PACIFICORP /OR/ - Quarter Report: 2006 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ________________

Commission file number: 1-5152

PacifiCorp

(Exact name of registrant as specified in its charter)

State of Oregon
(State or other jurisdiction of
incorporation or organization)

93-0246090
(I.R.S. Employer
Identification No.)

825 N.E. Multnomah Street, Portland, Oregon
(Address of principal executive offices)

97232
(Zip Code)

503-813-5000

(Registrant’s telephone number, including area code)

None

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

Large accelerated filer o Accelerated filer o Non-accelerated filer x

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class		Outstanding at October 27, 2006

Common Stock, no par value		357,060,915 shares

All shares of outstanding common stock are indirectly owned by MidAmerican Energy Holdings Company, 666 Grand Avenue, Des Moines, Iowa.

PACIFICORP

		Page No.

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited):
	Report of Independent Registered Public Accounting Firm	2
	Consolidated Statements of Income and Retained Earnings	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Cash Flows	6
	Notes to the Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 4.	Controls and Procedures	29
PART II.	OTHER INFORMATION	30
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Submission of Matters to a Vote of Security Holders	30
Item 5.	Other Information	30
Item 6.	Exhibits	31
Signature		32

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of PacifiCorp:

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and its subsidiaries (“PacifiCorp”) as of September 30, 2006, and the related consolidated statements of income and retained earnings for the three and six-month periods ended September 30, 2006, and of cash flows for the six-month period ended September 30, 2006. These interim financial statements are the responsibility of PacifiCorp’s management.

We conducted our review 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 review, we are not aware of any material modifications that should be made to such consolidated interim financial statements as of September 30, 2006, and for the three- and six-month periods then ended for them to be in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial information as of March 31, 2006, and for the three- and six-month periods ended September 30, 2005, were not audited or reviewed by us and, accordingly, we do not express an opinion or any form of assurance on them.

/s/ Deloitte & Touche LLP

Portland, Oregon

November 3, 2006

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

(Unaudited)

	Three Months Ended September 30,						Six Months Ended September 30,

(Millions of dollars)	2006			2005			2006			2005

Revenues	$	1,097.4		$	620.7		$	1,957.3		$	1,502.1

Operating expenses:
Energy costs		566.7			115.1			902.7			467.5
Operations and maintenance		253.2			239.4			512.8			497.1
Depreciation and amortization		118.3			112.3			234.0			223.2
Taxes, other than income taxes		26.7			24.7			52.9			49.2

Total		964.9			491.5			1,702.4			1,237.0

Income from operations		132.5			129.2			254.9			265.1

Interest expense and other (income) expense:
Interest expense		72.3			70.1			141.5			139.4
Interest income		(2.5	)		(1.9	)		(4.1	)		(4.6	)
Allowance for borrowed funds		(6.4	)		(4.0	)		(11.2	)		(8.4	)
Allowance for equity funds		(5.8	)		(2.5	)		(11.8	)		(5.1	)
Other		(1.8	)		(0.6	)		(2.2	)		(2.6	)

Total		55.8			61.1			112.2			118.7

Income from operations before income tax expense		76.7			68.1			142.7			146.4
Income tax expense		17.3			28.7			40.7			60.6

Net income		59.4			39.4			102.0			85.8
Preferred dividend requirement		(0.5	)		(0.5	)		(1.0	)		(1.0	)

Earnings on common stock	$	58.9		$	38.9		$	101.0		$	84.8

RETAINED EARNINGS AT BEGINNING OF PERIOD	$	672.1		$	441.5		$	630.0		$	446.4
Net income		59.4			39.4			102.0			85.8
Cash dividends declared:
Preferred stock		(0.5	)		(0.5	)		(1.0	)		(1.0	)
Common stock		—			(52.8	)		—			(103.6	)

RETAINED EARNINGS AT END OF PERIOD	$	731.0		$	427.6		$	731.0		$	427.6

The accompanying notes are an integral part of these Consolidated Financial Statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(Millions of dollars or shares)	September 30, 2006			March 31, 2006

ASSETS
Current assets:
Cash and cash equivalents	$	67.8		$	119.6
Accounts receivable, net of allowance for doubtful accounts of $12.0/September and $11.4/March		346.8			266.8
Unbilled revenue		163.1			148.2
Inventories at average costs:
Materials and supplies		135.3			131.2
Fuel		91.5			80.9
Current derivative contract asset		174.7			221.7
Deferred income taxes		6.7			—
Other		75.3			46.9

Total current assets		1,061.2			1,015.3

Property, plant and equipment		15,604.5			15,102.4
Accumulated depreciation and amortization		(5,783.1	)		(5,611.5	)

		9,821.4			9,490.9
Construction work-in-progress		813.1			618.3

Total property, plant and equipment, net		10,634.5			10,109.2

Other assets:
Regulatory assets		867.3			884.3
Derivative contract regulatory asset		212.5			94.7
Non-current derivative contract asset		271.0			345.3
Deferred charges and other		287.8			282.5

Total other assets		1,638.6			1,606.8

Total assets	$	13,334.3		$	12,731.3

The accompanying notes are an integral part of these Consolidated Financial Statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, continued

(Unaudited)

(Millions of dollars or shares)	September 30, 2006			March 31, 2006

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	376.3		$	361.3
Accrued employee expenses		98.8			118.0
Taxes payable		60.6			50.8
Interest payable		65.9			63.0
Current derivative contract liability		119.9			97.9
Deferred income taxes		—			16.9
Long-term debt and capital lease obligations, currently maturing		325.5			216.9
Preferred stock subject to mandatory redemption, currently maturing		37.5			3.7
Notes payable and commercial paper		79.7			184.4
Other		125.8			103.2

Total current liabilities		1,290.0			1,216.1

Deferred credits:
Deferred income taxes		1,610.7			1,621.2
Investment tax credits		63.7			67.6
Regulatory liabilities		816.9			804.7
Non-current derivative contract liability		505.1			461.2
Pension and other post employment liabilities		388.9			385.0
Other		381.4			361.4

Total deferred credits		3,766.7			3,701.1

Long-term debt and capital lease obligations, net of current maturities		3,960.0			3,721.0
Preferred stock subject to mandatory redemption, net of current maturities		—			41.3

Total liabilities		9,016.7			8,679.5

Commitments and contingencies (See Note 4)
Shareholders’ equity:
Preferred stock		41.3			41.3

Common equity:
Common shareholder’s capital (357.1 no par shares issued and outstanding)		3,529.5			3,381.9
Retained earnings		731.0			630.0
Accumulated other comprehensive (loss) income:
Unrealized gain on derivative contracts, net of tax of $10.9/September		17.8			—
Unrealized gain on available-for-sale securities, net of tax of $1.3/September and $1.7/March		2.1			2.7
Minimum pension liability, net of tax of ($2.5)/September and March		(4.1	)		(4.1	)

Total common equity		4,276.3			4,010.5

Total shareholders’ equity		4,317.6			4,051.8

Total liabilities and shareholders’ equity	$	13,334.3		$	12,731.3

The accompanying notes are an integral part of these Consolidated Financial Statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended September 30,

(Millions of dollars)	2006			2005

Cash flows from operating activities:
Net income	$	102.0		$	85.8
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized loss on derivative contracts, net		98.1			46.0
Depreciation and amortization		234.0			223.2
Deferred income taxes and investment tax credits, net		(39.9	)		(9.3	)
Regulatory asset/liability establishment and amortization		15.5			36.8
Other		27.1			11.2
Changes in:
Accounts receivables, net and other current assets		(98.9	)		(62.5	)
Inventories		(14.7	)		(7.4	)
Amounts due to/from affiliates - Scottish Power, net		—			(20.4	)
Accounts payable and accrued liabilities		49.8			(58.1	)
Pension and post employment costs and other		(17.9	)		0.7

Net cash provided by operating activities		355.1			246.0

Cash flows from investing activities:
Capital expenditures		(780.5	)		(470.0	)
Proceeds from available-for-sale securities		46.3			85.3
Purchases of available-for-sale securities		(59.8	)		(45.8	)
Other		8.1			(2.8	)

Net cash used in investing activities		(785.9	)		(433.3	)

Cash flows from financing activities:
Changes in short-term debt		(104.7	)		(172.5	)
Proceeds from long-term debt, net of issuance costs		346.3			296.0
Proceeds from equity contributions		145.2			250.0
Dividends paid		(1.0	)		(104.6	)
Repayments of long-term debt and capital lease obligations		(0.3	)		(150.0	)
Redemptions of preferred stock		(7.5	)		(7.5	)
Other		1.0			—

Net cash provided by financing activities		379.0			111.4

Change in cash and cash equivalents		(51.8	)		(75.9	)
Cash and cash equivalents at beginning of period		119.6			199.3

Cash and cash equivalents at end of period	$	67.8		$	123.4

The accompanying notes are an integral part of these Consolidated Financial Statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Basis of Presentation and Summary of Significant Accounting Policies

PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electric utility company serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and also engages in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining and other fuel-related services, as well as environmental remediation. The Consolidated Financial Statements of PacifiCorp include its integrated electric utility operations and its wholly owned and majority-owned subsidiaries. Intercompany transactions and balances have been eliminated upon consolidation. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company (“MEHC”), which is 88.2% owned by Berkshire Hathaway Inc.

The accompanying unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and the instructions for the United States Securities and Exchange Commission (the “SEC”) Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. In the opinion of management, the unaudited Consolidated Financial Statements include all adjustments, including normal recurring adjustments, considered necessary for a fair presentation of the financial position as of September 30, 2006, the results of operations for the three and six months ended September 30, 2006 and 2005 and the cash flows for the six months ended September 30, 2006 and 2005. The March 31, 2006 Consolidated Balance Sheet data was derived from audited financial statements. A portion of PacifiCorp’s business is of a seasonal nature and, therefore, results of operations for the three and six months ended September 30, 2006 and 2005 are not necessarily indicative of the results for a full year. These Consolidated Financial Statements should be read in conjunction with the financial statements and related notes in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006.

These interim statements have been prepared using accounting policies consistent with those applied at March 31, 2006, except in relation to new accounting standards described below and the implementation of cash flow hedge accounting described in Note 2 - Derivative Instruments.

In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. PacifiCorp’s report covering the transition period beginning April 1, 2006 and ending December 31, 2006 will be filed on Form 10-K.

Reclassifications

Certain reclassifications of prior years’ amounts have been made to conform to the current year’s method of presentation. These reclassifications had no effect on previously reported consolidated net income.

New Accounting Standards

FIN 48

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes– an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. PacifiCorp is currently evaluating the impact of adopting FIN 48 on its consolidated financial position and results of operations.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for establishing fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair

value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. PacifiCorp is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS No. 158”). SFAS No. 158 requires an employer to recognize an asset or liability for the overfunded or underfunded status of a defined benefit postretirement plan measured as the difference between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree healthcare plan, the benefit obligation is the accumulated postretirement benefit obligation.

SFAS No. 158 also requires entities to recognize as a component of other comprehensive income, net of tax, the actuarial gains and losses and prior service costs and credits that arise during the period, but that were not recognized as components of net periodic benefit cost of the period pursuant to SFAS No 87, Employers’ Accounting for Pensions (“SFAS No. 87”), and SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (“SFAS No. 106”). However, as PacifiCorp is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (“SFAS No. 71”), the adjustments to accumulated other comprehensive income would be recognized as a regulatory asset if it is considered probable that the amounts would be recovered in future retail rates when recognized through net periodic benefit cost. SFAS No. 158 does not impact the calculation of net periodic benefit cost. Amounts recorded either in accumulated other comprehensive income or as a regulatory asset will be adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of SFAS No. 87 and SFAS No. 106.

SFAS No. 158 also requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87, Employers’ Accounting for Pensions, to measure up to three months prior to the financial statement date. The recognition and related disclosure provisions of SFAS No. 158 are effective for fiscal years ending after December 15, 2006, while the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. SFAS No. 158 is to be applied prospectively. PacifiCorp is currently evaluating the impact of adopting SFAS No. 158 on its consolidated financial position and results of operations.

Note 2 - Derivative Instruments

PacifiCorp’s derivative instruments are recorded on the Consolidated Balance Sheets as assets or liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). Changes in the fair value of derivatives are recognized in earnings during the period of change, except for contracts designated as cash flow hedges or that are probable of recovery in retail rates. Changes in the fair value of short- and long-term contracts probable of recovery in retail rates are deferred as regulatory assets or liabilities pursuant to SFAS No. 71.

Unrealized gains and losses on derivative contracts not held for trading purposes are presented in the Consolidated Statements of Income and Retained Earnings as Revenues for sales contracts and as Energy costs and Operations and maintenance expense for purchase contracts and financial swaps. Unrealized and realized gains and losses from all derivative contracts held for trading purposes, including those where physical delivery is required, are recorded on a net basis in the Consolidated Statements of Income and Retained Earnings as Revenues.

The following table summarizes the changes in fair value of PacifiCorp’s derivative contracts from March 31, 2006 to September 30, 2006, as well as the changes in fair value of those derivative contracts that have been recognized as a net regulatory asset (liability) because the contracts are probable of receiving recovery in retail rates.

	Net Asset (Liability)						Net Regulatory Asset (Liability)

(Millions of dollars)	Trading			Non-trading

Fair value of contracts outstanding at March 31, 2006	$	0.2		$	7.7		$	94.7
Contracts realized or otherwise settled during the period		0.1			(26.3	)		(29.6	)
Change in valuation technique (a)		—			(23.0	)		23.0
Change in estimate of recoverability (b)		—			—			(40.3	)
Other changes in fair values (c)		(3.4	)		(134.6	)		164.7

Fair value of contracts outstanding at September 30, 2006	$	(3.1	)	$	(176.2	)	$	212.5

______________

(a)

Effective August 31, 2006, PacifiCorp enhanced its valuation techniques for long-term contracts by changing from a best-estimate forecast to a probability-weighted expected value approach for valuing the long-dated (periods subsequent to September 30, 2012) natural gas price forecast. This approach results in a measurement that is more representative of the fair value of forward long-term contracts This change had the effect of decreasing the fair value of contracts by $23.0 million, offset by an increase in net regulatory assets by the same amount.

(b)

During the three months ended September 30, 2006, PacifiCorp reached a new general rate case stipulation with several parties in Utah and received approval from the Oregon Public Utility Commission for a new general rate case settlement in Oregon. Utah and Oregon together account for approximately 70.0% of PacifiCorp’s retail electric operating revenues. Based on management’s consideration of the two new rate settlements, as well as the net power cost recovery adjustment clauses obtained in Wyoming and California earlier in 2006, PacifiCorp changed its estimate of the contracts receiving recovery in retail rates. Effective July 21, 2006, PacifiCorp recorded a $40.3 million decrease in net regulatory assets for previously recorded net unrealized gains related to contracts that it determined were probable of being recovered in retail rates with a corresponding pre-tax charge to net income of $43.9 million and a pre-tax increase to Accumulated other comprehensive income of $3.6 million.

(c)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts.

The following table summarizes where the pre-tax changes in the fair value of derivative contracts were included in the Consolidated Financial Statements:

	Six Months Ended September 30,
(Millions of dollars)	2006

Change in net derivative asset (liability) included in:
Income from operations	$	(98.1	)
Change in Regulatory net asset/liability		(117.8	)
Other comprehensive income		28.7

Change in net derivative asset (liability)	$	(187.2	)

The following table summarizes the amount of the pre-tax unrealized gains and losses included within the Consolidated Statements of Income and Retained Earnings associated with changes in the fair value of PacifiCorp’s derivative contracts that are not included in retail rates or designated as cash flow hedges and include the amounts related to the change in estimate described above.

	Three Months Ended September 30,						Six Months Ended September 30,

(Millions of dollars)	2006			2005			2006			2005

Revenues	$	80.7		$	(361.6	)	$	54.5		$	(293.0	)
Operating expenses:
Energy costs		(146.0	)		302.6			(152.8	)		247.9
Operations and maintenance		(1.2	)		0.8			0.2			(0.9	)

Total unrealized loss on derivative contracts	$	(66.5	)	$	(58.2	)	$	(98.1	)	$	(46.0	)

Cash Flow Hedging

In order to reduce the impact of fluctuations in forward prices of electricity and natural gas on PacifiCorp’s results of operations, PacifiCorp initiated cash flow hedging in April 2006 for a portion of its derivative contracts, primarily comprised of electricity sales and natural gas purchase contracts. Changes in the fair value of derivative contracts designated as cash flow hedges are recorded as other comprehensive income to the extent the hedges are effective in offsetting changes in future cash flows for forecasted electricity and natural gas purchase and sales transactions. Amounts included in Accumulated other comprehensive income are reclassified to Revenues or Energy costs when the forecasted sale or purchase transaction is recognized in earnings, or when it is probable that the forecasted transaction will not occur.

At September 30, 2006, PacifiCorp had cash flow hedges with expiration dates through December 2006. During the six months ended September 30, 2006, hedge ineffectiveness was an accumulated $0.4 million pre-tax gain. At September 30, 2006, $28.7 million of pre-tax net unrealized gains are forecasted to be reclassified from Accumulated other comprehensive income into earnings over the next three months as contracts settle. However, the actual amount reclassified into earnings may vary from the amounts recorded as of September 30, 2006 due to future price changes. Hedge ineffectiveness and reclassifications from Accumulated other comprehensive income to earnings are presented in Revenues for sales contracts and contracts held for trading purposes and in Energy costs for purchase contracts and financial swaps.

Foreign Currency Derivatives

PacifiCorp has entered into an agreement with a turbine supplier in connection with the construction of a wind project that requires PacifiCorp to make certain payments in Eurodollars (“€”). To mitigate the related exposure to fluctuations in foreign currency exchange rates, PacifiCorp entered into a forward contract to purchase €76.8 million at a fixed price of U.S. dollars. This contract has a series of payments and settlement dates extending to March 15, 2007 that correspond to the payments to be made in Eurodollars in accordance with the supply agreement. The forward contract qualifies as a derivative instrument under SFAS No. 133. As the cost of the associated wind project is expected to be recovered in retail rates, the unrealized loss on this contract of $0.2 million at September 30, 2006 was recorded as a regulatory asset.

Weather Derivatives

PacifiCorp had a non-exchange traded streamflow weather derivative contract to reduce PacifiCorp’s exposure to variability in weather conditions that affect hydroelectric generation. Under this agreement, which expired on September 30, 2006, PacifiCorp paid an annual premium in return for the right to make or receive payments if streamflow levels were above or below certain thresholds. PacifiCorp estimates and records an asset or liability corresponding to the total expected future cash flows in accordance with Emerging Issues Task Force No. 99-2, Accounting for Weather Derivatives. The net liability recorded for this contract was $4.0 million at September 30, 2006 and $2.1 million at March 31, 2006. PacifiCorp recognized losses on this contract of $3.1 million for the three months ended September 30, 2006; $3.4 million for the three months ended September 30, 2005; $12.4 million for the six months ended September 30, 2006; and $15.6 million for the six months ended September 30, 2005.

Note 3 - Financing Arrangements

In August 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1, 2036. PacifiCorp used the proceeds for general corporate purposes, including the reduction of short-term debt.

PacifiCorp amended and restated its existing $800.0 million committed bank revolving credit agreement in July 2006. Changes included the extension of the termination date from August 29, 2010 to July 6, 2011.

Note 4 - Commitments and Contingencies

PacifiCorp follows SFAS No. 5, Accounting for Contingencies, to determine accounting and disclosure requirements for contingencies. PacifiCorp operates in a highly regulated environment. Governmental bodies such as the Federal Energy Regulatory Commission (the “FERC”), state regulatory commissions, the SEC, the Internal Revenue Service, the Department of Labor, the United States Environmental Protection Agency and others have authority over various aspects of PacifiCorp’s business operations and public reporting. Reserves are established when required, in management’s judgment, and disclosures regarding litigation, assessments and creditworthiness of customers or counterparties, among others, are made when appropriate. The evaluation of these contingencies is performed by various specialists inside and outside of PacifiCorp.

From time to time, PacifiCorp is also a party to various legal claims, actions, complaints and disputes, certain of which involve material amounts. PacifiCorp has recorded $8.9 million in reserves as of September 30, 2006 related to various outstanding legal actions and disputes, excluding those discussed below. This amount represents PacifiCorp’s best estimate of probable losses related to these matters. PacifiCorp currently believes that disposition of these matters will not have a material adverse effect on PacifiCorp’s consolidated financial position, results of operations or liquidity.

Environmental Matters

PacifiCorp is subject to numerous environmental laws, including the Federal Clean Air Act and various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws could potentially impact future operations. Environmental contingencies identified at September 30, 2006 principally consist of air quality matters. Pending or proposed air regulations would, if enacted, require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxides and other pollutants below current levels. These reductions would be required to address regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. In the future, PacifiCorp may incur significant costs to comply with various stricter air emissions requirements. These potential costs are expected to consist primarily of capital expenditures and would be included in rates and, as such, would not have a material adverse impact on PacifiCorp’s consolidated financial position or results of operations. Environmental remediation liabilities recorded at September 30, 2006 totaled $42.0 million.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 50 plants with an aggregate plant net capacity of 1,139.4 megawatts (“MW”). The FERC regulates 93.9% of the installed capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing under the Federal Power Act. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of additional relicensing costs, operations and maintenance expense and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. As of September 30, 2006, PacifiCorp had incurred $76.5 million in costs for ongoing hydroelectric relicensing, which are reflected in Construction work-in-progress on the Consolidated Balance Sheet. PacifiCorp expects that these and future costs will be included in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated financial position or results of operations.

In May 2006, the FERC approved PacifiCorp’s application to amend the Bear River license to remove the 7.5-MW nameplate-rated Cove hydroelectric plant and facilities. Removal of the Cove dam was completed in September 2006.

California Refund Case

PacifiCorp is a party to a FERC proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices. PacifiCorp has a reserve of $17.7 million for these potential refunds. PacifiCorp’s ultimate exposure

to refunds is dependent upon any order issued by the FERC in this proceeding. In addition, beginning in summer 2000, California market conditions resulted in defaults of amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator and California Power Exchange. PacifiCorp has reserved $5.0 million for these receivables.

Note 5 – Common Shareholder’s Equity

PacifiCorp received capital contributions in cash of $145.2 million during the six months ended September 30, 2006 from its direct parent, PPW Holdings LLC, a subsidiary of MEHC.

Note 6 – Employee Benefits

The components of net periodic benefit cost for the three and six months ended September 30, 2006 and 2005 are as follows:

	Retirement Plans

	Three Months Ended September 30,						Six Months Ended September 30,

(Millions of dollars)	2006			2005			2006			2005

Service cost	$	11.6		$	7.7		$	19.1		$	15.4
Interest cost		18.8			18.6			37.6			37.2
Expected return on plan assets (a)		(18.1	)		(19.2	)		(36.2	)		(38.4	)
Amortization of unrecognized net obligation		0.6			2.1			1.3			4.2
Amortization of unrecognized prior service cost		0.3			0.3			0.6			0.6
Amortization of unrecognized loss		6.6			5.3			13.3			10.7
Cost of termination benefits		0.3			—			0.6			—
Curtailment loss (b)		—			—			0.7			—

Net periodic benefit cost	$	20.1		$	14.8		$	37.0		$	29.7

	Other Postretirement Benefits

	Three Months Ended September 30,						Six Months Ended September 30,

(Millions of dollars)	2006			2005			2006			2005

Service cost	$	2.2		$	2.2		$	4.5		$	4.4
Interest cost		8.2			7.6			16.4			15.2
Expected return on plan assets (a)		(6.4	)		(6.5	)		(12.9	)		(13.1	)
Amortization of unrecognized net obligation		3.0			3.0			6.0			6.1
Amortization of unrecognized prior service cost		0.7			0.5			1.4			1.0
Amortization of unrecognized loss		1.4			0.6			2.9			1.3

Net periodic benefit cost	$	9.1		$	7.4		$	18.3		$	14.9

(a)	The market-related value of plan assets, among other factors, is used to determine expected return on plan assets and is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning in the first year in which they occur.

(b)	Represents the curtailment loss related to the Supplemental Executive Retirement Plan.

Employer Contributions

PacifiCorp contributed $78.6 million to its retirement plans and $0.1 million to its other postretirement benefit plan during the six months ended September 30, 2006. PacifiCorp expects to contribute another $2.6 million to its retirement plans and $27.4 million to its other postretirement benefit plan during the three months ending December 31, 2006.

Severance

PacifiCorp has undertaken a review of its organization and workforce. As a result of the review, PacifiCorp incurred severance expense of $14.8 million during the three months ended September 30, 2006 compared to $1.5 million during the three months ended September 30, 2005; and $23.0 million during the six months ended September 30, 2006 compared to $5.5 million during the six months ended September 30, 2005.

Note 7 - Income Taxes

PacifiCorp uses an estimated annual effective tax rate for computing the provision for income taxes on an interim basis. The difference between taxes calculated as if the United States federal statutory tax rate of 35.0% was applied to income from operations before income taxes and the recorded income tax expense is reconciled as follows:

	Six Months Ended September 30,

	2006		2005

Federal statutory rate	35.0	%	35.0	%
State taxes, net of federal benefit	3.3		3.3
Effect of regulatory treatment of depreciation differences	5.9		6.3
Tax reserves and settlements (a)	(7.4	)	2.5
Tax credits (b)	(5.9	)	(3.0	)
Other	(2.4	)	(2.7	)

Effective income tax rate	28.5	%	41.4	%

(a)

PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Consolidated Balance Sheets to provide for the possibility of adverse outcomes in tax proceedings. In addition, tax benefits are recognized in the period in which resolution is reached with the taxing authorities. The current year benefit is primarily attributable to resolution of certain items previously outstanding with the Internal Revenue Service related to the examination of tax years ended March 31, 2001 through March 31, 2003. PacifiCorp anticipates that the resolution of the remaining outstanding issues related to the federal income tax returns through March 31, 2003 will not have a material adverse impact on its consolidated financial position or results of operations.

(b)	PacifiCorp earned higher tax credits during the six months ended September 30, 2006 due to federal and state tax credits earned through the investment in and operation of renewable energy resources.

Note 8 - Comprehensive Income

The components of comprehensive income are as follows:

	Three Months Ended September 30,				Six Months Ended September 30,

(Millions of dollars)	2006		2005		2006			2005

Net income	$	59.4	$	39.4	$	102.0		$	85.8
Other comprehensive income:
Unrealized gain on derivative contracts, net of tax of $13.5 and $10.9/2006		22.0		—		17.8			—
Unrealized gain (loss) on available-for-sale securities, net of tax of $0.9 and $(0.4)/2006 and $0.1 and $(0.3)/2005		1.5		0.1		(0.6	)		(0.6	)

Total comprehensive income	$	82.9	$	39.5	$	119.2		$	85.2

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

The Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.

PacifiCorp is a regulated electric utility company serving approximately 1.7 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commission in each state approves rates for retail electric sales within that state. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and incorporated municipalities. Wholesale activities are regulated by the Federal Energy Regulatory Commission (the “FERC”). PacifiCorp owns, or has interests in, 69 thermal, hydroelectric and wind generating plants with a net plant owned capacity of 8,550.4 megawatts (“MW”). The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric generation facilities. PacifiCorp delivers electricity through approximately 59,500 miles of distribution lines and approximately 15,600 miles of transmission lines.

In July 2006, PacifiCorp changed its Pacific Power and Utah Power operating brand names in Wyoming, Utah and Idaho to Rocky Mountain Power. PacifiCorp will continue to operate under the brand name Pacific Power in Oregon, Washington and California.

Forward-Looking Statements

This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, made in this report are forward-looking. When used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report, the words “may,” “could,” “believes,” “estimates,” “expects,” “anticipates,” “forecasts,” “plans,” “intends,” “projected,” “potential” and variations of such words and similar expressions are intended to identify forward-looking statements. Forward-looking statements included in this report relate to, among other matters, the effect on PacifiCorp of the following: potential adjustment of regulatory rates to cover costs; the impact of new accounting standards or accounting policy changes; the outcome of litigation or regulatory proceedings and rulemaking; the timing of future regulatory filings or proceedings; environmental laws; capital expenditure levels; results from, and the timing of, the construction or repair of generating facilities; hydroelectric relicensing and decommissioning activities; pension and other postretirement contributions; future dividends on common stock; off-balance sheet arrangements; the effect of risk management measures, including derivative instruments used for hedging and system balancing purposes; fluctuations in forward prices for electricity and natural gas; and the efficiency and effectiveness of PacifiCorp’s resource and fuel procurement and related planning. Forward-looking statements reflect management’s current expectations, plans or projections and are inherently uncertain. There can be no assurance the results predicted will be realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The following are among the factors that could cause actual results to differ materially from the forward-looking statements:

•	The outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies, including any related commitments by PacifiCorp or restrictions on its future activities;

•	Changes in prices and availability for both purchases and sales of wholesale electricity, natural gas and other fuel sources that could have a significant impact on generation capacity and cost and changes in other operating costs that could affect PacifiCorp’s cost recovery;

•

Changes in legislation or regulatory requirements, including continued implementation of the Energy Policy Act of 2005, legislative or regulatory outcomes limiting the ability of public utilities to recover income tax expense in retail rates such as Oregon Senate Bill 408 and related rules, industry restructuring and deregulation initiatives;

•	Industrial, commercial and residential customer growth and demographic patterns in PacifiCorp’s service territories;

•	Changes in economic or weather conditions or the occurrence of other natural events that could affect electricity usage or supply;

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

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

•	Performance of PacifiCorp’s generation facilities, including the level of planned and unplanned outages;

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

•	Changes resulting from MidAmerican Energy Holdings Company (“MEHC”) ownership;

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

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

•	Continued availability of funds to meet liquidity requirements;

•	The impact of any required performance under off-balance sheet arrangements;

•	Financial condition and creditworthiness of significant customers and suppliers;

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

•	Changes in PacifiCorp’s credit ratings;

•

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

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

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

•	The risks discussed in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006 and its other reports filed with the SEC.

Any forward-looking statements issued by PacifiCorp should be considered in light of these factors. PacifiCorp does not intend to update or revise any forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting such forward-looking statements or if PacifiCorp later becomes aware that these assumptions are not likely to be achieved.

Accounting Matters

Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the Consolidated Financial Statements. The estimates and assumptions may change as time passes and accounting guidance evolves. Management bases its estimates and assumptions on historical experience and on other various judgments that it believes are reasonable at the time of application. Changes in these estimates and assumptions could have a material impact on the Consolidated Financial Statements.

If estimates and assumptions are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Any critical accounting estimates, in addition to certain less significant accounting estimates, are discussed with senior members of management and PacifiCorp’s Board of Directors, as appropriate, and are disclosed to the MEHC Audit Committee. Those policies with estimates that management considers critical are Derivatives, Pensions and Other Postretirement Benefits, Regulation, Unbilled Revenues and Contingencies, which are described in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006 under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” During the six months ended September 30, 2006, PacifiCorp made the following changes in its derivative accounting estimates as discussed in “Part I - Item 1. Financial Statements – Note 2 – Derivatives:”

•	PacifiCorp changed its estimate of the number of derivative contracts probable of receiving recovery in retail rates as a result of the Utah general rate case stipulation and the general rate case settlement in Oregon in July 2006; and

•	PacifiCorp enhanced its valuation technique for certain long-term derivative contracts in August 2006 by changing from a best-estimate approach to a probability-weighted approach.

For new accounting standards, see “Part I – Item 1. Financial Statements – Note 1 – Basis of Presentation and Summary of Significant Accounting Policies,” which are incorporated by reference into this Item 2.

RESULTS OF OPERATIONS

Overview

PacifiCorp’s net income was $102.0 million for the six months ended September 30, 2006 compared to $85.8 million for the six months ended September 30, 2005. The increase in net income was primarily due to higher retail prices approved by regulators, higher output from hydroelectric generation plants, higher margins on wholesale system balancing activities and a lower effective tax rate, partially offset by higher net unrealized losses on derivative contracts, higher severance costs and higher depreciation expense due to higher plant in service.

Output from PacifiCorp-owned hydroelectric facilities for the six months ended September 30, 2006 increased by 185,448 megawatt-hours (“MWh”), or 11.7%, compared to the six months ended September 30, 2005. This increase was primarily attributable to current-year water conditions that improved relative to the prior-year period. PacifiCorp’s hydroelectric generation was 102.5% of normal for the six months ended September 30, 2006, compared to 87.6% of normal for the six months ended September 30, 2005, based on a 30-year average. Output from PacifiCorp’s thermal plants decreased by 90,576 MWh, or 0.4%, during the six months ended September 30, 2006 compared to the six months ended September 30, 2005.

Net unrealized losses on derivative contracts were $98.1 million during the six months ended September 30, 2006 compared to net unrealized losses of $46.0 million during the six months ended September 30, 2005. The increase in net unrealized losses was due to $46.4 million of higher net unrealized losses on contracts that settled during the current period and $43.9 million of net unrealized losses in the current period resulting from the change in estimate of contracts considered probable of receiving recovery in retail rates due to regulatory settlements in Utah and Oregon, partially offset by $38.2 million of higher net unrealized gains due to net favorable movements in forward prices. See discussion of the change in estimate at “Part I - Item 1. Financial Statements – Note 2 – Derivatives.”

See “Regulation” below for a state-by-state update of regulatory matters.

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

Revenues

	Three Months Ended September 30,					Favorable/ (Unfavorable)

(Millions of dollars)	2006		2005			$ Change			% Change

Retail	$	803.3	$	755.0		$	48.3		6.4	%
Wholesale sales and other		294.1		(134.3	)		428.4		319.0

Total revenues	$	1,097.4	$	620.7		$	476.7		76.8

Retail energy sales (thousands of MWh)		13,704		13,236			468		3.5
Wholesale energy sales (thousands of MWh)		3,401		3,614			(213	)	(5.9	)
Total retail customers (in thousands)		1,655		1,618			37		2.3

Retail revenues increased $48.3 million, or 6.4%, primarily due to:

•	$24.3 million of increases from higher retail prices approved by regulators;

•	$18.4 million of increases due to higher average customer usage, primarily as a result of warmer weather as compared to the prior period; and

•	$12.9 million of increases relating to growth in the number of customers; partially offset by,

•	$7.3 million of decreases due to changes in customer usage at different tariff levels.

Wholesale sales and other revenues increased $428.4 million, or 319.0%, primarily due to:

•	$442.3 million of increases due to changes in the fair value of derivative contracts; and

•	$15.3 million of increases related to non-physically settled system balancing transactions; partially offset by,

•	$20.4 million of decreases primarily due to lower volumes and lower average prices on realized wholesale sales transactions.

Operating Expenses

	Three Months Ended September 30,				Favorable/ (Unfavorable)

(Millions of dollars)	2006		2005		$ Change			% Change

Energy costs	$	566.7	$	115.1	$	(451.6	)	(392.4	)%
Operations and maintenance		253.2		239.4		(13.8	)	(5.8	)
Depreciation and amortization		118.3		112.3		(6.0	)	(5.3	)
Taxes, other than income taxes		26.7		24.7		(2.0	)	(8.1	)

Total operating expenses	$	964.9	$	491.5	$	(473.4	)	(96.3	)

Energy costs increased $451.6 million, or 392.4%, primarily due to:

•	$448.6 million of increases due to changes in the fair value of derivative contracts;

•	$31.2 million of increases related to higher volumes and higher average prices of natural gas consumed; and

•	$3.6 million of increases due to higher wheeling expenses, primarily due to increased rates; partially offset by,

•	$36.3 million of decreases in purchased electricity due to lower volumes and lower average prices.

Operations and maintenance expense increased $13.8 million, or 5.8%, primarily due to:

•	$13.3 million of increases in employee severance costs; partially offset by,

•	$2.5 million of decreases in annual incentive plan expense.

Depreciation and amortization expense increased $6.0 million, or 5.3%, primarily due to higher plant in service.

Interest and Other (Income) Expense

	Three Months Ended September 30,						Favorable/ (Unfavorable)

(Millions of dollars)	2006			2005			$ Change			% Change

Interest expense	$	72.3		$	70.1		$	(2.2	)	(3.1	)%
Interest income		(2.5	)		(1.9	)		0.6		31.6
Allowance for borrowed funds		(6.4	)		(4.0	)		2.4		60.0
Allowance for equity funds		(5.8	)		(2.5	)		3.3		132.0
Other		(1.8	)		(0.6	)		1.2		200.0

Total	$	55.8		$	61.1		$	5.3		8.7

Interest expense increased $2.2 million, or 3.1%, primarily due to higher average variable rates during the three months ended September 30, 2006.

Allowance for borrowed and equity funds increased $5.7 million, primarily due to applying higher prescribed allowance for funds used during construction rates to higher Construction work-in-progress balances during the three months ended September 30, 2006.

Income Tax Expense

Income tax expense decreased $11.4 million, primarily due to:

•	$9.9 million of income tax benefits primarily due to the resolution of certain matters previously outstanding with the Internal Revenue Service; and

•	$3.8 million of decreases primarily due to increases in federal and state tax credits earned through the investment in and operation of renewable energy resources.

Six Months Ended September 30, 2006 Compared to Six Months Ended September 30, 2005

Revenues

	Six Months Ended September 30,				Favorable/ (Unfavorable)

(Millions of dollars)	2006		2005		$ Change			% Change

Retail	$	1,498.3	$	1,397.2	$	101.1		7.2	%
Wholesale sales and other		459.0		104.9		354.1		337.6

Total revenues	$	1,957.3	$	1,502.1	$	455.2		30.3

Retail energy sales (thousands of MWh)		25,871		24,768		1,103		4.5
Wholesale energy sales (thousands of MWh)		6,603		6,733		(130	)	(1.9	)
Total retail customers (in thousands)		1,655		1,618		37		2.3

Retail revenues increased $101.1 million, or 7.2%, primarily due to:

•	$45.4 million of increases due to higher average customer usage, primarily as a result of warmer weather as compared to the previous period;

•	$42.7 million of increases from higher retail prices approved by regulators; and

•	$23.7 million of increases relating to growth in the number of customers; partially offset by,

•	$10.9 million of decreases due to changes in customer usage at different tariff levels.

Wholesale sales and other revenues increased $354.1 million, or 337.6%, primarily due to:

•	$347.5 million of increases due to changes in the fair value of derivative contracts; and

•	$27.2 million of increases related to non-physically settled system balancing transactions; partially offset by,

•	$9.8 million of decreases primarily due to lower volumes and lower average prices on realized wholesale sales transactions.

Operating Expenses

	Six Months Ended September 30,				Favorable/ (Unfavorable)

(Millions of dollars)		2006		2005	$ Change			% Change

Energy costs	$	902.7	$	467.5	$	(435.2	)	(93.1	)%
Operations and maintenance		512.8		497.1		(15.7	)	(3.2	)
Depreciation and amortization		234.0		223.2		(10.8	)	(4.8	)
Taxes, other than income taxes		52.9		49.2		(3.7	)	(7.5	)

Total operating expenses	$	1,702.4	$	1,237.0	$	(465.4	)	(37.6	)

Energy costs increased $435.2 million, or 93.1%, primarily due to:

•	$400.7 million of increases due to changes in the fair value of derivative contracts;

•	$33.3 million of increases related to higher volumes and higher average prices of natural gas consumed; and

•	$8.0 million of increases due to higher wheeling expenses, primarily due to increased rates; partially offset by,

•	$4.5 million of decreases in purchased electricity due to the impact of lower prices net of higher volumes; and

•	$3.2 million of decreases related to lower losses on the fair value of streamflow weather derivative contracts compared to the prior year.

Operations and maintenance expense increased $15.7 million, or 3.2%, primarily due to:

•	$17.5 million of increases in employee severance costs; and

•	$4.3 million of increases in employee expenses primarily due to higher pension and other postretirement benefit costs; partially offset by,

•	$7.6 million of decreases in annual incentive plan expense.

Depreciation and amortization expense increased $10.8 million, or 4.8%, primarily due to higher plant in service.

Interest and Other (Income) Expense

	Six Months Ended September 30,						Favorable/ (Unfavorable)

(Millions of dollars)	2006			2005			$ Change			% Change

Interest expense	$	141.5		$	139.4		$	(2.1	)	(1.5	)%
Interest income		(4.1	)		(4.6	)		(0.5	)	(10.9	)
Allowance for borrowed funds		(11.2	)		(8.4	)		2.8		33.3
Allowance for equity funds		(11.8	)		(5.1	)		6.7		131.4
Other		(2.2	)		(2.6	)		(0.4	)	(15.4	)

Total	$	112.2		$	118.7		$	6.5		5.5

Interest expense increased $2.1 million, or 1.5%, primarily due to higher average variable rates during the six months ended September 30, 2006.

Allowance for borrowed and equity funds increased $9.5 million, primarily due to applying higher prescribed allowance for funds used during construction rates to higher Construction work-in-progress balances during the six months ended September 30, 2006.

Income Tax Expense

Income tax expense decreased $19.9 million, primarily due to:

•	$14.2 million of income tax benefits primarily due to the resolution of certain matters previously outstanding with the Internal Revenue Service; and

•	$4.0 million of decreases primarily due to increases in federal and state tax credits earned through the investment in and operation of renewable energy resources.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities, including additional long-term debt issuances, and also by capital contributions from PacifiCorp’s direct parent company, PPW Holdings LLC. Issuance of longer-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures, market conditions, regulatory approvals and other considerations.

Operating Activities

Net cash flows provided by operating activities increased $109.1 million to $355.1 million for the six months ended September 30, 2006, compared to $246.0 million for the six months ended September 30, 2005, primarily due to the timing of cash collections and payments, higher retail revenues resulting from higher prices and a decrease in net cash collateral requirements, partially offset by an increase in net wholesale receivables due to system balancing activities.

Investing Activities

Capital spending totaled $780.5 million for the six months ended September 30, 2006, compared to $470.0 million for the six months ended September 30, 2005. Capital spending increased primarily due to the purchase of the 100.5-MW Leaning Juniper 1 Wind Plant, initial investment in the 140.4-MW Marengo Wind Plant, as well as ongoing construction of the Lake Side Power Plant, construction and installation of emission control equipment and various capital projects related to transmission and distribution and other generation facilities, partially offset by decreases in expenditures for the construction of the Currant Creek Power Plant, which commenced full combined-cycle operation in March 2006.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt decreased by $104.7 million during the six months ended September 30, 2006, primarily due to the use of proceeds from long-term debt, capital contributions received from PacifiCorp’s direct parent company, PPW Holdings LLC, and the utilization of short-term investments included in Cash and cash equivalents, partially offset by capital expenditures in excess of net cash from operations. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $79.7 million was outstanding at September 30, 2006, with a weighted-average interest rate of 5.3%.

Revolving Credit and Other Financing Agreements

PacifiCorp’s short-term borrowings and certain other financing arrangements are supported by an $800.0 million committed bank revolving credit agreement, which was amended and restated during July 2006. Changes included an extension of the termination date from August 2010 to July 2011. The interest rate on advances under this facility is generally based on the London Interbank Offered Rate (LIBOR) plus a margin that varies based on PacifiCorp’s credit ratings. As of September 30, 2006, this facility was fully available and there were no borrowings outstanding.

At September 30, 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $25.6 million of standby letters of credit to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available as of September 30, 2006 and expire periodically through February 2011.

PacifiCorp’s revolving credit and other financing agreements contain customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 65.0%. At September 30, 2006, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Long-Term Debt

During the six months ended September 30, 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1, 2036.

During the six months ended September 30, 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035 and made scheduled long-term debt repayments of $150.0 million.

Preferred Stock

PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during each of the six months ended September 30, 2006 and 2005.

Common Shareholder’s Capital

PacifiCorp received capital contributions of $145.2 million in cash from its direct parent company, PPW Holdings LLC, during the six months ended September 30, 2006.

PacifiCorp issued 23,354,191 shares of common stock to its former parent company, PacifiCorp Holdings, Inc. (“PHI”), in consideration of the capital contributions of $250.0 million in cash made by PHI during the six months ended September 30, 2005.

Dividends

During the six months ended September 30, 2006, PacifiCorp had the following dividend activity:

•	$2.5 million declared on preferred stock and preferred stock subject to mandatory redemption, of which

$1.5 million was recorded as interest expense; and

•	$2.6 million paid on preferred stock and preferred stock subject to mandatory redemption.

During the six months ended September 30, 2005, PacifiCorp had the following dividend activity:

•	$103.6 million declared and paid on common stock;

•	$2.7 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $1.7 million was recorded as interest expense; and

•	$2.9 million paid on preferred stock and preferred stock subject to mandatory redemption.

Future Uses of Cash

Dividends

No dividends were declared or paid on common stock during the six months ended September 30, 2006. PacifiCorp does not presently anticipate that it will declare dividends on common stock during the three months ending December 31, 2006.

Capital Expenditure Program

As of September 30, 2006, capital expenditures, which exclude the non-cash allowance for equity funds used during construction, are expected to be approximately $1,154.3 million for the nine months ended December 31, 2006. These capital expenditures include $578.7 million for ongoing operational projects, $485.7 million for generation development projects, including renewable resources, and $89.9 million for emissions control equipment to address current and anticipated air quality regulations.

The estimate provided above for generation development projects includes the majority of the remaining costs for the construction of the Lake Side Power Plant, the completion of the Leaning Juniper 1 Wind Plant and investment and construction for the Marengo Wind Plant, as well as contracts for investments in two additional wind plants. These recent wind plant investments partially satisfy the purchase commitments made to state regulatory commissions as part of the March 2006 sale of PacifiCorp to MEHC.

The Lake Side Power Plant is expected to cost approximately $347.0 million, including $13.2 million of non-cash allowance for equity funds used during construction and is scheduled to be completed in May 2007. As of September 30, 2006, $272.5 million has been spent, including $7.6 million of non-cash allowance for equity funds used during construction.

The 100.5-MW Leaning Juniper 1 Wind Plant was purchased in July 2006 and became commercially operational in September 2006. Initial investment in the 140.4-MW Marengo Wind Plant occurred in September 2006 and construction is scheduled to be completed by August 2007.

Capital expenditures are subject to continuing review and revision by PacifiCorp, and actual costs could vary from estimates due to various factors. The estimates of capital expenditures for the nine months ending December 31, 2006 generally exclude the potential impact on generation and transmission capacity of future decisions arising from further stages of PacifiCorp’s various Integrated Resource Plans. Additional expenditures may be significant but are spread over a number of years and cannot be accurately estimated at this time. Based on future decisions arising from the Integrated Resource Plan process, including additional wind generation expenditures to meet regulatory commitments, the estimate of capital expenditures may be revised.

Future Generation and Conservation – Requests for Proposals

In July 2006, PacifiCorp filed its 2012 draft request for proposals under its updated 2004 Integrated Resource Plan with the Utah Public Service Commission (the “UPSC”) and the Oregon Public Utility Commission (the “OPUC”). The draft request for proposals is for generation resources of between 840.0 MW and 915.0 MW to be available in 2012 through 2013. The scope of this draft request for proposals is focused on resources capable of delivering energy and capacity in or to PacifiCorp’s network transmission system in PacifiCorp’s eastern service territory. All transaction and resource decisions will be evaluated on a comparable least-cost and risk-balanced approach. In response to issues and concerns from stakeholders, PacifiCorp filed a revised version of the 2012 draft request for proposals in October 2006. Conditional approvals are expected from the state commissions in November 2006.

Contractual Obligations and Commercial Commitments

PacifiCorp enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. There have been no material changes outside the ordinary course of business for such commitments since March 31, 2006. For an in-depth discussion of PacifiCorp’s contractual obligations and commercial commitments, see “Contractual Obligations and Commercial Commitments” in “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006.

Pension Protection Act of 2006

On August 17, 2006, the Pension Protection Act of 2006 (the “Pension Act”) was signed into law. The Pension Act includes a requirement for qualified pension plans to be fully funded within seven years following the January 1, 2008 effective date. PacifiCorp does not anticipate any significant changes to the amount of funding previously anticipated through 2007. PacifiCorp is reviewing the impacts of the Pension Act on funding requirements for its retirement plan for 2008 and beyond. As a result of the Pension Act, PacifiCorp may be required to accelerate contributions to its retirement plan for periods after 2007 and there may be more volatility in annual contributions in the future.

Credit Ratings

There has been no change in PacifiCorp’s credit ratings since March 31, 2006. These ratings are subject to change or withdrawal at any time by the respective credit ratings services. Each credit rating should be evaluated independently of any other rating.

In conjunction with its risk management activities, PacifiCorp must meet credit quality standards required by counterparties. In accordance with industry practice, contractual agreements that govern PacifiCorp’s energy management activities either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed certain ratings-dependent threshold levels or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s creditworthiness. If one or more of PacifiCorp’s credit ratings decline below investment grade, PacifiCorp would be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy management activities. As of September 30, 2006, PacifiCorp’s credit ratings from Standard & Poor’s and Moody’s were investment grade; however, if the ratings were to fall below investment grade, PacifiCorp’s estimated potential collateral requirements could total as much as $416.2 million. PacifiCorp’s potential collateral requirements could fluctuate considerably due to seasonality, market prices and their volatility, a loss of key PacifiCorp generating facilities or other related factors.

For a further discussion of PacifiCorp’s credit ratings and their effect on PacifiCorp’s business, see “Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006.

Off-Balance Sheet Arrangements

PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees, indemnifications or similar arrangements. PacifiCorp currently has indemnification obligations for breaches of warranties or covenants in connection with the sale of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with revised Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. See “Item 8. Financial Statements and Supplementary Data - Note 11 – Guarantees and Other Commitments and Note 13 – Consolidation of Variable-Interest Entities” for more information on these obligations and arrangements in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006.

Regulation

See “Item 1. Business – Regulation” in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006 for information concerning the federal and state regulatory matters in which PacifiCorp is involved. Certain developments with respect to those matters are set forth below and in “Part I – Item 1. Financial Statements – Note 4 – Commitments and Contingencies,” which is incorporated by reference into this discussion.

Federal Regulatory Matters

Hydroelectric Relicensing

Klamath hydroelectric project – (Klamath River, Oregon and California)

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 161.4-MW Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license granted by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. The united States Departments of Interior and Commerce are scheduled to file a modified proposal for the licensing terms and conditions in January 2007 that takes into consideration the administrative law judge’s ruling, the FERC’s draft environmental impact statement described below and other appropriate matters, including the value of the Klamath hydroelectric project and the electricity it produces. PacifiCorp is currently evaluating the impact of the ruling on the Klamath hydroelectric project relicensing process.

Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. The draft environmental impact statement is open to public comment and the FERC is conducting public meetings and accepting written comments during November 2006. The FERC is expected to issue its final environmental impact statement by April 2007.

State Regulatory Matters

Utah

In March 2006, PacifiCorp filed a general rate case with the UPSC related to increased investments in Utah due to growing demand for electricity. In April 2006, PacifiCorp filed a revised case reflecting the effects of PacifiCorp’s sale to MEHC, which reduced the original requested increase from $197.2 million to $194.1 million. In July 2006, a stipulation was reached with several parties and was filed with the UPSC. The stipulation calls for an annual increase of $115.0 million, or 9.95%, with $85.0 million of the increase effective December 11, 2006 and the remaining $30.0 million effective June 1, 2007. Under the terms of the stipulation, PacifiCorp has agreed not to file another rate case until after December 11, 2007. Also as part of the stipulation, PacifiCorp’s Power Cost Adjustment Mechanism (“PCAM”) application will be withdrawn. An order is expected before December 11, 2006.

Oregon

In February 2006, PacifiCorp filed a general rate case request with the OPUC for an increase of approximately $112.0 million, or 13.2%. The request was related to investments in generation, transmission and distribution infrastructure and increases in fuel and general operating expenses, including power plant maintenance. In September 2006, the OPUC approved a settlement agreement with all parties, under which PacifiCorp will receive an annual increase for non-power cost items of $33.0 million effective January 1, 2007.Also on January 1, 2007, PacifiCorp will receive an increase for power costs using the existing transition adjustment mechanism, which will be capped at $10.0 million for January 1, 2007. After 2007, PacifiCorp’s power costs will be updated annually using the existing transition adjustment mechanism without a cap. PacifiCorp has agreed not to file a new rate case prior to September 1, 2007.

In September 2005, Oregon’s governor signed into law Senate Bill 408. This legislation is intended to address differences between taxes based on income that are collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or affiliated groups in which utilities are included for income tax reporting purposes.

Oregon Senate Bill 408, requires that all regulated, investor-owned utilities that provided electric or natural gas service to an average of 50,000 or more Oregon customers in 2003 file an annual tax report with the OPUC. Among other information, the tax report must contain; (i) the amount of taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, and (ii) the amount of taxes “authorized to be collected in rates.” If the OPUC determines that the amount of taxes “authorized to be collected” differs by more than $100,000 from the amount of taxes paid, in either direction, the OPUC shall require the public utility to implement a rate schedule with an automatic adjustment clause result in a surcredit or a surcharge on customer bills. The law is applicable for years beginning on or after January 1, 2006. The first tax report that can result in a rate adjustment will be filed on or before October 15, 2007 with the resulting surcredit or surcharge, if any, implemented in rates on or before June 1, 2008.

A permanent rulemaking docket was opened by the OPUC in September 2005 to establish rules for the implementation of Oregon Senate Bill 408. In September 2006, the OPUC adopted final administrative rules setting forth the method of calculating the portion of the total consolidated tax liability that is “properly attributed” to the regulated operations of the utility, as well as other items necessary for the implementation of Oregon Senate Bill 408.

The final administrative rules define the amount of federal, state, and local taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, as the lowest of; (i) the total tax liability of the affiliated group of which the utility is a member, (ii) the standalone tax liability of the utility, or (iii) the tax liability calculated using the “apportionment method.” The “apportionment method” uses an evenly weighted three-factor formula premised on property, payroll and sales, with amounts for the regulated operations of the utility in the numerator and amounts for the affiliated group in the denominator, to generate an allocation factor that is applied against the tax liability of PacifiCorp’s respective affiliated group in order to “apportion” part of that tax liability to the regulated operations of the utility. For federal purposes, the affiliated group of which PacifiCorp is a member is Berkshire Hathaway Inc. and its subsidiaries. For state and local purposes, the affiliated group differs based upon jurisdictional filing requirements.

As a result of the law and the final administrative rules, the tax liability of the affiliated group of which PacifiCorp is a member and the affiliated group’s impact on the factor determined under the “apportionment method” may impact the amount of taxes paid and “properly attributed” to PacifiCorp. PacifiCorp cannot reasonably predict the financial results and the related impact of its federal affiliated group, Berkshire Hathaway Inc. and its subsidiaries, and therefore, cannot determine the impact this law may have on its consolidated financial position and results of operations.

Additionally, the calculation of “taxes authorized to be collected in rates,” as defined by the OPUC, is based upon assumptions in the latest rate case(s) used to set rates for the respective financial reporting period. As such, “taxes authorized to be collected in rates” does not reflect actual tax collections. The resulting difference between actual tax collections and the amount deemed collected pursuant to Oregon Senate Bill 408 may be a benefit or detriment to PacifiCorp and cannot be reasonably predicted.

The OPUC recognizes that a potential conflict between its rules and federal Internal Revenue Code regulations, could deny PacifiCorp the tax benefits of accelerated depreciation. As such, the OPUC has required that no later than December 31, 2006, the affected utilities each file a request for a private letter ruling from the Internal Revenue Service on this issue, which may result in reconsideration of further changes to the rule or underlying law.

Oregon Senate Bill 408 cannot be used to decrease utility rates below a fair and reasonable level and the final administrative rules expressly provide that a utility may challenge any adjustment if it would result in rates that are not fair, just and reasonable resulting in confiscatory rates.

PacifiCorp continues to evaluate its legal and legislative options.

In November 2004, PacifiCorp filed a general rate case request with the OPUC. Following four partial stipulations with participating parties, PacifiCorp’s requested revenue requirement increase was $52.5 million. In September 2005, the OPUC issued an order granting PacifiCorp a general rate increase of $25.9 million, or an average increase of 3.2%, effective October 2005. The OPUC’s order reduced PacifiCorp’s revenue requirement by $26.6 million

based on the OPUC’s interpretation of Senate Bill 408. In October 2005, PacifiCorp filed with the OPUC a motion for reconsideration and rehearing of the rate order generally on the basis that the tax adjustment was not made in compliance with applicable law. With the motion, PacifiCorp also filed a deferred accounting application with the OPUC to track revenues related to the disallowed tax expenses. In July 2006, a final order was issued by the OPUC affirming its initial application of Senate Bill 408. The order also modified the tax adjustment, resulting in an additional annual increase in PacifiCorp’s revenue of $6.1 million effective July 2006, as well as granting deferred accounting for the period from October 2005 to July 2006. In September 2006, PacifiCorp filed an application for deferred accounting treatment of the remainder of the tax adjustment, pending the outcome of the permanent rulemaking for Senate Bill 408. This application was necessary to ensure that PacifiCorp is allowed the opportunity to recover any revenue shortfall related to its allocated tax expense in rates for 2006, to the extent any such revenue shortfall is not recovered through the Senate Bill 408 automatic adjustment clause.

Wyoming

In March 2006, the Wyoming Public Service Commission (the “WPSC”) approved an agreement that settled the general rate case filed by PacifiCorp in October 2005 and a separate request filed by PacifiCorp in December 2005 to recover increased costs of net wholesale purchased power used to serve Wyoming customers. The agreement provides for an annual rate increase of $15.0 million effective March 1, 2006, an additional annual rate increase of $10.0 million effective July 1, 2006, a PCAM and an agreement by the parties to support a forecast test year in the next general rate case application.

In June 2006, the WPSC approved tariffs and rate schedules to implement the rate increase of $10.0 million annually, unbundling of net power costs from base rates, and establishing a PCAM effective July 2006.

Washington

In May 2005, PacifiCorp filed a general rate case request with the Washington Utilities and Transportation Commission (the “WUTC”) for an increase of approximately $39.2 million annually, which was later reduced to approximately $30.0 million. In April 2006, the WUTC issued an order denying PacifiCorp’s request to increase retail rates. The WUTC determined that application of PacifiCorp’s cost allocation methodology failed to satisfy the statutory requirements that resources must benefit Washington ratepayers.

In April 2006, PacifiCorp filed a petition for reconsideration of the order and requested an increase of not less than $11.0 million. PacifiCorp also filed a limited rate request seeking a rate increase of approximately $7.0 million, which represents a 2.99% increase in rates. In June 2006, the WUTC suspended PacifiCorp’s limited rate request and consolidated the request with the general rate case. In July 2006, the WUTC issued an order denying PacifiCorp’s request for reconsideration and rejecting the 2.99% limited rate request filing.

In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23.2 million, or 10.2%. The WUTC set an eight-month schedule with an expected order date of June 15, 2007. As part of the filing, PacifiCorp proposed a Washington-only cost allocation methodology, which is based on PacifiCorp’s western resources. The rate case included a five-year pilot on the proposed allocation methodology and a PCAM.

Idaho

In June 2006, three applications were filed for approval with the Idaho Public Utilities Commission (the “IPUC”) proposing adjustments to the rates of certain Idaho customers for a total increase of $8.25 million. The applications are based on settlement agreements reached after negotiations between PacifiCorp and those customers. The IPUC conditionally approved the first request effective September 1, 2006, subject to refund upon issuance of a final order. The remaining two requests each have a proposed effective date of January 1, 2007. A hearing on these applications has been tentatively scheduled for November 2006, with an order expected by December 2006. If these three applications are approved by the IPUC, PacifiCorp would not file a general rate case in 2006 as originally anticipated.

California

In November 2005, PacifiCorp filed a general rate case with the California Public Utilities Commission (the “CPUC”) for an increase of $11.0 million annually, or an average increase of 15.6%, related to increasing costs, including power costs and operating expenses, as well as significant needed capital investments. In May 2006, PacifiCorp filed an update that resulted in a net requested average increase of $12.8 million annually, or 18.9%, for California customers. In July 2006, a settlement agreement was reached with the Division of Ratepayer Advocates and other parties on revenue requirement and other aspects of the case, including a $7.3 million annual increase. Hearings were held in late July 2006 to address the effect of the rate increase on irrigation customers in the Klamath River basin. An order is expected from the CPUC by the end of 2006 with new rates effective January 1, 2007.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PacifiCorp participates in a wholesale energy market that includes public utility companies, electricity and natural gas marketers, financial institutions, industrial companies and government entities. A variety of products exist in this market, ranging from electricity and natural gas purchases and sales for physical delivery to financial instruments such as futures, swaps, options and other complex derivatives. Transactions may be conducted directly with customers and suppliers, through brokers, or with an exchange that serves as a central clearing mechanism.

PacifiCorp is subject to the various risks inherent in the energy business, including credit risk, interest rate risk and commodity price risk. For an in-depth discussion of these risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in PacifiCorp’s Annual Report on Form 10-K for the year ended

March 31, 2006.

Risk Management

As disclosed in PacifiCorp’s Annual Report on Form 10-K for the year ended March 31, 2006, PacifiCorp’s risk management policy permitted the hedging of PacifiCorp’s existing energy and asset exposures, and to a limited extent, arbitrage activities to take advantage of market inefficiencies. In July 2006, PacifiCorp expanded its policy to permit both arbitrage and trading activities within the limits established in the risk management policy.

Credit Risk

The following table represents PacifiCorp’s September 30, 2006 distribution of unsecured credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts and takes into account contractual netting rights.

Distribution of Credit Exposure	% of Total

Investment grade - Externally rated	73.9	%
Non-investment grade - Externally rated	1.3
Investment grade - Internally rated	0.1
Non-investment grade - Internally rated	24.7

	100.0	%

“Externally rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally rated” represents those relationships that have no rating by a major credit rating agency. For those relationships, PacifiCorp utilizes internally developed, commercially appropriate rating methodologies and credit scoring models to develop a public rating equivalent.

The “Non-investment grade – Internally rated” component of PacifiCorp’s overall credit exposure reflects the market value of a small number of contracts that support PacifiCorp’s Integrated Resource Plan and Oregon’s electric energy restructuring legislation as it relates to renewable energy projects, as well as compliance with FERC regulations requiring utilities to purchase power from qualifying facilities.

Interest Rate Risk

PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. Increases or decreases in interest rates are reflected in PacifiCorp’s revenue requirement upon which, rate cases are based. Any adverse change to PacifiCorp’s credit rating could negatively impact PacifiCorp’s ability to borrow and the interest rates that are charged.

As of September 30, 2006, PacifiCorp had fixed-rate long-term liabilities of $3,755.2 million in aggregate principal amount and having a fair value of $3,955.6 million. These instruments have fixed interest rates and therefore do not expose PacifiCorp to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $132.4 million if interest rates were to increase by 10.0% from their levels at September 30, 2006. In general, such a decrease in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity.

At September 30, 2006, PacifiCorp had $621.4 million of variable-rate liabilities and $59.8 million of temporary cash investments and had no financial derivatives in effect relating to interest rate exposure.

Based on a sensitivity analysis as of September 30, 2006, for a one-year horizon, PacifiCorp estimates that if market interest rates average 1.0% higher (lower), interest expense, net of offsetting impacts on interest income, would increase (decrease) by $5.6 million. Comparatively, based on a sensitivity analysis as of March 31, 2006, for a one-year horizon, had interest rates averaged 1.0% higher (lower), PacifiCorp estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by $6.1 million. These amounts include the effect of invested cash and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding at September 30, 2006 and March 31, 2006. The decrease in interest rate sensitivity was due to the decrease in outstanding variable-rate commercial paper, partially offset by the decrease in invested cash. If interest rates changed significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that might be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.

Commodity Price Risk

PacifiCorp’s exposure to market risk due to commodity price change is primarily related to its fuel and electricity commodities that affect energy supply and demand. These fuel and electricity commodities are subject to fluctuations due to unpredictable factors, such as weather, economic conditions, electricity demand and plant performance, that affect energy supply and demand. PacifiCorp’s energy purchase and sales activities are governed by PacifiCorp’s risk management policy and the risk levels established as part of that policy.

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk (“VaR”) approach, as well as other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in comparison to established limits, and restricts its open positions subject to price risk in terms of quantity at each delivery location for each forward time period.

VaR computations are based on a historical simulation technique, utilizing historical price changes over a specified (holding) period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions. The quantification of market risk using VaR provides a consistent measure of risk across PacifiCorp’s continually changing portfolio. VaR represents an estimate of possible changes at a given level of confidence in fair value that would be measured on its portfolio assuming hypothetical movements in forward market prices and is not necessarily indicative of actual results that may occur.

PacifiCorp’s VaR computations utilize several key assumptions. The calculation includes short-term derivative commodity instruments, the expected resource and demand obligations from PacifiCorp’s long-term contracts, the expected generation levels from PacifiCorp’s generation assets and the expected retail and wholesale load levels. The portfolio reflects flexibility contained in contracts and assets, which accommodate the normal variability in PacifiCorp’s demand obligations and generation availability. These contracts and assets are valued to reflect the variability PacifiCorp experiences as a load-serving entity. Contracts or assets that contain flexible elements are often referred to as having embedded options or option characteristics. These options provide for energy volume changes that are sensitive to market price changes.

Therefore, changes in the option values affect the energy position of the portfolio with respect to market prices, and this effect is calculated daily. When measuring portfolio exposure through VaR, these position changes that result from the option sensitivity are held constant through the historical simulation.

Effective for the three months ending September 30, 2006, PacifiCorp changed its VaR methodology for risk management purposes. The previous VaR methodology was based on a 24-month forward position, 99.0% confidence interval and five-day holding period. The new methodology is based on a 48-month forward position, 95.0% confidence interval and one-day holding period. The change to 95.0% confidence interval and one-day holding period makes PacifiCorp’s VaR methodology more consistent with industry practices. The increase in length of the forward position from 24 to 48 months is based on management’s intention to more actively manage net power cost exposure beyond 24 months and up to 48 months.

As of September 30, 2006, PacifiCorp’s estimated potential one-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 48 months was $6.8 million, as measured by the VaR computations described above. The minimum, average and maximum daily VaR (one-day holding periods) for the three and six months ended September 30, 2006 are as follows:

	Three Months Ended September 30,		Six Months Ended September 30,
(Millions of dollars)	2006		2006

Minimum VaR (measured)	$	6.8	$	6.8
Average VaR (calculated)		12.1		12.0
Maximum VaR (measured)		15.2		16.4

PacifiCorp maintained compliance with its VaR limit procedures during the six months ended September 30, 2006. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Fair Value of Derivatives

The following table summarizes the changes in the fair value of PacifiCorp’s derivative contracts from March 31, 2006 to September 30, 2006, as well as changes in fair value of those derivative contracts that have been recognized as a net regulatory asset (liability) because the contracts are probable of receiving recovery in retail rates.

	Net Asset (Liability)						Net Regulatory Asset (Liability)

(Millions of dollars)	Trading			Non-trading

Fair value of contracts outstanding at March 31, 2006	$	0.2		$	7.7		$	94.7
Contracts realized or otherwise settled during the period		0.1			(26.3	)		(29.6	)
Change in valuation technique (a)		—			(23.0	)		23.0
Change in estimate of recoverability (b)		—			—			(40.3	)
Other changes in fair values (c)		(3.4	)		(134.6	)		164.7

Fair value of contracts outstanding at September 30, 2006	$	(3.1	)	$	(176.2	)	$	212.5

(a)

Effective August 31, 2006, PacifiCorp enhanced its valuation techniques for long-term contracts by changing from a best-estimate forecast to a probability-weighted expected value approach for valuing the long-dated (periods subsequent to September 30, 2012) natural gas price forecast. This approach results in a measurement that is more representative of the fair value of forward long-term contracts. This change had the effect of decreasing the fair value of contracts by $23.0 million, offset by an increase in net regulatory assets by the same amount.

(b)

During the three months ended September 30, 2006, PacifiCorp reached a new general rate case stipulation with several parties in Utah and received approval from the OPUC for a new general rate case settlement in Oregon. Utah and Oregon together account for approximately 70.0% of PacifiCorp’s retail electric

operating revenues. Based on management’s consideration of the two new rate settlements, as well as the net power cost recovery adjustment clauses obtained in Wyoming and California earlier in 2006, PacifiCorp changed its estimate of the contracts receiving recovery in retail rates. Effective July 21, 2006, PacifiCorp recorded a $40.3 million decrease in net regulatory assets for previously recorded net unrealized gains related to contracts that it determined were probable of being recovered in retail rates with a corresponding pre-tax charge to net income of $43.9 million and a pre-tax increase to Accumulated other comprehensive income of $3.6 million.

(c)	Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including those based on models, on new and existing contracts.

PacifiCorp’s valuation models and assumptions are continuously updated to reflect current market information. Evaluations and refinements of model assumptions are performed on a periodic basis.

The following table shows summarized information with respect to valuation techniques and contractual maturities of PacifiCorp’s energy-related contracts qualifying as derivatives under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, at September 30, 2006.

	Fair Value of Contracts at Period-End

(Millions of dollars)	Maturity less than 1 year			Maturity 1-3 years			Maturity 4-5 years			Maturity in excess of 5 years			Total Fair Value

Trading:
Values based on quoted market prices from third-party sources	$	(3.3	)	$	0.2		$	—		$	—		$	(3.1	)

Non-trading:
Values based on quoted market prices from third-party sources	$	33.3		$	13.9		$	(2.3	)	$	0.9		$	45.8
Values based on models and other valuation methods		24.8			36.6			8.3			(291.7	)		(222.0	)

Total non-trading	$	58.1		$	50.5		$	6.0		$	(290.8	)	$	(176.2	)

Regulatory net asset (liability)	$	(21.6	)	$	(50.7	)	$	(6.0	)	$	290.8		$	212.5

Standardized derivative contracts that are valued using market quotations are classified as “values based on quoted market prices from third-party sources.” All remaining contracts, which include non-standard contracts and contracts for which market prices are not routinely quoted, are classified as “values based on models and other valuation methods.” Both classifications utilize market curves as appropriate for the first six years.

ITEM 4.

CONTROLS AND PROCEDURES

PacifiCorp maintains disclosure controls and procedures designed to provide reasonable assurance that material information required to be disclosed by it in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that the information is accumulated and communicated to PacifiCorp’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. PacifiCorp performed an evaluation, under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of PacifiCorp’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, PacifiCorp’s management, including its Chief Executive Officer and Chief Financial Officer, concluded

that the disclosure controls and procedures were effective as of the end of the period covered by this report.

On March 21, 2006, MEHC completed its purchase of PacifiCorp, at which time PacifiCorp became a subsidiary of MEHC. Although PacifiCorp has maintained its disclosure controls and procedures that were in effect prior to the acquisition, subsequent to the acquisition there have been material changes in PacifiCorp’s internal control over financial reporting. The material changes are due to the effect of the acquisition on PacifiCorp’s control environment, which includes changes in the composition of the board of directors and senior management, changes in PacifiCorp’s organizational structure, as well as a reorganization of the corporate finance department. PacifiCorp believes these changes have not negatively affected its internal control over financial reporting.

During the three months ended September 30, 2006, there was no other change in PacifiCorp’s internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Securities Exchange Act of 1934 Rules 13a-15 or 15d-15 that occurred that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

For a description of legal proceedings, see PacifiCorp’s Annual Report on Form 10-K for the year ended

March 31, 2006, as well as “Item 1. Financial Statements – Note 4 – Commitments and Contingencies.”

ITEM 1A.

RISK FACTORS

There has been no material change to PacifiCorp’s risk factors from those disclosed in its Annual Report on Form 10-K for the year ended March 31, 2006.

ITEM 2.

UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS

No information is required to be reported pursuant to this item.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

No information is required to be reported pursuant to this item.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No information is required to be reported pursuant to this item.

ITEM 5.

OTHER INFORMATION

No information is required to be reported pursuant to this item.

ITEM 6.

EXHIBITS

10.1	Summary of Key Terms of Patrick Reiten Compensation.

12.1	Statements of Computation of Ratio of Earnings to Fixed Charges.

12.2	Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

31.1	Section 302 Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a).

31.2	Section 302 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a).

32.1	Section 906 Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350.

32.2	Section 906 Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350.

______________

SIGNATURE

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

	PACIFICORP
Date: November 3, 2006	By:	/s/ DAVID J. MENDEZ

		David J. Mendez
		Chief Financial Officer and officer duly authorized to sign this report on behalf of registrant