Portland General Electric (POR) 10-Q 2006 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period endedJune 30, 2006
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from _____v___________ to _______________ Commission File Number 1-5532-99
	PORTLAND GENERAL ELECTRIC COMPANY
	(Exact name of registrant as specified in its charter)

Oregon		93-0256820
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
	121 SW Salmon Street, Portland, Oregon 97204
	(Address of principal executive offices) (zip code)

Registrant's telephone number, including area code:(503) 464-8000

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 ___

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. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes          No    X  

Number of shares of Common Stock outstanding as of July 31, 2006: 62,500,000 shares of common stock, no par value.

Table of Contents

		Page Number
Definitions		3
PART I. Financial Information
	Item 1. Financial Statements
	Condensed Consolidated Statements of Income	4
	Condensed Consolidated Statements of Retained Earnings	4
	Condensed Consolidated Statements of Comprehensive Income	5
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
	Item 2.  Management's Discussion and Analysis of
	Financial Condition and Results of Operations	28
	Item 3.  Quantitative and Qualitative Disclosures
	About Market Risk	60
	Item 4. Controls and Procedures	63
PART II. Other Information
	Item 1. Legal Proceedings	64
	Item 1A. Risk Factors	65
	Item 6. Exhibits	66
	Signatures	68

Definitions

Bankruptcy Court	United States Bankruptcy Court for the Southern District of New York
Boardman	Boardman Coal Plant
Chapter 11 Plan	Fifth Amended Joint Plan of Affiliated Debtors Pursuant to Chapter 11 of the United States Bankruptcy Code, dated January 9, 2004 and as thereafter amended and supplemented from time to time
Colstrip	Colstrip Units 3 and 4 Coal Plant
Debtors	Enron Corp. and its reorganized debtor subsidiaries under the Chapter 11 Plan
DEQ	Oregon Department of Environmental Quality
EITF	Emerging Issues Task Force of the Financial Accounting Standards Board
Enron	Enron Corp., as reorganized debtor pursuant to its Supplemental Modified Fifth Amended Joint Plan of Affiliated Debtors Pursuant to Chapter 11 of the Bankruptcy Code, confirmed by the United States Bankruptcy Court For The Southern District of New York (Case No. 01-16034) on July 15, 2004 and effective November 17, 2004
EPA	Environmental Protection Agency
ESS	Energy Service Supplier
FERC	Federal Energy Regulatory Commission
Financial Statements	Condensed Consolidated Financial Statements of Portland General Electric Company included in Part I, Item 1 of this report
kWh	Kilowatt-Hour
Mill	One tenth of one cent
MW	Megawatt
MWh	Megawatt-hour
OPUC	Public Utility Commission of Oregon
PGE or the Company	Portland General Electric Company
Port Westward	Port Westward Power Plant
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board
Trojan	Trojan Nuclear Plant

PART I

Financial Information

Item 1. Financial Statements

Portland General Electric Company and Subsidiaries CondensedConsolidated Statements of Income (Unaudited)
		Three Months Ended June 30,										Six Months Ended June 30,
		2006					2005					2006						2005
		(Dollars in Millions, Except per Share Amounts)
Operating Revenues			$		351			$		333			$			732			$				704
Operating Expenses
	Purchased power and fuel			143					131					375							273
	Production and distribution			33					34					69							62
	Administrative and other			45					47					79							85
	Depreciation and amortization			53					58					110							118
	Taxes other than income taxes			18					18					38							38
	Income taxes			18					13					14							43
				310					301					685							619
Net Operating Income				41					32					47							85
Other Income
	Miscellaneous			2					1					5							3
	Income taxes			-					-					1							1
				2					1					6							4
Interest Charges
	Interest on long-term debt and other			16					17					32							35
Net Income		$		27			$		16		$			21			$				54
Common Stock:
	Weighted-Average Shares Outstanding
(millions), Basic and Diluted				62.5					62.5					62.5							62.5
	Earnings per Average Share,
Basic and Diluted		$		0.43			$		0.26		$			0.34			$				0.87
The accompanying notes are an integral part of these condensed consolidated financial statements.
Portland General Electric Company and Subsidiaries Condensed ConsolidatedStatements of Retained Earnings (Unaudited)
		Three Months Ended June 30,									Six Months Ended June 30,
		2006				2005					2006									2005
		(In Millions)
Balance at Beginning of Period (*)		$		552			$		682		$			558			$				644
Net Income					27					16						21							54
					579					698						579							698
Dividends Declared - Common Stock		14					-				14							-
Balance at End of Period		$		565			$		698		$				565			$				698
	(*) Balances for 2005 restated. See Note 12.
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries

Condensed Consolidated Statements ofComprehensive Income

(Unaudited)

			Three Months Ended										Six Months Ended
			June 30,										June 30,
				2006			2005					2006					2005
				(In Millions)
Accumulated other comprehensive income (loss) - Beginning of Period
	Unrealized gain (loss) on derivatives classified as cash flow hedges			$	(2)		$		4			$			-			$		(2)
	Minimum pension liability adjustment				(3)			(4)						(3)						(4)
	Total			$	(5)		$	-			$			(3)		$				(6)
Net Income				$	27		$	16			$				21	$				54
Other comprehensive income, net of tax:
	Unrealized gains (losses) on derivatives classified as cash flow   hedges:
		Other unrealized holding net gains (losses) arising during the
		period, net of related taxes of $(5) and $5 for the three
		months ended June 30, 2006 and 2005 and $13 and $(25)
		for the six months ended June 30, 2006 and 2005		7			(9)				(19)					38
		Reclassification adjustment for contract settlements included
		in net income, net of related taxes of $(1) and $8 for the three months ended June 30, 2006 and 2005 and $3
		and $8 for the six months ended June 30, 2006 and 2005		1			(13)				(7)					(12)
		Reclassification adjustment in net income due to discontinuance
		of cash flow hedges, net of related taxes of $1		-			-				-					(1)
		Reclassification of unrealized gains (losses) to SFAS No. 71
		regulatory (liability) asset, net of related taxes of $5 and $(11)
		for the three months ended June 30, 2006 and 2005 and $(16)
		and $15 for the six months ended June 30, 2006 and 2005		(8)			19				24					(22)
	Total - Unrealized gains (losses) on derivatives classified as
		cash flow hedges		-			(3)				(2)					3
	Minimum pension liability adjustment			-			-				-					-
		Total Other comprehensive income (loss)		-			(3)				(2)					3
Comprehensive income				$	27		$			13	$				19	$			57
Accumulated other comprehensive income (loss) - End of Period
	Unrealized gain (loss) on derivatives classified as cash flow hedges			$	(2)		$			1	$				(2)		$			1
	Minimum pension liability adjustment			(3)			(4)				(3)					(4)
Total				$		(5)	$			(3)	$				(5)	$			(3)
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited)
				June 30,		December 31,
				2006		2005
			(In Millions)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $338 and $177)			$	4,445		$	4,224
	Accumulated depreciation			(1,834)			(1,788)
				2,611			2,436
Other Property and Investments
	Nuclear decommissioning trust, at market value			36			31
	Non-qualified benefit plan trust			68			69
	Miscellaneous			30			34
				134			134
Current Assets
	Cash and cash equivalents			69			122
	Accounts and notes receivable (less allowance for uncollectible accounts of $50 and $50)			143			203
	Unbilled revenues			55			78
	Assets from price risk management activities			103			259
	Inventories, at average cost			63			54
	Prepayments and other			27			24
	Deferred income taxes			2			-
				462			740
Deferred Charges
	Regulatory assets			240			217
	Miscellaneous			109			111
				349			328
				$	3,556		$	3,638
Capitalization and Liabilities
Capitalization
	Common stock equity:
		Common stock, no par value, 80,000,000
		shares authorized; 62,500,000 shares outstanding		$	642		$	642
		Retained earnings		565			558
		Accumulated other comprehensive income (loss):
		Unrealized loss on derivatives classified as cash flow hedges		(2)			-
		Minimum pension liability adjustment		(3)			(3)
	Long-term debt			952			879
				2,154			2,076
Commitments and Contingencies (see Notes)
Current Liabilities
	Long-term debt due within one year			55			11
	Accounts payable and other accruals			163			260
	Liabilities from price risk management activities			109			129
	Customer deposits			5			53
	Accrued interest			14			17
	Accrued taxes			46			42
	Dividends payable			14			-
	Deferred income taxes			-			51
				406			563
Other
	Deferred income taxes			238			218
	Deferred investment tax credits			9			10
	Trojan asset retirement obligation			108			107
	Accumulated asset retirement obligation			26			27
	Regulatory liabilities:
		Accumulated asset retirement removal costs		382			349
		Other		120			175
	Non-qualified benefit plan liabilities			81			79
	Miscellaneous			32			34
				996			999
				$	3,556		$	3,638
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed ConsolidatedStatements of Cash Flows (Unaudited)
			Six Months Ended
			June 30,
			2006		2005 (As Restated - See Note 12)
			(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities
	Net income		$	21	$	54
		Non-cash items included in net income:
		Depreciation and amortization	110		118
		Deferred income taxes	(31)		(30)
		Net assets from price risk management activities	92		(10)
		Power cost adjustment	-		9
		Regulatory deferrals - price risk management activities	(67)		(1)
		Other non-cash income and expenses (net)	4		(6)
		Changes in working capital:
		Net margin deposit activity	(48)		28
		Decrease in receivables	84		35
		Decrease in payables	(109)		(41)
		Other working capital items - net	(14)		30
		Other - net	4		14
Net Cash Provided by Operating Activities			46		200
Cash Flows From Investing Activities:
	Capital expenditures		(211)		(128)
	Purchases of nuclear decommissioning trust securities		(20)		(16)
	Sales of nuclear decommissioning trust securities		10		11
	Other - net		5		(3)
Net Cash Used in Investing Activities			(216)		(136)
Cash Flows From Financing Activities:
	Repayment of long-term debt		(158)		(8)
	Issuance of long-term debt		275		-
Net Cash Provided by (Used in) Financing Activities			117		(8)
Increase (Decrease) in Cash and Cash Equivalents			(53)		56
Cash and Cash Equivalents, Beginning of Period			122		204
Cash and Cash Equivalents, End of Period			$	69	$	260
Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	29	$	29
		Income taxes	42		66
	Non-cash investing and operating activities:
		Accrued capital additions	22		6
The accompanying notes are an integral part of these condensed consolidated financial statements.

Notes to Condensed ConsolidatedFinancial Statements (Unaudited)

Note 1 - Principles of Interim Statements

The interim financial statements have been prepared by PGE and, in the opinion of management, reflect all material adjustments which are necessary for a fair statement of results for the interim periods presented. Such statements, which are unaudited, are presented in accordance with the interim reporting requirements of the Securities and Exchange Commission (SEC), which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Interim financial results do not ne cessarily represent those to be expected for the year. It is management's opinion that, when the interim statements are read in conjunction with the Company's 2005 Annual Report on Form 10-K filed with the SEC, the disclosures are adequate to make the information presented not misleading.

Reclassifications -Certain amounts in the prior year have been reclassified for comparative purposes. These reclassifications had no material effect on PGE's previously reported consolidated financial position, results of operations, or cash flows.

Note 2 - Employee Benefits

Pension and Other Post-Retirement Plans

PGE sponsors a non-contributory defined benefit pension plan, substantially all members of which are current or former PGE employees. The assets of the pension plan are held in a trust. Pension plan calculations include several assumptions which are reviewed annually with PGE's consulting actuaries and updated as appropriate.

The amounts included under Non-Qualified Benefit Plans in the accompanying table primarily represent obligations for a Supplemental Executive Retirement Plan (SERP). Investments in a non-qualified benefit plan trusts, consisting of trust-owned life insurance policies and marketable securities, are intended to be the primary source for financing these plans.

PGE also participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" in the table). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum contribution per employee. Contributions made to a Voluntary Employees' Beneficiary Association (VEBA) trust are used to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers. In addition, PGE has established Health Retirement Accounts (HRAs) for its employees under which the Company makes contributions to trusts to provide for claims by retirees for qualified medical costs.

The measurement date for these plans is December 31. PGE does not expect to make contributions to the pension plan, SERP, or post-retirement health and life insurance plans during 2006; contributions to the HRAs are not expected to be material.

The following tables reflect the components of net periodic benefit cost for the periods indicated (in millions):

Three Months Ended June 30:	Defined Benefit				Non-Qualified
	Pension Plan				Benefit Plans				Other Benefits
	2006		2005		2006		2005		2006		2005
Components of net periodic benefit cost:
Service cost	$	3	$	3	$	-	$	-	$	-	$	-
Interest cost on benefit obligation	7		7		-		1		1		1
Expected return on plan assets	(10)		(10)		(1)		-		-		-
Amortization of transition asset	-		-		-		-		-		-
Amortization of prior service cost	-		-		-		-		-		-
Recognized (gain) loss		1		-		1		-		-		-
Net periodic benefit cost (income)	$	1	$	-	$	-	$	1	$	1	$	1
Six Months Ended June 30:	Defined Benefit				Non-Qualified
	Pension Plan				Benefit Plans				Other Benefits
	2006		2005		2006		2005		2006		2005
Components of net periodic benefit cost:
Service cost	$	6	$	6	$	-	$	-	$	-	$	-
Interest cost on benefit obligation	14		14		-		1		2		2
Expected return on plan assets	(20)		(20)		(1)		-		-		-
Amortization of transition asset	-		-		-		-		-		-
Amortization of prior service cost	-		-		-		-		-		-
Recognized (gain) loss		2		-		1		-		-		-
Net periodic benefit cost (income)	$	2	$	-	$	-	$	1	$	2	$	2

Note 3 - Price Risk Management

PGE utilizes derivative instruments, including electricity forward, swap, and option contracts and natural gas forward, swap, option, and futures contracts in its retail (non-trading) electric utility activities to manage its exposure to commodity price risk and to minimize net power costs for service to its retail customers. Under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), derivative instruments are recorded on the Balance Sheet as an asset or liability measured at estimated fair value, with changes in fair value recognized currently in earnings, unless specific hedge accounting criteria are met.

Changes in the fair value of retail (non-trading) derivative instruments prior to settlement that do not qualify for either the normal purchase and normal sale exception or for hedge accounting are recorded on a net basis in Purchased Power and Fuel expense. As derivative instruments are settled, sales are recorded in Operating Revenues, with purchases, natural gas swaps and futures recorded in Purchased Power and Fuel expense. PGE records the non-physical settlement of non-trading electricity derivative activities on a net basis in Purchased Power and Fuel expense, in accordance with Emerging Issues Task Force Issue (EITF) No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and "Not Held for Trading Purposes".

Special accounting for qualifying hedges allows gains and losses on a derivative instrument to be recorded in Other Comprehensive Income (OCI) until they can offset the related results on the hedged item in the Income Statement. As discussed below, the effects of changes in fair value of certain derivative instruments entered into to hedge the Company's future non-trading retail resource requirements are subject to regulation and therefore are deferred pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

PGE discontinued its electricity and natural gas trading (non-retail) activities in early 2005. Unrealized and realized gains and losses on the settlement of all derivative instruments related to such activities were reported on a net basis, as required by EITF 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities.

Non-Trading Activities

PGE participates in the wholesale marketplace in order to balance its supply of power to meet the needs of its retail customers, manage risk, and administer its current long-term wholesale contracts. Such activities include power purchases and sales resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. Most of PGE's non-trading wholesale sales have been to utilities and power marketers and have been predominantly short-term. In this process, PGE may net purchases and sales with the same counterparty rather than simultaneously receiving and delivering physical power. These net transactions are also referred to as "book outs." Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations are physically settled.

SFAS No. 133 requires unrealized gains and losses on derivative instruments that do not qualify for either the normal purchase and normal sale exception or hedge accounting to be recorded in earnings in the current period. Current rates approved by the Public Utility Commission of Oregon (OPUC) are based on a valuation of all the Company's energy resources, including derivative instruments existing on October 27, 2005 that will settle during the 12-month period from January 1, 2006 to December 31, 2006. Such valuation was based on forward price curves in effect on November 8, 2005 for electricity and natural gas. The timing difference between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. As these contracts are settled, the regulatory asset or regulatory liability is reversed. However, as there is cur rently no power cost adjustment mechanism in effect for 2006, unrealized gains and losses related to new derivatives not included in rates that will settle in 2006, and changes in fair value of financial derivatives used to set 2006 rates, are not deferred as regulatory assets or regulatory liabilities, which can result in timing differences and earnings variability during the year.

The following table reflects unrealized gains and losses recorded in earnings for the periods indicated (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Non-Trading Activities
Unrealized gains (losses)	$	(13)	$	(4)	$	(92)	$	11
SFAS No. 71 regulatory (liability) asset		9		(3)		67		1
Net unrealized gains (losses)	$	(4)	$	(7)	$	(25)	$	12

The following table reflects derivative activities from cash flow hedges recorded in OCI (before taxes) for the periods indicated (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Derivative Activities Recorded in OCI
Other unrealized holding net gains (losses) arising during the period	$	12	$	(14)	$	(32)	$	63
Reclassification adjustment for contract settlements included in net income		2		(21)		(10)		(20)
Reclassification adjustment in net income due to discontinuance of cash flow hedges(*)		-		-		-		(2)
Reclassification of unrealized (gains) losses to SFAS No. 71 regulatory (liability) asset		(13)		30		40		(37)
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges	$	1	$	(5)	$	(2)	$	4

(*) Due to the probability that the original forecasted transactions will not occur.

Hedge ineffectiveness from cash flow hedges was not material in the first six months of 2006 and 2005. As of June 30, 2006, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 63 months. The Company estimates that of the $23 million of net unrealized gains in OCI at June 30, 2006, $20 million will be reclassified into earnings within the next twelve months (offset by $23 million in SFAS No. 71 regulatory liabilities) and $3 million will be reclassified over the remaining 51 months (fully offset by SFAS No. 71 regulatory liabilities).

Trading Activities

Prior to 2005, PGE utilized forward, swap, option, and futures contracts to participate in electricity and natural gas markets for non-retail purposes. In early 2005, PGE discontinued its trading activities for non-retail purposes; existing transactions, which were not material, were settled by December 31, 2005. Trading activities were not reflected in PGE's retail prices.

Note 4 - Legal and Environmental Matters

Legal Matters

Trojan Investment Recovery -In 1993, following the closure of the Trojan Nuclear Plant as part of its least cost planning process, PGE sought full recovery of, and a rate of return on, its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order (1995 Order) which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals and requested reviews were subsequently filed in the Marion County Circuit Court, the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The primary plaintiffs in the litigation were the Citizens' Utility Board (CUB) and the Utility Reform Project (URP). The Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and URP each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. PGE requested the Oregon Supreme Court to suspend its review of the 1998 Court of Appeals opinion pending resolution of URP's complaint with the OPUC challenging the accounting and ratemaking e lements of the settlement agreements approved by the OPUC in September 2000 (discussed below). On November 19, 2002, the Oregon Supreme Court dismissed PGE's and URP's petitions for review of the 1998 Oregon Court of Appeals decision. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

In 2000, while the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of, and return on, its investment in the Trojan plant. URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining credit due customers under terms of the 1997 merger of the Company's parent corporation at the time (Portland General Corporation) with Enron. The settlement al so allowed PGE recovery of approximately $47 million in income tax benefits related to the Trojan investment which had been flowed through to customers in prior years; it is estimated that such amount will be substantially recovered from PGE customers by the end of 2006. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE's investment in Trojan is no longer included in rates charged to customers, either through a return of or a return on that investment. Authorized collection of Trojan decommissioning costs is unaffected by the settlement agreements or the OPUC orders.

The URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, after a full contested case hearing, the OPUC issued an order (2002 Order) denying all of URP's challenges, and approving the accounting and ratemaking elements of the 2000 settlement. URP appealed the 2002 Order to the Marion County Circuit Court. On November 7, 2003, the Marion County Circuit Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have filed appeals to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On December 14, 2004, the Judge granted the Class Action Plaintiffs' motion for Class Certification and Partial Summary Judgment and denied PGE's motion for Summary Judgment. On March 3, 2005 and March 29, 200 5, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed and seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions. Briefing and arguments have been completed and a decision is pending.

On March 3, 2004, the OPUC re-opened three dockets in which it had addressed the issue of a return on PGE's investment in Trojan, including the 1995 Order and 2002 Order related to the settlement of 2000. The OPUC will consider the matter in two or more phases. Hearings in the first phase of the proceeding have been held and a decision is pending.

On February 14, 2005, PGE received a Notice of Potential Class Action Lawsuit for Damages and Demand to Rectify Damages from counsel representing Frank Gearhart, David Kafoury and Kafoury Brothers, LLC (Potential Plaintiffs), stating that Potential Plaintiffs intend to bring a class action lawsuit against the Company. Potential Plaintiffs allege that for the period from October 1, 2000 to the present, PGE's electricity rates have included unlawful charges for a return on investment in Trojan in an amount in excess of $100 million. Under Oregon law, there is no requirement as to the time the lawsuit must be filed following the 30-day notice period. No action has been filed to date.

Management cannot predict the ultimate outcome of the above matters. However, it believes these matters will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows for a future reporting period. No reserves have been established by PGE for any amounts related to this issue.

Multnomah County Business Income Taxes - In January 2005, David Kafoury and Kafoury Brothers, LLC filed a class action lawsuit in Multnomah County Circuit Court against PGE on behalf of all PGE customers who were billed on their electric bills and paid amounts for Multnomah County Business Income Taxes (MCBIT) after 1996 that the plaintiffs alleged were never paid to Multnomah County. The charges were billed and collected under OPUC rules that allow utilities to collect taxes imposed by the county. As PGE was included in Enron's consolidated income tax return, the Company paid the tax it collected to Enron. The plaintiffs sought judgment against PGE for restitution of MCBIT in excess of $6 million, plus interest, recoverable costs, and reasonable attorney fees. The plaintiffs filed an amended complaint on February 25, 2005, adding claims for fraud, unjust enrichment, conversion, statutory violations, and seeking punitive damages.

On December 28, 2005, the parties agreed to a settlement by which PGE will make refunds and payments totaling $10 million, inclusive of interest and plaintiffs' attorney fees, costs, and expenses as approved by the Court's final order. The settlement includes no admission of liability or wrongdoing by PGE. Distribution to customers is limited to amounts collected during the period 1999 through 2005. PGE established a reserve of $10 million in 2005 related to the settlement. On July 28, 2006, the settlement was approved by the Multnomah County Circuit Court. Refunds to customers are expected to begin in September 2006.

Union Grievances - In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers Local 125 (IBEW), the bargaining unit representing PGE's union workers, alleging that losses in their pension/savings plan were caused by Enron's manipulation of its stock. The grievances, which did not specify an amount of claim, sought binding arbitration. On August 14, 2003, the Multnomah County Circuit Court granted PGE's motion for summary judgment, finding that the grievances were not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision to the Oregon Court of Appeals. Both the U.S. District Court and the Bankruptcy Court approved the settlement of the class action litigation styledIn re Enron Corp. Securities Derivative & "ERISA" Litigation, Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action). On September 13, 2005, the U.S. District Court entered a Bar Order in the Tittle Action, which specifically barred all claims arising out of this case, including the IBEW grievance proceeding. On July 5, 2006, the Oregon Court of Appeals issued its opinion, holding that the judgment in the Tittle Action precludes the IBEW from pursuing its grievances, rendering the appeal moot, and dismissed the appeal.

Colstrip Royalty Claim - Western Energy Company (WECO) transports coal from the Rosebud Mine in Montana under a Coal Transportation Agreement with owners of Colstrip Units 3 and 4, in which PGE has a 20% ownership interest. In 2002 and 2003, WECO received two orders from the Office of Minerals Revenue Management of the U.S. Department of the Interior which asserted underpayment of royalties and taxes by WECO related to transportation of coal from the mine to Colstrip. WECO subsequently appealed the two orders to the Minerals Management Service (MMS) of the U.S. Department of the Interior. On March 28, 2005, the appeal by WECO was substantially denied. On April 28, 2005, WECO appealed the decision of the MMS to the Interior Board of Land Appeals of the U.S. Department of the Interior.

In May 2005, WECO received a "Preliminary Assessment Notice" from the Montana Department of Revenue, asserting claims similar to those of the Office of Minerals Revenue Management.

WECO has indicated to the owners of Colstrip Units 3 and 4 that, if WECO is unsuccessful in the above appeal process, it will seek reimbursement of any royalty payments by passing these costs on to the owners.

Management cannot predict the ultimate outcome of the above matters. Based on information currently known to the Company's management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. If WECO is able to pass any of these costs on to the owners, the Company would most likely seek recovery through the ratemaking process.

City of Portland Challenge of Stock Issuance -On February 10, 2006, the City of Portland appealed the OPUC order approving distribution of the new PGE common stock (OPUC Order) in both the Marion County Circuit Court and the Oregon Court of Appeals. The City filed in both courts due to the jurisdictional uncertainty created by new Oregon law governing appeals of OPUC decisions. On July 19, 2006, the Court of Appeals granted the OPUC's motion to dismiss the action before that Court. In its appeal to the Circuit Court, the City alleges that the OPUC made its decision on an inadequate record, failed to enter adequate findings in support of its decision, abused the discretion granted it by Oregon law, and based its decision on a statute that constituted an unlawful delegation from the Oregon Legislature. The City requests the OPUC Order be modified, reversed or remanded. The matter is proceeding in the Marion County Circuit Court. Management cannot predict the ultimate outcome o f this matter, however, it believes it will not have a material adverse impact on the Company's financial statements.

Environmental Matters

Harborton - A 1997 investigation by the Environmental Protection Agency (EPA) of a 5.5 mile segment of the Willamette River known as the Portland Harbor revealed significant contamination of sediments within the harbor. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund). In December 2000, PGE received a "Notice of Potential Liability" regarding its Harborton Substation facility and was included, along with sixty-eight other companies, on a list of Potentially Responsible Parties (PRPs) with respect to the Portland Harbor Superfund Site.

Also in 2000, PGE agreed with the Oregon Department of Environmental Quality (DEQ) to perform a voluntary remedial investigation of its Harborton Substation site to confirm whether any hazardous substances had been released from the substation property into the Portland Harbor sediments. In February 2002, PGE submitted its final investigative report to the DEQ, indicating that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site and that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The DEQ submitted the final investigative report to the EPA and, in a May 18, 2004 letter, the EPA stated that "based on the summary information provided by DEQ and the limited data EPA has at this stage in its process, EPA agrees at this time, that this site does not appear to be a current so urce of contamination to the river." Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis PRP.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter or estimate any potential loss. However, it believes this matter will not have a material adverse impact on the Company's financial statements.

Harbor Oil -Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company's power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil is also utilized by other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site that impacted an approximate two acre area. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyl's (PCBs), have been detected at the site. On September 29, 2003, Harbor Oil was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter starts a period for PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance a Remedial Investigation and Feasibility Study of the Harbor Oil site. Discussions among the EPA and the PRPs, including PGE, are continuing.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Harbor Oil Site or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company's financial statements.

Note 5 - Related Party Transactions

The tables below detail the Company's related party balances and transactions (in millions):

			June 30, 2006	December 31, 2005
Payables to affiliated companies
	Enron Corp:
		Accounts Payable(a)	$  -	$  4
		Income Taxes Payable(b)	-	25
(a)Included in Accounts payable and other accruals on the Condensed Consolidated Balance Sheets
(b)Included in Accrued taxes on the Condensed Consolidated Balance Sheets

For the Six Months Ended June 30			2006	2005
Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services(a)	$ (1)	$ 2
(a)Included in Administrative and other on the Condensed Consolidated Statements of Income

Effective with the April 3, 2006 issuance of new PGE common stock, PGE is no longer a subsidiary of Enron. PGE and its subsidiaries are no longer included in Enron's consolidated tax return and will file their own consolidated tax returns and remit payments directly to taxing authorities.

As PGE was included in Enron's consolidated income tax return prior to April 3, 2006, the Company made payments to Enron for PGE's income tax liabilities. The $25 million income taxes payable to Enron at December 31, 2005 represents a net current income taxes payable for the fourth quarter of 2005 that was paid to Enron in January 2006. In April 2006, PGE paid Enron $17 million for net current income taxes payable for the first quarter of 2006.

Enron incurred costs related to the resolution of issues associated with its bankruptcy and litigation related to certain employee benefit plans in which PGE employees previously participated. Enron billed PGE for a portion of these costs as work continued toward resolution of the issues. At December 31, 2005, PGE had $4 million payable to Enron related to these costs. Final resolution of the issues resulted in a $1 million reduction in the amount payable to Enron and a corresponding reduction in Administrative and other expense. In March 2006, PGE paid the remaining $3 million balance due to Enron.

Note 6 - Receivables and Refunds on Wholesale Market Transactions

Receivables - California Wholesale Market

As of June 30, 2006, PGE has net accounts receivable balances totaling approximately $63 million from the California Independent System Operator (ISO) and the California Power Exchange (PX) for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).

In March 2001, the PX filed for bankruptcy and in April 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code. PGE filed a proof of claim in each of the proceedings for all past due amounts. Although both entities have emerged from their bankruptcy proceedings as reorganized debtors, not all claims filed in the proceedings, including those filed by PGE, have been resolved. PGE is continuing to pursue collection of these claims.

Management continues to assess PGE's exposure relative to these receivables. Based upon Federal Energy Regulatory Commission (FERC) orders regarding the methodology to be used to calculate refunds and the FERC's indication that potential refunds related to California wholesale sales (see "Refunds on Wholesale Transactions" below) can be offset with accounts receivable related to such sales, PGE has established reserves totaling $40 million related to this receivable amount. The Company is examining numerous options, including legal, regulatory, and other means, to pursue collection of any amounts ultimately not received through the bankruptcy process.

Refunds on Wholesale Transactions

California

On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds for wholesale sales transactions made between October 2, 2000 and June 20, 2001 in the spot markets (defined by the FERC as 24 hours or less) operated by the ISO and PX. The order established evidentiary hearings to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

Also in August 2002, the FERC Staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly.

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds, based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates its potential liability under the modified methodology at between $40 million and $50 million, of which $40 million has been established as a reserve, as discussed above.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the methodology for the pricing of natural gas. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds, and, on December 20, 2003 the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals; several other parties have also appealed the October 16, 2003 order. On May 12, 2004, the FERC issued an order (Rehearing Order) that denied further requests for rehearing of the October 16, 2003 order. Although there continue to be miscellaneous orders issued in the underlying FERC proceeding, the Ninth Circuit Court of Appeals has now begun to hear the numerous appeals. It has bifurcated appeals of the existing cases into two phases. The first con sidered arguments regarding jurisdictional issues and the permissible scope of refund liability, both in terms of the time frame for which refunds were ordered and the types of transactions subject to refund. As to the jurisdictional issues, on September 6, 2005, the Court ruled that the FERC did not have jurisdiction to order municipal utilities and other governmental entities to make refunds for the sales they had made to the ISO and PX that are the subject of the refund proceeding. The Court agreed to defer the rehearing deadline on the jurisdictional issue decision until the remainder of the first phase is decided. The second phase will consider the issues relating to the refund methodology itself. PGE expects that the Court will establish additional phases as the continuing issues remaining before the FERC become final and are appealed.

On August 2, 2006, the Court issued its decision on the remainder of the issues in the first phase (Phase I). The Court upheld the refund effective date of October 2, 2000, but remanded to the FERC the issue of whether it should order refunds for the summer 2000 period pursuant to its authority under Section 309 of the Federal Power Act (FPA) to remedy tariff violations. The Court also affirmed the FERC's orders on the scope of the refund proceeding, except with regard to the FERC's exclusion of ISO and PX contracts in excess of 24 hours and energy exchanges. The Court held that transactions in the ISO and PX markets with a duration in excess of 24 hours, as well as energy exchanges, should be included within the scope of the refund case. In a separate action, the Court ordered a 45-day extension in the time to file for rehearing of its Phase I decisions (resulting in a 90-day period for rehearings to be filed), urging the parties to use the time to assess possibilities of settlement. Mana gement is continuing to analyze the impact of this decision on PGE, including the impact, if any, on the amount of any refund liability.

In addition to the Rehearing Order, the FERC also issued a separate order that provided clarification regarding certain aspects of the methodology for California generators to recover fuel costs incurred to generate power that were in excess of the gas cost component used to establish the refund liability (Fuel Cost Order). On September 24, 2004, the FERC issued an order that denied requests for rehearing of the Fuel Cost Order and also adopted a new methodology to allocate the excess amounts of fuel costs that California generators are permitted to recover. Additional clarifying orders continue to be issued periodically. Under the new allocation methodology, PGE could be required to pay additional amounts in those hours when it was a net buyer in California spot markets, thus increasing its net refund liability. PGE does not expect a material increase in the Company's potential refund exposure. Partly as a means of limiting its exposure to additional fuel costs, PGE has opted to become a participant in several settlements filed jointly by large generators and California parties, and approved by the FERC during 2004 and 2005.

In August 2005, PGE joined in a settlement agreement resolving issues relating to the allocation of the wind-up costs of the PX for both past and future periods. The settlement has been approved by the FERC. Although under the agreement PGE will bear certain additional costs associated with PX obligations to conduct and finalize refund calculations, PGE does not expect those costs to be material to its financial statements.

In several of its underlying refund orders, the FERC has indicated that if marketers, such as PGE, believe that the level of their refund liability has caused them to incur an overall revenue shortfall for their sales to the ISO and PX during the refund period, they will be permitted to file a cost study to prove that they should be permitted to recover additional revenues in excess of the mitigated prices in order to cover their costs. By order issued August 8, 2005, the FERC provided guidelines regarding the manner in which these studies should be conducted and the principles that should govern their preparation. PGE filed for rehearing of certain aspects of the August 8, 2005 order, and, on September 14, 2005, it filed its cost recovery study with the FERC. The study showed that, pursuant to the principles set forth in the August 8, 2005 order and subject to rehearing, PGE's costs to serve the ISO and PX markets exceeded the revenues PGE will receive from those mitig ated sales by over $27 million. By order issued January 26, 2006, the FERC conditionally accepted PGE's September 14, 2005 cost filing, subject to PGE making a compliance filing to eliminate certain costs, to include additional revenues, and to supplement its analysis with additional cost, load, and resource data. On February 10, 2006, PGE submitted a compliance filing with two alternative cases incorporating the FERC-required changes. The compliance filing shows a revenue deficit for PGE's sales to the ISO and PX (that is, a reduction to PGE's refund liability) of from approximately $20 million to approximately $30 million, depending on the methodology ultimately accepted by the FERC. Third parties have challenged PGE's compliance filing and requested that it be rejected in its entirety or that the cost offset be reduced to zero, and PGE has filed a response to those challenges. Pursuant to the procedure established by the FERC in the January 26, 2006 order that required each seller whos e cost filing has been accepted to incorporate in its filing final ISO and PX settlement data, PGE has provided its revised filing to the ISO and PX for further processing.

PGE believes that the FERC erred in certain of its findings in the January 26, 2006 order, and has filed a request for rehearing as to several issues. Due to the continuing uncertainty related to these matters, PGE has made no adjustment to the $40 million reserve previously established for the Company's potential liability, as described above.

The FERC has indicated that any refunds PGE may be required to pay related to California wholesale sales (plus interest from collection date) can be offset by accounts receivable (plus interest from due date) related to sales in California (see "Receivables - California Wholesale Market" above). In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost adjustment mechanism in effect at that time. This could further mitigate the financial effect of any refunds made or received by the Company.

Challenge of the California Attorney General to Market-Based Rates - On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, alleging that the FERC's authorization of market-based rates violated the FPA, and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals. On September 8, 2004, the Court issued an opinion uph olding the FERC's authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC, upon remand, to reconsider whether refunds should be ordered. On October 25, 2004, certain parties filed a petition for rehearing with the Court. In the refund case and in related dockets, the California Attorney General and other California parties have argued that refunds should be ordered retroactively to at least May 1, 2000. Management cannot predict the outcome of these proceedings or whether the FERC will order refunds retroactively to May 1, 2000, and if so, how such refunds would be calculated.

Anomalous Bidding Allegations

By order issued on June 25, 2003, the FERC instituted an investigation into allegations of anomalous bidding activities and practices ("economic withholding") on the part of numerous parties, including PGE. The FERC determined that bids above $250 per MW in the period from May 1, 2000 through October 2, 2000 may have violated tariff provisions of the ISO and the PX. The FERC required companies that bid in excess of $250 per MW to provide information on their bids to the FERC investigation staff. PGE responded to the FERC's inquiries and, on May 12, 2004, the FERC investigation staff issued to PGE a letter terminating the investigation as to the Company without further action. On March 10, 2005, certain California parties filed appeals with the Ninth Circuit Court of Appeals, contesting the FERC's conduct of the investigation of the anomalous bidding allegations and the issuance of the dismissal letters.

Pacific Northwest

In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders.

Management cannot predict the ultimate outcome of the above matters related to wholesale transactions in California and the Pacific Northwest. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows for future reporting periods.

Note 7 - New Oregon Law-Utility Rate Treatment of Income Taxes

A new law, commonly referred to as Oregon Senate Bill 408 (SB 408), seeks to adjust the way that PGE and most other Oregon investor-owned electric and gas utilities collect income taxes from ratepayers. SB 408 attempts to more closely match tax amounts collected in revenues with the amount of income taxes paid to governmental entities by investor-owned utilities or their consolidated group. The new law requires that utilities file reports with the OPUC by October 15 of each year regarding the amount of taxes paid by the utility or its consolidated group (with certain adjustments), as well as the amount of taxes authorized to be collected in rates, as defined by the statute. If the OPUC determines that the difference between the two amounts is greater than $100,000, the utility is required to establish an "automatic adjustment clause" to adjust rates. The first adjustment under the automatic adjustment clause applies only to taxes paid to units of government and collected fr om ratepayers on or after January 1, 2006.

PGE, along with other utilities and consumer groups, has been participating in the OPUC's SB 408 rulemaking process. PGE proposed that the rules include an earnings test that would be incorporated into the automatic adjustment clause. Under the earnings test, the utility would not surcharge or refund to customers if the utility's earnings were above or below a specified level.

On July 14, 2006, the OPUC issued an interim order (Interim Order) that sets forth preliminary decisions regarding the implementation of SB 408. In the Interim Order, the OPUC declined to adopt the earnings test proposed by PGE. In addition, the OPUC proposed a methodology to determine refunds that establishes a formula to determine the ratio of a utility's business to its parent company's business. This ratio is then multiplied by the amount of total taxes paid by the parent company to determine the amount that should be properly attributed to the utility.

Effective with the April 3, 2006 issuance of new PGE common stock, PGE is no longer a subsidiary of Enron and will file its own consolidated tax returns and remit payments directly to taxing authorities. However, in April 2006 PGE paid $17 million to Enron for net current taxes payable for the first quarter of 2006 when PGE was still included in Enron's consolidated group for filing consolidated federal and state income tax returns. Under the proposals in the Interim Order, PGE could be required to refund to customers a portion of that amount, as well as a portion of the future amount it collects for taxes in its current rates.

On December 30, 2005, PGE filed with the OPUC an application for deferred accounting to prevent either the financial enrichment or financial harm to the Company should the rules implementing SB 408 include the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. The deferred amount would reflect the tax effect of the difference between PGE's implied operating costs under a fixed margin assumption and the Company's actual operating costs. The Interim Order does propose the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. In the Interim Order, the OPUC indicated that it would review deferral applications related to SB 408 on a case by case basis, but would view such applications with skepticism.

In its assessment of the Interim Order, PGE has revised its estimates of the range of potential refunds to customers for 2006 to be from $18 million to $66 million. Based on the low end of the range, the Company recorded a $9 million (pre-tax) reserve for the first half of 2006 for a potential refund obligation to customers using a percentage of estimated annual revenues collected through this period.

The OPUC will accept public comments on its preliminary decision until August 21, 2006 and is expected to adopt permanent rules in September 2006 or later. PGE will continue to evaluate the OPUC's proposals and participate in the rulemaking proceeding, including considering whether to continue to pursue adoption of an earnings test and elimination of the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. Any final rules adopted and rate adjustments ordered by the OPUC are subject to court appeal by any party.

The Company is unable to predict the ultimate outcome of the implementation of SB 408 due to uncertainties as to the final OPUC rules, consideration of the deferral application, the ability to secure rate relief apart from the results implied by SB 408, and the possibility of litigation.

Complaint and Application for Deferral - Income Taxes - On October 5, 2005, the Utility Reform Project and Ken Lewis (Complainants) filed a Complaint with the OPUC alleging that, since September 2, 2005 (the effective date of SB 408), PGE's rates are not just and reasonable and are in violation of SB 408 because they contain approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any government. The Complaint requests that the OPUC order the creation of a deferred account for all amounts charged to ratepayers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes.

Also on October 5, 2005, the Complainants filed an Application for Deferred Accounting with the OPUC, claiming that PGE is charging ratepayers $92.6 million annually for federal and state income taxes that are not being paid, and that such charges are not fair, just and reasonable. The Application for Deferred Accounting requests that the portion of PGE's revenue representing estimated PGE liabilities for federal and state income taxes, less any amounts of federal and state income taxes paid by PGE or on behalf of PGE, be deferred for later incorporation in rates.

On December 27, 2005, the OPUC issued a Joint Ruling to hold the Complaint and the Application for Deferred Accounting in abeyance pending rehearing of an order previously issued by the OPUC in a rate proceeding involving another Oregon electric utility. On July 10, 2006, the OPUC issued the order in the matter related to the other utility and has commenced the proceeding on the Complaint. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Note 8 - Common Stock

Common Stock Issuance

In accordance with Enron's Chapter 11 Plan, on April 3, 2006 PGE issued 62.5 million shares (of 80 million, no par value, shares authorized) of new PGE common stock. Approximately 27 million shares (43% of total shares distributed) of the new PGE common stock were issued to the Debtors' creditors holding allowed claims, and approximately 35.5 million shares (57% of total shares distributed) were issued to a Disputed Claims Reserve (DCR), where the shares will be held to be released over time to the Debtors' creditors holding allowed claims, in accordance with the Chapter 11 Plan. The 42.8 million shares of PGE common stock previously held by Enron were cancelled. Following issuance of the new PGE common stock, PGE ceased to be a subsidiary of Enron. The new PGE common stock is listed on the New York Stock Exchange under the ticker symbol POR.

PGE accounted for the stock issuance in the same manner as a stock split and has retroactively adjusted all periods presented. The Company's balance sheet reflects the combined book values of the $3.75 par value common stock that was cancelled and other paid-in capital into the new item "Common stock, no par value." PGE's income statement reflects "Earnings per Average Share" for both current and prior periods, with such amounts based upon the number of outstanding shares of new PGE common stock. Costs incurred for the issuance of new common stock, and for PGE to become a publicly-traded company, were charged to operating expense as incurred.

In addition to the issuance of the 62.5 million shares of new PGE common stock described above, approximately 4.7 million shares have been registered for future issuance pursuant to the Portland General Electric Company 2006 Stock Incentive Plan.

Common Stock Dividends

The OPUC order approving the issuance of new PGE common stock includes a stipulation containing several conditions, including a requirement that, after issuance of the new common stock, PGE cannot pay a common stock dividend that would cause the common equity capital percentage to fall below 48% (plus $40 million, as discussed below) without OPUC approval. The requirement is reduced to 45% when the DCR holds between 20% and 40% of the issued and outstanding common stock of PGE, with no minimum common equity capital percentage requirement when the DCR holds less than 20% of the issued and outstanding common stock of PGE. At June 30, 2006, the DCR held 55% of total issued and outstanding common stock of PGE. PGE has agreed to maintain the additional $40 million of common equity until an OPUC order is issued in the Company's pending general rate case to assure PGE's financial capacity to absorb any adjustment(s) in its revenue requirement related to its former ownership by Enron.

Note 9 - Credit Facility and Debt

Pursuant to PGE's application, the FERC issued an order on February 3, 2006 which authorized the Company to issue short-term debt, including commercial paper, in an amount not to exceed $400 million outstanding at any one time, over the two-year period February 8, 2006 through February 7, 2008. To meet short-term cash requirements, PGE has established a program under which it may from time to time issue commercial paper for terms of up to 270 days. The commercial paper program is supported by the Company's $400 million five-year unsecured revolving credit facility, which in July 2006 was amended to extend the termination date to July 14, 2011. The amount available under the commercial paper program is limited to the unused line of credit under the revolving credit facility.

Although the commercial paper program subjects the Company to fluctuations in interest rates, reflecting current market conditions, individual instruments carried a fixed rate during their respective terms. Due to the short-term nature of the commercial paper, the fair value of such instruments approximates their book value.

Short-term borrowings and related interest rates were as follows (dollars in millions):

		June 30,		December 31,
		2006		2005
Aggregate short-term debt outstanding -
	Commercial paper	$	-	$	-
Weighted average interest rate -
	Commercial paper*		-		-
Unused committed line of credit		$	395	$	383

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2006		2005		2006		2005
Average daily amounts of short-term debt
	outstanding -
		Commercial paper	$	23	$	-	$	17	$	-
Weighted daily average interest rate -
		Commercial paper*		5.0%		-		4.9%		-
Maximum amount outstanding during the
	period -
		Commercial paper	$	57	$	-	$	57	$	-

*Interest rates exclude the effect of commitment fees, facility fees, and other financing fees

On May 24, 2006, PGE issued $275 million of First Mortgage Bonds as a private placement to certain institutional buyers, pursuant to a Bond Purchase Agreement between PGE and the buyers. One series of the bonds, in the principal amount of $175 million, bears interest at an annual rate of 6.31% and is scheduled to mature on May 1, 2036. The other series, in the principal amount of $100 million, bears interest at an annual rate of 6.26% and is scheduled to mature on May 1, 2031. The bonds are redeemable at the option of PGE at designated "make-whole" redemption prices. The bonds were issued under PGE's Indenture of Mortgage and Deed of Trust, dated July 1, 1945, as supplemented (including the Fifty-Sixth Supplemental Indenture dated May 1, 2006). PGE used the proceeds from the bond issuance for the early retirement of the $150 million principal amount of 8 1/8% Series First Mortgage Bonds due in 2010, and for general corporate purposes. Approximately $13 million of costs related to the retirement of the 8 1/8% Series bonds, consisting primarily of a redemption premium, was deferred for future amortization over the life of the new bonds and is included within Regulatory assets on the Condensed Consolidated Balance Sheets.

Note 10 - Guarantees

PGE enters into finance and power purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities. The Company has not recorded any liability on the Condensed Consolidated Balance Sheets with respect to these indemnifications. Based on PGE's historical experience and the evaluation of the specific indemnities, management believes the likelihood that PGE would be required to perform or otherwise incur any significant losses is remote.

Note 11 - New Accounting Standards

SFAS No. 123R (SFAS 123R), Share-Based Payment, was issued in December 2004 and superseded SFAS No. 123 and Accounting Principles Board Opinion 25, Accounting for Stock-Based Compensation. SFAS 123R is effective for annual reporting periods beginning after June 15, 2005. Companies that issue share-based payment awards to employees are required to recognize compensation expense based on the fair value of the expected vested portion of the award as of the grant date over the vesting period of the award. Forfeitures that occur before the award vesting date will be adjusted from the total compensation expense, but once the award vests, no adjustment to compensation expense is allowed for forfeitures or unexercised awards. In addition, SFAS 123R requires recognition of compensation expense of all existing outstanding awards that are not fully vested for their remaining vesting period as of the effective date that were not accounted for under a fair value method of accounting at the t ime of their award. PGE had no outstanding equity awards at June 30, 2006. On July 13, 2006, PGE awarded restricted stock units to its Board of Directors, officers, and certain key employees, the effect of which is not expected to have a material impact on the financial statements of the Company.

FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109, was issued in July 2006 and is effective for annual reporting periods beginning after December 15, 2006. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. It requires that a tax position meet a "more-likely-than-not threshold" for the benefit of an uncertain tax position to be recognized in the financial statements. FIN 48 requires recognition in the financial statements of the best estimate of the effects of a tax position only if that position is more likely than not of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. PGE is evaluating the application of FIN 48 with respect to its income taxes.

Note 12 - Restatement of Prior Period Financial Statements

Non-Utility Property - Asset Retirement Obligation

During the financial closing process for the year ended December 31, 2005, PGE determined that a $20 million liability established in 1997 for estimated future demolition and remediation costs related to tenant leasehold improvements on non-utility land located adjacent to the Company's Sullivan Hydro Plant did not include consideration of salvage values. Inclusion of salvage values would have reduced the recorded liability by $8 million (to $12 million) and adjusted related deferred taxes by $3 million.

In addition, upon the January 1, 2003 adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, the Company should have further reduced the recorded liability by $4 million (to its estimated $8 million fair value) and adjusted related deferred income taxes by $2 million.

The combined effect of the above on the beginning balance of Retained Earnings as of January 1, 2005, as included in PGE's Condensed Consolidated Statements of Retained Earnings, was an increase from $637 million (as previously reported) to $644 million (as restated).

In addition, the Company has restated the presentation of the activities within the Nuclear Decommissioning Trust to disclose amounts on a gross basis, rather than on a net basis, in the Condensed Consolidated Statements of Cash Flows.

Item 2.Management's Discussion and Analysis of Financial

Condition and Results of Operations

Overview

Ownership of PGE -On April 3, 2006, 62.5 million shares of new PGE common stock were issued to Enron's creditors holding allowed claims and to a Disputed Claims Reserve, where the shares will be held to be released over time to such creditors. The new PGE common stock is listed on the New York Stock Exchange under the symbol POR. The previously outstanding PGE common stock, all of which was held by Enron, was cancelled, and PGE is no longer a subsidiary of Enron. For further information, see "Ownership of PGE" in "Financial and Operating Outlook" of this Item 2.

Customers -PGE continues its focus on providing safe and reliable electric service to its 791,000 retail customers, including approximately 14,000 new customers added in the past twelve months. The Company continues to rank well in overall customer satisfaction.

Oregon's economy continued to expand in the first half of 2006, albeit slower in the second quarter, with the state's unemployment rate at 5.4% in June, down significantly from that of the last two years. Oregon's non-farm employment (seasonally adjusted) reached a record high during the current quarter and stood at 3.4% above the same period a year ago.

Retail loads during the first half of 2006 increased due to both continued customer growth and weather conditions. Energy use by all major customer sectors increased over the first half of last year. On June 26, 2006, the Company recorded an all-time high net system load "summer" peak of 3,586 MW. Weather adjusted retail energy sales increased 2.1% compared to the first half of 2005 and are projected to maintain this level for the remainder of 2006.

Power Supply -Regional hydro conditions in 2006 exceed average levels and are significantly improved from the Pacific Northwest's severe to moderate drought conditions of the past three years. Increased stream flows in both the Clackamas and Deschutes river systems, where PGE's facilities are located, resulted in a 44% increase in the Company's hydro generation compared to the first half of 2005. Improved regional conditions resulted in a 22% increase in output received from mid-Columbia River hydro projects with which PGE has long-term power purchase contracts and have also contributed to lower wholesale market prices. Current forecasts indicate continued above-normal hydro conditions for the remainder of this year.

The Boardman Coal Plant, taken out of service in late October 2005 for repair of the plant's turbine rotor, remained out of service during the first four-and-a-half months of 2006 for repairs to both the turbine and generator rotors. Although Boardman was operational by late May 2006, it was again taken offline in early June for repairs to the low pressure turbine unit. The plant returned to full operation in early July. Due to favorable water conditions, PGE was able to meet a greater portion of its retail load requirement, and partially offset the loss of Boardman generation, with output from the Company's hydroelectric generating facilities.

PGE continues to implement its Integrated Resource Plan (IRP) to meet the electricity needs of its customers, with the 400 MW Port Westward natural gas-fired plant on schedule for completion in the first quarter of 2007. PGE currently plans to file a new IRP with the OPUC by the end of 2006 or in early 2007.

The OPUC recently granted approvals related to the Company's planned acquisition of development rights for the Biglow Canyon Wind Farm that would allow PGE to develop up to 450 MW of energy capacity. A settlement agreement related to the license application for the Company's four hydroelectric projects on the Clackamas River was submitted to the FERC in late March 2006 for review and approval.

Regulatory bodies continue to examine the issues of regional haze and mercury in the atmosphere and could require that the Company make modifications to certain of its generating facilities.

Operations -The Company continues to achieve solid rankings for power quality and reliability, measured in terms of outage frequency and duration.

Plans are continuing for the demolition of major structures at the closed Trojan nuclear power facility, with implosion of the cooling tower successfully completed in late-May 2006. Site preparation for demolition of remaining structures (including turbine, control, auxiliary, and fuel buildings) has begun, with removal planned during 2006 and 2007. The final phase of project demolition, including the plant's containment building, is scheduled for 2008. PGE has designed the demolition work to minimize impacts on the environment and surrounding communities.

Regulatory Matters -In March 2006, PGE filed a general rate case and proposed new tariffs for consideration by the OPUC, based upon a 2007 test year. The filing includes power costs, recovery of the Company's investment in Port Westward, and general (non-power) costs. The Company also submitted to the OPUC a preliminary "Resource Valuation Mechanism" (RVM) filing related to projected 2007 power costs, which has been consolidated with the general rate case. For further information, see "General Rate Case" in "Financial and Operating Outlook" of this Item 2.

PGE has filed an application with the OPUC seeking deferral, for future ratemaking treatment, of replacement power costs related to the period during which Boardman was out of service for repair of the plant's turbine rotor, which ended on February 5, 2006. For further information, see "Boardman Coal Plant - Repair Outages" in "Financial and Operating Outlook" of this Item 2.

PGE continues to participate with other utilities and consumer groups in the OPUC's rule making process to implement Oregon Senate Bill 408, which seeks to match amounts collected in rates for income taxes with income taxes paid to governmental entities by investor-owned utilities or their consolidated group. There remains considerable uncertainty regarding the new law, with numerous issues subject to interpretation by the OPUC, and the Company continues to evaluate its potential effects.

Financial Performance -Although PGE returned to profitability in the second quarter of 2006, earnings for the first half of the year were adversely affected by the high cost of power to replace the output of Boardman during the plant's repair outages, with incremental power costs estimated at approximately $52 million during the first half of 2006. Higher energy sales and improved hydro conditions only partially offset the effect of the Boardman outage on the Company's financial results for the first half of 2006.

PGE continues to maintain its investment grade bond ratings and is able to provide stable operating cash flow and adequate liquidity through both its $400 million credit facility and access to the commercial paper market. In May 2006, the Company issued $275 million in First Mortgage Bonds as a private placement, using the proceeds for the early retirement of the outstanding $150 million principal amount of 8 1/8% Series First Mortgage Bonds due in 2010, and for general corporate purposes. The Company continues to invest in its new Port Westward generation facility and is planning for the development of renewable energy from the Biglow Canyon Wind Farm.

Results of Operations

The following review of PGE's results of operations should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, quarterly operating earnings are not necessarily indicative of results to be expected for calendar year 2006.

2006 Compared to 2005 for the Three Months Ended June 30

PGE's net income in the second quarter of 2006 was $27 million ($0.43 per share) compared to $16 million ($0.26 per share) in the second quarter of 2005. The increase in earnings was due primarily to improved margins on energy sales, resulting largely from favorable hydro conditions. Higher energy sales, resulting from both an increase in customers and warmer weather, along with reduced maintenance expenses at the Company's thermal generating plants and a reduction in administrative and other expenses, also contributed to the increase in earnings for the quarter. Results for the second quarter of 2006 include the effect of a $5 million after tax reserve for a potential refund obligation to customers, reflecting the Company's current estimate of the impact of SB 408.

The following table summarizes Operating Revenues and Energy Sold and Delivered for the second quarter of 2006 and 2005:

			Three Months Ended June 30,
Operating Revenues			2006	2005	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$ 318	$ 304	$    14
		Direct Access Customer Revenues	(3)	-	(3)
Total Retail Revenues			315	304	11
Wholesale (Non-Trading)			30	25	5
Other Operating Revenues			6	4	2
Total Operating Revenues			$ 351	$ 333	$    18
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		4,312	4,040	272
	Energy Delivered to Direct Access Customers		263	306	(43)
Total Retail Energy Deliveries			4,575	4,346	229
Wholesale (Non-Trading)			897	467	430
Trading Activities			-	88	(88)
Total Energy Sold and Delivered			5,472	4,901	571

Total Operating Revenues in the second quarter of 2006 increased approximately 5.4% from last year's second quarter, as a 3.6% increase in Total Retail Revenues was accompanied by higher Wholesale and Other Operating Revenues. The increase in Total Retail Revenues resulted from both higher energy sales and a 2006 rate increase related to higher power costs. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2 for further information). A 6.7% increase in Retail Energy Sales resulted primarily from an approximate 13,900 increase in the average number of customers served over the second quarter of 2005, warmer weather, and higher industrial sales. Energy use by all major customer classes increased during the second quarter of 2006, with residential energy sales up 2% and commercial and industrial sales up 5.2% and 19.7%, respectively. The increase in industrial sales was primarily attributable to two large customers, one of which normally generates most of i ts own power requirements, and another which purchased its energy from an ESS in 2005 but returned to PGE for service at the beginning of 2006.

Partially offsetting the above increases was a $9 million ($5 million after tax) reserve for a potential refund obligation to customers related to the Company's current estimate of the impact of SB 408. (See "New Oregon Law - Utility Rate Treatment of Income Taxes" in the "Financial and Operating Outlook" of this Item 2 for further information). In addition, there was a $6 million reduction in the collection of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Depreciation and Amortization expense). The reduction in Direct Access Customer Revenues resulted from "transition adjustment" credits reflecting the difference between the cost and market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

Wholesale revenues increased by about 20% from last year's second quarter primarily due to higher energy sales. Partially offsetting the increased demand was lower average spot market prices in the second quarter of 2006, resulting primarily from increased regional hydro availability.

The increase in Other Operating Revenues from last year's second quarter was the result of increased sales of unutilized transmission capacity and by higher revenues from the sale of natural gas in excess of generating plant requirements.

Purchased Power and Fuel expense increased $12 million (9%) from last year's second quarter. The increase was due primarily to increased power purchases to meet higher total system load requirements. Approximately $8 million of incremental power costs were incurred to replace the output of Boardman, which was offline for repairs during most of the second quarter of 2006. The increase in power purchases was partially offset by lower prices reflecting the impact of increased hydro availability.

Company generation decreased 40% from that of last year's second quarter, with reduced thermal generation, resulting from the Boardman outages, partially offset by a 25% increase in PGE hydro production, resulting from increased stream flows. Total generation met approximately 22% of PGE's retail load during the second quarter of 2006, compared to 40% last year.

The following table indicates PGE's total system load (including both retail and wholesale) for the second quarter of 2006 and 2005. Average variable power costs include wheeling and exclude unrealized gains and losses from derivative instruments.

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)
	2006	2005	2006	2005
Generation	1,018	1,701	8.9	9.4
Term Purchases	3,921	2,895	26.3	29.6
Spot Purchases	548	163	20.1	18.6
Total System Load	5,487	4,759	25.4	24.9

Production, distribution, administrative and other expenses decreased $3 million (4%) from the second quarter of 2005 due primarily to last year's second quarter settlement of certain asserted claims and a reduction in maintenance expenses at PGE's thermal generating facilities in 2006.

Depreciation and Amortization expense decreased $5 million (9%) primarily due to a $6 million decrease in amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues). Depreciation of utility plant increased approximately $1 million.

Income taxes increased $5 million due to higher taxable income in the second quarter of 2006.

2006 Compared to 2005 for the Six Months Ended June 30

PGE's net income was $21 million ($0.34 per share) in the first half of 2006 compared to net income of $54 million ($0.87 per share) in the first half of 2005. The decrease in earnings was due primarily to reduced margins on energy sales, caused by replacement power costs related to the extended, unplanned repair outages of Boardman, and unrealized losses on power and natural gas contracts in the first half of 2006. Increased costs related to winter storm restoration, Boardman repair and maintenance, and customer support activities were offset by lower administrative expenses in this year's first half. Results for the first half of 2006 include the effect of a $5 million after tax reserve for a potential refund obligation to customers, reflecting the Company's current estimate of the impact of SB 408.The following table summarizes Operating Revenues and Energy Sold and Delivered for the six-month periods ending June 30, 2006 and 2005:

			Six Months Ended June 30,
Operating Revenues			2006	2005	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$ 676	$ 641	$    35
		Direct Access Customer Revenues	(6)	-	(6)
Total Retail Revenues			670	641	29
Wholesale (Non-Trading)			54	52	2
Other Operating Revenues			8	11	(3)
Total Operating Revenues			$ 732	$ 704	$    28
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		9,085	8,564	521
	Energy Delivered to Direct Access Customers		510	588	(78)
Total Retail Energy Deliveries			9,595	9,152	443
Wholesale (Non-Trading)			1,509	1,080	429
Trading Activities			-	574	(574)
Total Energy Sold and Delivered			11,104	10,806	298

Total Operating Revenues in the first half of 2006 increased approximately 4% from the first half of last year due to higher Total Retail Revenues. The increase in Total Retail Revenues resulted from both higher energy sales and a 2006 rate increase related to higher power costs. (See "Resource Valuation Mechanism" in "Financial and Operating Outlook" of this Item 2 for further information). A 6.1% increase in Retail Energy Sales in the first half of 2006 resulted from an approximate 13,400 increase in the average number of customers served over the first half of 2005, higher industrial sales, and weather conditions. Colder weather in this year's first quarter, along with warmer weather in June, contributed to higher energy use. Energy use by all major customer classes increased, with residential energy sales up 5.3% and commercial and industrial sales up 4% and 12.7%, respectively. The increase in industrial sales was primarily attributable to two large customers, one of which normally ge nerates most of its own power requirements and another which purchased its energy from an ESS in 2005 but returned to PGE for service at the beginning of 2006.

Partially offsetting the above increases was a $9 million ($5 million after tax) reserve for a potential refund obligation to customers related to the Company's current estimate of the impact of SB 408. (See "New Oregon Law - Utility Rate Treatment of Income Taxes" in the "Financial and Operating Outlook" of this Item 2 for further information.) In addition, there was a $14 million reduction in the collection of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Depreciation and Amortization expense). The reduction in Direct Access Customer Revenues resulted from "transition adjustment" credits reflecting the difference between the cost and market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

Purchased Power and Fuel expense increased $102 million (37%) from the first half of last year. The increase was due primarily to the cost of replacing coal-fired generation at Boardman and results of portfolio management activities in power and natural gas markets, related to the effect of increased hydro availability on market prices. Approximately $52 million of incremental power costs were incurred in the first half of 2006 to replace the output of Boardman, which was taken out of service in late October 2005 for repair of the plant's turbine rotor and which remained out of service for most of the first half of 2006 for additional repairs, including those to the plant's generator rotor. (See "Boardman Coal Plant - Repair Outages" in "Financial and Operating Outlook" of this Item 2 for further information). In addition, expenses in the first half of 2006 include $25 million of unrealized net losses on derivative activities, compared to $12 million of unrealized net gains in the fir st half of 2005. It is expected that the unrealized losses at the end of this year's second quarter will reverse during the remainder of 2006 upon settlement of the related contracts.

Company generation decreased 37% from that of last year's first half, with reduced thermal generation partially offset by a 44% increase in PGE hydro production, resulting from increased stream flows. Total generation met approximately 25% of PGE's retail load during the first half of 2006, compared to 43% last year.

The following table indicates PGE's total system load (including both retail and wholesale) for the first half of 2006 and 2005. Average variable power costs include wheeling and exclude unrealized gains and losses from derivative instruments.

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)
	2006	2005	2006	2005
Generation	2,452	3,916	5.4	11.3
Term Purchases	7,746	6,039	35.5	32.1
Spot Purchases	1,074	320	26.9	34.6
Total System Load	11,272	10,275	31.0	26.8

PGE's average variable power cost increased about 16% from last year's first half due primarily to the higher cost of term purchases required to replace the output of Boardman. Improved margins on settled natural gas hedging transactions, related to increased prices and the Company's portfolio position, reduced the average cost of generation.

Production, distribution, administrative and other expenses increased $1 million (1%) from the first half of 2005. Increased maintenance and repair expenses at PGE's thermal generating plants and increased distribution expenses (including service restoration costs related to wind and rain storms during the first quarter of 2006) were largely offset by a reduction in administrative expenses in the first half of 2006 related to the settlement of certain asserted claims in the first half of 2005.

Depreciation and Amortization expense decreased $8 million (7%) primarily due to a $14 million decrease in amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues). Depreciation of utility plant increased approximately $3 million.

Income taxes decreased $29 million due to lower taxable income in the first half of 2006.

Capital Resources and Liquidity

Review of Statements of Cash Flows

Cash Provided by Operations is used to meet the day-to-day cash requirements of PGE. Supplemental cash is obtained from external borrowings, as needed.

A significant portion of cash from operations consists of charges that are recovered in customer revenues for depreciation and amortization of utility plant that require no current period cash outlay. The recovery from customers of prior capital expenditures through depreciation and amortization provides a source of funding for current and future cash requirements. Cash flows from operations can also be affected by changes in the price of power and fuel as well as by weather conditions, as temperatures outside the normal range can affect electricity usage and resultant cash flow.

Cash provided by operating activities totaled $46 million in the first half of 2006 compared to $200 million in the same period last year. The decrease was due primarily to an increase of $77 million in payments for power and fuel purchases and a $76 million decrease in cash collateral deposits held from certain wholesale customers.

Cash balances are temporarily invested primarily in government money market funds and short-term commercial paper that have remaining maturities of less than three months from the date of acquisition. Such investments, which are considered cash equivalents, are consistent with PGE's investment objectives to preserve principal, maintain liquidity, and diversify risk, and are limited to investment grade securities (primarily short term). During the second quarter, the Company repaid its outstanding short-term borrowings with a portion of the proceeds from the issuance of First Mortgage Bonds (described below).

Investing Activities consist primarily of improvements and additions to PGE's distribution, transmission, and generation facilities. The $83 million increase in capital expenditures in the first half of 2006 is primarily due to construction costs of Port Westward. Other expenditures were related to the expansion of PGE's distribution system to support both new and existing customers within the Company's service territory.

Financing Activities provide supplemental cash for both day-to-day operations and capital requirements as needed. PGE relies on cash from operations, the issuance of commercial paper, borrowings under its revolving credit facilities, and long-term financing activities to support such requirements.

In May 2006, PGE issued $275 million of First Mortgage Bonds, consisting of two series. One series, in the principal amount of $175 million, bears interest at an annual rate of 6.31% and will mature in 2036. The other series, in the principal amount of $100 million, bears interest at an annual rate of 6.26% and will mature in 2031. PGE used the proceeds from the bond issuance for the early retirement of the $150 million principal amount of 8 1/8% Series First Mortgage Bonds due in 2010, and for general corporate purposes. PGE also repaid $5 million of conservation bonds and retired $3 million of preferred stock.

The issuance of additional First Mortgage Bonds and preferred stock requires PGE to meet earnings coverage and security provisions set forth in the Company's Amended and Restated Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on June 30, 2006 it could issue up to approximately $262 million of additional First Mortgage Bonds under the most restrictive issuance test in the mortgage. In addition, it is estimated that the Company could issue up to approximately $38 million in preferred stock under the restrictions set forth in the Amended and Restated Articles of Incorporation. Any issuances would also be subject to market conditions and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits, and/or deposits of cash. Based on the availa bility of the short-term credit facility and the expected ability to issue long-term debt and equity securities, management believes there is sufficient liquidity to meet the Company's anticipated capital and operating requirements.

PGE has a $400 million revolving credit facility with a group of commercial banks. The facility, which is unsecured, is available for general corporate purposes, with the maximum amount available to PGE for borrowings and/or the issuance of standby letters of credit. At June 30, 2006, PGE had utilized approximately $5 million in letters of credit, with $1 million related to wholesale trading activities and $4 million related to Port Westward. In July 2006, the facility was amended to extend the termination date to July 14, 2011.

The credit facility allows PGE to borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the facility. A provision of the facility allows PGE to annually request that the termination date be extended for one additional year. Any request requires approval of a majority of the participating banks, with the termination date extended only for those banks approving the request. The facility provides that all outstanding loans mature on the termination date of the facility. The facility requires annual fees based on PGE's unsecured credit rating, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. At June 30, 2006, the Company's consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 44.9%.

PGE has authorization from the FERC to issue short-term debt, including commercial paper, in an amount not to exceed $400 million outstanding at any one time, over the two-year period February 8, 2006 through February 7, 2008.

Cash Requirements

PGE's access to short-term debt markets provides necessary liquidity to support the Company's current operating activities, including the purchase of electricity and fuel. Long-term capital requirements are driven largely by debt refinancing activities and capital expenditures for distribution, transmission, and generation facilities supporting both new and existing customers.

PGE's liquidity and capital requirements are significantly affected by operating, capital expenditure, debt service, and working capital needs, including margin deposit requirements related to the Company's wholesale trading activities. PGE's revolving credit facility provides a primary source of liquidity, supplementing operating cash flow and supporting the Company's commercial paper program. PGE's ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements (including the effects of these factors on the Company's credit ratings), and alternatives available to investors. The Company's ability to obtain and renew such financing depends on its credit ratings as well as on bank credit markets, both generally and for electric utilities in particular.

PGE's financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company's financial obligations. PGE's objective is to maintain a common equity ratio (common equity to the total of consolidated capitalization, long-term debt due within one year, and short-term borrowings) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE's common equity ratios were 54.3% and 57.5% at June 30, 2006 and December 31, 2005, respectively.

As previously indicated, a significant portion of cash provided by operations consists of depreciation and amortization of utility plant which is recovered in rates. PGE estimates recovery of such charges will approximate $175 million to $215 million annually over the period 2006-2008. Combined with all other sources, total cash provided by operations is estimated to range from $155 million to $295 million annually during the 2006-2008 period.

The following table indicates PGE's projected primary cash requirements for the years indicated (in millions):

	2006	2007	2008
Capital expenditures (*)	$340 - $360	$210 - $230	$290 - $310
Long-term debt maturities	$11	$67	-

(*) Includes expenditures related to the construction of Port Westward (approximately $159 for 2006 and $13 for 2007) and for fish passage measures at the Pelton Round Butte hydroelectric project (approximately $50 for 2008). Excludes expenditures related to the Biglow Canyon Wind Farm and other projects subject to further approval. Phase I of the proposed Biglow Canyon Wind Farm (126 MW capacity) could add approximately $218 of capital expenditures over the 2006-2008 period.

The OPUC order approving the issuance of new PGE common stock includes a stipulation containing several conditions, including a requirement that, after issuance of the new common stock, PGE cannot pay a common stock dividend that would cause the common equity capital percentage to fall below 48% (plus $40 million) without OPUC approval. The requirement is reduced to 45% when the Disputed Claims Reserve (DCR) holds between 20% and 40% of the issued and outstanding common stock of PGE, with no minimum common equity capital percentage requirement when the DCR holds less than 20% of the issued and outstanding common stock of PGE. At June 30, 2006, the DCR held 55% of the total issued and outstanding common stock of PGE. PGE has agreed to maintain the additional $40 million of common equity until an OPUC order is issued in the Company's pending general rate case to assure PGE's financial capacity to absorb any adjustment(s) in its revenue requirement related to its former ownership by Enron.

A cash dividend of $14 million was declared on May 12, 2006 and paid to common shareholders on July 17, 2006. The Company expects to pay regular quarterly dividends on its common stock. However, the declaration of such dividends is at the discretion of the Company's Board of Directors and is not guaranteed. The amount of common dividends will depend upon PGE's results of operations and financial condition, future capital expenditures and investments, any applicable regulatory and contractual restrictions, and other factors that the Board of Directors considers relevant.

Credit Ratings

PGE's secured and unsecured debt are rated at investment grade by Moody's Investors Service (Moody's), Standard and Poor's (S&P), and Fitch Ratings (Fitch).

PGE 's current credit ratings are as follows:

	Moody's	S&P	Fitch
First Mortgage Bonds	Baa1	BBB+	A-
Senior unsecured debt	Baa2	BBB	BBB+
Preferred stock	Ba1	BBB-	-
Commercial paper	Prime-2	A-2	F-2
Outlook:	Stable	Negative	Stable

Should Moody's or S&P (or both) reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On June 30, 2006, PGE had posted approximately $6 million of collateral, consisting of $1 million in letters of credit and $5 million in cash. Based on the Company's non-trading portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of June 30, 2006, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $52 million and decreases to approximately $17 million by year-end 2006. The approximate amount of additional collateral that could be requested upon a dual agency downgrade event to below investment grade is approximately $64 million and decreases to approximately $19 million by year-end 2006.

In addition to collateral calls, a credit rating reduction could impact the terms and conditions of long-term debt issued in the future. Any rating reductions could also increase interest rates and fees on PGE's revolving credit facility, increasing the cost of funding the Company's day-to-day working capital requirements. PGE's financing arrangements do not contain ratings triggers that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. Management believes that PGE's existing line of credit, access to the commercial paper market, and cash from operations provide the Company with sufficient liquidity to meet its day-to-day cash requirements.

Contractual Obligations and Commercial Commitments

PGE's contractual obligations have not changed materially from those amounts disclosed in the Company's 2005 Annual Report on Form 10-K.

Critical Accounting Policies and Estimates

New Oregon Tax Law

In 2005, the State of Oregon adopted Senate Bill 408 (SB 408), a new law that seeks to adjust the way that PGE and most other Oregon investor-owned electric and gas utilities collect income taxes from ratepayers. The law authorizes an adjustment to retail customer rates based on the difference between "taxes authorized to be collected" and "taxes paid" to governmental entities on or after January 1, 2006. In its assessment of the OPUC's July 14, 2006 interim order, PGE has revised its estimates of the range of potential refunds to customers for 2006 to be from $18 million to $66 million. Based on the low end of the range, the Company recorded a $9 million (pre-tax) reserve for the first half of 2006 for a potential refund obligation to customers using a percentage of estimated annual revenues collected through this period. PGE will continue to evaluate the interim order and participate in the OPUC's rulemaking proceedings. As the ultimate outcome of such proceedings, including final ru les adopted by the OPUC, is uncertain, the above estimates are subject to change. For further information, see "New Oregon Law - Utility Rate Treatment of Income Taxes" in "Financial and Operating Outlook" of this Item 2.

PGE's critical accounting policies that require the use of estimates and assumptions are discussed further in the Company's Annual Report on Form 10-K for the year ended December 31, 2005.

Financial and Operating Outlook

Retail Customer Growth and Energy Deliveries

Weather adjusted retail energy deliveries to PGE and ESS customers increased 2.1% for the six months ended June 30, 2006, compared to the same period last year. The increase was due primarily to 1.7% and 3.1% increases, respectively, in residential and commercial deliveries. Increased residential sales resulted primarily from an 11,800 increase in the average number of customers served during the first half of 2006 over the first half of 2005. Higher commercial and industrial sales resulted from a 1,600 increase in the average number of customers served and higher average usage. PGE forecasts total weather adjusted energy deliveries to PGE and ESS customers in 2006 to increase by approximately 2% from last year.

Power and Fuel Supply

Current forecasts indicate that regional hydro conditions will exceed average levels in 2006. Volumetric water supply forecasts for the Pacific Northwest, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, indicate the April-to-September runoff (as measured at The Dalles, Oregon) at 107% of normal, compared to actual runoffs of 74% in 2005 and 81% in 2004. Hydro conditions in the Clackamas and Deschutes river systems, where PGE's hydro facilities are located, are currently projected to be 92% and 100% of normal, respectively, compared to actual runoffs of approximately 72% and 87% of normal, respectively, in 2005.

PGE generated 22% of its retail load requirement in the first half of 2006, with 12% met with hydro generation and the remaining 10% with thermal generation; short- and long-term purchases were utilized to meet the remaining load. PGE's ability to purchase power in the wholesale market, along with the Company's base of thermal and hydroelectric generating capacity, currently provides the flexibility to respond to seasonal fluctuations in the demand for electricity both within its service territory and from its wholesale customers.

Factors that can affect the availability and price of purchased power and fuel include weather conditions in the Northwest and Southwest, the performance of major generating facilities in both regions, regional hydro conditions, and prices of natural gas and coal used to fuel thermal generating plants. Market prices of natural gas can also be affected by destructive storms and extreme weather in other sections of the United States. Power and natural gas prices have moderated since late 2005, due primarily to increased hydro availability within the region. The general upward trend of energy prices experienced in recent years, however, is expected to continue.

Price Risk Management - As PGE's primary business is to serve its retail customers, it uses derivative instruments to manage its exposure to commodity price risk and to minimize net power costs to serve customers. Under SFAS No. 133, as amended, PGE records unrealized gains and losses in earnings in the current period for derivative instruments that do not qualify for either the normal purchases and normal sales exception or cash flow hedge accounting. The timing difference between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in rates is recorded as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71. Derivative instruments that qualify for the normal purchases and normal sales exception are recorded in earnings on a settlement basis, and cash flow hedges are recorded in OCI until they can offset the related results on the hedged item in the income statement.

From the time prices are set in the RVM process until the end of the RVM period, any changes to electricity and natural gas prices used in the RVM will result in unrealized gains and losses to be recorded in earnings in the current period on existing and new derivative instruments that do not qualify for the normal purchases and normal sales exception or cash flow hedges. Price movements in electricity and natural gas markets cause PGE to make power and natural gas purchases and sales decisions around the economic dispatch of its own generation. Derivative instruments that qualify for the normal purchases and normal sales exception or cash flow hedges, and forecasted transactions related to these decisions are not recorded in earnings in the current period, but are recognized in earnings when the contracts are settled in future periods. As a result, this timing difference may create earnings volatility between reporting periods.

Ownership of PGE

The registered owner of the new PGE common stock held in the DCR is the Disbursing Agent associated with the DCR. The Disbursing Agent will oversee the release of new PGE common stock from the DCR to the Debtors' creditors that hold allowed claims. All shares of new PGE common stock held in the DCR will be voted by the Disbursing Agent at the direction of the Disputed Claims Reserve Overseers (DCRO). Approval of any offer to purchase the new PGE common stock from the DCR will be the responsibility of the DCRO, in accordance with guidelines approved by the Bankruptcy Court. The DCRO is currently comprised of those individuals who serve on Enron's Board of Directors.

The distribution of new PGE common stock was approved by all required regulatory agencies, including the OPUC. The OPUC order approving the distribution of the new PGE common stock (OPUC Order) includes 17 conditions that relate to, among other things: certain service quality measures; additional direct access options for commercial and industrial customers; maintenance of PGE's financial strength during the conclusion of the Enron bankruptcy process; and certain indemnifications for PGE from Enron related to Enron-sponsored employee benefit plans and certain liabilities related to taxes that may be imposed as the result of PGE's inclusion in Enron's consolidated tax group. These indemnifications are included in the separation agreement described below.

On February 10, 2006, the City of Portland appealed the OPUC Order in both the Marion County Circuit Court and the Oregon Court of Appeals. The City filed in both courts due to the jurisdictional uncertainty created by new Oregon law governing appeals of OPUC decisions. On July 19, 2006, the Court of Appeals granted the OPUC's motion to dismiss the action before that Court. In its appeal to the Circuit Court, the City alleges that the OPUC made its decision on an inadequate record, failed to enter adequate findings in support of its decision, abused the discretion granted it by Oregon law, and based its decision on a statute that constituted an unlawful delegation from the Oregon Legislature. The City requests the OPUC Order be modified, reversed or remanded. The matter is proceeding in the Marion County Circuit Court. Management cannot predict the ultimate outcome of this matter,however, it believes it will not have a material adverse impact on the Company's financial statements.

On February 13, 2006, the Utility Reform Project filed with the OPUC an application for reconsideration of the OPUC Order. On February 28, 2006, PGE, the Citizens Utility Board, and the OPUC staff filed oppositions to URP's application for reconsideration. Also on February 28, 2006, the City filed in support of URP's application and added new grounds for reconsideration of the OPUC Order. PGE filed in opposition to the City's new grounds for reconsideration on March 13, 2006. On April 10, 2006, the OPUC issued an order that denied the URP's and the City's requests for reconsideration of the OPUC Order.

Separation Agreement -On April 3, 2006, PGE and Enron entered into a separation agreement, as required by the OPUC order that approved the distribution of new PGE common stock. The separation agreement provides generally for the settlement of intercompany amounts, the termination of intercompany agreements between PGE and Enron (except for certain provisions of a previously executed separate tax allocation agreement), and certain indemnifications for PGE from Enron related to Enron-sponsored employee benefit plans and certain liabilities related to taxes that may be imposed as the result of PGE's inclusion in Enron's consolidated tax group.

Release from Enron Pension Plan Liability -On May 8, 2006, the Pension Benefit Guaranty Corporation (PBGC) and PGE entered into a release with respect to the Enron Corp. Cash Balance Plan and the pension plans of other Enron debtor subsidiaries (Pension Plans). The PBGC irrevocably and unconditionally forever released, acquitted and discharged PGE and its subsidiaries and affiliates and each of their past and present officers, agents, directors, employees and representatives from all liability under Title IV of the Employee Retirement Income Security Act of 1974 with respect to the Pension Plans.

Oregon Tax Credits - PGE generated approximately $15 million of Oregon tax credits that, due to taxable income limitations, were not utilized by Enron prior to the separation of the two companies on April 3, 2006. In prior years, PGE was able to utilize these tax credits to reduce its tax payment obligation to Enron pursuant to a tax sharing agreement. To the extent that Enron is unable to utilize these credits on its tax returns, PGE expects that it will be able to utilize such tax credits on its Oregon income tax returns in periods subsequent to its separation from Enron. Any amounts not utilized by PGE on its Oregon income tax return for the period April 3, 2006 through December 31, 2006 are expected to be available for carryover and utilization in future years. PGE had a quarterly income tax payment due to the state of Oregon on July 15, 2006. A portion of the tax credits was utilized to offset this liability and reduce the amount of the tax credits carried forward. Du e to uncertainties related to Enron's ability to utilize the credits and the application of SB 408 (see "New Oregon Law - Utility Rate Treatment of Income Taxes" below), the Company is currently unable to determine the ultimate accounting treatment that would be usedfor any of the tax credits utilized by PGE on its income tax returns filed subsequent to the separation from Enron which were previously used by PGE to reduce tax payments to Enron.

Boardman Coal Plant - Repair Outages

On October 22, 2005, following the detection of vibrations in Boardman's steam turbine rotor, the plant was taken out of service and the rotor was removed for repair. On February 6, 2006, during the process of returning the plant to operation, the generator rotor was damaged and subsequently removed for repair. The generator rotor was repaired and the plant was operational in late May. In early June, the plant was again taken out of service for repairs to its low pressure turbine unit; upon completion of these repairs, the plant returned to full operation in early July 2006. Due to the extended outage, annual maintenance requirements, originally scheduled for the second quarter of 2006, were completed in the first quarter while the plant was out of service.

The extended outages of Boardman required that PGE replace its portion of the plant's generation with both higher cost purchases in the wholesale market and increased generation from the Company's natural gas-fired generating plants. Incremental power costs during the plant's outages totaled approximately $92 million, including $44 million in the first quarter and $8 million in the second quarter of 2006. Reduced replacement power costs in the second quarter of 2006 reflect the impact of favorable regional hydro conditions on wholesale power prices.

On November 18, 2005, PGE filed with the OPUC an "Application for Deferred Accounting of Excess Power Costs Due to Plant Outage." The application requested an order authorizing PGE to defer for later ratemaking treatment excess power costs associated with Boardman's turbine rotor, effective on the date of the application. The application seeks deferral of the difference between Boardman's variable power costs used in setting rates for 2005 and 2006 (under the Company's RVM) and replacement power costs incurred during the turbine rotor outage. The deferral period for the outage ended on February 5, 2006 with the installation of the repaired turbine rotor. The deferral amount is currently estimated at approximately $46 million. The OPUC staff's initial response would provide for recovery of approximately $450,000 of such costs. The proceeding on the application is continuing. No deferral has yet been recorded by the Company. Management cannot predict the timing or the ultimate outcome of a d ecision by the OPUC on the Company's application. Under the RVM process, a 4-year rolling average of historical forced outages of PGE's generating plants is used in setting expected power costs. To the extent the Company is not allowed to recover replacement power costs for Boardman under the deferred accounting application, impacts of the turbine rotor forced outage (October 23, 2005 through February 5, 2006) may be included in the 4-year rolling average component of rates requested under the RVM process beginning in 2007.

PGE did not file an application to defer incremental power costs related to the generator rotor outage (February 6, 2006 through late May 2006), and will not propose the inclusion of this outage in the 4-year rolling average of forced outages in its annual power cost update filings starting in 2008.

New Oregon Law - Utility Rate Treatment of Income Taxes

A new law, commonly referred to as Oregon Senate Bill 408 (SB 408), seeks to adjust the way that PGE and most other Oregon investor-owned electric and gas utilities collect income taxes from ratepayers. SB 408 attempts to more closely match tax amounts collected in revenues with the amount of income taxes paid to governmental entities by investor-owned utilities or their consolidated group. The new law requires that utilities file reports with the OPUC by October 15 of each year regarding the amount of taxes paid by the utility or its consolidated group (with certain adjustments), as well as the amount of taxes authorized to be collected in rates, as defined by the statute. If the OPUC determines that the difference between the two amounts is greater than $100,000, the utility is required to establish an "automatic adjustment clause" to adjust rates. The first adjustment under the automatic adjustment clause applies only to taxes paid to units of government and collected from rate payers on or after January 1, 2006.

PGE, along with other utilities and consumer groups, has been participating in the OPUC's SB 408 rulemaking process. PGE proposed that the rules include an earnings test that would be incorporated into the automatic adjustment clause. Under the earnings test, the utility would not surcharge or refund to customers if the utility's earnings were above or below a specified level.

On July 14, 2006, the OPUC issued an interim order (Interim Order) that sets forth preliminary decisions regarding the implementation of SB 408. In the Interim Order, the OPUC declined to adopt the earnings test proposed by PGE. In addition, the OPUC proposed a methodology to determine refunds that establishes a formula to determine the ratio of a utility's business to its parent company's business. This ratio is then multiplied by the amount of total taxes paid by the parent company to determine the amount that should be properly attributed to the utility.

Effective with the April 3, 2006 issuance of new PGE common stock, PGE is no longer a subsidiary of Enron and will file its own consolidated tax returns and remit payments directly to taxing authorities. However, in April 2006, PGE paid $17 million to Enron for net current taxes payable for the first quarter of 2006 when PGE was included in Enron's consolidated group for filing consolidated federal and state income tax returns. Under the proposals in the Interim Order, PGE could be required to refund to customers a portion of that amount, as well as a portion of the future amount it collects for taxes in its current rates.

On December 30, 2005, PGE filed with the OPUC an application for deferred accounting to prevent either the financial enrichment or financial harm to the Company should the rules implementing SB 408 include the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. The deferred amount would reflect the tax effect of the difference between PGE's implied operating costs under a fixed margin assumption and the Company's actual operating costs. The Interim Order does propose the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. In the Interim Order, the OPUC indicated that it would review deferral applications related to SB 408 on a case by case basis, but would view such applications with skepticism.

In its assessment of the Interim Order, PGE has revised its estimates of the range of potential refunds to customers for 2006 to be from $18 million to $66 million. Based on the low end of the range, the Company recorded a $9 million (pre-tax) reserve for the first half of 2006 for a potential refund obligation to customers using a percentage of estimated annual revenues collected through this period.

The OPUC will accept public comments on its preliminary decision until August 21, 2006 and is expected to adopt permanent rules in September 2006 or later. PGE will continue to evaluate the OPUC's proposals and participate in the rulemaking proceeding, including considering whether to continue to pursue adoption of an earnings test and elimination of the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. Any final rules adopted and rate adjustments ordered by the OPUC are subject to court appeal by any party.

The Company is unable to predict the ultimate outcome of the implementation of SB 408 due to uncertainties as to the final OPUC rules, consideration of the deferral application, the ability to secure rate relief apart from the results implied by SB 408, and the possibility of litigation.

Complaint and Application for Deferral - Income Taxes

On October 5, 2005, the URP and Ken Lewis (Complainants) filed a Complaint with the OPUC alleging that, since September 2, 2005 (the effective date of SB 408), PGE's rates are not just and reasonable and are in violation of Senate Bill 408 because they contain approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any government. The Complaint requests that the OPUC order the creation of a deferred account for all amounts charged to ratepayers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes.

Also on October 5, 2005, the Complainants filed an Application for Deferred Accounting with the OPUC, claiming that PGE is charging ratepayers $92.6 million annually for federal and state income taxes that are not being paid, and that such charges are not fair, just and reasonable. The Application for Deferred Accounting requests that the portion of PGE's revenues representing estimated PGE liabilities for federal and state income taxes, less any amounts of federal and state income taxes paid by PGE or on behalf of PGE, be deferred for later incorporation in rates.

On December 27, 2005, the OPUC issued a Joint Ruling to hold the Complaint and the Application for Deferred Accounting in abeyance pending rehearing of an order previously issued by the OPUC in a rate proceeding involving another Oregon electric utility. On July 10, 2006, the OPUC issued the order in the matter related to the other utility and has commenced the proceeding on the Complaint. Management cannot predict the ultimate outcome of these matters or estimate any potential loss.

Class Action Lawsuit - Multnomah County Business Income Taxes

In January 2005, David Kafoury and Kafoury Brothers, LLC filed a class action lawsuit in Multnomah County Circuit Court against PGE on behalf of all PGE customers who were billed on their electric bills and paid amounts for Multnomah County Business Income Taxes (MCBIT) after 1996 that the plaintiffs alleged were never paid to Multnomah County. The charges were billed and collected under OPUC rules that allow utilities to collect taxes imposed by the county. As PGE was included in Enron's consolidated income tax return, the Company paid the tax it collected to Enron. The plaintiffs sought judgment against PGE for restitution of MCBIT in excess of $6 million, plus interest, recoverable costs, and reasonable attorney fees. The plaintiffs filed an amended complaint in February 2005, adding claims for fraud, unjust enrichment, conversion, statutory violations, and seeking punitive damages.

On December 28, 2005, the parties agreed to a settlement by which PGE will make refunds and payments totaling $10 million, inclusive of interest and plaintiffs' attorney fees, costs, and expenses as approved by the Court's final order. The settlement includes no admission of liability or wrongdoing by PGE. Distribution to customers is limited to amounts collected during the period 1999 through 2005. PGE established a reserve of $10 million in 2005 related to the settlement. On July 28, 2006, the settlement was approved by the Multnomah County Circuit Court. Refunds to customers are expected to begin in September 2006.

City of Portland Actions

In September 2005, the Portland City Council directed the City Attorney and City staff to obtain from PGE information regarding the collection and payment of utility income taxes. PGE voluntarily provided extensive financial and operational data to the City. The City broadened its inquiry to include PGE's power trading activities in 2000 and 2001, and on March 23, 2006, the City issued a subpoena to PGE seeking numerous records and documents. PGE has determined that there are a number of legal and practical issues concerning the City's request for additional information, and has declined to provide any additional data to the City while those issues remain unresolved. On April 21, 2006, PGE filed a complaint in Multnomah County Circuit Court seeking clarity on whether the City has investigatory and ratemaking authority.

On May 5, 2006, the City of Portland filed a complaint against PGE with the OPUC. The complaint alleges that Enron and PGE should not have filed income taxes on a unitary basis under Oregon law. The complaint also alleges that PGE made certain cash payments to Enron under a tax allocation agreement which at the time had not been approved by the SEC, and that PGE did not submit the agreement to the OPUC for a determination as to whether the agreement was fair and reasonable and in the public interest as provided under Oregon law. The City requests rulings from the OPUC confirming the violations alleged in the complaint; an investigation of those matters; an order directing PGE to make no further stock dividend distributions until the legality and reasonableness of PGE's tax filings is determined; and an assessment of penalties of $10,000 for each violation of any statute administered by the OPUC and for each instance of failure by PGE to perform duties required of a utility under Oregon law. On July 31, 2006, the OPUC issued an order dismissing the first two claims. PGE disagrees with the City's allegations in the complaint and will vigorously defend against it at the OPUC.

General Rate Case

PGE filed a general rate case and proposed tariffs with the OPUC in March 2006 that would increase rates by $143 million (8.9 percent) in 2007 and allow a return on equity of 10.75 percent. About half of the proposed increase is related to power and fuel costs, as included in the Company's RVM process (described below). The remaining increase is related to recovery of the Company's investment in Port Westward and to increased general (non-power) costs. The Company is also proposing a tariff under which it would share with customers a portion of the difference between each year's forecast and actual net variable power costs. The filing is the Company's first general rate increase request since 2001.

The initial proposal of the OPUC Staff, issued in early July 2006, includes a $30 million (1.9 percent) increase in PGE's rates and an allowed return on equity of 9.8 percent. The OPUC staff's initial proposal marks an early stage in the ratemaking process. The Company is reviewing the Staff's proposal and is in settlement discussions with all participants. The OPUC is expected to issue its final order in January 2007, following settlement conferences, additional testimony, and public hearings.

Resource Valuation Mechanism

PGE's RVM tariff mechanism requires annual updates of the Company's net variable power costs for inclusion in base rates for the following year. Developed in compliance with guidelines for Oregon's energy restructuring law that allow businesses direct access to energy service suppliers, the RVM utilizes a combination of market prices and the value of the Company's resources to establish power costs and set prices for energy services. It provides for an adjustment, finalized in mid-November each year, which is effective on January 1 of the following year.

Power Cost Price Increase - 2006 Based upon projections in PGE's 2006 RVM filing, the OPUC authorized an approximate 3.7% average retail price increase for 2006, due largely to substantial increases in the cost of wholesale power and continued high prices for natural gas. Increases (including the effect of all credits and adjustments) range from 1.7% for residential customers to 5.3% and 5.4%, respectively, for small and large non-residential customers. Such adjustments are expected to increase PGE's 2006 revenues by approximately $47 million.

Preliminary Power Cost Filing - 2007 On March 28, 2006, PGE submitted an RVM filing with the OPUC containing an estimate of 2007 power costs based upon preliminary information that will be updated later in 2006. Preliminary estimatesindicate an approximate 4% to 5% average retail price increase (including the effect of all credits and adjustments), due primarily to higher natural gas prices and retail load requirements, as well as increases in the cost of wholesale power purchases.This filing has been consolidated with the Company's general rate case filing.

Hydro Relicensing

On March 30, 2006, PGE filed with the FERC a settlement agreement related to the license application for the Company's four hydro projects on the Clackamas River. On June 16, 2006, the FERC issued a Draft Environmental Impact Statement that recommends PGE's proposed action with minor modifications. It is not certain when the FERC will issue a new license for the projects. Until a new license is approved, the plants will operate under annual licenses issued by the FERC.

Trojan Investment Recovery

In 1993, following the closure of the Trojan Nuclear Plant as part of its least cost planning process, PGE sought full recovery of, and a rate of return on, its Trojan plant costs, including decommissioning, in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order (1995 Order) which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

Numerous challenges, appeals, and requested reviews were subsequently filed in the Marion County Circuit Court, the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC's authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The Oregon Court of Appeals issued an opinion in 1998, stating that the OPUC does not have the authority to allow PGE to recover a return on the Trojan investment, but upholding the OPUC's authorization of PGE's recovery of the Trojan investment and ordering remand of the case to the OPUC. PGE, the OPUC, and the Utility Reform Project each requested the Oregon Supreme Court to conduct a review of the Court of Appeals decision. On November 19, 2002, the Oregon Supreme Court dismissed the petitions for review. As a result, the 1998 Oregon Court of Appeals opinion stands and the case has been remanded to the OPUC.

In 2000, while the petitions for review of the 1998 Court of Appeals decision were pending at the Oregon Supreme Court, PGE, the Citizens Utility Board, and the staff of the OPUC entered into settlement agreements with respect to litigation over recovery of, and return on, its investment in the Trojan plant. The settlement agreements, approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC's September 2000 order. In March 2002, the OPUC issued an order (2002 Order) denying all of URP's challenges and approving the accounting and ratemaking elements of the 2000 settlement. URP appealed the 2002 Order to the Marion County Circuit Court and on November 7, 2003, the Court issued an o pinion remanding the case to the OPUC for action to reduce rates or order refunds. The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have appealed to the Oregon Court of Appeals.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the rates PGE charges its customers. On December 14, 2004, the Judge granted the Class Action Plaintiffs' motion for Class Certification and Partial Summary Judgment and denied PGE's motion for Summary Judgment. On March 3, 2005 and March 29, 200 5, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial Judge to dismiss the complaints or to show cause why they should not be dismissed and seeking to overturn the Class Certification. On May 3, 2005, the Oregon Supreme Court granted both Petitions. Briefing and arguments have been completed and a decision is pending.

On March 3, 2004, the OPUC re-opened three dockets in which it had addressed the issue of a return on PGE's investment in Trojan, including the 1995 Order and 2002 Order related to the settlement of 2000. The OPUC will consider the matter in two or more phases. Hearings in the first phase of the proceeding have been held and a decision is pending.

Threatened Litigation - Class Action Lawsuit - On February 14, 2005, PGE received a Notice of Potential Class Action Lawsuit for Damages and Demand to Rectify Damages from counsel representing Frank Gearhart, David Kafoury and Kafoury Brothers, LLC (Potential Plaintiffs), stating that Potential Plaintiffs intend to bring a class action lawsuit against the Company. Potential Plaintiffs allege that for the period from October 1, 2000 to the present, PGE's electricity rates have included unlawful charges for a return on investment in Trojan in an amount in excess of $100 million. Under Oregon law, there is no requirement as to the time the lawsuit must be filed following the 30-day notice period. No action has been filed to date.

Management cannot predict the ultimate outcome of the above matters. However, it believes that the resolution will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows for a future reporting period. No reserves have been established by PGE for any amounts related to this issue.

Receivables and Refunds on Wholesale Market Transactions

Receivables - California Wholesale Market

As of June 30, 2006, PGE has net accounts receivable balances totaling approximately $63 million from the California ISO and the PX for wholesale electricity sales made from November 2000 through February 2001. The Company estimates that the majority of this amount was for sales by the ISO and PX to Southern California Edison Company and Pacific Gas & Electric Company (PG&E).

In March 2001, the PX filed for bankruptcy and in April 2001, PG&E filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code. PGE filed a proof of claim in each of the proceedings for all past due amounts. Although both entities have emerged from their bankruptcy proceedings as reorganized debtors, not all claims filed in the proceedings, including those filed by PGE, have been resolved. PGE is continuing to pursue collection of these claims.

Management continues to assess PGE's exposure relative to these receivables. Based upon FERC orders regarding the methodology to be used to calculate refunds and the FERC's indication that potential refunds related to California wholesale sales (see "Refunds on Wholesale Transactions" below) can be offset with accounts receivable related to such sales, PGE has established reserves totaling $40 million related to this receivable amount. The Company is examining numerous options, including legal, regulatory, and other means, to pursue collection of any amounts ultimately not received through the bankruptcy process.

Refunds on Wholesale Transactions

California -On July 25, 2001, the FERC issued an order establishing the scope of and methodology for calculating refunds for wholesale sales transactions made between October 2, 2000 and June 20, 2001 in the spot markets (defined by the FERC as 24 hours or less) operated by the ISO and PX. The order established evidentiary hearings to develop a factual record to provide the basis for the refund calculation. Several additional orders clarifying and further defining the methodology have since been issued by the FERC. Appeals of the FERC orders were filed and in August 2002 the U.S. Ninth Circuit Court of Appeals issued an order requiring the FERC to reopen the record to allow the parties to present additional evidence of market manipulation.

Also in August 2002, the FERC Staff issued a report that included a recommendation that natural gas prices used in the methodology to calculate potential refunds be reduced significantly, which could result in a material increase in PGE's potential refund obligation.

In December 2002, a FERC administrative law judge issued a certification of facts to the FERC regarding the refunds, based on the methodology established in the 2001 FERC order rather than the August 2002 FERC Staff recommendation. On March 26, 2003, the FERC issued an order in the California refund case (Docket No. EL00-95) adopting in large part the certification of facts of the FERC administrative law judge but adopting the August 2002 FERC Staff recommendation on the methodology for the pricing of natural gas in calculating the amount of potential refunds. PGE estimates its potential liability under the modified methodology at between $40 million and $50 million, of which $40 million has been established as a reserve, as discussed above.

Numerous parties, including PGE, filed requests for rehearing of various aspects of the March 26, 2003 order, including the methodology for the pricing of natural gas. On October 16, 2003, the FERC issued an order reaffirming, in large part, the modified methodology adopted in its March 26, 2003 order. PGE does not agree with the FERC's methodology for determining potential refunds and, on December 20, 2003, the Company appealed the FERC's October 16, 2003 order to the U.S. Ninth Circuit Court of Appeals; several other parties have also appealed the October 16, 2003 order. On May 12, 2004, the FERC issued an order (Rehearing Order) that denied further requests for rehearing of the October 16, 2003 order. Although there continue to be miscellaneous orders issued in the underlying FERC proceeding, the Ninth Circuit Court of Appeals has now begun to hear the numerous appeals.It has bifurcated appeals of the existing cases into two phas es. The first considered arguments regarding jurisdictional issues and the permissible scope of refund liability, both in terms of the time frame for which refunds were ordered and the types of transactions subject to refund. As to the jurisdictional issues, on September 6, 2005, the Court ruled that the FERC did not have jurisdiction to order municipal utilities and other governmental entities to make refunds for the sales they had made to the ISO and PX that are the subject of the refund proceeding. The Court agreed to defer the rehearing deadline on the jurisdictional issue decision until the remainder of the first phase is decided. The second phase will consider the issues relating to the refund methodology itself. PGE expects that the Court will establish additional phases as the continuing issues remaining before the FERC become final and are appealed.

On August 2, 2006, the Court issued its decision on the remainder of the issues in the first phase (Phase I). The Court upheld the refund effective date of October 2, 2000, but remanded to the FERC the issue of whether it should order refunds for the summer 2000 period pursuant to its authority under Section 309 of the Federal Power Act (FPA) to remedy tariff violations. The Court also affirmed the FERC's orders on the scope of the refund proceeding, except with regard to the FERC's exclusion of ISO and PX contracts in excess of 24 hours and energy exchanges. The Court held that transactions in the ISO and PX markets with a duration in excess of 24 hours, as well as energy exchanges, should be included within the scope of the refund case. In a separate action, the Court ordered a 45-day extension in the time to file for rehearing of its Phase I decisions (resulting in a 90-day period for rehearings to be filed), urging the parties to use the time to assess possibilities of settlement. Mana gement is continuing to analyze the impact of this decision on PGE, including the impact, if any, on the amount of any refund liability.

In addition to the Rehearing Order on May 12, 2004, the FERC also issued a separate order that provided clarification regarding certain aspects of the methodology for California generators to recover fuel costs incurred to generate power that were in excess of the gas cost component used to establish the refund liability (Fuel Cost Order). On September 24, 2004, the FERC issued an order that denied requests for rehearing of the Fuel Cost Order and also adopted a new methodology to allocate the excess amounts of fuel costs that California generators are permitted to recover. Additional clarifying orders continue to be issued periodically. Under the new allocation methodology, PGE could be required to pay additional amounts in those hours when it was a net buyer in California spot markets, thus increasing its net refund liability. PGE does not expect a material increase in the Company's potential refund exposure. Partly as a means of limiting its exposure to additional fuel costs, PGE has opted to become a participant in several settlements filed jointly by large generators and California parties, and approved by the FERC during 2004 and 2005.

In August 2005, PGE joined in a settlement agreement resolving issues relating to the allocation of the wind-up costs of the PX for both past and future periods. The settlement has been approved by the FERC. Although under the agreement PGE will bear certain additional costs associated with PX obligations to conduct and finalize refund calculations, PGE does not expect those costs to be material to its financial statements.

In several of its underlying refund orders, the FERC has indicated that if marketers, such as PGE, believe that the level of their refund liability has caused them to incur an overall revenue shortfall for their sales to the ISO and PX during the refund period, they will be permitted to file a cost study to prove that they should be permitted to recover additional revenues in excess of the mitigated prices in order to cover their costs. By order issued August 8, 2005, the FERC provided guidelines regarding the manner in which these studies should be conducted and the principles that should govern their preparation. PGE filed for rehearing of certain aspects of the August 8, 2005 order, and, on September 14, 2005, it filed its cost recovery study with the FERC. The study showed that, pursuant to the principles set forth in the August 8, 2005 order and subject to rehearing, PGE's costs to serve the ISO and PX markets exceeded the revenues PGE will receive from those mitigated sales by over $27 million. By order issued January 26, 2006, the FERC conditionally accepted PGE's September 14, 2005 cost filing, subject to PGE making a compliance filing to eliminate certain costs, to include additional revenues, and to supplement its analysis with additional cost, load, and resource data. On February 10, 2006, PGE submitted a compliance filing with two alternative cases incorporating the FERC-required changes. The compliance filing shows a revenue deficit for PGE's sales to the ISO and PX (that is, a reduction to PGE's refund liability) of from approximately $20 million to approximately $30 million, depending on the methodology ultimately accepted by the FERC. Third parties have challenged PGE's compliance filing and requested that it be rejected in its entirety or that the cost offset be reduced to zero, and PGE has filed responses to those challenges. Pursuant to the procedure established by the FERC in the January 26, 2006 order that required each seller whose cost fili ng has been accepted to incorporate in its filing final ISO and PX settlement data, PGE has provided its revised filing to the ISO and PX for further processing.

PGE believes that the FERC erred in certain of its findings in the January 26, 2006 order, and has filed a request for rehearing as to several issues. Due to the continuing uncertainty related to these matters, PGE has made no adjustment to the $40 million reserve previously established for the Company's potential liability, as described above.

The FERC has indicated that any refunds PGE may be required to pay related to California wholesale sales (plus interest from collection date) can be offset by accounts receivable (plus interest from due date) related to sales in California (see "Receivables - California Wholesale Market" above). In addition, any refunds paid or received by PGE applicable to spot market electricity transactions on and after January 1, 2001 in California may be eligible for inclusion in the calculation of net variable power costs under the Company's power cost adjustment mechanism in effect at that time. This could further mitigate the financial effect of any refunds made or received by the Company.

Challenge of the California Attorney General to Market-Based Rates - On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, alleging that the FERC's authorization of market-based rates violated the FPA, and, even if market-based rates were valid under the FPA, that the quarterly transaction reports required to be filed by sellers, including PGE, did not contain the transaction-specific information mandated by the FPA and the FERC. The complaint argued that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including PGE, to re-file their quarterly reports to include transaction-specific data. The California Attorney General appealed the FERC's decision to the Ninth Circuit Court of Appeals. On September 8, 2004, the Court issued an o pinion upholding the FERC's authority to approve market-based tariffs, but also holding that the FERC had the authority to order refunds, if quarterly filing of market-based sales transactions had not been properly made. The Court required the FERC, upon remand, to reconsider whether refunds should be ordered. On October 25, 2004, certain parties filed a petition for rehearing with the Court. In the refund case and in related dockets, the California Attorney General and other California parties have argued that refunds should be ordered retroactively to at least May 1, 2000. Management cannot predict the outcome of these proceedings or whether the FERC will order refunds retroactively to May 1, 2000, and if so, how such refunds would be calculated.

Anomalous Bidding Allegations - By order issued on June 25, 2003, the FERC instituted an investigation into allegations of anomalous bidding activities and practices ("economic withholding") on the part of numerous parties, including PGE. The FERC determined that bids above $250 per MW in the period from May 1, 2000 through October 2, 2000 may have violated tariff provisions of the ISO and the PX. The FERC required companies that bid in excess of $250 per MW to provide information on their bids to the FERC investigation staff. PGE responded to the FERC's inquiries and, on May 12, 2004, the FERC investigation staff issued to PGE a letter terminating the investigation as to the Company without further action. On March 10, 2005, certain California parties filed appeals with the Ninth Circuit Court of Appeals, contesting the FERC's conduct of the investigation of the anomalous bidding allegations and the issuance of the dismissal letters.

Pacific Northwest - In the July 25, 2001 order, the FERC also called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceedings and denying the claims for refunds. In July 2003, numerous parties filed requests for rehearing of the June 2003 FERC order. In November 2003 and February 2004, the FERC issued orders that denied all pending requests for rehearing. Parties have appealed various aspects of these FERC orders.

Management cannot predict the ultimate outcome of the above matters related to wholesale transactions in California and the Pacific Northwest. However, it believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows for future reporting periods.

Union Grievances

In November 2001, grievances were filed by several members of the International Brotherhood of Electrical Workers Local 125 (IBEW), the bargaining unit representing PGE's union workers, alleging that losses in their pension/savings plan were caused by Enron's manipulation of its stock. The grievances, which did not specify an amount of claim, sought binding arbitration. On August 14, 2003, the Multnomah County Circuit Court granted PGE's motion for summary judgment, finding that the grievances were not subject to arbitration. A final judgment was entered on October 6, 2003. On October 22, 2003, the IBEW appealed the decision to the Oregon Court of Appeals. Both the U.S. District Court and the Bankruptcy Court approved the settlement of the class action litigation styledIn re Enron Corp. Securities Derivative & "ERISA" Litigation, Pamela M. Tittle, et al, v. Enron Corp., et al, Civil Action No. H-01-3913, U.S. District Court for the Southern District of Texas, Houston Division (Tittle Action). On September 13, 2005, the U.S. District Court entered a Bar Order in the Tittle Action, which specifically barred all claims arising out of this case including the IBEW grievance proceeding. On July 5, 2006, the Oregon Court of Appeals issued its opinion holding that the judgment in the Tittle Action precludes the IBEW from pursuing their grievances, rendering the appeal moot, and dismissed the appeal.

Colstrip - Royalty Claim

Western Energy Company (WECO) transports coal from the Rosebud Mine in Montana under a Coal Transportation Agreement with owners of Colstrip Units 3 and 4, in which PGE has a 20% ownership interest. In 2002 and 2003, WECO received two orders from the Office of Minerals Revenue Management of the U.S. Department of the Interior which asserted underpayment of royalties and taxes by WECO related to transportation of coal from the mine to Colstrip. WECO subsequently appealed the two orders to the Minerals Management Service (MMS) of the U.S. Department of the Interior. On March 28, 2005, the appeal by WECO was substantially denied. On April 28, 2005, WECO appealed the decision of the MMS to the Interior Board of Land Appeals of the U.S. Department of the Interior.

In May 2005, WECO received a "Preliminary Assessment Notice" from the Montana Department of Revenue, asserting claims similar to those of the Office of Minerals Revenue Management.

WECO has indicated to the owners of Colstrip Units 3 and 4 that, if WECO is unsuccessful in the above appeal process, it will seek reimbursement of any royalty payments by passing these costs on to the owners.

Management cannot predict the ultimate outcome of the above matters. Based on information currently known to the Company's management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. If WECO is able to pass any of these costs on to the owners, the Company would most likely seek recovery through the ratemaking process.

Environmental Matters

Harborton

A 1997 EPA investigation of a 5.5-mile segment of the Willamette River known as the Portland Harbor revealed significant contamination of sediments within the harbor. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund).

In May 2000, the Company entered into a "Voluntary Agreement for Remedial Investigation and Source Control Measures" (the Voluntary Agreement) with the DEQ, in which the Company agreed to complete a remedial investigation at the Harborton site under terms of the agreement.

In December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. The notice included a "Portland Harbor Initial General Notice List" containing sixty-eight other companies that the EPA believes may be Potentially Responsible Parties with respect to the Portland Harbor Superfund Site.

In February 2002, PGE submitted its final remedial investigative report to the DEQ summarizing its investigations. The report indicated that the investigations demonstrated that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the Harborton Substation site and that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The DEQ submitted the final investigative report to the EPA and in a May 18, 2004 letter, the EPA stated that "Based on the summary information provided by DEQ and the limited data EPA has at this stage in its process, EPA agrees at this time, that this site does not appear to be a current source of contamination to the river."

In a December 6, 2005 letter, the DEQ notified PGE that it is terminating the Voluntary Agreement, which is deemed to be satisfied. The DEQ further stated that "Based on our review of existing information and our understanding of current site conditions, DEQ determined that the site is not likely a current source of contamination to the river and that the site is a low priority for further action." Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis Potentially Responsible Party.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Portland Harbor or the liability of Potentially Responsible Parties, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on its financial statements.

Harbor Oil

Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company's power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil is also utilized by many other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site that impacted an approximate two acre area. Elevated levels of contaminants, including petroleum products, metals, pesticides, and polychlorinated biphenyl's (PCBs), have been detected at the site. On September 29, 2003, Harbor Oil was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter starts a period for PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance a Remedial Investigation and Feasibility Study of the Harbor Oil site. Discussions among the EPA and the PRPs, including PGE, are continuing.

Sufficient information is currently not available to determine either the total cost of investigation and remediation of the Harbor Oil Site or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company's financial statements.

Air Quality

PGE's operations, principally its fossil-fuel electric generation plants, are subject to the federal Clean Air Act (CAA) and other federal regulatory requirements. State governments also monitor and administer certain portions of the CAA and must set standards that are at least equal to federal standards. Oregon's air quality standards exceed federal standards. Primary pollutants addressed by the CAA that affect PGE are sulfur dioxide (SO₂), nitrogen oxides (NO_x), carbon monoxide (CO), and particulate matter. PGE manages its emissions by the use of low sulfur fuel, emission controls, emission monitoring, and combustion controls.

Colstrip -In December 2003, PPL Montana, LLC (PPL Montana), the operator of the Colstrip coal fired generating plant, received an Administrative Compliance Order (ACO) from the EPA pursuant to the CAA. The EPA alleges that since 1980, Colstrip Units 3 and 4, in which PGE has a 20% ownership interest, have been in violation of the clean air permit issued under the CAA. The permit requires Colstrip Units 3 and 4 to submit, for review and approval by the EPA, an analysis and proposal for reducing NO_x emissions to address visibility concerns if and when the EPA establishes requirements for such emissions. The EPA asserts that regulations it established in 1980 triggered the requirement. PPL Montana is currently negotiating a consent decree with the EPA to resolve this matter, which would include penalties (if any) that may be assessed.

In addition to the ACO, the EPA has issued an information request with respect to the Colstrip units. The EPA is investigating whether older coal-fired plants have been modified over the years in a manner that would subject them to more stringent requirements under the CAA. Based on the settlement discussions with PPL Montana on the ACO, the EPA has indicated that it will not pursue this information request.

Regional Haze Study - In accordance with new federal regional haze rules, the DEQ is conducting an assessment of emission sources pursuant to a Regional Haze Best Available Retrofit Technology (RH BART) process. Several other states are conducting a similar process. The DEQ is working with ten RH BART eligible sources in Oregon, including PGE's Boardman and Beaver generating plants. A demonstration analysis for identified sources, utilizing modeling techniques, is currently planned to begin during the second half of 2006. Those sources determined to cause, or contribute to, visibility impairment at protected areas will be subject to an RH BART Determination. In January 2006, the Company volunteered to participate in a DEQ pilot project that will analyze information about air emissions from Boardman to determine their effect on visibility in the region, particularly in wilderness and scenic areas. The pilot project is expected to be completed by the end of 2006.

Mercury - In May 2005, the U.S. Environmental Protection Agency (EPA) established the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from the nation's coal-fired electric generating plants. The CAMR includes a federal "cap-and-trade" program (scheduled to begin in 2010), that establishes a cumulative total ("cap") of mercury emissions from all electric generating plants in the United States and assigns to each state a mercury emissions "budget." Individual states have the choice of adopting this model or establishing their own programs, which must be submitted for approval by November 2006.

Oregon has started a rulemaking process that may result in adoption of requirements stricter than those of the EPA, as well as a form of the CAMR requirements, into the state's program, which could impact the operations of Boardman. Montana is considering whether to incorporate CAMR or stricter requirements, which could impact the operations of Colstrip. It is not yet known what impacts state and federal regulations on air quality standards may have on future operations, operating costs, or generating capacity of PGE's thermal generating plants. Although the full impact of future state and federal remediation measures is not yet determinable, it is expected that such measures will increase expenditures for PGE and be included in customer rates.

New Accounting Standards

SFAS No. 123R (SFAS 123R), Share-Based Payments, was issued in December 2004 and superseded SFAS No. 123 and Accounting Principles Board Opinion 25, Accounting for Stock-Based Compensation. SFAS 123R is effective for annual reporting periods beginning after June 15, 2005. Companies that issue share-based payment awards to employees are required to recognize compensation expense based on the fair value of the expected vested portion of the award as of the grant date over the vesting period of the award. Forfeitures that occur before the award vesting date will be adjusted from the total compensation expense, but once the award vests, no adjustment to compensation expense is allowed for forfeitures or unexercised awards. In addition, SFAS 123R would require recognition of compensation expense of all existing outstanding awards that are not fully vested for their remaining vesting period as of the effective date that were not accounted for under a fair value method of accounting at th e time of their award. PGE had no outstanding equity awards at June 30, 2006. On July 13, 2006, PGE awarded restricted stock units to its Board of Directors, officers, and certain key employees, the effect of which is not expected to have a material impact on the financial statements of the Company.

FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109, was issued in July 2006 and is effective for annual reporting periods beginning after December 15, 2006. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. It requires that a tax position meet a "more-likely-than-not threshold" for the benefit of an uncertain tax position to be recognized in the financial statements. FIN 48 requires recognition in the financial statements of the best estimate of the effects of a tax position only if that position is more likely than not of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. PGE is evaluating the application of FIN 48 with respect to its income taxes.

Information Regarding Forward-Looking Statements

This report contains statements that are forward-looking within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements of expectations, beliefs, plans, objectives, assumptions or future events or performance. Words or phrases such as "anticipates," "believes," "should," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," or similar expressions identify forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that PGE's expectations, beliefs or projections will be achieved or accomplished.

In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

• the outcome of the Company's pending general rate case;
• governmental policies and regulatory investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and rate structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of net variable power costs and other capital investments, and present or prospective wholesale and retail competition;
• matters regarding new Oregon law (including that related to utility rate treatment of income taxes), resulting in potential earnings volatility and adverse effects on operating results;
• events related to the City of Portland, Oregon investigations with regard to rates charged by the Company, and any attempt by the City to set rates for PGE customers located within the City;
• changes in weather, hydroelectric, and energy market conditions, which could affect PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;
• wholesale energy prices (including the effect of FERC price controls) and their effect on the availability and price of wholesale power purchases and sales in the western United States;
• the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;
• operational factors affecting PGE's power generation facilities;
• increasing national and international concerns regarding global warming and proposed regulations that could result in requirements for additional pollution control equipment or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, to mitigate carbon dioxide and other gas emissions, including regional haze and mercury emissions affecting the Company's thermal generating plants;
• changes in, and compliance with, environmental and endangered species laws and policies;
• financial or regulatory accounting principles or policies imposed by governing bodies;
• residential, commercial, and industrial growth and demographic patterns in PGE's service territory;
• the loss of any significant customer, or changes in the business of a major customer, that may result in changes in demand for PGE services;
• the ability of PGE to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;
• capital market conditions, including interest rate fluctuations and capital availability;
• changes in PGE's credit ratings, which could have an impact on the availability and cost of capital;
• legal and regulatory proceedings and issues;
• employee workforce factors, including strikes, work stoppages, and the loss of key executives;
• general political, economic, and financial market conditions; and
• terrorist activities.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Item 3.Quantitative and QualitativeDisclosures About Market Risk

PGE is exposed to various forms of market risk (including changes in commodity prices, foreign currency exchange rates, and interest rates), as well as to credit risk. These changes may affect the Company's future financial results, as discussed below.

Commodity Price Risk

PGE's primary business is to provide electricity to its retail customers. The Company uses purchased power contracts to supplement its thermal and hydroelectric generation to respond to fluctuations in the demand for electricity and variability in generating plant operations. In meeting these needs, PGE is exposed to market risk arising from the need to purchase power and to purchase fuel for its natural gas and coal fired generating units. The Company uses instruments such as forward contracts, which may involve physical delivery of an energy commodity; swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity; and options and futures contracts to mitigate risk that arises from market fluctuations of commodity prices.

Gains and losses from non-trading instruments that reduce commodity price risks are recognized when settled in Purchased Power and Fuel expense, or in wholesale revenue. Valuation of these financial instruments reflects management's best estimates of market prices, including closing New York Mercantile Exchange and over-the-counter quotations, time value of money, and volatility factors underlying the commitments.

PGE actively manages its risk to ensure compliance with its risk management policies. The Company monitors open commodity positions in its energy portfolio using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 months, including estimates of retail load and plant generation in the non-trading portfolio. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology, the average, high, and low value at risk on the Company's non-trading portfolio in the first half of 2006 were $6.7 million, $9.9 million, and $3.8 million, respectively, and in 2005 were $3.7 mill ion, $5.0 million, and $2.7 million, respectively.

PGE's non-trading activities are subject to regulation. The timing differences between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in prices are deferred as regulatory assets and regulatory liabilities to reflect the effects of regulation under SFAS No. 71. As contracts are settled, these deferrals reverse. In PGE's non-trading value at risk methodology, no amounts are included for potential deferrals under SFAS No. 71.

Foreign Currency Exchange Rate Risk

PGE faces exposure to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars in its non-trading portfolio. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE monitors its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy.

At June 30, 2006, a 10% change in the value of the Canadian dollar would result in an immaterial change in pre-tax income for transactions that will settle over the next 12 months.

Interest Rate Risk

To meet short-term cash requirements, PGE has established a program under which it may from time to time issue commercial paper for terms of up to 270 days; such issuances are supported by the Company's $400 million five-year unsecured revolving credit facility. Although the commercial paper program subjects the Company to fluctuations in interest rates, reflecting current market conditions, individual instruments carry a fixed rate during their respective terms. At June 30, 2006, PGE had no short-term debt outstanding through the issuance of commercial paper.

PGE currently has no financial instruments to mitigate risk related to changes in short-term interest rates, including those on commercial paper; however, it will consider such instruments in the future as necessary.

Credit Risk

PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. PGE manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. The Company also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded to reflect credit risk related to wholesale accounts receivable.

The large number and diversified base of residential, commercial, and industrial customers, combined with the Company's ability to discontinue service, contribute to reduced credit risk with respect to trade accounts receivable from retail electricity sales. Estimated provisions for uncollectible accounts receivable related to retail electricity sales are provided for such risk. At June 30, 2006, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following table presents PGE's credit exposure for commodity non-trading activities and their subsequent maturity as of June 30, 2006. The table reflects credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities (dollars in millions):

				Maturity of Credit Risk Exposure
Rating	Credit Risk Before Collateral	Percentage of Total Exposure	Credit Collateral	2006	2007	2008	2009	2010	After 2010
Investment Grade	$  76	95%	$  28	$  19	$  22	$ 20	$  4	$  2	$ 9
Non-Investment Grade	1	1%	-	1	-	-	-	-	-
Internally Rated - Investment Grade	3	4%	-	3	-	-	-	-	-
Total	$  80	100%	$  28	$  23	$  22	$ 20	$  4	$  2	$ 9

Investment Grade includes those counterparties with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody's) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. Non-Investment Grade includes those counterparties with below investment grade credit ratings on senior unsecured debt. For non-rated counterparties, PGE performs credit analysis to determine an internal credit rating that approximates investment or non-investment grade. Included in this analysis is a review of counterparty financial statements, specific business environment, access to capital, and indicators from debt and capital markets. The credit exposure includes activity for electricity and natural gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit and may represent prepayment or credit exposure assurance.

Omitted from the non-trading market risk exposures above are long-term power purchase contracts with certain public utility districts in the State of Washington and with the City of Portland, Oregon. These contracts provide PGE with a percentage share of hydro facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2018. Management believes that circumstances that could result in the nonperformance by these counterparties are remote.

Risk Management Committee

PGE has a Risk Management Committee (RMC) which is responsible for providing oversight of the adequacy and effectiveness of the corporate policies, guidelines, and procedures for market and credit risk management related to the Company's energy portfolio management activities. The RMC, which provides quarterly reports to the Audit Committee of PGE's Board of Directors, consists of officers and Company representatives with responsibility for risk management, finance and accounting, legal, rates and regulatory affairs, power operations, and generation operations. The RMC reviews and recommends for adoption policies and procedures, establishes risk limits subject to PGE Board approval, and monitors compliance with policies, procedures, and limits on a regular basis through reports and meetings.

For further information on price risk management activities, see Note 3, Price Risk Management, in the Notes to Financial Statements.

Item 4.Controls and Procedures

1. Disclosure Controls and Procedures. Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company's disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, the information relating to the Company (including its consolidated subsidiaries) required to be disclosed by the Company in the reports that it files or submits under the Exchange Act and are effective in ensuring that informati on required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
2. Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II

Other Information

Item 1.Legal Proceedings

For further information regarding the following proceedings, see PGE's 2005 Annual Report on Form 10-K and other reports filed with the SEC since its 2005 Form 10-K was filed.

City of Portland v. Oregon Public Utility Commission, Portland General Electric Company, Stephen Forbes Cooper, LLC, Citizens' Utility Board of Oregon, Industrial Customers of Northwest Utilities, Community Action Directors of Oregon, and Oregon Energy Coordinators Association, Court of Appeals of the State of Oregon, Case No. A131268GE and Marion County Oregon Circuit Court, Case No. 06C11248.

On July 19, 2006, the Oregon Court of Appeals dismissed the action before it. The matter is proceeding in the Marion County Circuit Court.

Portland General Electric Company v. International Brotherhood of Electrical Workers, Local No. 125 (Union Grievances), Multnomah County Circuit Court for the State of Oregon, Case No. 0205-05132.

On July 5, 2006, the Oregon Court of Appeals issued its opinion holding that the judgment in the Tittle Action precludes the IBEW from pursuing their grievances, rendering the appeal moot, and dismissed the appeal.

Portland General Electric Co. v. City of Glendale (California), United States District Court for the District of Oregon, Case No. 051321

The FERC denied Glendale's request for a rehearing, which was filed following the FERC's dismissal of Glendale's complaint on December 19, 2005. A Notice of Appeal to the Ninth Circuit Court was filed by Glendale on June 13, 2006.

David Kafoury, an individual, and Kafoury Brothers, LLC, an Oregon Limited Liability Corporation, each as representative of class, etc. v. Portland General Electric Company,Multnomah County Circuit Court for the State of Oregon, Case No. 0501-00627

On July 28, 2006, the settlement was approved by the Multnomah County Circuit Court.

City of Portland v. Portland General Electric Company, Complaint before the Public Utility Commission of Oregon; Docket No. UM1262.

On July 31, 2006, the OPUC issued an order dismissing two claims (that Enron and PGE should not have filed income taxes on a unitary basis under Oregon law and that PGE made certain cash payments to Enron under a tax allocation agreement which at the time had not been approved by the SEC) of the three claims made by the City of Portland.

Item 1A. Risk Factors

In addition to other information set forth in this report, the factors discussed below and in Part I, Item 1A. Risk Factors in PGE's Annual Report on Form 10-K for the year ended December 31, 2005 should be carefully considered, as they could materially affect the Company's results of operations, financial condition, or cash flows. Additional risks and uncertainties not presently known, or that are not currently considered to be significant, may also adversely affect PGE's results of operations, financial condition, or cash flows.

Regulations involving compliance with state and federal laws related to emissions from coal-fired electric generating plants could adversely affect PGE's results of operations.

Oregon and federal regulators are currently reviewing air emissions from PGE's Boardman Coal Plant as part of separate regulatory processes related to haze, mercury, and the plant's air permit. The Company expects regulators to require additional emissions controls to be installed at the plant, although specific measures will depend on the outcome of the reviews. Installation of such control measures will increase expenditures for PGE and its customers. In addition, Montana regulators are considering stricter requirements related to mercury emissions that could impact the operations of Colstrip, in which PGE has a 20% ownership interest. Although the full impact of required state and federal remediation measures is not yet determinable, they could have an adverse effect on future operations, operating costs, and generating capacity at both Boardman and Colstrip.

A new Oregon law related to income taxes could result in refunds to PGE's customers and adversely impact the Company's earnings.

On July 14, 2006, the OPUC issued an interim order that sets forth preliminary decisions regarding the implementation of SB 408. In its assessment of the interim order, PGE has revised its estimates of the range of potential refunds to customers for 2006 to be from $18 million to $66 million. Based on the low end of the range, the Company recorded a $9 million (pre-tax) reserve for the first half of 2006 for a potential refund obligation to customers using a percentage of estimated annual revenues collected through this period.

PGE will continue to evaluate the interim order and participate in the OPUC's rulemaking proceedings. As the ultimate outcome of such proceedings, including final rules adopted by the OPUC, is uncertain, the above estimates are subject to change. For further information, see "New Oregon Law - Utility Rate Treatment of Income Taxes" in "Financial and Operating Outlook" of Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations."

Item 6.Exhibits

(3) Articles of Incorporation and Bylaws

3.1 * Amended and Restated Articles of Incorporation of Portland General Electric Company [Form 8-K filed April 3, 2006, Exhibit (3.1)].

3.2 * Portland General Electric Company Third Amended and Restated Bylaws, as amended on May 12, 2006 [Form 8-K filed May 17, 2006, Exhibit (3.1)].

(4) Instruments defining the rights of security holders, including indentures

Certain instruments defining the rights of holders of other long-term debt of PGE are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount authorized under each such omitted instrument does not exceed 10 percent of the total assets of PGE and its subsidiaries on a consolidated basis. PGE hereby agrees to furnish a copy of any such instrument to the SEC upon request.

4.1 * Fifty-sixth Supplemental Indenture dated May 1, 2006 [Form 8-K filed May 25, 2006, Exhibit (4.1)].

(10) Material Contracts

10.1 * Separation Agreement between Enron Corp. and Portland General Electric Company dated April 3, 2006 [Form 8-K filed April 3, 2006, Exhibit (10.1)].

10.2 * Portland General Electric Company 2006 Outside Directors' Deferred Compensation Plan [Form 8-K filed May 17, 2006, Exhibit (10.1)].

10.3 * Form of Directors' Restricted Stock Unit Agreement [Form 8-K filed July 14, 2006, Exhibit (10.1)].

10.4 * Form of Officers' Performance Stock Unit Agreement [Form 8-K filed July 14, 2006, Exhibit (10.2)].

10.5 * Form of Officers' Restricted Stock Unit Agreement [Form 8-K filed July 14, 2006, Exhibit (10.3)].

(31) Rule 13a-14(a)/15d-14(a) Certifications

31.1 Certification of Chief Executive Officer of Portland General Electric Company (filed herewith).

31.2 Certification of Chief Financial Officer of Portland General Electric Company (filed herewith).

(32) Section 1350 Certifications

Certifications of Chief Executive Officer and Chief Financial Officer of Portland General Electric Company Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

* Incorporated by reference as indicated.

SIGNATURES

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

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

Date	August 3, 2006	By:	/s/ James J. Piro
			James J. Piro Executive Vice President, Finance Chief Financial Officer and Treasurer

Date	August 3, 2006	By:	/s/ Kirk M. Stevens
			Kirk M. Stevens Controller and Assistant Treasurer