to customers of past renewable energy credit sales in excess of base rates; and

• $11 million of decreases due to the elimination of certain regulatory liabilities resulting from the Utah DSM settlement and the Utah general rate case order in the prior year.

Operations and maintenance increased $13 million, or 2%, for 2011 compared to 2010 primarily due to higher salaries and benefit expenses and higher materials and supplies expense, partially offset by the write-off of a portion of a Utah DSM regulatory asset in 2010.

Depreciation and amortization increased $42 million, or 10%, for 2011 compared to 2010 primarily due to higher plant in service.

Taxes, other than income taxes increased $15 million, or 15%, for 2011 compared to 2010 primarily due to increased property taxes driven by higher plant in service.

Allowances for borrowed and equity funds decreased $46 million, or 47%, for 2011 compared to 2010 primarily due to lower qualified construction work-in-progress balances.

Income tax expense increased $11 million to $178 million for 2011 compared to 2010 and the effective tax rates were 30% and 27% for 2011 and 2010, respectively. The increase in PacifiCorp's effective tax rate was primarily due to the regulatory treatment of certain deferred income taxes, partially offset by higher production tax credits associated with PacifiCorp's wind-powered generating facilities.

19

Liquidity and Capital Resources

As of September 30, 2011, PacifiCorp's total net liquidity was $1.202 billion. The components of total net liquidity are as follows (in millions):

Cash and cash equivalents	$	151
Available revolving credit facilities	$	1,355
Less:
Short-term debt	—
Letters of credit supporting tax-exempt bond obligations	(304		)
Net revolving credit facilities available	$	1,051
Total net liquidity	$	1,202
Unsecured revolving credit facilities:
Maturity dates(1)	2012, 2013
Largest single bank commitment as a % of total(2)	16		%

(1) For further discussion regarding PacifiCorp's credit facilities, refer to Note 8 of Notes to Consolidated Financial Statements in Item 8 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2010.

(2) 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, 2011 and 2010 were $1.452 billion and $1.044 billion, respectively. The $408 million increase was primarily due to higher income tax receipts of $243 million mainly attributable to bonus depreciation, higher retail prices approved by regulators and changes in collateral posted for derivative contracts, partially offset by lower net proceeds from wholesale electricity sales and purchases.

In September 2010, the President signed the Small Business Jobs Act into law, extending retroactively to January 1, 2010 the 50% bonus depreciation for qualifying property purchased and placed in service in 2010. In December 2010, the President signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 into law, which provided for 100% bonus depreciation for qualifying property purchased and placed in service after September 8, 2010 and prior to January 1, 2012, and 50% bonus depreciation for qualifying property purchased and placed in service after December 31, 2011 and prior to January 1, 2013. As a result of the new laws, PacifiCorp's cash flows from operations are expected to benefit in 2011 and 2012 due to bonus depreciation on qualifying assets placed in service.

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Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2011 and 2010 were $(1.067) billion and $(1.259) billion, respectively. Capital expenditures decreased $181 million. Capital expenditures incurred consisted mainly of the following during the nine-month periods ended September 30 and exclude amounts for non-cash equity AFUDC:

2011:

• Emissions control equipment on existing generating facilities totaling $160 million for installation or upgrade of sulfur dioxide scrubbers, low nitrogen oxide burners and particulate matter control systems.

• Transmission system investments totaling $152 million, including permitting and right-of-way costs for the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona to Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The transmission line is expected to be placed in service in 2013.

• The development and construction of the Lake Side 2 637-MW combined-cycle combustion turbine natural gas-fired generating facility ("Lake Side 2") totaling $123 million, which is expected to be placed in service in 2014.

• Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $643 million.

2010:

• Emissions control equipment totaling $256 million, including costs for a sulfur dioxide scrubber and low nitrogen oxide burners at the Dave Johnston generating facility and costs for installation or upgrade of sulfur dioxide scrubbers on various other generating facilities.

• Transmission system investments totaling $246 million, including construction costs for the Populus to Terminal segment of the Energy Gateway Transmission Expansion Program, which was placed in service in 2010.

• The construction of wind-powered generating facilities totaling $147 million for the 111-MW Dunlap Ranch I wind project that was placed in service in October 2010.

• Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $547 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2011 were $(265) million. Uses of cash totaled $664 million and substantially consisted of $550 million for dividends paid to PPW Holdings, $73 million for scheduled repayments on long-term debt and $36 million for the net repayment of short-term debt. Sources of cash totaled $399 million and consisted of proceeds from the issuance of long-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2010 were $130 million, which primarily consisted of $100 million of capital contributions and $34 million of net borrowings 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, 2011, PacifiCorp had no short-term debt outstanding. As of December 31, 2010, PacifiCorp had $36 million of short-term debt outstanding at a weighted average interest rate of 0.3%.

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Long-term Debt

In May 2011, PacifiCorp issued $400 million of 3.85% First Mortgage Bonds due June 15, 2021. The net proceeds were used to fund capital expenditures, repay short-term debt and for general corporate purposes.

PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $1.6 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.

As of September 30, 2011, 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 letters of credit were fully available as of September 30, 2011 and expire periodically through November 19, 2012.

Common Equity

In January 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings on February 28, 2011. In March 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings on April 20, 2011.

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 ratings, 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; outcomes of regulatory proceedings; 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, hydroelectric decommissioning and associated operating costs are generally incorporated into PacifiCorp's rates.

Forecasted capital expenditures, which include amounts for expenditures accrued but not yet paid and exclude amounts for non-cash equity AFUDC, are approximately $1.6 billion for 2011 and include the following:

• $230 million for generation development projects, primarily for development and construction of Lake Side 2, which is expected to be placed in service in 2014.

• $234 million for transmission system investments, including $169 million for the Energy Gateway Transmission Expansion Program, which includes permitting, right-of-way and initial construction costs for the Mona to Oquirrh transmission line.

• $206 million for environmental projects to install and upgrade emissions control equipment at certain coal-fired generating facilities to meet air quality and visibility permit requirements through reductions of sulfur dioxide, nitrogen oxides and particulate matter emissions.

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

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Integrated Resource Plan

As required by certain state regulations, PacifiCorp uses an 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 receives a formal notification in five states as to whether the IRP meets the commission's IRP standards and guidelines, referred to as acknowledgment. In March 2011, PacifiCorp filed its 2011 IRP with the state commissions. In June 2011, an addendum to the 2011 IRP with supplemental resource analysis was filed with the state commissions. In September 2011, PacifiCorp received acknowledgment from the IPUC.

Requests for Proposals

PacifiCorp has issued a series of individual 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 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 sought 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. As a result, PacifiCorp signed an engineer, procure and construct contract for Lake Side 2, which is expected to be placed in service in June 2014. The Lake Side 2 generating facility is currently being constructed adjacent to PacifiCorp's Lake Side generating facility, which is located in Vineyard, Utah, about 40 miles south of Salt Lake City. In April 2011, the UPSC issued an order approving the construction of Lake Side 2. PacifiCorp has obtained all of the necessary construction permits and certificates, and in May 2011, PacifiCorp issued a notice to proceed with construction of the Lake Side 2 generating facility.

In October 2011, PacifiCorp filed its draft 2016 All Source RFP with the UPSC and OPUC. The 2016 All Source RFP will seek 600 MW on a system wide basis from projects to be in service by June 2016. The 2016 All Source RFP will be issued to the market in early 2012.

Contractual Obligations

As of September 30, 2011, 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, 2010 other than the 2011 debt issuance previously discussed and the additional purchase obligation disclosed in Note 8 of Notes to Consolidated Financial Statements. Additionally, refer to the "Capital Expenditures" discussion included in "Liquidity and Capital Resources."

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Regulatory Matters

In addition to the discussion contained herein regarding updates to regulatory matters based upon material 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, 2010, refer to Note 8 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for additional regulatory matter updates.

FERC

As a result of a 2007 multi-party settlement with the FERC regarding long-term shared usage, coordinated operation and maintenance, and planning of certain 500-kV transmission lines, PacifiCorp agreed to file a Federal Power Act Section 205 rate change filing for its system-wide transmission service rates no later than June 1, 2011. In May 2011, PacifiCorp filed its Federal Power Act Section 205 rate case. In August 2011, the FERC issued an order accepting PacifiCorp's filing and allowing the proposed rates to become effective December 25, 2011, subject to refund. The FERC has requested that PacifiCorp and intervenors to the proceeding seek to arrive at a settlement for the proposed rates. If a settlement is not reached, hearings will be held before the FERC to arrive at final approved rates. Settlement discussions are underway with intervenors.

State Regulatory Matters

Utah

In March 2009, PacifiCorp filed for an ECAM with the UPSC. The filing recommended that the UPSC adopt the mechanism to recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. 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 requesting deferral of incremental REC revenue in excess of the REC 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 REC 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 December 2010, the UPSC approved a separate stipulation that provided a $3 million monthly credit to customers effective January 1, 2011 to be applied toward the UPSC's final decision. In March 2011, the UPSC issued its final order approving the use of an EBA in Utah to begin at the conclusion of the general rate case described below. Under the EBA, which has been established as a four year pilot program, 70% of any difference between actual net power costs incurred and the amount of net power costs recovered through base rates, subject to certain other adjustments, are deferred during the calendar year. PacifiCorp must then file by March 15 of the following year to initiate collection or refund of the deferred balance. The UPSC did not address in its EBA order the ratemaking treatment of the deferred accounts for net power costs and REC revenues in excess of the levels included in rates since the 2009 general rate case. In April 2011, PacifiCorp filed a petition with the UPSC for clarification and reconsideration of certain aspects of the EBA order. In May 2011, the UPSC granted PacifiCorp's petition for reconsideration of the UPSC's decision to exclude financial swaps from the EBA. The UPSC denied reconsideration of the 70% sharing of incremental net power costs not in base rates and clarified that the final order does not preclude future consideration of balancing account treatment for REC sales. These issues are included in the settlement described in the following paragraph.

In January 2011, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $232 million, or an average price increase of 14%. In June 2011, PacifiCorp filed its rebuttal testimony with the UPSC reducing the requested rate increase to $188 million, or an average price increase of 11%. In July 2011, PacifiCorp filed a settlement with the UPSC, which was approved by the UPSC in August 2011 and resulted in a $117 million rate increase, or an average price increase of 7% effective September 21, 2011. The settlement resolves all major dockets outstanding before the UPSC. Under the terms of the settlement, financial swaps are included in the EBA and a collaborative process with Utah stakeholders may result in future modifications to PacifiCorp's risk management and hedging policies. The settlement also concludes the ratemaking treatment of deferred accounts for net power costs and estimated sales of RECs in excess of the levels included in rates since the 2009 general rate case. The settlement provides for $60 million of net power costs in excess of amounts included in base rates to be recovered from Utah customers over a three-year period beginning June 1, 2012, without carrying charges. The settlement also provides for a $33 million credit to customers related to sales of RECs that substantially occurred in prior years and that will be credited to Utah customers over a period of approximately nine months beginning September 21, 2011, plus carrying charges. The settlement also establishes a balancing account for prospective REC sales. The settlement stipulation defers decisions regarding the ratemaking treatment associated with the Klamath hydroelectric system's four mainstem dams and relicensing and settlement costs as described in Note 8 to Notes to Consolidated Financial Statements.

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Oregon

In March 2011, PacifiCorp made its initial filing for the annual TAM with the OPUC for an annual increase of $62 million to recover the anticipated net power costs forecasted for calendar year 2012. In July 2011, PacifiCorp filed updated net power costs, reflecting an increase in the overall request to $63 million. In August 2011, PacifiCorp filed its surrebuttal testimony in the TAM proceeding decreasing the overall request to $59 million due to a reduction in forecasted net power costs. In September 2011, PacifiCorp reached a settlement with several parties, including the OPUC staff, to reduce the requested increase to $51 million, or an average price increase of 4%. The OPUC is expected to issue a decision on the stipulation in the fourth quarter of 2011. The new rates are subject to updates through November 2011 and will be effective January 1, 2012.

In October 2010, PacifiCorp filed its 2009 tax report under Oregon Senate Bill 408 ("SB 408"). In January 2011, PacifiCorp entered into a stipulation with the OPUC staff and the Citizens' Utility Board of Oregon, whereby PacifiCorp, the OPUC staff and the Citizens' Utility Board of Oregon agreed to a surcharge of $13 million, plus interest. In April 2011, the OPUC issued an order adopting the stipulation without significant modification. The $13 million, plus interest, was recorded in earnings in the second quarter of 2011 and is being collected over a one-year period that began in June 2011.

In May 2011, Oregon Senate Bill 967 ("SB 967") was enacted into law. SB 967 immediately repealed and replaced SB 408, and as a result, PacifiCorp will no longer be required to file tax reports under SB 408. Among other matters, SB 967 directs the OPUC to consider the income tax component of rates when conducting ratemaking proceedings. The enactment of SB 967 did not impact PacifiCorp's consolidated financial results.

Wyoming

In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The PCAM concluded with the final deferral of net power costs in November 2010 and collection through March 2012. In February 2011, the WPSC issued an order approving an ECAM effective December 1, 2010, under which 70% of any difference between actual net power costs incurred and the amount of net power costs recovered through base rates, subject to certain other adjustments, are deferred as incurred during the calendar year. PacifiCorp must then file by March 15 of the following year to initiate collection or refund of the deferred balance beginning June 1.

In November 2010, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $98 million, or an average price increase of 17%. In May 2011, PacifiCorp filed its rebuttal testimony with the WPSC reducing the requested rate increase to $80 million. In June 2011, the WPSC approved a multi-party stipulation resulting in an annual rate increase of $62 million, or an average price increase of 11%. The stipulation also established a surcredit and a balancing account to pass on to or collect from customers any difference between the amount of the REC sales established in the surcredit and actual REC sales. The surcredit will be established annually based on PacifiCorp's forecasted REC sales, and the difference between the surcredit and actual REC sales will be tracked in the balancing account. For 2011, the surcredit was set at $17 million, or a 3% reduction. The rates were effective September 22, 2011.

In February 2011, PacifiCorp filed its final PCAM application with the WPSC requesting recovery of $16 million in deferred net power costs over the 12-month period ending March 31, 2012. PacifiCorp requested and received approval from the WPSC to implement an $11 million interim rate increase over the $5 million reflected in the tariff to be effective from April 1, 2011 until the WPSC issues a final order. In September 2011, PacifiCorp reached an agreement with intervening parties and filed a stipulation with the WPSC to recover $14 million in deferred net power costs. In October 2011, the WPSC approved the stipulation with an effective date of November 1, 2011.

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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%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. In March 2011, the WUTC issued a final order and clarification letter approving an annual increase of $33 million, or an average price increase of 12%, reduced in the first year by a customer bill credit of $5 million, or 2%, related to the sale of RECs expected during the twelve-month period ended March 31, 2012. The new rates were effective in April 2011. In April 2011, PacifiCorp filed a petition for reconsideration requesting the WUTC reconsider various items on the final order, including income tax and net power cost issues and the WUTC's conclusions with respect to rate of return. The WUTC staff also filed a petition for reconsideration. In May 2011, the WUTC denied the petitions for reconsideration filed by PacifiCorp and the WUTC staff. In May 2011 in accordance with the March 2011 order, PacifiCorp submitted additional information to the WUTC regarding PacifiCorp's proceeds from sales of RECs for the period January 1, 2009 forward and a detailed proposal for a tracking mechanism for proceeds of RECs. In July 2011, the WUTC issued an order requiring additional testimony regarding the ratemaking treatment of historical Washington-allocated proceeds from sales of RECs and the tracking mechanism. Initial and reply briefs from all parties are due in November 2011.

In July 2011, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $13 million, or an average price increase of 4%, with an effective date no later than June 1, 2012.

Idaho

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%. In November 2010, the requested annual increase was reduced to $25 million, or an average price increase of 12%. In December 2010, the IPUC issued an interim order approving an annual increase of $14 million, or an average price increase of 7% with an effective date of December 28, 2010. In February 2011, the IPUC issued its final order with no revisions to the December 2010 increase. In March 2011, PacifiCorp petitioned the IPUC seeking reconsideration or rehearing on certain aspects of the order, including the IPUC's conclusion that 27% of PacifiCorp's Populus to Terminal transmission line investment is not currently used and useful and should be carried as plant held for future use. The Idaho-allocated share of 27% of the investment is approximately $13 million. In April 2011, the IPUC issued an order, accepting in part and rejecting in part, PacifiCorp's motion for reconsideration, resulting in no significant changes to the IPUC's initial order. In May 2011, PacifiCorp filed an appeal of the Populus to Terminal decision to the Idaho Supreme Court requesting a determination on the legality of the IPUC's decision to exclude 27% of the Populus to Terminal line as a result of its conclusion that the line is not fully used and useful. As a result of the settlement discussed below, PacifiCorp has joined in a motion filed with the Idaho Supreme Court in October 2011, to stay the procedural schedule associated with the appeal until January 30, 2012. Should the Idaho Supreme Court grant the motion, it will allow time for the IPUC to issue an order approving the treatment of the Populus to Terminal investment set forth in the settlement of the May 2011 general rate case described below.

In May 2011, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $33 million, or an average price increase of 15%. In October 2011, a settlement was reached with the majority of parties in the case that, if approved by the IPUC, will result in a two-year agreement to increase rates by $17 million each year effective January 1, 2012 and January 1, 2013, representing an average price increase of 8% and 7%, respectively. If approved, the settlement will also resolve the dispute over the 27% of PacifiCorp's Populus to Terminal investment and recommends that the IPUC provide recovery of PacifiCorp's investment beginning on or after January 1, 2014. Hearings in the general rate case are scheduled for December 2011.

In February 2011, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $13 million in deferred net power costs. In March 2011, the IPUC issued an order approving recovery of $10 million beginning April 1, 2011 and the remaining $3 million beginning in 2012.

California

In August 2011, PacifiCorp filed an application with the CPUC to increase rates pursuant to the ECAC. In the application, PacifiCorp requested a rate increase of $2 million, or an average price increase of 2%. If approved by the CPUC, the new rates will be effective January 1, 2012.

In October 2011, PacifiCorp filed its annual PTAM attrition adjustment with the CPUC. The filing requested an increase of $1 million, or an average price increase of 1%. If approved by the CPUC, the new rates will be effective January 1, 2012.

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Hydroelectric Decommissioning

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. In early February 2005, the parties agreed to modify the settlement agreement, establishing a total cost to decommission not to exceed $21 million, excluding inflation. In October 2010, the Washington Department of Ecology issued a Clean Water Act 401 certificate, and in December 2010, the FERC issued a surrender order for project decommissioning modifying PacifiCorp's proposed decommissioning plans and directing a 2011 decommissioning. In January 2011, PacifiCorp filed a request for clarification and rehearing of the surrender order and a motion for stay with the FERC requesting reinstatement of PacifiCorp's decommissioning proposal. In April 2011, the FERC issued an order on rehearing, granting PacifiCorp nearly all of the changes it requested, but did not shorten the required agency consultation and FERC approval periods. In June 2011, PacifiCorp formally notified the FERC of its acceptance of the terms and conditions of the orders that govern the surrender of the project license. PacifiCorp commenced on-site decommissioning activities in June 2011 and the dam was breached in late October 2011 as planned. Post breach, near-term activities will focus on sediment management within the former reservoir area. Complete dam removal is expected by September 2012.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, 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 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, 2010.

Clean Air Standards

Clean Air Mercury Rule/Hazardous Air Pollutant Maximum Achievable Control Technology Standards

In March 2011, the EPA proposed a new rule that will require coal-fired generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of a "Maximum Achievable Control Technology" standard rather than a cap-and-trade system. The public comment period closed in August 2011 and the final rule is expected to be issued in November 2011. The proposed rule requires that new and existing coal-fired facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards within three years after the final rule is promulgated, with individual sources granted an additional year to complete installation of controls if approved by the permitting authority. Until the rule is final, PacifiCorp cannot fully determine the costs to comply with the requirements; however, PacifiCorp believes that its emission reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators are consistent with the EPA's proposed rules and will support PacifiCorp's ability to comply with the proposal's standards for acid gases and non-mercury metallic hazardous air pollutants. PacifiCorp anticipates having to take additional actions to reduce mercury emissions and otherwise comply with the proposal's standards. Incremental costs to install and maintain mercury emissions control equipment and additional emissions monitoring equipment at each of PacifiCorp's coal-fired generating facilities will increase the cost of providing service to customers.

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Regional Haze

The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's generating facilities meet the threshold applicability criteria to be eligible units under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable progress towards achieving natural visibility conditions in Class I areas by requiring emissions controls, known as best available retrofit technology, on sources constructed between 1962 and 1977 with emissions that are anticipated to cause or contribute to impairment of visibility. Utah submitted its SIP and suggested that the emissions reduction projects planned by PacifiCorp are sufficient to meet its initial emissions reduction requirements. Utah approved amendments to its SIP submittal in April 2011, and those amendments, along with its previous SIP submittal, await approval or further direction from the EPA. Wyoming submitted its regional haze SIP to the EPA in January 2011. PacifiCorp believes that its planned emissions reduction projects will satisfy the regional haze requirements in Utah and Wyoming. It is possible that additional controls may be required after the respective SIPs have been considered by the EPA or that the timing of installation of planned controls could change. In October 2011, the EPA issued a Clean Air Act Section 114 request for information seeking analyses relating to best available retrofit technology at PacifiCorp's Hunter and Huntington generating facilities in Utah. The request is currently under review.

Climate Change

GHG Tailoring Rule

Effective January 2, 2011, power plants, among other facilities, were required to comply with the first phase of the GHG Tailoring Rule, which provides that any source that already has a Title V operating permit is required to have GHG provisions added to its permits upon renewal. In addition, the GHG Tailoring Rule provides that if projects at existing major sources result in an increase in emissions of GHG of at least 75,000 tons per year, such projects could trigger permitting requirements and the application of best available control technology to address GHG emissions. The second phase of the GHG Tailoring Rule took effect July 1, 2011 and broadened the scope of the sources that are required to obtain federal permits to limit GHGs to any new or modified sources that emit more than 100,000 tons per year of GHG, regardless of whether a major source air permit is required for any other pollutant regulated under the Clean Air Act.

New major sources are also required to undergo permitting and install the best available control technology if their GHG emissions exceed the applicable threshold. Several legal challenges have been filed to the EPA's final GHG Tailoring Rule in the United States Court of Appeals for the District of Columbia Circuit. The EPA issued GHG best available control technology guidance documents in an effort to provide permitting authorities guidance on how to conduct a best available control technology review for GHG. Permitting authorities are beginning to implement the GHG Tailoring Rule and determine what constitutes best available control technology for GHG. PacifiCorp is in the process of obtaining permits for certain existing facilities to install emissions reduction equipment to comply with the Regional Haze Rules and assessed the impacts of the projects on GHG emissions under the GHG Tailoring Rule. No GHG emissions limit is expected to be included in the permits. However, Lake Side 2 was subject to a best available control technology review and the permit includes a limit for carbon dioxide equivalent emissions. The GHG Tailoring Rule will result in the imposition of a permit limit for GHG emissions at certain facilities, which management believes will not have a material impact on PacifiCorp.

GHG New Source Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emission reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG by September 30, 2011, as amended, and issue final regulations by May 26, 2012. However, in mid-September, the EPA indicated it would not meet the September 30, 2011 deadline to promulgate the standards and it has not yet established a new schedule for issuing the proposed rules. It is unclear what standards the EPA will establish for new and modified sources or what the guidelines will be for existing sources. Until the standards are proposed and finalized, the impact on PacifiCorp cannot be determined.

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Regional and State Activities

Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact PacifiCorp and include:

• The Western Climate Initiative, a comprehensive regional effort to reduce GHG emissions by 15% below 2005 levels by 2020 through a cap-and-trade program that includes the electricity sector. The Western Climate Initiative includes the states of California, Montana, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. The state and provincial partners have agreed to begin reporting GHG emissions in 2011 for emissions that occurred in 2010. The first phase of the cap-and-trade program is scheduled to begin on January 1, 2012; however, only California, British Columbia and Quebec appear to be in a position to implement their programs in 2012.

• In October 2011, the California Air Resources Board adopted a GHG cap-and-trade program that will be implemented effective January 1, 2012 and will impose compliance obligations on entities in 2013. In addition, California law imposes a GHG emissions performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-art combined-cycle natural gas-fired generating facility, as well as legislation that adopts an economy-wide cap on GHG emissions to 1990 levels by 2020.

Reporting

California mandatory GHG reporting requirements began with 2008 emissions and PacifiCorp has reported its emissions annually since their inception. In September 2009, the EPA issued its final rule regarding mandatory GHG Reporting beginning January 1, 2010. Under GHG Reporting, suppliers of fossil fuels, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG are required to submit annual reports to the EPA. PacifiCorp is subject to this requirement and submitted its first report prior to September 30, 2011.

Federal Legislation

Legislation introduced in the 112^th Congress has been focused on repeal or delay of the EPA's ability to regulate GHG emissions. There is currently no federal legislation pending to regulate GHG emissions.

Renewable Portfolio Standards

In 2011, the California Legislature passed, and the governor signed, legislation to expand the state's RPS to require an average of 20% of retail load to be procured from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020 and each year thereafter. The new law supersedes the California Air Resources Board 33% renewable electricity standard adopted pursuant to Executive Order S-21-09 in September 2009. The 2011 legislation expands the RPS to all California retail sellers, changes the flexible compliance mechanisms for retail sellers and limits the use of out-of-state renewable electricity generation to comply with the law.

Water Quality Standards

In March 2011, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The proposed rule establishes requirements for all power generating facilities that withdraw more than 2 million gallons per day, based on total design intake capacity, of water from waters of the United States and use at least 25% of the withdrawn water exclusively for cooling purposes. The proposed rule includes impingement (i.e., when fish and other organisms are trapped against screens when water is drawn into a facility's cooling system) mortality standards to be met through average impingement mortality or intake velocity design criteria and entrainment (i.e., when organisms are drawn into the facility) standards to be determined on a case-by-case basis. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The rule is required to be finalized by the EPA by July 2012. PacifiCorp will be required to complete impingement and entrainment studies in 2013. The costs of compliance with the cooling water intake structure rule cannot be determined until the rule is final and the prescribed studies are conducted. In the event that PacifiCorp's existing intake structures require modification, the costs are not anticipated to be significant.

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Coal Combustion Byproduct Disposal

In December 2008, an ash impoundment dike at the Tennessee Valley Authority's Kingstonpower 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 the storage and disposal of coal combustion byproducts. 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 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. The public comment period closed in November 2010. The EPA has indicated it does not intend to finalize the rule in 2011 and the substance of the final rule is not known. The impact of the proposed regulations on coal combustion byproducts cannot be determined at this time; however, PacifiCorp has begun developing surface impoundment and landfill compliance plan options to ensure that physical infrastructure decisions are aligned with the potential outcomes of the rulemaking.

Other

PacifiCorp expects that it will be allowed to recover the prudently incurred costs to comply with the environmental laws and regulations discussed above. PacifiCorp's planning efforts take into consideration the complexity of balancing factors such as: (1) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (2) avoidance of excessive reliance on any one generation technology; (3) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (4) state-specific energy policies, resource preferences and economic development efforts; (5) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (6) keeping rates as affordable as possible. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost-effective and places PacifiCorp at risk of not having access to necessary capital, material and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, PacifiCorp has established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts reduce costs associated with replacement power and maintain system reliability.

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.

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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 wholesale energy 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, 2011, 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, 2011, PacifiCorp would have been required to post $288 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 5 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, are 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." The Reform Act provides certain exemptions from these regulations for commercial end-users that use derivatives to hedge and manage the commercial risk of their businesses. 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.

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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, 2010. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2010.

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, 2010. PacifiCorp's exposure to market risk and its management of such risk has not changed materially since December 31, 2010. Refer to Note 5 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, 2011.

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 United States Securities and Exchange Commission'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, 2011 that has materially affected, or is reasonably likely to materially affect, PacifiCorp's internal control over financial reporting.

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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, 2010 and Part II, Item 1 of each of PacifiCorp's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2011 and June 30, 2011.

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, but postponed the trial just before it was set to begin. In September 2011, the case was assigned to a new judge who established a new trial date beginning April 2012. 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, 2010.

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)

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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 MSHA under the 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- and nine-month periods ended September 30, 2011. Legal actions pending before the Federal Mine Safety and Health Review Commission, which are not exclusive to citations, notices, orders and penalties assessed by MSHA, are as of September 30, 2011. Closed or idled mines have been excluded from the table below as no citations, orders or notices were issued for such mines during the nine-month period ended September 30, 2011. In addition, there were no fatalities at PacifiCorp's coal mines or coal processing facilities during the nine-month period ended September 30, 2011.

	Mine Safety Act
Coal Mine or Coal Processing Facility	Section 104 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
Three-month period ended September 30, 2011
Deer Creek	7	—	—	—	—	—	$	9	12
Bridger (surface)	—	—	—	—	—	—	1		6
Bridger (underground)	6	—	—	—	—	—	54		18
Cottonwood Preparatory Plant	—	—	—	—	—	—	—		—
Wyodak Coal Crushing Facility	—	—	—	—	—	—	—		—
Nine-month period ended September 30, 2011
Deer Creek	14	—	—	—	—	—	$	29	12
Bridger (surface)	6	—	—	—	—	—	10		6
Bridger (underground)	32	1	—	—	—	—	120		18
Cottonwood Preparatory Plant	1	—	—	—	—	—	—		—
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.

Item 6. Exhibits

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

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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 4, 2011	/s/ Douglas K. Stuver
	Douglas K. Stuver
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

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EXHIBIT INDEX

Exhibit No.	Description
4.1*	Twenty-Fourth Supplemental Indenture, dated as of May 1, 2011, to PacifiCorp's Mortgage and Deed of Trust dated as of January 9, 1989 (Exhibit 4.1, Current Report on Form 8-K, filed May 12, 2011, File No. 1-5152).
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.
101	The following financial information from PacifiCorp's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Comprehensive Income, and (vi) the Notes to Consolidated Financial Statements, tagged as blocks of text.
*	Incorporated herein by reference.

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