Portland General Electric (POR) 10-Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period endedSeptember 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 October 31, 2006: 62,502,400 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	5
	Condensed Consolidated Statements of Comprehensive Income	6
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements	9
	Item 2.  Management's Discussion and Analysis of
	Financial Condition and Results of Operations	32
	Item 3.  Quantitative and Qualitative Disclosures
	About Market Risk	66
	Item 4. Controls and Procedures	69
PART II. Other Information
	Item 1. Legal Proceedings	70
	Item 1A. Risk Factors	70
	Item 5. Other Information	71
	Item 6 Exhibits	73
	Signatures	74

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 September 30,									Nine Months Ended September 30,
		2006				2005					2006				2005
		(Dollars in Millions, Except per Share Amounts)
Operating Revenues		$	372		$			355	$			1,104		$		1,059
Operating Expenses
	Purchased power and fuel		198					166				573				439
	Production and distribution		34					30				103				92
	Administrative and other		40					42				119				127
	Depreciation and amortization		55					57				165				175
	Taxes other than income taxes		19					18				57				56
	Income taxes		6					6				20				49
			352				319					1,037				938
Net Operating Income			20				36					67				121
Other Income (Deductions)
	Miscellaneous			7			(2)						12				1
	Income taxes			-			2						1				3
				7			-						13				4
Interest Charges
	Interest on long-term debt and other			17			17						49				52
Net Income		$		10		$	19			$			31		$		73
Common Stock: Weighted-average shares outstanding (thousands), Basic				62,500			62,500						62,500				62,500
Weighted-average shares outstanding (thousands), Diluted				62,505			62,500						62,502				62,500
Earnings per share, Basic and Diluted (Note 10)		$		0.16		$	0.30			$			0.50		$		1.17
Dividends declared per share		$		0.225		$	*			$			0.45		$		*
* Dividends per share for 2005 are not meaningful as the Company was a wholly-owned subsidiary.
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Retained Earnings (Unaudited)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006					2005
	(In Millions)
Balance at Beginning of Period (*)	$	565		$	698	$	558		$			644
Net Income			10		19			31					73
			575		717			589					717
Dividends Declared - Common Stock			14		150			28					150
Balance at End of Period	$		561	$	567	$		561		$			567
(*) Balances for 2005 restated. See Note 14.
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										Nine Months Ended
			September 30,										September 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)		$		1			$			-			$		(2)
	Minimum pension liability adjustment				(3)			(4)						(3)						(4)
	Total			$	(5)		$	(3)			$			(3)		$				(6)
Net Income				$	10		$	19			$				31	$				73
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 $(47) for the three
		months ended September 30, 2006 and 2005 and $17 and $(72) for the nine months ended September 30, 2006 and 2005		(7)			71				(27)					109
		Reclassification adjustment for contract settlements included
		in net income, net of related taxes of $1 and $3 for the three months ended September 30, 2006 and 2005 and $5 and $11
		for the nine months ended September 30, 2006 and 2005		(1)			(5)				(7)					(17)
		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
		$39 for the three months ended September 30, 2006 and 2005 and $(21) and $54 for the nine months ended September 30, 2006 and 2005		8			(60)				32					(82)
	Total - Unrealized gains (losses) on derivatives classified as
		cash flow hedges		-			6				(2)					9
	Minimum pension liability adjustment			-			1				-					1
		Total Other comprehensive income (loss)		-			7				(2)					10
Comprehensive income				$	10		$			26	$				29	$			83
Accumulated other comprehensive income (loss) - End of Period
	Unrealized gain (loss) on derivatives classified as cash flow hedges			$	(2)		$			7	$				(2)		$			7
	Minimum pension liability adjustment			(3)			(3)				(3)					(3)
Total				$		(5)	$			4	$				(5)	$			4
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited)
				September 30,		December 31,
				2006		2005
			(In Millions)
Assets
Electric Utility Plant - Original Cost
	Utility plant (includes construction work in progress of $361 and $177)			$	4,504		$	4,224
	Accumulated depreciation			(1,850)			(1,788)
				2,654			2,436
Other Property and Investments
	Nuclear decommissioning trust, at market value			39			31
	Non-qualified benefit plan trust			68			69
	Miscellaneous			25			34
				132			134
Current Assets
	Cash and cash equivalents			50			122
	Accounts and notes receivable (less allowance for uncollectible accounts of $49 and $50)			168			203
	Unbilled revenues			57			78
	Assets from price risk management activities			74			259
	Inventories, at average cost			64			54
	Margin deposits			23			-
	Prepayments and other			41			24
	Deferred income taxes			26			-
				503			740
Deferred Charges
	Regulatory assets			268			217
	Miscellaneous			108			111
				376			328
				$	3,665		$	3,638
Capitalization and Liabilities
Capitalization
	Common stock equity:
		Common stock, no par value, 80,000,000
		shares authorized; 62,502,400 shares outstanding		$	642		$	642
		Retained earnings		561			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			937			879
				2,135			2,076
Commitments and Contingencies (see Notes)
Current Liabilities
	Long-term debt due within one year			67			11
	Accounts payable and other accruals			201			260
	Liabilities from price risk management activities			139			129
	Customer deposits			5			53
	Accrued interest			18			17
	Accrued taxes			50			42
	Dividends payable			14			-
	Deferred income taxes			-			51
				494			563
Other
	Deferred income taxes			263			218
	Deferred investment tax credits			8			10
	Trojan asset retirement obligation			108			107
	Accumulated asset retirement obligation			26			27
	Regulatory liabilities:
		Accumulated asset retirement removal costs		400			349
		Other		118			175
	Non-qualified benefit plan liabilities			81			79
	Miscellaneous			32			34
				1,036			999
				$	3,665		$	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)
			Nine Months Ended
			September 30,
			2006		2005 (As Restated - See Note 14)
			(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities
	Net income		$	31	$	73
		Non-cash items included in net income:
		Depreciation and amortization	165		175
		Deferred income taxes	(35)		(15)
		Net assets from price risk management activities	138		(76)
		Power cost adjustment	-		13
		Regulatory deferrals - price risk management activities	(125)		58
		Other non-cash income and expenses (net)	34		4
		Changes in working capital:
		Net margin deposit activity	(71)		132
		Decrease in receivables	56		(1)
		Decrease in payables	(62)		5
		Other working capital items - net	(27)		15
		Other - net	4		19
Net Cash Provided by Operating Activities			108		402
Cash Flows From Investing Activities:
	Capital expenditures		(269)		(188)
	Purchases of nuclear decommissioning trust securities		(30)		(25)
	Sales of nuclear decommissioning trust securities		16		16
	Other - net		3		(5)
Net Cash Used in Investing Activities			(280)		(202)
Cash Flows From Financing Activities:
	Repayment of long-term debt		(161)		(29)
	Issuance of long-term debt		275		-
	Dividends paid		(14)		(150)
Net Cash Provided by (Used in) Financing Activities			100		(179)
Increase (Decrease) in Cash and Cash Equivalents			(72)		21
Cash and Cash Equivalents, Beginning of Period			122		204
Cash and Cash Equivalents, End of Period			$	50	$	225
Supplemental disclosures of cash flow information
	Cash paid during the period:
		Interest, net of amounts capitalized	$	38	$	45
		Income taxes	73		88
	Non-cash activities:
		Accrued capital additions	23		1
		Common stock dividends declared but not paid	14		-
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 Portland General Electric Company (PGE or the Company) and, in the opinion of management, reflect all adjustments which are necessary for a fair presentation of the 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. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, interim financial results do not necessarily 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 Postretirement 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 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 postretirement 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 postretirement 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 September 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	$	-	$	-	$	-	$	1
Interest cost on benefit obligation	7		6		1		1		1		1
Expected return on plan assets	(10)		(10)		(1)		(1)		-		(1)
Amortization of transition asset	-		-		-		-		-		-
Amortization of prior service cost	-		1		-		-		-		1
Recognized (gain) loss		1		-		-		-		-		1
Net periodic benefit cost (income)	$	1	$	-	$	-	$	-	$	1	$	3
Nine Months Ended September 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	$	9	$	9	$	-	$	-	$	-	$	1
Interest cost on benefit obligation	21		20		1		2		3		3
Expected return on plan assets	(30)		(30)		(2)		(1)		-		(1)
Amortization of transition asset	-		-		-		-		-		-
Amortization of prior service cost	-		1		-		-		-		1
Recognized (gain) loss		3		-		1		-		-		1
Net periodic benefit cost (income)	$	3	$	-	$	-	$	1	$	3	$	5

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				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Non-Trading Activities
Unrealized gains (losses)	$	(46)	$	66	$	(138)	$	77
SFAS No. 71 regulatory asset (liability)		58		(59)		125		(58)
Net unrealized gains (losses)	$	12	$	7	$	(13)	$	19

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Derivative Activities Recorded in OCI
Other unrealized holding net gains (losses) arising during the period	$	(12)	$	118	$	(44)	$	181
Reclassification adjustment for contract settlements included in net income		(2)		(8)		(12)		(28)
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		(99)		53		(136)
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges	$	(1)	$	11	$	(3)	$	15

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

Hedge ineffectiveness from cash flow hedges was not material in the first nine months of 2006 and 2005. As of September 30, 2006, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 60 months. The Company estimates that of the $8 million of net unrealized gains in OCI at September 30, 2006, $9 million will be reclassified into earnings within the next twelve months (more than offset by $13 million in SFAS No. 71 regulatory liabilities) and $1 million in net unrealized losses will be reclassified over the remaining 48 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 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. 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 (1998 Remand).

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 (2003 Remand). The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have filed appeals of the Marion County Circuit Court decision to the Oregon Court of Appeals.

The OPUC combined the 1998 Remand and the 2003 Remand into one proceeding and is considering the matter in phases. The first phase addresses what rates would have been if the OPUC had interpreted the law to prohibit a return on the Trojan investment. The subsequent phases will address reconciling the results of the first phase with actual rates, and adjusting rates to the extent necessary. A decision is pending in the first phase of the proceeding.

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 August 31, 2006, the Oregon Supreme Court issued a ruling on PGE's Petitions for Alternative Writ of Mandamus, abating the class action proceedings until the OPUC responds to the 2003 Remand (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through rate reductions or refunds, for any amount of return on the Trojan investment PGE collected in rates for the period from April 1995 through October 2000. The Supreme Court further stated that if the OPUC determines that it can provide a remedy to PGE's customers, then the class action proceedings may become moot in whole or in part, but if the OPUC determines that it cannot p rovide a remedy, and that decision becomes final, the court system may have a role to play. The Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. On October 5, 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions for one year.

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, punitive damages, and attorney fees.

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. 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. In September 2006, the Company began making refunds, which are expected to be completed during the fourth quarter of 2006.

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 during the period October 1991 through December 2001. 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 late September 2006, WECO received an additional order from the Office of Minerals Revenue Management to report and pay additiona l royalties for the period January 2002 through December 2004.

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. On July 19, 2006, the Court of Appeals granted the OPUC motion to dismiss the action before that Court. On October 20, 2006, the City filed a Notice and Order of Voluntary Dismissal with the Marion County Circuit Court.

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 the 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 the 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):

			September 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 Nine Months Ended September 30			2006	2005
Expenses billed from affiliated companies
	Enron Corp:
		Intercompany services(a)	$ (1)	$ 3
(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 September 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 (Ninth Circuit); 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 has now begun to hear the numerous appeals. It has bifurcated appeals of the existing cases into two phases. The first phas e (Phase I) 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 Jurisdictional Decision). The Court agreed to defer the rehearing deadline on the Jurisdictional Decision until the remainder of Phase I 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 Ninth Circuit issued its decision on the remainder of the issues in Phase I (Refund Scope Decision). It 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. It 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, and 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 Ninth Circuit 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. On October 23, 2006, the Ninth Circuit issued an extension to February 28, 2007 as the date by which rehearing petitions of the Refund Scope Decision must be filed, but denied a motion for a similar extension for rehearing petitions as to the Jurisdictional Decision. Although the August 2, 2006 Ninth Circuit decision did not mandate industry-wide refunds for the summer 2000 period, it is possible that, upon remand, the FERC could decide to order such additional refunds. Management cannot predict the outcome of any FERC proceeding or how summer refunds, if they are ordered, might be calculated.

The FERC also issued an 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. On July 31, 2006, the Court summarily denied rehearing.

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 customers. SB 408 attempts to more closely match income 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 a report with the OPUC 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. This report is to be filed by October 15th of the year following the reporting year. 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 cl ause applies only to taxes paid to units of government and collected from customers on or after January 1, 2006.

On September 14, 2006, the OPUC issued a final order (Final Order) that adopted permanent rules (Rules) to implement SB 408. In the Rules, the OPUC adopted the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. The OPUC also adopted a methodology to determine the amounts properly attributed to the utility from a consolidated tax payment using a formula to determine the ratio of the utility's payroll, property and sales to the consolidated group's amounts for the same items. This ratio is then multiplied by the amount of total taxes paid by the consolidated group to determine the utility's attributed portion. The OPUC also determined that interest should begin to accrue beginning January 1, 2006 using a mid-year convention for differences between income taxes collected and income taxes paid to governmental entities for tax year 2006.

In the Final Order, the OPUC addressed the so-called "double whammy" effect wherein the application of the Rules can result in unusual outcomes in certain situations. If a utility incurs higher expenses or receives lower revenues, resulting in lower taxes paid than the OPUC assumed it would incur in its last rate case, the automatic adjustment clause under SB 408 will require the utility to make a refund to customers and decrease the utility's earnings. Conversely, if a utility incurs lower expenses or receives higher revenues, resulting in higher taxes paid than the OPUC assumed it would incur in its last rate case, the automatic adjustment clause under SB 408 will surcharge customers and increase the utility's earnings. The OPUC stated in the Final Order that it will be responsive to concerns related to the consequences of the "double whammy" problem, and may address those concerns in other regulatory proceedings; however, it did not provide clear guidance on avenues of relief.

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 Rules do use 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. In an interim order in the rulemaking process, 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.

Effective with the April 3, 2006 issuance of new PGE common stock, PGE is no longer a subsidiary of Enron and files its own consolidated tax returns and remits 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 Rules, PGE will likely be required to refund to customers the majority of that amount.

As a result of its assessment of the Rules, PGE has revised its estimate of potential refunds to customers to be approximately $42 million for fiscal year 2006. Based on this estimate, the Company recorded a $31 million (pre-tax) reserve for the first nine months of 2006, including $22 millionduring the third quarter. In addition, $1 million of interest expense was accrued for the first nine months of 2006. In accordance with the statute, the Company will file a report with the OPUC by October 15, 2007 for the 2006 tax year regarding the amount of taxes paid by the Company as well as the amount of taxes authorized to be collected in rates, as defined by the statute. Any refunds to customers for the 2006 tax year would begin after June 1, 2008.

PGE will continue to evaluate its options for changing or modifying the legislation and Rules, and challenging any adjustment that follows for the 2006 tax year.

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 July 10, 2006, the OPUC commenced proceedings on the Complaint and Deferral. On September 11, 2006, PGE filed Amended Comments on the Application for Deferred Accounting, and an Amended Motion to Dismiss the Complaint. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Note 8 - Stock-Based Compensation

On July 13, 2006, PGE granted Restricted Stock Units and/or Performance Stock Units (Stock Units) to non-employee members of the Company's Board of Directors, officers, and certain key employees. Each Stock Unit represents the right to receive one share of the Company's common stock at a future date, subject to applicable vesting requirements. The grants were made pursuant to the terms of the Portland General Electric Company 2006 Stock Incentive Plan, and are subject to the terms and conditions of the plan and individual award agreements between the Company and each grantee. A total of 4,687,500 shares of common stock was registered for future issuance under the plan.

PGE's eight non-employee directors were granted a total of 9,608 Restricted Stock Units as part of their annual compensation arrangement. Each director was granted 1,201 units, valued at $30,000 based upon the closing stock price on the grant date. The grants vest over a one-year period in equal installments on the last day of each calendar quarter and will be settled exclusively in shares of the Company's common stock, provided that the director remains a member of the Board of Directors. The non-employee director grants also provide for the quarterly payment of Dividend Equivalent Rights (DERs) on the non-vested Restricted Stock Units. The DERs are settled in cash on the date that the related dividends are paid to holders of PGE's common stock.

PGE also awarded a total of 88,601 Restricted Stock Units and 89,238 Performance Stock Units to officers and certain key employees of the Company. The number of Stock Units was determined by dividing a specified award amount for each grantee by the closing stock price on the grant date. Both Restricted Stock Unit and Performance Stock Unit grants provide for the payment of DERs during the vesting period, which entitle the grantee to receive an amount equal to dividends paid on a share of PGE's common stock between the grant date and the vesting date. The DERs vest on the same schedule as the Stock Units and are settled in shares of PGE common stock valued at the closing stock price on the vesting date.

The Restricted Stock Unit grants to PGE officers provide for vesting over a three-year period in equal installments on each anniversary of the grant date. The Restricted Stock Unit grants to key employees vest at the end of the three-year period following the grant date. Under both officer and key employee grants, applicable service requirements must be met in order for the Restricted Stock Units to vest.

Performance Stock Units for both officers and key employees vest if performance goals related to overall customer satisfaction, electric service power quality and reliability, generating plant availability, and net income (compared to budget) are met at the end of a three-year performance period. Vesting of Performance Stock Units will be calculated by multiplying the number of units granted by a performance percentage determined by PGE's Board of Directors. The performance percentage will be calculated based on whether and to what extent the performance goals have been met. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

A total of 187,447 total Stock Units, with a grant date fair value of $24.96 each, were awarded on July 13, 2006. During the quarter, 2,400 non-employee director Restricted Stock Units, with a fair value of $24.41 each, vested. No Stock Units were forfeited during the quarter. A total of 185,047 Stock Units, with a weighted-average fair value of $25.25, remained outstanding and unvested at September 30, 2006. A total of 4,500,053 shares remain available for future grants. The plan had no impact on cash flow for the quarter ended September 30, 2006.

Effective July 1, 2006, PGE adopted SFAS No. 123R, Share-Based Payment, which requires that the compensation cost related to share-based payment transactions be recognized in financial statements at fair value, based on the market price of the underlying common stock on the date of grant, and charged to expense over the vesting period based on the number of shares expected to vest. No compensation cost is recognized for unvested awards that are forfeited. The Company adopted SFAS No. 123R using the Modified Prospective Application method, which applies to new awards and to awards modified, repurchased, or cancelled as of the beginning of the period in which SFAS No. 123R is adopted. For the three months ended September 30, 2006, PGE recorded $0.4 million of stock-based compensation expense (included in Administrative and other expense in the Condensed Consolidated Statements of Income), with a corresponding credit to additional paid-in capital. No equity compensation costs were capitalized . Based upon the attainment of performance goals that would allow the vesting of 100% of awarded Performance Stock Units, and utilizing an estimated forfeiture rate of 3%,unrecognized compensation expense related to unvested Stock Units was $4.2 million at September 30, 2006, of which $0.4 million, $1.6 million, $1.5 million, and $0.7 million is expected to be expensed during the remainder of 2006, 2007, 2008, and 2009, respectively.

Note 9 - 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 of the new PGE common stock were initially issued to the Debtors' creditors holding allowed claims, and approximately 35.5 million shares 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. For further information regarding PGE's Stock Incentive Plan, see Note 8 - Stock-Based Compensation.

Common Stock Dividend Restrictions

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 September 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 E nron.

Note 10 - Earnings Per Share

The following table presents the computation of basic and diluted earnings per common share for the three months and nine months ended September 30, 2006 and 2005:

			Three Months Ended September 30,		Nine Months Ended September 30,
			2006	2005	2006	2005
Numerator:
	Net Income (in millions)		$   10	$   19	$   31	$   73
Denominator (in thousands):
	Weighted-average common shares outstanding-basic		62,500	62,500	62,500	62,500
	Effect of dilutive securities:
		Restricted Stock*	5	-	2	-
	Weighted-average common shares outstanding-diluted		62,505	62,500	62,502	62,500
Earnings per share - basic			$ 0.16	$ 0.30	$ 0.50	$ 1.17
Earnings per share - diluted			$ 0.16	$ 0.30	$ 0.50	$ 1.17

*Restricted Stock Units and related Dividend Equivalent Rights granted under the Portland General Electric Company 2006 Stock Incentive Plan are discussed in Note 8, Stock-Based Compensation.

Note 11 - 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):

		September 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				Nine Months Ended
			September 30,				September 30,
			2006		2005		2006		2005
Average daily amounts of short-term debt
	outstanding -
		Commercial paper	$	-	$	-	$	11	$	-
Weighted daily average interest rate -
		Commercial paper*		-		-		4.9%		-
Maximum amount outstanding during the
	period -
		Commercial paper	$	-	$	-	$	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 12 - 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 13 - New Accounting Standards

Effective July 1, 2006, PGE adopted SFAS No. 123R, Share-Based Payment, using the Modified Prospective Application method. SFAS No. 123R supersedes SFAS No. 123, Accounting for Stock-Based Compensation, and Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees. SFAS No. 123R requires that companies recognize compensation expense, based upon the fair value of the awards at the grant date, for all equity-based compensation awards issued to employees that are expected to vest over the vesting period of the award. On July 13, 2006, PGE awarded restricted stock units to non-employee members of the Company's Board of Directors, officers, and certain key employees. The adoption of SFAS No. 123R did not have a material impact on the financial statements of the Company. For additional information related to PGE's equity compensation plans, see Note 8, Stock-Based Compensation.

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. Based upon a preliminary assessment of the application of FIN 48 with respect to PGE's income taxes, the adoption of FIN 48 is not expected to have a material effe ct on the financial statements of the Company.

SFAS No. 157 (SFAS 157), Fair Value Measurements, was issued in September 2006 and is effective for annual reporting periods beginning after November 15, 2007. SFAS 157 provides enhanced guidance for the use of fair value to measure assets and liabilities. It also requires expanded disclosure regarding the extent to which fair value is used for such measurements, information used to measure fair value, and the effect of fair value measurements on earnings. Provisions of SFAS 157 apply whenever other accounting standards require (or permit) assets or liabilities to be measured at fair value, but does not expand the use of fair value in any new circumstances. PGE is evaluating the application of SFAS 157 with respect to its assets and liabilities.

SFAS No. 158 (SFAS 158), Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans, was issued in September 2006. SFAS 158 requires an employer to recognize in its statement of financial position an asset for a plan's overfunded status or a liability for a plan's underfunded status, measure a plan's assets and its obligations that determine its funded status as of the end of the employer's fiscal year, and recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The Company is currently evaluating the effect that adoption of SFAS 158 will have on its financial statements.

SEC Staff Accounting Bulletin No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, was issued in September 2006. In addressing the current diversity of practice, SAB 108 provides interpretive guidance on how misstatements should be quantified and requires use of a "dual approach" method when evaluating the materiality of financial statement errors. Such approach requires consideration of the impact of misstatements on both the income statement ("rollover" method) and balance sheet ("iron curtain" method). If such consideration, along with the evaluation of all relevant quantitative and qualitative factors, results in quantifying a misstatement as material, adjustment of financial statements is required. The application of SAB 108, which is required for fiscal years ending after November 15, 2006, is not expected to have a material effect on the financial statements of the Company.

Note 14 - 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). The combined effect on the balance of Retained Earnings as of July 1, 2005 was an increase from $691 million (as previously reported) to $698 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

The current strength of Oregon's economy has contributed to continued customer growth and increasing demand for electricity within PGE's service territory. New thermal generation is scheduled to come on line during the first quarter of 2007 to meet continued load growth and supplement the output of the Company's current generating facilities, which performed well during the third quarter of 2006. In addition, PGE's pursuit of wind generation resources demonstrates the Company's increased commitment to renewable energy.

During the third quarter of 2006, certain events occurred that could have significant impact on the Company. In August, the U.S. Ninth Circuit Court of Appeals issued a ruling in the California Wholesale Refunds matter and the Oregon Supreme Court ruled on the case involving recovery of PGE's investment in Trojan. The Company views the developments in these matters as process steps toward ultimate resolution. Although some clarity was provided, considerable uncertainty remains with respect to their final impact on the Company. In September, the OPUC issued permanent rules for the implementation of Oregon Senate Bill 408 (SB 408); as a result, the Company recorded an additional reserve for potential customer refunds. Further discussion of each of these matters is contained in the "Financial and Operating Outlook" section of this Item 2.

Ownership of PGE -The transition of PGE to an independent publicly-owned company occurred in April 2006 with the issuance of new PGE common stock and the execution of a separation agreement with the Company's former parent. 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 793,000 retail customers, including approximately 14,000 new customers added in the past twelve months. The Company continues to be ranked well for overall customer satisfaction.

Oregon's economy continued to expand in the first nine months of 2006, with the state's seasonally adjusted unemployment rate at 5.4% in September, the lowest rate since February 2001 and down significantly from the high of 8.5% in July 2003. Oregon's non-farm employment (seasonally adjusted) reached a record high during the current quarter and stood at 3.1% above the same period last year.

Total retail energy deliveries for the first nine months of 2006 increased 4.1% over the same period in 2005, as the result of continued customer growth, colder-than-normal winter weather and significantly warmer-than-normal summer weather. On a weather adjusted basis, retail energy deliveries are up 2.7% from last year. Energy use by all major customer sectors increased in the first nine months of this year. On July 24, 2006, the Company recorded a new all-time high net system load "summer" peak of 3,706 MW, surpassing the previous record set one month earlier.

Power Supply -Regional hydro conditions during 2006 have exceeded 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 32% increase in hydro generation from the first nine months of 2005. Improved regional conditions have resulted in an 18% 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 near normal hydro conditions for the remainder of this year.

PGE continues to implement its 2002 Integrated Resource Plan (IRP) to meet the electricity needs of its growing customer base, 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 in the first half of 2007. 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 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 its thermal generating facilities. The EPA and several states, including Oregon and Montana, are expected to tighten controls on mercury emissions, which could have an impact on both the Boardman and Colstrip 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.

Operations -The Company's thermal generation portfolio is once again at full strength with the return of the Boardman Coal Plant to full operation on July 1. 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. The Company continues to achieve solid rankings for reliability of service, measured in terms of outage frequency and duration, and for dependable power quality.

Plans continue for the demolition of major structures at the closed Trojan nuclear power facility, with implosion of the cooling tower successfully completed. Demolition of the fuel and auxiliary buildings has begun and preparation for demolition of the turbine and control buildings is currently underway, with removal activities continuing into 2007. Removal of 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.

Financial Performance -Earnings for the first nine months of 2006 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, all of which was recorded in the first half of this year. In addition, the Company recorded a $31 million reserve for the potential refund obligation to customers related to the impact of Senate Bill 408, based upon permanent rules adopted by the OPUC.

PGE maintains its investment grade bond ratings and stable operating cash flow, with adequate liquidity available through both its $400 million credit facility and access to the commercial paper market. Such sources, combined with the Company's long-term borrowing capability, are expected to sufficiently provide for continued capital requirements, including investment in the new Port Westward generating facility and 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 September 30

PGE's net income in the third quarter of 2006 was $10 million ($0.16 per diluted share) compared to $19 million ($0.30 per diluted share) in the third quarter of 2005. The decrease in earnings was due primarily to the net effect of a $13 million after tax reserve for a potential refund obligation to customers related to the Company's current estimates of the impacts of SB 408, and a $5 million after tax reserve recorded in the third quarter of 2005 for the refund to customers of previously collected local income taxes. The effect of higher energy sales, resulting from both an increase in customers and warmer weather, was partially offset by higher production and distribution expenses during the quarter.

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

			Three Months Ended September 30,
Operating Revenues			2006	2005	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$ 312	$ 312	$       -
		Direct Access Customer Revenues	(3)	-	(3)
Total Retail Revenues			309	312	(3)
Wholesale (Non-Trading)			60	35	25
Other Operating Revenues			3	8	(5)
Total Operating Revenues			$ 372	$ 355	$    17
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		4,464	4,274	190
	Energy Delivered to Direct Access Customers		253	326	(73)
Total Retail Energy Deliveries			4,717	4,600	117
Wholesale (Non-Trading)			1,119	570	549
Trading Activities			-	123	(123)
Total Energy Sold and Delivered			5,836	5,293	543

Total Operating Revenues in the third quarter of 2006 increased approximately 4.8% from last year's third quarter, with higher Wholesale Revenues partially offset by lower Total Retail and Other Operating Revenues. Retail Revenues were unchanged from last year's third quarter, as higher energy sales and a 2006 rate increase related to higher power costs were offset by a $22 million pre-tax reserve for a potential refund obligation to customers related to the Company's current estimates of the impacts of SB 408. (See "Resource Valuation Mechanism" and "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 $7 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 refle cting the difference between the cost and market value of PGE's power supply portfolio, as provided by Oregon's electricity restructuring law.

A 2.5% increase in Total Retail Energy Deliveries resulted primarily from an approximate 13,900 increase in the average number of customers served over the third quarter of 2005, warmer weather, and higher industrial sales. Energy sales to all major customer classes increased during the third quarter of 2006, with residential energy sales up 3.4% and commercial and industrial sales up 1.6% and 13.6%, respectively. The increase in industrial sales was largely attributable to two large customers, one of which normally generates 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.

Wholesale revenues increased 71% from last year's third quarter as higher wholesale energy sales volume resulted from favorable hydro generation conditions, availability of thermal generation, and excess wholesale power purchases. This volume increase was partially offset by lower average spot market prices that resulted primarily from increased regional hydro generation.

The decrease in Other Operating Revenues from last year's third quarter was primarily the result of current year losses from the sale of natural gas in excess of generating plant requirements.

Purchased Power and Fuel expense increased $32 million (19%) from last year's third quarter. The increase was due to both increased power purchases to meet higher total system load requirements as well as higher wholesale prices. Company generation increased 10% from that of last year's third quarter, with a 12% increase in thermal generation. Total generation met approximately 50% of PGE's retail load during the third quarter of 2006 compared to 47% in the third quarter of 2005.

The following table indicates PGE's total system load (including both retail and wholesale) for the third 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	2,364	2,145	17.3	14.5
Term Purchases	2,821	2,528	47.1	37.5
Spot Purchases	702	489	28.9	57.6
Total System Load	5,887	5,162	35.7	32.6

Production, distribution, administrative and other expenses increased $2 million (3%) from last year's third quarter. Increased maintenance costs at the Company's thermal generating plants, as well as higher tree trimming expenses included in distribution costs, were partially offset by a reduction in customer support and employee benefit expenses in the third quarter of 2006.

Depreciation and Amortization expense decreased $2 million (4%). A $7 million decrease in the amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues) was partially offset by increased depreciation of utility plant.

Income taxes were unchanged from last year's third quarter, as lower taxes resulting from a decrease in third quarter 2006 taxable income were offset by the effect of state tax refunds and certain adjustments related to depreciation, both recorded in 2005.

Other Income (Miscellaneous) increased $9 million, related primarily to the establishment, in the third quarter of 2005, of an initial $8 million reserve related to the future refund to Multnomah County customers of previously collected income taxes. (See "Class Action Lawsuit - Multnomah County Business Income Taxes" in the "Financial and Operating Outlook" of this Item 2 for further information).

2006 Compared to 2005 for the Nine Months Ended September 30

PGE's net income was $31 million ($0.50 per diluted share) in the first nine months of 2006 compared to net income of $73 million ($1.17 per diluted share) in the first nine months of 2005. The decrease in earnings was due to unrealized losses on power and natural gas contracts as well as replacement power costs related to the extended, unplanned repair outages of Boardman in the first half of 2006. In addition, results for the first nine months of 2006 include the effect of a $19 million after tax reserve for a potential refund obligation to customers, reflecting the Company's current estimates of the impacts of SB 408. Increased distribution expenses, including those related to winter storm restoration, and maintenance expenses at the Company's thermal generating plants were partially offset by lower administrative expenses, related primarily to the 2005 settlement of certain asserted claims.

The following table summarizes Operating Revenues and Energy Sold and Delivered for the nine-month periods ending September 30, 2006 and 2005:

			Nine Months Ended September 30,
Operating Revenues			2006	2005	Increase/ (Decrease)
(In Millions)
Retail Operating Revenues:
		Retail	$    988	$    953	$    35
		Direct Access Customer Revenues	(9)	-	(9)
Total Retail Revenues			979	953	26
Wholesale (Non-Trading)			114	87	27
Other Operating Revenues			11	19	(8)
Total Operating Revenues			$ 1,104	$ 1,059	$    45
Energy Sold and Delivered
(In Thousands of MWhs)
Retail Energy Deliveries
	Retail Energy Sales		13,549	12,838	711
	Energy Delivered to Direct Access Customers		763	914	(151)
Total Retail Energy Deliveries			14,312	13,752	560
Wholesale (Non-Trading)			2,628	1,650	978
Trading Activities			-	697	(697)
Total Energy Sold and Delivered			16,940	16,099	841

Total Operating Revenues in the first nine months of 2006 increased approximately 4.2% from the first nine months of last year due to increases in both Retail and Wholesale Revenues. The increase in 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). Partially offsetting the above increases was a $31 million pre-tax reserve for a potential refund obligation to customers related to the Company's current estimates of the impacts 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 $19 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 Custo mer 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.

A 4.1% increase in Total Retail Deliveries in the first nine months of 2006 resulted from an approximate 13,600 increase in the average number of customers served over the first nine months of 2005, higher industrial sales, and weather conditions. Colder weather in this year's first quarter, along with significantly warmer weather in June and September, contributed to higher energy use. Energy sales to all major customer classes increased, with residential energy sales up 4.6% and commercial and industrial sales up 3.2% and 13%, respectively. The increase in industrial sales was primarily attributable to two large customers, one of which normally generates 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.

Wholesale revenues increased 31% from the first nine months of last year as higher wholesale energy sales volume resulted from favorable hydro generation conditions and excess wholesale power purchases. This volume increase was partially offset by lower average spot market prices that resulted primarily from increased regional hydro generation.

The decrease in Other Operating Revenues from last year's first nine months was primarily the result of current year losses from the sale of natural gas in excess of generating plant requirements.

Purchased Power and Fuel expense increased $134 million (31%) from the first nine months of last year. The increase was due to the cost of replacing coal-fired generation at Boardman, an increase in power purchases required to meet higher total system load requirements, and higher wholesale prices. Approximately $52 million of incremental power costs were incurred in the first two quarters 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 nine months of 2006 include $13 million of unrealized net losses on derivative activities, compared to $19 million of unrealized net gains in the first nine months of 2 005. It is expected that the unrealized losses at the end of this year's third quarter will reverse during the remainder of 2006 upon settlement of the related contracts.

Company generation decreased 21% in the first nine months of 2006 compared to the same period last year, with reduced thermal generation (related primarily to Boardman's outage) partially offset by a 32% increase in PGE hydro production, resulting from increased stream flows. Total generation met approximately 33% of PGE's retail load during the first nine months of 2006, compared to 44% in the same period last year. Hydro production met approximately 10% of PGE's total retail load in the first nine months of 2006, compared to 8% last year.

The following table indicates PGE's total system load (including both retail and wholesale) for the first nine months 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	4,816	6,061	11.2	12.4
Term Purchases	10,567	8,567	38.6	33.7
Spot Purchases	1,776	809	27.7	48.5
Total System Load	17,159	15,437	32.6	28.8

Production, distribution, administrative and other expenses increased $3 million (1%) from the first nine months of 2005. Higher production and distribution expenses resulted primarily from increased maintenance and repair activities at PGE's thermal generating plants, service restoration costs related to wind and rain storms during the first quarter of 2006, and increased tree trimming costs. A decrease in administrative and other expenses from the first nine months of last year was largely the result of the settlement of certain asserted claims in the first half of 2005.

Depreciation and Amortization expense decreased $10 million (6%). A $19 million decrease in the amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues) was partially offset by increased depreciation of utility plant.

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

Other Income (Miscellaneous) increased $11 million, related primarily to the establishment, in the third quarter of 2005, of an initial $8 million reserve related to the future refund to Multnomah County customers of previously collected income taxes. (See "Class Action Lawsuit - Multnomah County Business Income Taxes" in the "Financial and Operating Outlook" of this Item 2 for further information). In addition, there was a $5 million increase in Allowance for Funds Used During Construction, resulting primarily from the current construction of Port Westward. Partially offsetting these increases was a $2 million decrease in interest income on regulatory assets, due to declining balances as amounts are recovered from customers.

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 $108 million in the nine months ended September 30, 2006 compared to $402 million provided by operating activities in the same period last year. The decrease was due primarily to an $80 million increase in power and fuel purchases and a $203 million decrease in cash collateral deposits received 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).

Investing Activities consist primarily of improvements to PGE's distribution, transmission, and generation facilities. The $81 million increase in capital expenditures in the nine months ended September 30, 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 facility, 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 amount of $175 million, bears interest at an annual rate of 6.31% and will mature in 2036. The other series, in the 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 issuances 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 $8 million of conservation bonds and retired $3 million of preferred stock.

In July 2006, PGE paid a cash dividend of $14 million, or 22.5 cents per share, on its common stock. In July 2005, PGE paid a common stock dividend of $150 million to Enron.

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 Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on September 30, 2006 it could issue up to approximately $160 million of 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 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 availability 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 five-year 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 September 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.

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. In July 2006, upon approval of all participating banks, the facility was amended to extend the termination date to July 14, 2011. 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 ratings, 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 September 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, 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 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 54.4% and 57.5% at September 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 $160 million to $260 million annually over the period 2006-2008. Combined with all other sources, total cash provided by operations is estimated to range from $230 million to $300 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 (*)	$360 - $380	$450 - $470	$250 - $270
Long-term debt maturities	$11	$67	-

(*) Include expenditures related to Phase I of the proposed Biglow Canyon Wind Farm (126 MW capacity) (approximately $22 for 2006 and $225 for 2007), the construction of Port Westward (approximately $159 for 2006 and $12 for 2007), and fish passage measures at the Pelton Round Butte hydroelectric project (approximately $48 for 2006 - 2008).

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. Following a distribution of shares on October 3, 2006, the DCR holds 53% 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 relate d to its former ownership by Enron.

On August 1, 2006, the Company declared common stock dividends of $14 million, which were paid in October 2006. On October 26, 2006, the PGE Board of Directors approved a quarterly common stock dividend of 22.5 cents per share. The dividend is payable on January 15, 2007, to shareholders of record at the close of business on December 26, 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 is 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 September 30, 2006, PGE had posted approximately $24 million of collateral with wholesale counterparties, consisting of $1 million in letters of credit and $23 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 September 30, 2006, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $67 million and decreases to approximately $25 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 $135 million and decreases to a pproximately $69 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 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. On September 14, 2006, the OPUC issued a final order that adopted permanent rules to implement SB 408. As a result of its assessment of the rules, PGE has revised its estimate of potential refunds to customers to be approximately $42 million for fiscal year 2006. Based on this estimate, the Company recorded a $31 million (pre-tax) reserve for the first nine months of 2006, including $22 millionduring the third quarter. In addition, $1 million of interest expense was accrued for the first nine months of 2006. PGE will continue to evaluate its options for changing or modifying the legislatio n and rules, and challenging any adjustment that follows for the 2006 tax year. 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 2.7% for the nine months ended September 30, 2006, compared to the same period last year. The increase was due primarily to 2.4% and 2.9% increases, respectively, in residential and commercial deliveries. Increased residential sales resulted primarily from a 12,000 increase in the average number of customers served during the first nine months of 2006 over the first nine months 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 3% from last year.

Power and Fuel Supply

Current forecasts indicate that regional hydro conditions for the full year 2006 will approximate or slightly exceed normal levels and will surpass 2005 levels. Volumetric water supply forecasts for the Pacific Northwest region, 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 runoff of 74% of normal in 2005. 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 33% of its retail load requirement in the first nine months of 2006, with 23% met with thermal generation and the remainder met with hydro 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 and Canada. Power and natural gas prices have moderated since late 2005, due primarily to increased hydro availability within the region and a relatively quiet hurricane season in the Gulf of Mexico, in contrast to 2005.

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. On July 19, 2006, the Court of Appeals granted the OPUC motion to dismiss the action before that Court. On October 20, 2006, the City filed a Notice and Order of Voluntary Dismissal with the Marion County Circuit Court.

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. Uncertainties exist with respect to the timing and ability by Enron to utilize the credits. 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 quarterly income tax payments due to the State of Oregon during the second and third quarters of 2006. A portio n of the tax credits was utilized to offset these liabilities with no effect on income. Any realization of these tax credits will be reflected as an adjustment to equity.

Boardman Coal Plant - Repair Outages

On October 22, 2005, Boardman was taken out of service to repair its steam turbine rotor. 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 on July 1, 2006.

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 repair outage, 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 repair 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.

Under the RVM process, a 4-year rolling average of historical forced outages of PGE's generating plants is used in projecting plant availability and expected power costs. If the OPUC does not grant the Company's request for cost deferral, it is possible that some or all of the impacts of the turbine rotor outage (October 23, 2005 through February 5, 2006) may be approved for inclusion in the 4-year rolling average component of rates requested under the RVM process, beginning in 2007. It is also possible that PGE will receive no recovery for the excess power costs incurred during the Boardman outage. Management cannot predict the ultimate outcome of these matters. An OPUC decision is expected in late 2006 or early 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 customers. SB 408 attempts to more closely match income 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 a report with the OPUC 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. This report is to be filed by October 15th of the year following the reporting year. 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 app lies only to taxes paid to units of government and collected from customers on or after January 1, 2006.

On September 14, 2006, the OPUC issued a final order (Final Order) that adopted permanent rules (Rules) to implement SB 408. In the Rules, the OPUC adopted the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. The OPUC also adopted a methodology to determine the amounts properly attributed to the utility from a consolidated tax payment using a formula to determine the ratio of the utility's payroll, property and sales to the consolidated group's amounts for the same items. This ratio is then multiplied by the amount of total taxes paid by the consolidated group to determine the utility's attributed portion. The OPUC also determined that interest should begin to accrue beginning January 1, 2006 using a mid-year convention for differences between income taxes collected and income taxes paid to governmental entities for tax year 2006.

In the Final Order, the OPUC addressed the so-called "double whammy" effect wherein the application of the Rules can result in unusual outcomes in certain situations. If a utility incurs higher expenses or receives lower revenues, resulting in lower taxes paid than the OPUC assumed it would incur in its last rate case, the automatic adjustment clause under SB 408 will require the utility to make a refund to customers and decrease the utility's earnings. Conversely, if a utility incurs lower expenses or receives higher revenues, resulting in higher taxes paid than the OPUC assumed it would incur in its last rate case, the automatic adjustment clause under SB 408 will surcharge customers and increase the utility's earnings. The OPUC stated in the Final Order that it will be responsive to concerns related to the consequences of the "double whammy" problem, and may address those concerns in other regulatory proceedings; however, it did not provide clear guidance on avenues of relief.

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 Rules do use 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. In an interim order in the rulemaking process, 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.

Effective with the April 3, 2006 issuance of new PGE common stock, PGE is no longer a subsidiary of Enron and files its own consolidated tax returns and remits 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 Rules, PGE will likely be required to refund to customers the majority of that amount.

As a result of its assessment of the Rules, PGE has revised its estimate of potential refunds to customers to be approximately $42 million for fiscal year 2006. Based on this estimate, the Company recorded a $31 million (pre-tax) reserve for the first nine months of 2006, including $22 millionduring the third quarter. In addition, $1 million of interest expense was accrued for the first nine months of 2006. In accordance with the statute, the Company will file a report with the OPUC by October 15, 2007 for the 2006 tax year regarding the amount of taxes paid by the Company as well as the amount of taxes authorized to be collected in rates, as defined by the statute. Any refunds to customers for the 2006 tax year would begin after June 1, 2008.

PGE will continue to evaluate its options for changing or modifying the legislation and Rules, and challenging any adjustment that follows for the 2006 tax year.

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 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 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 July 10, 2006, the OPUC commenced proceedings on the Complaint and Deferral. On September 11, 2006, PGE filed Amended Comments on the Application for Deferred Accounting, and an Amended Motion to Dismiss 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, punitive damages, and attorney fees.

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. 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. In September 2006, the Company began making refunds, which are expected to be completed during the fourth quarter of 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.The complaint is proceeding.

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 required under Oregon law. On July 31, 2006, the OPUC dismissed the 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. For the remaining claim, the City requests a ruling from the OPUC confirming the alleged violations; an investigation of those matters; an order directing PGE to make no further stock dividend dist ributions 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. PGE disagrees with the remaining complaint and is vigorously defending 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 %) in 2007 and allow a return on equity of 10.75 %. 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.

PGE, the OPUC, and intervenors have signed Stipulation agreements which settle all revenue requirement issues except cost of capital, power costs, and Port Westward. In October 2006, the OPUC Staff filed testimony that proposes a $70 million reduction to PGE's originally filed revenue requirements, reflecting a 9.4% return on equity, other changes to PGE's proposed cost of capital, and adjustments to PGE's recovery of projected power costs. PGE disagrees with the OPUC Staff position and filed testimony with the OPUC in late October in response to Staff and intervenors' testimony. Public hearings are scheduled for early November, with the OPUC expected to issue its final order in January 2007.

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), which became effective January 1, 2006, 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 In March 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. This filing has been consolidated with the Company's general rate case filing. In early October 2006, the OPUC approved a Stipulation agreement that includes an $8.6 million reduction to forecast annual net variable power costs for 2007. A final RVM forecast will be made in November 2006 with RVM rates to become effective on January 1, 2007. These rates are to remain in effect until revised rates resulting from PGE's general rate case go into effect, which is anticipated to be no later than January 17, 2007. To date, PGE and parties to the general rate case have not reached agreement on net variable power costs that will be included in rates expected to be in effect commencing January 17, 2007.

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 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 (1998 Remand).

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 agreements to settle the litigation related to PGE's 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 Marion County Circuit Court issued an opinion remanding the case to the OPUC for action to reduce rates or order refunds (2003 Remand). The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC have appealed the Marion County Circuit Court decision to the Oregon Court of Appeals.

The OPUC combined the 1998 Remand and the 2003 Remand into one proceeding and is considering the matter in phases. The first phase addresses what rates would have been if the OPUC had interpreted the law to prohibit a return on the Trojan investment. The subsequent phases will address reconciling the results of the first phase with actual rates, and adjusting rates to the extent necessary. A decision is pending in the first phase of the proceeding.

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 August 31, 2006, the Oregon Supreme Court issued a ruling on PGE's Petitions for Alternative Writ of Mandamus, abating these class action proceedings until the OPUC responds to the 2003 Remand (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through rate reductions or refunds, for any amount of return on the Trojan investment PGE collected in rates for the period from April 1995 through October 2000. The Supreme Court further stated that if the OPUC determines that it can provide a remedy to PGE's customers, then the class action proceedings may become moot in whole or in part, but if the OPUC determines that it cannot provide a remedy, and that decision becomes final, the court system may have a role to play. The Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. On October 5, 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions for one year.

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 September 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 (Ninth Circuit); 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 has now begun to hear the numerous appeals.It has bifurcated appeals of the existing cases into two phase s. The first phase (Phase I) 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 Jurisdictional Decision). The Court agreed to defer the rehearing deadline on the Jurisdictional Decision until the remainder of Phase I 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 Ninth Circuit issued its decision on the remainder of the issues in Phase I (Refund Scope Decision). It 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. It 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, and 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 Ninth Circuit 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. On October 23, 2006, the Ninth Circuit issued an extension to February 28, 2007 as the date by which rehearing petitions of the Refund Scope Decision must be filed, but denied a motion for a similar extension for rehearing petitions as to the Jurisdictional Decision. Although the August 2, 2006 Ninth Circuit decision did not mandate industry-wide refunds for the summer 2000 period, it is possible that, upon remand, the FERC could decide to order such additional refunds. Management cannot predict the outcome of any FERC proceeding or how summer refunds, if they are ordered, might be calculated.

The FERC also issued an 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. On July 31, 2006, the Court summarily denied rehearing.

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.

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 during the period October 1991 through December 2001. 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 late September 2006, WECO received an additional order from the Office of Minerals Revenue Management to report and pay additional royalties for the period Janu ary 2002 through December 2004.

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 the 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.

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.

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, began in September 2006 and is currently in progress. 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. PGE is working with the Oregon DEQ and the OPUC to craft a feasible solution to the adoption of the proposed standards. PGE has estimated the capital cost for mercury controls at Boardman at up to $92 million, with annual incremental operations and maintenance costs at up to $7.8 million (estimates in 2006 dollars at 100% of total project costs). The Company has urged the DEQ to grant mercury allocation credits to PGE in order to defray the cost to customers of the Company's compliance with the proposed mercury limits.

In October 2006, the Montana Board of Environmental Review adopted final rules on mercury emissions from coal-fired generating units, including Colstrip, that set strict mercury emission limits by 2010 and established a review process to ensure that such facilities continue to utilize the latest mercury emission control technology. The rules will be submitted to the EPA for review and determination of their compliance with CAMR requirements.

Colstrip Air Permit -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.

Stock-Based Compensation

On July 13, 2006, PGE granted Restricted Stock Units and/or Performance Stock Units (Stock Units) to non-employee members of the Company's Board of Directors, officers, and certain key employees. Each Stock Unit represents the right to receive one share of the Company's common stock at a future date, subject to applicable vesting requirements. The grants were made pursuant to the terms of the Portland General Electric Company 2006 Stock Incentive Plan, the purpose of which is to provide common stock-based incentives which will attract, retain, and motivate directors, officers, and key employees of the Company.

Effective July 1, 2006, PGE adopted SFAS No. 123R, Share-Based Payment, which requires that the compensation cost related to share-based payment transactions be recognized in financial statements 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. The Company adopted SFAS No. 123R using the Modified Prospective Application method of adoption, which applies to new awards and to awards modified, repurchased, or cancelled as of the beginning of the period in which SFAS No. 123R is adopted. For the quarter ended September 30, 2006, PGE recorded $0.4 million of stock-based compensation expense. Based upon the attainment of performance goals that would allow the vesting of 100% of awarded Performance Stock Units, and utilizing an estimated forfeiture rate of 3%, unrecognized compensation expense related to unvested stock units was $4.2 million at September 30, 2006, of which $0.4 million, $1.6 million, $1.5 million, and $ 0.7 million is expected to be expensed during the remainder of 2006, 2007, 2008, and 2009, respectively.

PGE expects to grant Restricted Stock Units to non-employee directors, as part of their annual compensation arrangement, on or about July 1 each year. It is also anticipated that Stock Unit grants will be made to PGE officers and key employees in future years, resulting in "overlapping" vesting periods and an increase in recorded compensation expense and additional paid-in capital.

For additional information, see Note 8, Stock-Based Compensation, in the Notes to Financial Statements.

New Accounting Standards

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. Based upon a preliminary assessment of the application of FIN 48 with respect to PGE's income taxes, the adoption of FIN 48 is not expected to have a mater ial effect on the financial statements of the Company.

SFAS No. 157 (SFAS 157), Fair Value Measurements, was issued in September 2006 and is effective for annual reporting periods beginning after November 15, 2007. SFAS 157 provides enhanced guidance for the use of fair value to measure assets and liabilities. It also requires expanded disclosure regarding the extent to which fair value is used for such measurements, information used to measure fair value, and the effect of fair value measurements on earnings. Provisions of SFAS 157 apply whenever other accounting standards require (or permit) assets or liabilities to be measured at fair value, but does not expand the use of fair value in any new circumstances. PGE is evaluating the application of SFAS 157 with respect to its assets and liabilities.

SFAS No. 158 (SFAS 158), Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans, was issued in September 2006. SFAS 158 requires an employer to recognize in its statement of financial position an asset for a plan's overfunded status or a liability for a plan's underfunded status, measure a plan's assets and its obligations that determine its funded status as of the end of the employer's fiscal year, and recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The Company is currently evaluating the effect that adoption of SFAS 158 will have on its financial statements.

SEC Staff Accounting Bulletin No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, was issued in September 2006. In addressing the current diversity of practice, SAB 108 provides interpretive guidance on how misstatements should be quantified and requires use of a "dual approach" method when evaluating the materiality of financial statement errors. Such approach requires consideration of the impact of misstatements on both the income statement ("rollover" method) and balance sheet ("iron curtain" method). If such consideration, along with the evaluation of all relevant quantitative and qualitative factors, results in quantifying a misstatement as material, adjustment of financial statements is required. The application of SAB 108, which is required for fiscal years ending after November 15, 2006, is not expected to have a material effect on the financial statements of the Company.

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 completion of the Port Westward Power Plant on schedule;
• 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 nine months of 2006 were $6.1 million, $9.9 million, and $3.8 million, respectively, and in 2005 we re $3.5 million, $5.1 million, and $1.8 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 September 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 September 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 September 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 September 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	$  55	90%	$  38	$  15	$  10	$ 15	$  4	$  2	$ 9
Non-Investment Grade	-	-	-	-	-	-	-	-	-
Internally Rated - Investment Grade	5	6%	-	5	-	-	-	-	-
Internally Rated - Non-Investment Grade	2	4%	-	2	-	-	-	-	-
Total	$  62	100%	$  38	$  22	$  10	$ 15	$  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.

Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court Case No. 03C 10639; andMorgan v. Portland General Electric Company, Marion County Circuit Court Case No. 03C 10640.

On August 31, 2006, the Oregon Supreme Court issued a ruling on PGE's Petitions for Alternative Writ of Mandamus abating these class action proceedings until the OPUC responds to the November 7, 2003 remand issued by the Marion County Circuit Court inCitizens' Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O'Neill v. Public Utility Commission of Oregon, Marion County Oregon Circuit Court No. 94C-10417.

On October 5, 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions for one year.

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 October 20, 2006, the City filed a Notice and Order of Voluntary Dismissal with the Marion County Circuit Court. The matter is proceeding in the Marion County Circuit Court.

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.

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

On September 14, 2006, the OPUC issued a final order that adopted permanent rules to implement SB 408. As a result of its assessment of the order, PGE has revised its estimate of potential refunds to customers to be approximately $42 million for fiscal year 2006. Based on this estimate, the Company has recorded a $31 million (pre-tax) reserve for the first nine months of 2006, including $22 million during the third quarter.

PGE will continue to evaluate its options for changing or modifying the legislation and rules, and challenging any adjustment that follows for the 2006 tax year. As the ultimate outcome of these matters 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 5. Other Information

Proposals and Business by Shareholders

The Company plans to hold its 2007 annual meeting of shareholders on May 2, 2007. We are hereby notifying our shareholders that December 1, 2006 will be the deadline for submitting shareholder proposals for inclusion in our proxy statement and form of proxy for the 2007 annual meeting, which we believe is a reasonable time before we will begin the printing and mailing of our proxy materials for the 2007 annual meeting. Shareholder proposals received by the Company after December 1, 2006 will be considered untimely and will not be considered for inclusion in the proxy statement and form of proxy for the 2007 annual meeting. In addition, shareholder proposals must be in compliance with applicable laws and regulations and our Bylaws in order to be considered for inclusion in the proxy materials for the 2007 annual meeting.

A shareholder of the Company may wish to have a proposal presented at the 2007 annual meeting, but not to have such proposal included in the Company's proxy statement and form of proxy relating to the annual meeting. Notice of any such proposal must be received by the Company no earlier than January 2, 2007 and no later than February 2, 2007, which we believe is a reasonable time before we will begin the printing and mailing of our proxy materials for the annual meeting. If notice is not received by that date, the proposal shall be deemed "untimely" for purposes of Rule 14a-4(c) promulgated under the Exchange Act and, therefore, the individuals named in the proxies solicited on behalf of the Board of Directors of the Company for use at the annual meeting will have the right to exercise discretionary voting authority as to such proposal.

Shareholder proposals should be addressed to Portland General Electric Company, Attention: Corporate Secretary at 121 SW Salmon Street, 1WTC1701, Portland, Oregon 97204. It is recommended that shareholders submitting proposals use certified mail, return receipt requested in order to provide proof of timely receipt. The Company reserves the right to reject, rule out of order, or take other appropriate action with respect to any proposal that does not comply with these and other applicable requirements, including conditions established by the SEC.

Appointment of Director

On October 26, 2006, PGE's Board of Directors appointed Neil J. Nelson as a director of the Company to serve until the next annual meeting of shareholders. Mr. Nelson is President and Chief Executive Officer of Siltronic Corp. He will serve on the Compensation and Human Resources Committee of the Board. There are no arrangements or understandings between Mr. Nelson and any other persons pursuant to which Mr. Nelson was selected as a director.

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 % 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.

(10) Material Contracts

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

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

10.3 * 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	October 31, 2006	By:	/s/ James J. Piro
			James J. Piro Executive Vice President, Finance Chief Financial Officer and Treasurer

Date	October 31, 2006	By:	/s/ Kirk M. Stevens
			Kirk M. Stevens Controller and Assistant Treasurer