Portland General Electric (POR) 10-Q 2007 Q1 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 endedMarch 31, 2007
	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 April 30, 2007: 62,507,396 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 Operation	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	59
Item 4. Controls and Procedures	62
PART II. Other Information
Item 1. Legal Proceedings	63
Item 1A. Risk Factors	64
Item 6. Exhibits	64
Signature	65

Definitions

Bankruptcy Court	United States Bankruptcy Court for the Southern District of New York
Boardman	Boardman Coal Plant
Chapter 11 Plan	Enron Creditors Recovery Corp.'s 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 Creditors Recovery 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 Creditors Recovery 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
PCAM	Power Cost Adjustment Mechanism
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 Condensed Consolidated Statements of Income (Unaudited)
	Three Months Ended March 31,
	2007			2006
	(In Millions, Except per Share Amounts)
Operating Revenues	$	436		$	381
Operating Expenses
Purchased power and fuel		203			232
Production and distribution		32			36
Administrative and other		45			34
Depreciation and amortization		45			57
Taxes other than income taxes		21			20
Income taxes		26			(4	)
		372			375
Net Operating Income		64			6
Other Income (Deductions)
Allowance for equity funds used during construction		5			3
Miscellaneous		4			-
Income taxes		(1	)		1
		8			4
Interest Charges
Interest on long-term debt and other		17			16
Net Income (Loss)	$	55		$	(6	)
Common Stock:
Weighted-average shares outstanding (thousands), Basic		62,505			62,500
Weighted-average shares outstanding (thousands), Diluted		62,525			62,500
Earnings (loss) per share, Basic and Diluted	$	0.88		$	(0.09	)
Dividends declared per share	$	0.225		$	*
* Not meaningful as the Company was a wholly-owned subsidiary of Enron.
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 March 31,
	2007		2006
	(In Millions)
Balance at Beginning of Period	$	587	$	558
Net Income (Loss)		55		(6	)
		642		552
Dividends Declared - Common Stock		14		-
Balance at End of Period	$	628	$	552
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Comprehensive Income (Unaudited)
	Three Months Ended March 31,
	(In Millions)
	2007			2006
Accumulated other comprehensive income (loss) - Beginning of Period
Unrealized gain (loss) on derivatives classified as cash flow hedges	$	-		$	-
Minimum pension liability adjustment		*			(3	)
Pension and other post-retirement plan's funded position		(6	)		*
Total	$	(6	)	$	(3	)
Net Income (Loss)	$	55		$	(6	)
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 $(2) and $17		3			(27	)
Reclassification adjustment for contract settlements included in net income, net of related taxes of $3 and $5		(4	)		(7	)
Reclassification of unrealized gains (losses) to SFAS No. 71 regulatory (liability) asset, net of related taxes of $(1) and $(21)		1			32
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges		-			(2	)
Minimum pension liability adjustment		*			-
Pension and other post-retirement plan's funded position, net of related taxes of $1		(1	)		-
Reclassification of defined benefit pension plan and other benefits to SFAS No. 71 regulatory asset, net of related taxes of $(1)		1			-
Total Other comprehensive income (loss)		-			(2	)
Comprehensive income (loss)	$	55		$	(8	)
Accumulated other comprehensive income (loss) - End of Period
Unrealized gain (loss) on derivatives classified as cash flow hedges	$	-		$	(2	)
Minimum pension liability adjustment		*			(3	)
Pension and other post-retirement plan's funded position		(6	)		*
Total	$	(6	)	$	(5	)
* With the adoption of SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, at December 31, 2006, certain information is no longer applicable. Similarly, certain information for 2007 was not previously applicable.
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited)
	March 31,			December 31,
	2007			2006
	(In Millions)
Assets
Electric Utility Plant - Original Cost
Utility plant (includes construction work in progress of $421 and $412)	$	4,650		$	4,582
Accumulated depreciation		(1,887	)		(1,864	)
		2,763			2,718
Other Property and Investments
Nuclear decommissioning trust, at market value		43			42
Non-qualified benefit plan trust		70			70
Miscellaneous		27			26
		140			138
Current Assets
Cash and cash equivalents		5			12
Accounts and notes receivable (less allowance for uncollectible accounts of $39 and $45)		206			177
Unbilled revenues		60			88
Assets from price risk management activities		92			93
Inventories, at average cost		62			64
Margin deposits		8			46
Prepayments and other		41			25
Deferred income taxes		7			22
		481			527
Deferred Charges
Regulatory assets		342			351
Miscellaneous		33			33
		375			384
	$	3,759		$	3,767
Capitalization and Liabilities
Capitalization
Common stock equity:
Common stock, no par value, 80,000,000 shares authorized; 62,507,396 and 62,504,767 shares outstanding at March 31, 2007 and December 31, 2006, respectively	$	643		$	643
Retained earnings		628			587
Accumulated other comprehensive income (loss):
Pension and other post-retirement plans		(6	)		(6	)
Long-term debt		943			937
		2,208			2,161
Commitments and Contingencies (see Notes)
Current Liabilities
Long-term debt due within one year		66			66
Short-term borrowings		29			81
Accounts payable and other accruals		208			212
Liabilities from price risk management activities		116			155
Customer deposits		5			5
Accrued interest		19			15
Accrued taxes		40			14
Dividends payable		14			14
		497			562
Other
Deferred income taxes		247			251
Deferred investment tax credits		6			7
Trojan asset retirement obligation		111			108
Accumulated asset retirement obligation		26			26
Regulatory liabilities:
Accumulated asset retirement removal costs		423			411
Other		107			112
Non-qualified benefit plan liabilities		86			84
Miscellaneous		48			45
		1,054			1,044
	$	3,759		$	3,767
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Cash Flows (Unaudited)
	Three Months Ended
	March 31,
	2007			2006
	(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income (loss) to net cash provided by (used in) operating activities
Net income (loss)	$	55		$	(6	)
Non-cash items included in net income:
Depreciation and amortization		45			57
Deferred income taxes		5			(21	)
Net assets from price risk management activities		(41	)		79
Power cost deferral		(23	)		-
Regulatory deferrals - price risk management activities		41			(58	)
Other non-cash income and expenses (net)		(10	)		7
Changes in working capital:
Net margin deposit activity		38			(46	)
(Increase) Decrease in receivables		(1	)		46
Increase (Decrease) in payables		23			(66	)
Other working capital items - net		(14	)		(18	)
Other - net		4			6
Net Cash Provided by (Used in) Operating Activities		122			(20	)
Cash Flows From Investing Activities:
Capital expenditures		(67	)		(130	)
Purchases of nuclear decommissioning trust securities		(7	)		(11	)
Sales of nuclear decommissioning trust securities		6			5
Other - net		(1	)		7
Net Cash Used in Investing Activities		(69	)		(129	)
Cash Flows From Financing Activities:
Short-term borrowings (repayments) - net		(52	)		43
Repayment of long-term debt		-			(3	)
Issuance of long-term debt		6			-
Dividends paid		(14	)		-
Net Cash Provided by (Used in) Financing Activities		(60	)		40
Decrease in Cash and Cash Equivalents		(7	)		(109	)
Cash and Cash Equivalents, Beginning of Period		12			122
Cash and Cash Equivalents, End of Period	$	5		$	13
Supplemental disclosures of cash flow information
Cash paid during the period:
Interest, net of amounts capitalized	$	10		$	17
Income taxes		-			24
Non-cash activities:
Accrued capital additions		23			14
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 2006 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 prior year financial statements have been reclassified for comparative purposes, as discussed below. These reclassifications had no effect on PGE's previously reported consolidated financial position, results of operations, or cash flows.

In the first quarter of 2006, unrealized gains and losses on certain derivative activities that were deferred under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, to reflect the effects of regulation, were included within "Other non-cash income and expenses (net)" in the Operating Activities section of the Condensed Consolidated Statements of Cash Flow. Beginning in the second quarter of 2006, these are reflected in the separate caption "Regulatory deferrals - price risk management activities", with prior period amounts reclassified for comparative purposes.

In the first three quarters of 2006, amounts representing "Allowance for equity funds used during construction" were included within "Miscellaneous" under "Other Income (Deductions)" on the Condensed Consolidated Statements of Income. Beginning in the fourth quarter of 2006, such amounts are reflected in a separate caption, with prior period amounts reclassified for comparative purposes.

Note 2 - Employee Benefits

Pension and Other Post-Retirement Plans

Defined Benefit Pension Plan -PGE sponsors a non-contributory defined benefit pension plan, of which substantially all members 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 trust investment consultants and are updated as appropriate.

Non-Qualified Benefit Plans -The amounts included under Non-Qualified Benefit Plans in the accompanying table primarily represent obligations for a Supplemental Executive Retirement Plan (SERP). The SERP was closed to new participants in 1997. Investments in a non-qualified benefit plan trust, consisting of trust owned life insurance policies and marketable securities, are intended to be the primary source for financing these plans.

Other Benefits -PGE also participates in non-contributory post-retirement health and life insurance plans ("Other Benefits" in the table below). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE's obligation by establishing a maximum benefit per employee. Contributions made to a voluntary employees' beneficiary association trust are used to fund these plans. Costs of these plans, based upon an actuarial study, are included in rates charged to customers. Post-retirement benefit plan calculations include several assumptions which are reviewed annually with PGE's consulting actuaries and trust investment consultants and updated as appropriate. In addition, PGE has established Health Retirement Accounts (HRAs) for its employees under which the Company makes contributions to trust accounts to provide for claims by retirees for qualified medical costs.

The measurement date for these plans is December 31. PGE does not expect to make contributions to the pension plan, SERP, or post-retirement health and life insurance plans during 2007; contributions to the HRAs are not expected to be material.

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

Three Months Ended March 31:	Defined Benefit Pension Plan						Non-Qualified Benefit Plans				Other Benefits
	2007			2006			2007		2006		2007		2006
Components of net periodic benefit cost:
Service cost	$	3		$	3		$	-	$	-	$	-	$	-
Interest cost on benefit obligation		7			7			-		-		1		1
Expected return on plan assets		(10	)		(10	)		-		-		-		-
Amortization of transition asset		-			-			-		-		-		-
Amortization of prior service cost		-			-			-		-		-		-
Recognized (gain) loss		1			1			-		-		-		-
Net periodic benefit cost (income)	$	1		$	1		$	-	$	-	$	1	$	1

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 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. For derivative instruments that are physically 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. The derivative instruments entered into to manage the Company's future non-trading retail resource requirements are subject to regulation; accordingly, the unrealized gains and losses are deferred pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

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.

Prior to December 2006, PGE recorded a regulatory asset or regulatory liability under SFAS No. 71 to offset unrealized gains and losses on certain non-trading contracts recorded prior to settlement to the extent that such contracts are included in the Company's Resource Valuation Mechanism (RVM). Upon settlement, the regulatory asset or regulatory liability is reversed. In its January 2007 general rate order, the Public Utility Commission of Oregon (OPUC) approved a new Power Cost Adjustment Mechanism (PCAM) by which PGE can adjust future rates to reflect the difference between each year's forecasted and actual net variable power costs on a settlement basis. As a result, a regulatory asset or regulatory liability is recorded to offset changes in fair value of derivative instruments not included in the RVM. Effective January 17, 2007, a new Annual Power Cost Update Tariff replaced the RVM.

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

	Three Months Ended
	March 31,
	2007		2006
Unrealized gains (losses)	$	41	$	(79)
SFAS No. 71 regulatory asset (liability)		(41)		58
Net unrealized gains (losses)	$	-	$	(21)

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

	Three Months Ended
	March 31,
	2007		2006
Unrealized holding net gains (losses) arising during the period	$	5	$	(44)
Reclassification adjustment for contract settlements included in net income		(7)		(12)
Reclassification of unrealized (gains) losses to SFAS No. 71 regulatory (liability) asset		2		53
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges	$	-	$	(3)

Hedge ineffectiveness from cash flow hedges was not material in the first quarter of 2007 and 2006. As of March 31, 2007, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 54 months. The Company estimates that of the $3 million of net unrealized gains in OCI at March 31, 2007, $1 million in net unrealized losses will be reclassified into earnings within the next twelve months (fully offset by SFAS No. 71 regulatory assets) and $4 million in net unrealized gains will be reclassified over the remaining 42 months (fully offset by SFAS No. 71 regulatory liabilities).

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 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 Oregon 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. The 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 se ttlement also 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; such amount wassubstantially 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.

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. 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 2003 Remand to the Oregon Court of Appeals. On February 16, 2007, the Oregon Court of Appeals declined to reverse or abate the 2003 Remand and ordered the parties to file revised briefs with the Court.

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.

In Order No. 07-157 (the Order) entered on April 19, 2007, the OPUC denied the motion PGE filed in November 2006 to consolidate phases and re-open the record. In addition, the Order abated the Phase I proceeding pending a decision by the Oregon Court of Appeals of the 2003 Remand, and ordered that a second phase of the joint remand proceedings be immediately commenced to investigate the OPUC's delegated authority to engage in retroactive ratemaking. The Order further stated that parties not now participating in the joint remand proceedings will be allowed to intervene and participate in the second phase.

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 i t 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.

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.

Colstrip Royalty Claim - Western Energy Company (WECO) supplies coal from the Rosebud Mine in Montana under a Coal Supply Agreement and a 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 repor t and pay additional 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.The owners of Colstrip Units 3 and 4 advised WECO that their position would be that these claims are not allowable costs under either the Coal Supply Agreement or the Transportation Agreement.

Management cannot predict the ultimate outcome of the above matters or estimate any potential loss. 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 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 from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. The notice listed sixty-eight other companies that the EPA believes may be Potentially Responsible Parties (PRPs) with respect to the Portland Harbor Superfund Site.

In February 2002, PGE provided a report on its remedial investigation of the Harborton site to the Oregon Department of Environmental Quality (DEQ). The report concluded 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 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 report to the EPA and, in a May 18, 2004 letter, the EPA notified the DEQ that, based on the summary information from the DEQ and the stage of the process, the EPA, as of that time, agreed, the Harborton site does not appear to be a current source of contamination to the river.

In December 6, 2005 letter, the DEQ notified PGE 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 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 condition, results of operations or cash flows.

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 biphenyls (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 started 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. PGE, along with other PRPs, is negotiating an Administrative Order of Consent with the EPA to conduct a Remedial Investigation/Feasibility Study.

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 condition, results of operations or cash flows.

Note 5 - Receivables and Refunds on Wholesale Market Transactions

On March 12, 2007, PGE reached a settlement that resolves all issues between the Company and certain California parties relating to wholesale energy transactions in the western markets during the January 1, 2000 through June 20, 2001 time period. The settlement resolves a number of proceedings and investigations before the Federal Energy Regulatory Commission (FERC) and the U.S. Ninth Circuit Court of Appeals relating to various issues and claims in the California refund case (Docket No. EL00-95), the issue of refunds for the summer 2000 period, investigations of anomalous bidding activities and market practices (Docket Nos. IN03-10-000 and EL03-165-000), claims for refunds related to sales in the Pacific Northwest (Docket No. EL01-10), and the complaint by the California Attorney General for refunds from market-based rates retroactively to May 1, 2000. In addition to PGE, parties to the settlement (collectively referred to as the California Parties) include the California Attor ney General, the California Department of Water Resources, the California Electricity Oversight Board, the California Public Utilities Commission, Southern California Edison Company, Pacific Gas & Electric Company, and San Diego Gas & Electric Company. Other affected market participants will be given the opportunity to join the settlement, but releases as to those parties do not cover transactions outside of the California organized markets, including potential claims in the Pacific Northwest. The rights of parties electing not to join the settlement are unaffected and they will neither receive the benefits of the settlement nor be subject to its obligations. PGE believes that any amount that it may owe to non-settling parties related to transactions in the California organized market would not be material. The settlement has been filed with the FERC for its approval.

PGE currently estimates that if the FERC approves the settlement it will receive a net cash payment from the California Power Exchange (PX) of approximately $27 million, which includes net interest on its past due receivables. PGE had previously established a reserve of $40 million related to these matters based upon its estimation of the potential liability. Based upon the terms of the settlement, PGE adjusted the reserve to approximately $34 million at March 31, 2007 and recorded a pre-tax increase to income of approximately $6 million in the first quarter of 2007 (reflected as a reduction to Purchased Power and Fuel expense).

Under terms of the settlement, all but $1.78 million of PGE's $62.7 million receivable balance, plus associated interest as of December 31, 2006 of $25.3 million, will be released either to an escrow account for payment to refund recipients or in cash to PGE. Under the settlement, PGE has agreed to refund to the market $65.4 million, which is comprised of a principal settlement amount of $48.4 million plus estimated interest of $17.0 million as of December 31, 2006. However, only $42.3 million of the principal settlement amount will be paid out in the settlement because PGE is receiving a $6.1 million credit for a payment in that amount that it made to certain of the California Parties in another proceeding. Thus, if the settlement is approved by the FERC, PGE will assign $59.3 million of the balance in its receivables account (plus additional interest accrued to the projected date of distribution) to an escrow account for distribution to the California Parties and other settling participa nts. PGE's interest stated above will also be adjusted forward to the projected date of distribution under the settlement. The settlement also provides that the PX will continue to hold a reserve of approximately $1.78 million that can be used to fulfill miscellaneous continuing obligations under the FERC refund proceedings. Any amount not so used would ultimately be returned to PGE.

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 Federal Power Act (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. 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, and on December 28, 2006, PGE joined with other parties in filing a petition for certiorari of this decision with the U.S. Supreme Court. On February 5, 2007, the California Attorney General filed in opposition to the petition for certiorari, or, in the alternative if the petition is granted, a cross-petition for certiorari challenging the legality of market-based rate tariffs.

In the refund case and in related dockets, including the above challenge to market based rates, the California Attorney General and other parties have argued that refunds should be ordered retroactively to at least May 1, 2000. The March 12, 2007 settlement in the California refund case described above resolves all claims as to market-based rates in western energy markets as between PGE and the named California Parties during the settlement period, January 1, 2000 through June 21, 2001; however, it does not settle such claims from market participants who do not opt-in to the settlement, nor does it settle such potential claims arising from transactions with other market participants outside of the California Independent System Operator ("CAISO") and PX markets. 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.

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. Bri efing has been completed and oral argument was held on January 8, 2007. A decision in the case is pending.

The March 12, 2007 settlement in the California refund case described above resolves all claims as between PGE and the named California Parties as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001; however, it does not settle such potential claims from other market participants.

Management cannot predict the ultimate outcome of the above matter related to wholesale transactions in 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 6 - Utility Rate Treatment of Income Taxes

An Oregon law, commonly referred to as SB 408, attempts to more closely match income tax amounts forecasted to be collected in revenues with the amount of income taxes paid to governmental entities by investor-owned utilities or their consolidated group. The 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 applies only to taxes paid to units of government and collected from customers on or after January 1, 2006.

The OPUC has adopted rules to implement SB 408. The rules include the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. The rules also include 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 its 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 its 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 OPUC 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.

PGE has estimated its potential refunds to customers to be approximately $42 million (including $2 million of accrued interest) for 2006 and recorded a (pre-tax) reserve of such amount for the year. (The reserve includes $17 million paid to Enron for net current taxes payable for the first quarter of 2006 when PGE was included in its former parent's consolidated group for filing consolidated federal and state income tax returns). Interest will continue to accrue on the reserve, with $1 million recorded in the first quarter of 2007. In accordance with the statute, PGE 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. Under the OPUC rules, any refunds to customers for the 2006 tax year would begin after June 1, 2008.

For 2007, PGE estimates a potential collection from customers of approximately $3 million for the year. Based on a percentage of estimated annual revenues collected in the first quarter of the year, PGE deferred, as a regulatory asset, approximately $1 million (including accrued interest) at March 31, 2007. Any collections from, or refunds to, customers for the 2007 tax year will be reported in the Company's October 15, 2008 filing with the OPUC.

The OPUC has proposed additional rulemaking to resolve remaining issues related to the application of SB 408 rules. PGE will continue to evaluate its options for modifying the legislation and rules, but does not anticipate any adjustment during this year's legislative session.

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. PGE opposes the deferral and has moved to dismiss the Complaint.

On July 10, 2006, the OPUC commenced proceedings on the Complaint and deferral. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

Note 7 - 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. As of March 31, 2007, approximately 32 million shares remained in the DCR.

PGE accounted for the stock issuance in the same manner as a stock split and has retroactively adjusted all periods presented. PGE's Condensed Consolidated Statement of Income reflects "Earnings per Average Share" for both current and prior periods, with such amounts based upon the number of outstanding shares of new PGE common stock. Costs incurred for the issuance of new common stock, and for PGE to become a publicly-traded company, were charged to operating expense as incurred.

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

Common Stock 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% (excluding short term borrowings) 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 March 31, 2007, the DCR held approximately 51% of total issued and outstanding common stock of PGE. Other conditions include a requirement that the OPUC be notified (simultaneously with the public) of any dividend declared by PGE's Board of Directors.

Note 8 - Stock-Based Compensation

In 2006, PGE adopted the Portland General Electric Company 2006 Stock Incentive Plan (the Plan). Under the Plan, PGE may grant a variety of equity based awards, including restricted stock units with time-based vesting conditions (Restricted Stock Units) and performance-based vesting conditions (Performance Stock Units) to non-employee directors, officers and certain key employees. A total of 4,687,500 shares of common stock were registered for future issuance under the plan.

On March 15, 2007, PGE granted 83,410 Performance Stock Units to officers and certain key employees and 5,600 Restricted Stock Units to 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. The grants provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. A DER entitles the grantee to receive an amount equal to dividends paid on a share of PGE's common stock, which dividends have a record date between the grant date and the vesting date of the DERs. The Performance Stock Unit DERs vest on the same schedule as the Performance 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 DERs are settled in shares of PGE common stock valued at each dividend payment date and vest on the same schedule as the Restricted Stock Units.

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 the Compensation and Human Resources Committee of PGE's Board of Directors. The performance percentage will be calculated based on whether and to what extent the performance goals have been met. In accordance with the Plan, however, in determining results relative to these goals the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

Also on March 15, 2007, a grant of 525 Restricted Stock Units, valued at $15,000, was made to a newly elected director. The grant vests in equal installments on March 31, 2007 and June 30, 2007 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 grant also provides for the quarterly payment of DERs on the non-vested Restricted Stock Units, to be settled in cash on the date that the related dividends are paid to holders of PGE's common stock. The cash from the settlement of the DERs may also be deferred under the terms of the Portland General Electric Company 2006 Outside Directors' Deferred Compensation Plan.

Restricted Stock Unit activity for the first quarter of 2007 is summarized in the following table:

	Non-employee Directors			Officers and Key Employees
	Units		Weighted Average Grant Date Fair Value	Units		Weighted Average Grant Date Fair Value
Restricted Stock Units:
Stock units outstanding - January 1, 2007	4,741		$ 25.31	86,201		$ 24.96
Stock units granted - March 15, 2007	525		28.55	5,600		28.55
Stock units forfeited	-		-	(800	)	24.96
Stock units vested	(2,629	)	25.63	-		-
Stock units outstanding - March 31, 2007	2,637		25.63	91,001		25.18

Performance Stock Unit activity for the first quarter of 2007 is summarized in the following table:

	Officers and Key Employees
	Units	Weighted Average Grant Date Fair Value
Performance Stock Units:
Stock units outstanding - January 1, 2007	89,238	$ 24.96
Stock units granted - March 15, 2007	83,410	28.55
Stock units forfeited	-
Stock units vested	-
Stock units outstanding - March 31, 2007	172,648	26.69

The weighted average fair value is measured based on the closing price of PGE common stock on the date of grant. A total of 4,413,818 shares remain available for future grants. The Plan had no material impact on cash flow for the three months ended March 31, 2007.

For the three months ended March 31, 2007, PGE recorded $1 million of stock-based compensation expense (included in Administrative and other expense in the Condensed Consolidated Statements of Income), with a corresponding credit to common stock equity. 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 $5.6 million at March 31, 2007, of which $1.9 million, $2.5 million, and $1.2 million is expected to be expensed in 2007, 2008, and 2009, respectively.

Note 9 - Earnings Per Share

The following table presents the computation of basic and diluted earnings per common share for the periods indicated:

	Three Months Ended March 31,
	2007		2006
Numerator:
Net Income (Loss) (in millions)	$	55	$	(6)
Denominator (in thousands):
Weighted-average common shares outstanding - basic		62,505		62,500
Effect of dilutive securities:
Restricted Stock*		20		-
Weighted-average common shares outstanding - diluted		62,525		62,500
Earnings (Loss) per share - basic	$	0.88	$	(0.09)
Earnings (Loss) per share - diluted	$	0.88	$	(0.09)
* 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. In addition, unvested performance stock units are not included in the computation of dilutive securities because the units are subject to a three year performance period.

Note 10 - Credit Facility and Debt

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.

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

	March 31,		December 31,
	2007		2006
Aggregate short-term debt outstanding -
Commercial paper		$    29		$    81
Weighted average interest rate -
Commercial paper*		5.4%		5.5%
Unused committed line of credit		$  363		$  313

	Three Months Ended
	March 31,
	2007		2006
Average daily amounts of short-term debt outstanding -
Commercial paper	$	40	$	12
Weighted daily average interest rate -
Commercial paper*		5.5%		4.7%
Maximum amount outstanding during the period -
Commercial paper	$	93	$	46

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

In December 2006, PGE and certain institutional buyers in the private placement market entered into an agreement under which PGE will sell $170 million of PGE's First Mortgage Bonds to the buyers. The bonds are to be issued at the direction of PGE at any time up to, but not later than, June 1, 2007. The bonds will bear interest from the original issue date at an annual rate of 5.80%, and will mature on June 1, 2039. The bonds will be issued pursuant to a Bond Purchase Agreement between PGE and the buyers and under PGE's Indenture of Mortgage and Deed of Trust, dated July 1, 1945, as supplemented, including the Fifty-seventh Supplemental Indenture dated December 1, 2006, between PGE and HSBC Bank USA, National Association (as successor to The Marine Midland Trust Company of New York) in its capacity as trustee. PGE intends to use the proceeds fromthe sale of the bondsfor general corporate purposes, which may in clude capital expenditures and/or the repayment of existing debt.

On March 8, 2007, PGE remarketed $5.8 million of variable interest rate Pollution Control Bonds due in 2031 under a new remarketing agreement.

On April 12, 2007, PGE and certain institutional buyers in the private placement market entered into an agreement under which PGE will sell $130 million of PGE's First Mortgage Bonds to the buyers. The bonds are to be issued at the direction of PGE at any time up to, but not later than, October 1, 2007. The bonds will bear interest from the original issue date at an annual rate of 5.81%, and will mature on October 1, 2037. The bonds will be issued pursuant to a Bond Purchase Agreement between PGE and the buyers and under PGE's Indenture of Mortgage and Deed of Trust, dated July 1, 1945, as supplemented, including the Fifty-eighth Supplemental Indenture dated April 1, 2007, between PGE and HSBC Bank USA, National Association in its capacity as trustee. PGE intends to use the proceeds fromthe sale of the Bondsfor general corporate purposes, which may include capital expenditures and/or the repayment of existing debt.

Note 11 - 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 12 - Income Taxes

PGE adopted FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109, on January 1, 2007. 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 before the benefit of an uncertain tax position can 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 its technical merits.

PGE has completed an assessment of FIN 48 with respect to the Company's income tax positions. Based on such assessment, PGE has not recorded any liability for uncertain tax positions. Any interest or penalties on any future income tax deficiencies would be recorded within Interest Charges or Other Deductions, respectively, in the Company's Condensed Consolidated Statements of Income.

PGE files income tax returns in the U.S federal jurisdiction, in the states of Oregon and Montana, and in Multnomah County, Oregon. The Company is no longer subject to federal audits for years prior to 2004. PGE is not currently under examination by any taxing jurisdiction.

Note 13 - Power Cost Adjustment Mechanism

Effective January 17, 2007, the OPUC approved a new Power Cost Adjustment Mechanism (PCAM) by which PGE can adjust future rates to reflect the difference between each year's forecasted net variable power costs (NVPC) included in rates (the baseline), and actual NVPC on a settlement basis. Under the PCAM, PGE will be subject to a portion of the business risk or benefit associated with actual NVPC varying from costs included in base rates by: (1) applying an asymmetrical deadband for PGE to absorb cost increases or decreases, with a 90/10 sharing of costs and benefits between customers and the Company, respectively, beyond the deadband, and (2) employing a regulated earnings test.

The asymmetrical deadband is based on 75 basis points below and 150 basis points above PGE's authorized return on equity (ROE), or approximately $(12) million and $24 million, respectively for 2007. The Annual Variance is defined as the difference between actual NVPC and baseline NVPC. An Annual Power Cost Variance (PCV), defined as 90% of the Annual Variance outside the deadband, is recorded as a customer refund or collection (subject to a regulated earnings test). For 2007, the final deadband will be updated to reflect the in service date of Port Westward. The following table summarizes the approximate PCAM deadband for 2007, assuming a June 1, 2007 in service date for Port Westward (in millions):

Annual Variance Amount	PCV Deferral for Refund or Collection
If more than $(12) below baseline - refund	90% of Annual Variance in excess of $(12)
Between $(12) and $24	No deferral
If more than $24 above baseline - collection	90% of Annual Variance in excess of $24

The refund or collection amount will be subject to a regulated earnings test for the year that the NVPC were incurred. The customer refund amount will be limited to the extent that such refund will not cause PGE's actual regulated ROE for the year to fall below its authorized ROE plus 100 basis points, or 11.1%. Conversely, the customer collection amount will be limited to the extent that such collection will not cause PGE's actual regulated ROE for the year to exceed its authorized ROE minus 100 basis points, or 9.1%. A regulatory asset or liability will be recorded, with the offset to Purchased Power and Fuel expense, for any PCV deferral that arises. Interest will accrue on any deferral at the Company's authorized rate of return.

As of March 31, 2007, the year-to-date Annual Variance is $2.4 million below the baseline. Since this variance amount is within the deadband, no regulatory liability was recorded for the first quarter 2007. Any regulatory asset or liability arising from the deadband calculation would be adjusted by a regulated earnings test calculation at year end. Final determination of any refund or collection amount would be determined by the OPUC through a public filing and review.

Annually, the Company will propose PCV adjustment rates that will amortize the PCV to customer rates. The OPUC will make the final determination regarding such rates and the period over which they would apply.

In addition, as part of its Order No. 07-015, issued on January 12, 2007, the OPUC adopted an Annual Power Cost Update Tariff, which replaces the Resource Valuation Mechanism. The Annual Power Cost Update Tariff provides for rate adjustments to reflect updated forecasts of net variable power costs for future calendar years. The approved Annual Power Cost Update Tariff establishes the new baseline NVPC for purposes of the PCAM calculation each year. PGE's initial filing under this tariff, submitted to the OPUC on April 2, 2007, contains a preliminary forecast of 2008 NVPC and projects an estimated 0.4% overall reduction in customer rates, effective January 1, 2008.

Note 14 - New Accounting Standards

SFAS No. 157, Fair Value Measurements, was issued in September 2006 and is effective for fiscal years beginning after November 15, 2007. SFAS No. 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 No. 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 No. 157 with respect to its assets and liabilities.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, was issued in February 2007 and is effective for fiscal years beginning after November 15, 2007. SFAS No. 159 provides entities the option to report most financial assets and liabilities at fair value, with changes in fair value recorded in earnings. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. PGE is evaluating the application of SFAS No. 159 with respect to its financial assets and liabilities.

Item 2.Management's Discussion and Analysis of Financial

Condition and Results of Operation

Overview

General - Portland General Electric Company (PGE or the Company) continues to focus on its long-term goals to achieve and maintain high customer value, provide reliable and reasonably priced power, achieve strong financial performance, attract and retain an engaged and valued workforce, and maintain its tradition of community involvement and active corporate responsibility. The current strength of Oregon's economy has contributed to customer growth and increasing demand for electricity within the Company's service territory. When the new Port Westward generating plant is placed in service,PGE will have delivered on its commitment to add cost-effective resources that supplement the output of existing facilities and reduce dependence on the volatile energy market. In addition, the Company is pursuing its commitment to renewable energy as it proceeds with construction of new wind generation facilities and supports legislative initiatives that encourage the growth of re newable energy in Oregon, including efforts to develop a Renewable Energy Standard. PGE will continue to explore new generating resources and additional energy efficiency opportunities, consistent with the Company's Integrated Resource Plan (IRP), to meet the growing energy needs of customers.

Customers -Oregon's economy expanded further in the first quarter of 2007, with the state's seasonally adjusted unemployment rate at 5.2% in March, down from 5.4% in December 2006 and from the high of 8.5% in July 2003. Oregon's non-farm employment (seasonally adjusted) reached a record high in March 2007 and stood at 0.8% above a year ago. The continued strong economy is expected to require further investment by PGE to meet increased energy requirements.

Total retail energy deliveries for the first quarter of 2007 increased 1.6% over the same period in 2006 primarily as the result of customer growth. On a weather adjusted basis, retail energy deliveries are up 1.7% from last year. Energy use by all major customer sectors increased in the first quarter of this year.

The Company added nearly 12,000 new customers in the past twelve months (including 3,600 in the first quarter of 2007) and now serves approximately 796,000 retail customers. PGE continues to rank well for overall customer satisfaction and recently launched a multi-year effort to increase customer satisfaction and seek input from our customers on the Company's decisions and actions.

PGE is currently investigating the installation of a system-wide advanced metering infrastructure (AMI) network. The AMI project would provide improved services to customers, achieve operational efficiencies and cost reductions, and serve as a platform for demand side management programs as they become cost effective. PGE has filed a tariff with the Public Utility Commission of Oregon (OPUC) for approval to move this project forward. For further information, see "Advanced Metering Infrastructure" in "Financial and Operating Outlook" of this Item 2.

Power Supply -PGE utilizes its own generating resources, along with wholesale market purchases, to meet the energy needs of its customers. The Company has adopted a power cost strategy that extends the terms for which it will enter into purchases and sales of power and fuel as it strives to achieve a resource portfolio that matches its retail load at the lowest possible cost. It is expected that this strategy will reduce price volatility for retail customers by better responding to changing energy market conditions.

PGE's plan to meet customers' future needs for electricity, utilizing the IRP process, includes a diversified resource portfolio of supply-side and demand-side resources designed to balance cost, price stability and overall risk. The Company currently plans to file a new IRP with the OPUC in the second quarter of 2007.

Regional hydro conditions during 2007 have been near normal. An increase in output received from mid-Columbia hydro projects with which PGE has long-term power purchase contracts was partially offset by lower generation from PGE's facilities on the Clackamas and Deschutes river systems. Current forecasts indicate slightly below normal hydro conditions for the remainder of this year.

PGE's generation resources performed well in the first quarter of 2007. The Company has adopted a Generation Excellence Initiative that focuses on operational excellence at its generating facilities, with a goal of continued cost effective and reliable plant operations.

Regulatory Matters -In January 2007, the OPUC issued an order in PGE's general rate case that included new retail rates related to both general and power costs. In addition, the order approved a 2.8% increase related to the recovery of Port Westward, to become effective when the plant goes into service. As the in service date of the plant has been delayed beyond May 1, 2007, the approved increase is subject to review. For further information, see "Port Westward Generating Plant" in "Financial and Operating Outlook" of this Item 2.

The OPUC also approved a new Annual Power Cost Update Tariff, with rate adjustments to reflect updated power cost forecasts, and a Power Cost Adjustment Mechanism (PCAM), with rate adjustments reflecting the difference between forecast and actual power costs. On April 2, 2007, PGE filed its initial Annual Power Cost Update Tariff, containing a preliminary forecast of 2008 net variable power costs, which projects an estimated 0.4% overall reduction in customer rates. For further information, see "Power Cost Adjustment Mechanism" and "General Rate Case" in "Financial and Operating Outlook" of this Item 2.

In February 2007, the OPUC issued an order authorizing PGE's request to defer for future rate recovery $26.4 million of excess power costs related to Boardman's 2005-2006 outage, subject to further review. Of this amount, $6 million was recorded in 2006, with the remaining $20.4 million recorded in the first quarter of 2007. For further information, see "Boardman Coal Plant - Repair Outages" in "Financial and Operating Outlook" of this Item 2.

On March 2, 2007, the Company filed a rate application with the OPUC seeking an increase in annual revenue requirements for recovery of costs related to the first phase of the Biglow Canyon Wind Farm, which is expected to be completed by the end of 2007. If approved, new rates would become effective beginning January 1, 2008. For further information, see "Biglow Canyon Wind Farm" in "Financial and Operating Outlook" of this Item 2.

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 Environmental Protection Agency (EPA) and several states, including Oregon and Montana, have tightened controls on mercury emissions, which could have an impact on both the Boardman and Colstrip plants. On April 2, 2007 the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gases, including carbon dioxide, under the Clean Air Act. 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 reflected in the Company's revenue requirements.

The Energy Policy Act of 2005 provided the Federal Energy Regulatory Commission (FERC) broad new authority to develop and enforce national and regional electric reliability standards. As a result, the FERC has designated mandatory standards, to become effective June 4, 2007, the majority of which will apply, in whole or in part, to PGE. The Company is currently evaluating the standards and is developing a plan to ensure compliance.

Pursuant to FERC Order 890, no later than July 13, 2007 PGE will make a compliance filing to incorporate into its Open Access Transmission Tariff (OATT) the non-rate terms and conditions contained in Order 890. In addition to that filing, PGE will submit additional compliance filings, with varying due dates, to incorporate new OATT provisions. FERC Order 890 will become effective on May 15, 2007.

Financial Performance -Operating results for the first quarter of 2007 were markedly improved from last year's first quarter due to significantly improved margins on higher retail energy deliveries. First quarter 2006 results were adversely affected by the approximate $44 million incremental cost of replacing the output of Boardman, which was out of service for repairs. Results for the first quarter of 2007 include the positive impacts of a $20 million deferral of Boardman replacement power costs for future rate recovery, as approved by the OPUC, and the settlement between PGE and certain California parties related to wholesale energy transactions in the western markets during 2000-2001, which resulted in a $6 million increase to pre-tax income.

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, along with the Company's ability to issue long-term debt and equity securities are expected to sufficiently provide for continued capital and operating requirements, including investment in renewable energy from the Biglow Canyon Wind Farm and the proposed AMI project. The Company plans to issue $170 million of First Mortgage Bonds by June 1, 2007 under an agreement reached late last year and $130 million of First Mortgage Bonds by October 1, 2007 under an April 2007 agreement.

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 2007.

2007 Compared to 2006 for the Three Months Ended March 31

PGE's net income in the first quarter of 2007 was $55 million, or $0.88 per diluted share, compared to a net loss of $(6) million, or $(0.09) per diluted share, in the first quarter of 2006. The first quarter of 2006 was adversely affected by the high cost of replacing the output of the Boardman coal plant, which was out of service for repairs from late 2005 through the first half of 2006, as well as unrealized losses on power and natural gas contracts. Results for the first quarter of 2007 include the positive impacts of the deferral of a portion of Boardman replacement power costs for future rate recovery (as approved by the OPUC), the settlement between PGE and certain California parties related to wholesale energy transactions in the western energy markets during 2000-2001, and higher energy deliveries. Higher administrative and general expenses were offset by reductions in Boardman repair and maintenance costs and depreciation and amortization expenses.

The following table summarizes Operating Revenues and Energy Sold and Delivered for the first quarter of 2007 and 2006:

	Three Months Ended March 31,
		2007		2006	Increase/ (Decrease)
Operating revenues (millions)
Retail sales
Residential	$	192	$	181	$	11
Commercial		139		130		9
Industrial		37		48		(11)
Total retail sales		368		359		9
Direct access customers
Commercial		-		(1)		1
Industrial		(3)		(2)		(1)
Tariff revenues		365		356		9
Regional Power Act credits		26		(1)		27
Provision for collection - SB 408		1		-		1
Accrued revenues		1		-		1
Total retail revenues		393		355		38
Wholesale revenues		37		24		13
Other operating revenues		6		2		4
Total Operating Revenues	$	436	$	381	$	55

	Three Months Ended March 31,
	2007		2006		Increase/ (Decrease)
Energy sold and delivered - MWhs (thousands)
Retail energy sales
Residential		2,270		2,212		58
Commercial		1,746		1,737		9
Industrial		578		824		(246)
Total retail energy sales		4,594		4,773		(179)
Delivery to direct access customers
Commercial		112		101		11
Industrial		394		146		248
Total retail energy deliveries		5,100		5,020		80
Wholesale sales		1,023		612		411
Total energy sold and delivered		6,123		5,632		491
Customers - end of period
Residential		699,845		689,604		10,241
Commercial		96,317		94,659		1,658
Industrial		261		258		3
Total retail customers		796,423		784,521		11,902

Total Operating Revenues in the first quarter of 2007 increased 14% from last year's first quarter, with a 10.7% increase in Total Retail Revenues accompanied by higher Wholesale and Other Operating Revenues. The increase in Retail Revenues resulted from both a 2007 rate increase and higher energy deliveries, as well as the conversion of Regional Power Act (RPA) benefits to all cash from a combination of cash and below-market power purchases. See "General Rate Case" in the "Financial and Operating Outlook" of this Item 2 for further information.

A 1.6% increase in total retail energy deliveries resulted primarily from an approximate 12,100 increase in the average number of customers served over the first quarter of 2006. Energy sales to residential customers increased 2.6% and total energy deliveries to commercial customers increased 1.1% during the first quarter of 2007. Lower sales to industrial customers resulted from an increase in direct access customers that now purchase their energy requirements from an Energy Service Supplier (ESS).

Wholesale revenues increased 54% from last year's first quarter due to higher wholesale energy sales that resulted from favorable hydro generation conditions, availability of thermal generation, and excess wholesale power purchases. This increase was partially offset by lower average spot market prices that resulted primarily from favorable hydro conditions and generation.

The increase in Other Operating Revenues from last year's first quarter was primarily the result of increased gains from the sale of natural gas in excess of generating plant requirements.

Purchased Power and Fuel expense in the first quarter of 2007 decreased $29 million, or 13%, from last year's first quarter. The decrease was due primarily to the incremental cost of replacing Boardman's generation during the plant's outage in the first quarter of 2006, as well as unrealized net losses on derivative activities in last year's first quarter. (See "Power and Fuel Supply" in the "Financial and Operating Outlook" of this Item 2 for further information.) In addition, first quarter 2007 results reflect the deferral, for future rate recovery, of $20 million of excess Boardman power costs (approved by the OPUC in February 2007), and an approximate $6 million reduction in the Company's wholesale credit reserve related to the settlement with certain California parties involving wholesale energy transactions in 2000-2001. (See "Receivables and Refunds on Wholesale Market Transactions" in the Financial and Operating Outlook" of this Item 2 for further information). These decreases in Purchased Power and Fuel expense were partially offset by increases in total system load, average variable power cost, and the termination of the RPA below-market power purchase.

Company generation increased 61% from that of last year's first quarter, resulting primarily from the return of Boardman to full operation. A 116% increase in thermal generation was partially offset by decreased hydro production due to lower stream flows in the first quarter of 2007. Total generation met approximately 46% of PGE's retail load during the first quarter of 2007 compared to 28% in the first quarter of 2006.

The following table indicates PGE's total system load (including both retail and wholesale) for the first quarters of 2007 and 2006. Average variable power costs include wheeling and exclude unrealized gains and losses from derivative instruments.

	Megawatt/VariablePowerCosts
	Megawatt-Hours (thousands)		Average Variable Power Cost (Mills/kWh)
	2007	2006	2007	2006
Generation	2,310	1,435	15.2	2.9
Term Purchases	3,133	3,825	51.3	44.9
Spot Purchases	555	526	29.6	34.0
Total System Load	5,998	5,786	38.1	36.4

PGE's average variable power cost increased about 5% from last year's first quarter due primarily to the higher average cost of term purchases. The lower average cost of generation in the first quarter of 2006 was the result of higher margins on settled natural gas hedging transactions.

Production, distribution, administrative and other expenses increased $7 million from last year's first quarter. Higher employee benefit and insurance costs in the first quarter of 2007 were partially offset by a reduction in repair and maintenance expenses at Boardman.

Depreciation and amortization expense decreased $12 million from the first quarter of 2006. An approximate $6 million decrease was attributable to reductions in both depreciation rates for utility plant and in the authorized recovery of Trojan decommissioning costs, both of which became effective in January 2007 pursuant to the OPUC order in PGE's general rate case. In addition, there was a $3 million decrease in the amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues) and a $3 million reduction in other amortization related to the deferral of certain tax credits.

Income taxes increased $30 million due primarily to higher taxable income.

Other Income increased $4 million primarily due to accrued interest (retroactive to January 2006) on $26.4 million of excess power costs associated with Boardman's repair outage, which has been deferred for future rate recovery pursuant to approval by the OPUC. A higher allowance for equity funds used during construction (AFDC), related primarily to PGE's new Port Westward plant, also contributed to the increase.

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. 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 $122 million in the first quarter of 2007 compared to $20 million used during the same period last year. The increase was due primarily to a reduction in margin deposit requirements with certain wholesale customers, as well as reduced power purchases from last year's first quarter, when the Company was required to replace the output of the Boardman coal plant. In addition, a January 2007 rate increase resulted in increased revenues from retail customers in the first quarter of this year.

Investing Activities consist of new construction and improvements to PGE's distribution, transmission, and generation facilities. The $63 million decrease in capital expenditures in the first quarter of 2007 compared to the same period last year is primarily due to lower construction costs for 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.

PGE repaid $52 million in short-term debt in the first quarter of 2007 compared to borrowings of $43 million in the same period last year. The Company also paid $14 million of common stock dividends during the first quarter of 2007. In March 2007, PGE remarketed $5.8 million of variable interest rate Pollution Control Bonds due in 2031 under a new remarketing agreement.

PGE has a $400 million five-year revolving credit facility with a group of commercial banks. The facility, which is unsecured, is used as backup for commercial paper borrowings and 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 March 31, 2007, PGE had $29 million of short-term commercial paper outstanding and had utilized approximately $8 million in letters of credit ($2 million related to wholesale trading activities and $6 million related to Port Westward), with approximately $363 million available for additional borrowings and/or letters of credit.

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 March  ;31, 2007, the Company's consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 44.4%.

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.

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 March 31, 2007 it could issue up to approximately $592 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 $690 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.

In December 2006 and April 2007, PGE entered into agreements with certain institutional buyers to issue $170 million and $130 million of PGE's First Mortgage Bonds by June 1, 2007 and October 1, 2007, respectively.

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.

Cash Requirements

Access to short-term debt markets provides necessary liquidity to support PGE'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 to support both new and existing customers.

PGE's liquidity and capital requirements can be significantly affected by operating costs, capital expenditures, debt service, and working capital needs, including margin deposits related to wholesale trading activity. PGE's revolving credit facility supplements operating cash flow and provides a primary source of liquidity. 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 total consolidated capitalization, including current debt maturities) 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 54.9% and 53.0% at March 31, 2007 and December 31, 2006, 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 to approximate $180 million to $190 million annually over the period 2007-2009. Combined with all other sources, cash provided by operations is estimated to range from $300 million to $320 million annually during the 2007-2009 period.

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

	2007	2008	2009
Capital expenditures (*)	$435 - $445	$250 - $270	$290 - $310
Long-term debt maturities	$66	-	-

(*) Includes expenditures related to Phase I of the Biglow Canyon Wind Farm (approximately $200 million for 2007), the construction of Port Westward (approximately $17 million for 2007), and fish passage measures at the Pelton Round Butte hydroelectric project (approximately $48 million for 2007 - 2009). Excludes expenditures related to the advanced metering infrastructure project, which remains subject to regulatory approval.

PGE's revolving credit facility may be used to fund any potential cash shortfall, with additional liquidity available, if necessary, from the issuance of long-term debt, equity securities, or a combination of the two, in the future. The structure, timing and amount of such financings depend on market conditions and financing needs.

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).

Dividends on Common Stock- The following table indicates common stock dividends declared in 2007:

Declaration Date	Record Date	Payment Date	Dividends Declared per Common Share
February 22, 2007	March 26, 2007	April 16, 2007	$0.225
May 2, 2007	June 25, 2007	July 16, 2007	$0.235

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.

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 dividend that would reduce the Company's common equity capital percentage below 48% of total capitalization (excluding short-term borrowings) without prior 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. As of April 2, 2007, the DCR held approximately 38% of the total outstanding common stock of PGE. Other conditions include a requirement that the OPUC be notified (simultaneously with the public) of any dividend declared by PGE's Board of Directors. Management believes that, at March 31, 2007, the Company has the ability to pay dividends, notwithstanding the above restrictions.

Credit Ratings

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

PGE's current credit ratings are as follows:

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

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 March 31, 2007, PGE had posted approximately $10 million of collateral, consisting of $2 million in letters of credit and $8 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 March 31, 2007, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $78million and decreases to approximately $9 million by year-end 2007. The approximate amount of additional collateral that could be requested upon a dual agency downgrade event to below investment grade is approximately $112 million and decreases to approximately $9 million by y ear-end 2007.

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.

Contractual Obligations and Commercial Commitments

PGE's contractual obligations have not changed materially from those amounts disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2006.

Critical Accounting Policies and Estimates

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, 2006.

Financial and Operating Outlook

Retail Customer Growth and Energy Deliveries

Weather adjusted retail energy deliveries to PGE and ESS customers increased 1.7% for the three months ended March 31, 2007, compared to the same period last year. The increase was due primarily to 2.0% and 1.5% increases, respectively, in residential and commercial deliveries. Increased residential sales resulted primarily from a 10,600 increase in the average number of customers served during the first three months of 2007 over the first three months of 2006. Higher commercial and industrial sales resulted from a 1,500 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 2007 to increase by approximately 1.3% from last year.

Power and Fuel Supply

Current forecasts indicate that regional hydro conditions for the full year 2007 will be slightly below normal 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 on the Columbia River (as measured at The Dalles, Oregon) at 92% of normal, compared to actual runoff of 107% of normal in 2006. Hydro conditions in the Clackamas and Deschutes river systems, where PGE's hydro facilities are located, are currently projected to be 88% and 92% of normal, respectively, compared to actual runoffs of approximately 92% and 100% of normal, respectively, in 2006.

PGE generated 46% of its retail load requirement in the first three months of 2007, with 34% 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. The addition of Port Westward in 2007 is expected to further enhance the Company's ability to meet its retail load requirements.

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 are currently showing upward trends in the forward markets. Such price increases could, in the longer term, affect the cost of natural gas required to fuel PGE's combustion turbine generating plants as well as prices of power purchased in the wholesale market.

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 (Accounting for Derivative Instruments and Hedging Activities), 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. 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. The timing difference between the recognition of unrealized gains and losses on certain derivative instruments (see discussion of RVM and PCAM below) and their realization and subsequent recovery in rates is record ed as a regulatory asset or regulatory liability to reflect the effects of regulation under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

From the time prices were set in the RVM process until the January 16, 2007 end of the RVM period, any changes to electricity and natural gas prices used in the RVM resulted in unrealized gains and losses that were recorded in earnings for existing and new derivative instruments that did not qualify for the normal purchases and normal sales exception or cash flow hedges. As a result, this timing difference created earnings volatility between reporting periods. The earnings volatility has been reduced with the adoption of a PCAM by the OPUC.

In its January 2007 general rate order, the OPUC approved a new PCAM by which PGE can adjust future rates to reflect the difference between each year's forecasted and actual net variable power costs on a settlement basis. Effective December 2006, PGE began to apply SFAS No. 71 to all derivative instruments to reflect the effects of regulation. Prior to December 2006, changes in the fair value of instruments not included in the RVM were not offset by a regulatory asset or regulatory liability.

In 2006, PGE adopted a "medium term" power cost strategy to better respond to changing energy market conditions. By extending the period in which the Company normally takes positions in power and fuel markets from 24 months to up to five years, PGE expects to reduce price volatility for its customers during the next three- to five-year period. Accordingly, PGE has amended its risk limits for the projected impact of the medium term strategy.

Ownership of PGE

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. The shares of PGE common stock previously held by Enron were cancelled. 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. As of April 2, 2007, the DCR held approximately 24 million shares, or 38%, of the total outstanding common stock 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 oversees the release of new PGE common stock from the DCR to the Debtors' creditors that hold allowed claims. On April 19, 2007, the Bankruptcy Court approved elimination of the co-sale requirement from the Chapter 11 Plan's Guidelines of the DCR, permitting the DCR to sell the remaining shares of the new PGE common stock in a public offering without a pro rata offering to current holders. 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). The DCRO is currently comprised of those individuals who serve on Enron's Board of Directors.

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 provided 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.

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 2006. A portion 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.

General Rate Case

On January 12, 2007, the OPUC issued an order approving an overall price increase of approximately 1.3%, which was allocated to all PGE customer classes. The increase represents the combined effect of a 2.8% increase related to cost recovery of Port Westward, to become effective when the plant goes into service, expected to be in June 2007, and a 1.4% decrease related to general costs, which became effective on January 17, 2007. The decrease related to general costs primarily reflects reductions in forecasted test year costs and the effects of decisions related to the cost of capital. The OPUC previously approved a 5.1% price increase for increased power and fuel costs in PGE's RVM filing, which became effective on January 1, 2007. The change in retail prices is based upon a 50% equity capital structure, a 10.1% return on equity (ROE), and an overall rate of return of 8.29%. The overall increase in annual revenues approved by the OPUC for 2007 for the RVM, the general rat e case, and Port Westward proceedings was $94.6 million, or 6.4%. The OPUC also established a process for reexamining the Port Westward rate increase if the plant-in-service date is on or after May 2, 2007. See "Port Westward Generating Plant" in this Item 2 for further information.

Power Cost Adjustment Mechanism

Effective January 17, 2007, the OPUC approved a new Power Cost Adjustment Mechanism (PCAM) by which PGE can adjust future rates to reflect the difference between each year's forecasted net variable power costs (NVPC) included in rates (the baseline), and actual NVPC on a settlement basis. Under the PCAM, PGE will be subject to a portion of the business risk or benefit associated with actual NVPC varying from costs included in base rates by: (1) applying an asymmetrical deadband for PGE to absorb cost increases or decreases, with a 90/10 sharing of costs and benefits between customers and the Company, respectively, beyond the deadband, and (2) employing a regulated earnings test.

The asymmetrical deadband is based on 75 basis points below and 150 basis points above PGE's authorized return on equity (ROE), or approximately $(12) million and $24 million, respectively for 2007. The Annual Variance is defined as the difference between actual NVPC and baseline NVPC. An Annual Power Cost Variance (PCV), defined as 90% of the Annual Variance outside the deadband, is recorded as a customer refund or collection (subject to a regulated earnings test). For 2007, the deadband will be updated to reflect the in service date of Port Westward. The following table summarizes the approximate PCAM deadband for 2007, assuming a June 1, 2007 in service date for Port Westward (in millions):

Annual Variance Amount	PCV Deferral for Refund or Collection
If more than $(12) below baseline - refund	90% of Annual Variance in excess of $(12)
Between $(12) and $24	No deferral
If more than $24 above baseline - collection	90% of Annual Variance in excess of $24

The refund or collection amount will be subject to a regulated earnings test for the year that the NVPC were incurred. The customer refund amount will be limited to the extent that such refund will not cause PGE's actual regulated ROE for the year to fall below its authorized ROE plus 100 basis points, or 11.1%. Conversely, the customer collection amount will be limited to the extent that such collection will not cause PGE's actual regulated ROE for the year to exceed its authorized ROE minus 100 basis points, or 9.1%. A regulatory asset or liability will be recorded, with the offset to Purchased Power and Fuel expense, for any PCV deferral that arises. Interest will accrue on any deferral at the Company's authorized rate of return.

As of March 31, 2007, the year-to-date Annual Variance is $2.4 million below the baseline. Since this variance amount is within the deadband, no regulatory liability was recorded for the first quarter 2007. Any regulatory asset or liability arising from the deadband calculation would be adjusted by a regulated earnings test calculation at year end. Final determination of any refund or collection amount would be determined by the OPUC through a public filing and review.

Annually, the Company will propose PCV adjustment rates that will amortize the PCV to customer rates. The OPUC will make the final determination regarding such rates and the period over which they would apply.

In addition, as part of its Order issued on January 12, 2007, the OPUC adopted an Annual Power Cost Update Tariff, which replaces the Resource Valuation Mechanism. The Annual Power Cost Update Tariff provides for rate adjustments to reflect updated forecasts of net variable power costs for future calendar years. The approved Annual Power Cost Update Tariff establishes the new baseline NVPC for purposes of the PCAM calculation each year. PGE's initial filing under this tariff, submitted to the OPUC on April 2, 2007, contains a preliminary forecast of 2008 NVPC and projects an estimated 0.4% overall reduction in customer rates, effective January 1, 2008.

Biglow Canyon Wind Farm

In accordance with PGE's plan to acquire additional wind generation, as outlined in its IRP, the Company is proceeding with construction of the Biglow Canyon Wind Farm, which it plans to own and operate, located in Sherman County, Oregon. PGE currently plans to construct the project in three phases over a four- to five-year period. The first phase of the project will have a capacity of 125 MW. It is expected to be completed by the end of 2007 at a total estimated cost of $255 million to $265 million, including AFDC. In November 2006, PGE executed an agreement to acquire 76 wind turbines for the project's first phase and in February 2007 entered into a contract for the balance of plant construction. The Company filed a rate application with the OPUC on March 2, 2007 seeking an approximate $13 million increase in annual revenue requirements for full recovery of costs related to the first phase of the Biglow Canyon Wind Farm.

Advanced Metering Infrastructure

On March 7, 2007, PGE filed a tariff with the OPUC seeking an increase of approximately $13 million in annual revenue requirements related to the deployment of over 800,000 new advanced meters. The AMI network would facilitate daily, two way communications between PGE and customers, and would provide improved services while achieving operational efficiencies and cost reductions. The proposed tariff would run for approximately two and a half years, coinciding with the period over which PGE deploys the meters. After the tariff period ends, the project's costs, net of savings, will be incorporated into a future general rate case. Once fully deployed, at an estimated capital cost of $130 million, the Company estimates that AMI will save approximately $16 million annually in operating expenses. A decision by the OPUC is expected by the end of the third quarter 2007.

Utility Rate Treatment of Income Taxes

An Oregon law, commonly referred to as SB 408, attempts to more closely match income tax amounts forecasted to be 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 applies only to taxes paid to units of government and collected from customers on or after January 1, 2006.

The OPUC has adopted rules to implement SB 408. The rules include the use of fixed reference points for margins and effective tax rates from a ratemaking proceeding. The rules also include 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 its 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 its 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 OPUC 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.

PGE has estimated its potential refunds to customers to be approximately $42 million (including $2 million of accrued interest) for 2006 and recorded a (pre-tax) reserve of such amount for the year. (The reserve includes $17 million paid to Enron for net current taxes payable for the first quarter of 2006 when PGE was included in its former parent's consolidated group for filing consolidated federal and state income tax returns). Interest will continue to accrue on the reserve, with $1 million recorded in the first quarter of 2007. In accordance with the statute, PGE 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. Under the OPUC rules, any refunds to customers for the 2006 tax year would begin after June 1, 2008.

For 2007, PGE estimates a potential collection from customers of approximately $3 million for the year. Based on a percentage of estimated annual revenues collected in the first quarter of the year, PGE deferred, as a regulatory asset, approximately $1 million (including accrued interest) at March 31, 2007. Any collections from, or refunds to, customers for the 2007 tax year will be reported in the Company's October 15, 2008 filing with the OPUC.

The OPUC has proposed additional rulemaking to resolve remaining issues related to the application of SB 408 rules. PGE will continue to evaluate its options for modifying the legislation and rules, but does not anticipate any adjustment during this year's legislative session.

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. PGE opposes the deferral and has moved to dismiss the Complaint.

On July 10, 2006, the OPUC commenced proceedings on the Complaint and deferral. Management cannot predict the ultimate outcome of this matter or estimate any potential loss.

City of Portland Actions

The City of Portland has indicated that it may pursue ratemaking for PGE's retail customers who reside within the City of Portland's boundaries. In September 2005, the Portland City Council approved a resolution directing 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 of Portland. The City of Portland subsequently broadened its inquiry to include PGE's power trading activities in 2000 and 2001 and requested that PGE provide many additional documents and records, and on March 23, 2006 issued a subpoena to PGE seeking numerous records and documents. PGE determined that there are a number of legal and practical issues concerning the City of Portland's subpoena and other requests for additional information, and has declined to provide any additional data to the City of Portland while those issues remain unresolved. On Apr il 21, 2006, PGE filed a complaint in Multnomah County Circuit Court seeking clarity on whether the City of Portland has investigatory and ratemaking authority. Trial has been set for September 2007 and the parties have been ordered to mediation. The City of Portland has agreed not to seek enforcement of the subpoena while this case is pending.

Boardman Coal Plant - Repair Outages

PGE's Boardman coal plant was taken out of service in late October 2005 for repairs and did not return to full operation until July 1, 2006. During the outage, PGE incurred incremental power costs of approximately $92 million, with $40 million and $52 million incurred in 2005 and 2006, respectively.

In November 2005, PGE filed an application with the OPUC to defer for later ratemaking treatment approximately $46 million, representing estimated excess power costs associated with a portion of Boardman's outage. On February 12, 2007, the OPUC issued an order authorizing PGE to defer $26.4 million, based on a sharing mechanism that divides responsibility for the outage costs between PGE's customers and shareholders. In April 2007, Industrial Customers of Northwest Utilities, a regional industrial trade association, filed a petition for reconsideration of the OPUC order.

Amortization of the deferred amount will be determined in a ratemaking proceeding expected to begin in the second quarter of 2007. The ratemaking proceeding will include a prudency review of PGE's actions with respect to the outage and acquisition of replacement power and a determination as to whether recovery of the deferred amount will cause PGE's earnings to exceed a reasonable range. PGE recorded a deferral in the amount of $6 million at December 31, 2006, with the remaining $20.4 million recorded in the first quarter of 2007. In addition, approximately $3 million of accrued interest (retroactive to January 1, 2006) was recorded in the first quarter of 2007; interest will continue to accrue on the deferred amount pending ratemaking determination.

Port Westward Generating Plant

In February 2005, pursuant to PGE's strategy to meet the electric energy needs of its customers outlined in its Integrated Resource Final Action Plan, PGE began construction of Port Westward, a 400 MW natural gas-fired facility located in Clatskanie, Oregon.

The in service date for Port Westward has been delayed from late April 2007 to June 2007 as a result of damaged blades in the compressor section of the gas turbine that were discovered by the construction contractor during the testing of the plant. The delay will allow time to make repairs, conduct additional inspections, and perform an analysis to determine the origin of the damage. Inspection and repair costs will be borne by the contractor under the fixed price contract with PGE.

During the delay, the Company will continue to capitalize AFDC as well as internal costs related to the project. The procurement contracts contain provisions that will offset a portion of these additional costs. The total estimated cost of the plant is now expected to be between $280 million and $290 million, including AFDC.

Based on current power market conditions, PGE expects the delay will not have a material effect on its power costs for the expected delay period.

In January 2007, the OPUC issued a rate order approving a 2.8% increase related to the cost recovery of Port Westward, to become effective when the plant goes into service. The OPUC also established a process for re-examining the Port Westward rate increase if the plant's in service date is on or after May 2, 2007. The OPUC staff and intervenors will have 15 days from the in service date to determine whether there is new information that requires a re-examination of PGE's costs in rates. PGE expects that new rates for Port Westward will go into effect once the plant is placed in service.

Hydro Relicensing

In March 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. In December 2006, the FERC issued a Final Environmental Impact Statement that recommended 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 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 Oregon 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 Utility Reform Project (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. The URP appealed the 2002 Order to the Marion County Circuit Court and on November 7, 2 003, 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 2003 Remand to the Oregon Court of Appeals. On February 16, 2007, the Oregon Court of Appeals declined to reverse or abate the 2003 Remand and ordered the parties to file revised briefs with the Court.

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.

In Order No. 07-157 (the Order) entered on April 19, 2007, the OPUC denied the motion PGE filed in November 2006 to consolidate phases and re-open the record. In addition, the Order abated the Phase I proceeding pending a decision by the Oregon Court of Appeals of the 2003 Remand, and ordered that a second phase of the joint remand proceedings be immediately commenced to investigate the OPUC's delegated authority to engage in retroactive ratemaking. The Order further stated that parties not now participating in the joint remand proceedings will be allowed to intervene and participate in the second phase.

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

On March 12, 2007, PGE reached a settlement that resolves all issues between the Company and certain California parties relating to wholesale energy transactions in the western markets during the January 1, 2000 through June 20, 2001 time period. The settlement resolves a number of proceedings and investigations before the FERC and the U.S. Ninth Circuit Court of Appeals relating to various issues and claims in the California refund case (Docket No. EL00-95), the issue of refunds for the summer 2000 period, investigations of anomalous bidding activities and market practices (Docket Nos. IN03-10-000 and EL03-165-000), claims for refunds related to sales in the Pacific Northwest (Docket No. EL01-10), and the complaint by the California Attorney General for refunds from market-based rates retroactively to May 1, 2000. In addition to PGE, parties to the settlement (collectively referred to as the California Parties) include the California Attorney General, the California Department of Water Resources, the California Electricity Oversight Board, the California Public Utilities Commission, Southern California Edison Company, Pacific Gas & Electric Company, and San Diego Gas & Electric Company. Other affected market participants will be given the opportunity to join the settlement, but releases as to those parties do not cover transactions outside of the California organized markets, including potential claims in the Pacific Northwest. The rights of parties electing not to join the settlement are unaffected and they will neither receive the benefits of the settlement nor be subject to its obligations. PGE believes that any amount that it may owe to non-settling parties related to transactions in the California organized market would not be material. The settlement has been filed with the FERC for its approval.

PGE currently estimates that if the FERC approves the settlement it will receive a net cash payment from the California Power Exchange (PX) of approximately $27 million, which includes net interest on its past due receivables. PGE had previously established a reserve of $40 million related to these matters based upon its estimation of the potential liability. Based upon the terms of the settlement, PGE adjusted the reserve to approximately $34 million at March 31, 2007 and recorded a pre-tax increase to income of approximately $6 million in the first quarter of 2007 (reflected as a reduction to Purchased Power and Fuel expense).

Under terms of the settlement, all but $1.78 million of PGE's $62.7 million receivable balance, plus associated interest as of December 31, 2006 of $25.3 million, will be released either to an escrow account for payment to refund recipients or in cash to PGE. Under the settlement, PGE has agreed to refund to the market $65.4 million, which is comprised of a principal settlement amount of $48.4 million plus estimated interest of $17.0 million as of December 31, 2006. However, only $42.3 million of the principal settlement amount will be paid out in the settlement because PGE is receiving a $6.1 million credit for a payment in that amount that it made to certain of the California Parties in another proceeding. Thus, if the settlement is approved by the FERC, PGE will assign $59.3 million of the balance in its receivables account (plus additional interest accrued to the projected date of distribution) to an escrow account for distribution to the California Parties and other settling participa nts. PGE's interest stated above will also be adjusted forward to the projected date of distribution under the settlement. The settlement also provides that the PX will continue to hold a reserve of approximately $1.78 million that can be used to fulfill miscellaneous continuing obligations under the FERC refund proceedings. Any amount not so used would ultimately be returned to PGE.

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 Federal Power Act (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. 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, and on December 28, 2006, PGE joined with other parties in filing a petition for certiorari of this decision with the U.S. Supreme Court. On February 5, 2007, the California Attorney General filed in opposition to the petition for certiorari, or, in the alternative if the petition is granted, a cross-petition for certiorari challenging the legality of market-based rate tariffs.

In the refund case and in related dockets, including the above challenge to market based rates, the California Attorney General and other parties have argued that refunds should be ordered retroactively to at least May 1, 2000. The March 12, 2007 settlement in the California refund case described above resolves all claims as to market-based rates in western energy markets as between PGE and the named California Parties during the settlement period, January 1, 2000 through June 21, 2001; however, it does not settle such claims from market participants who do not opt-in to the settlement, nor does it settle such potential claims arising from transactions with other market participants outside of the California Independent System Operator ("CAISO") and PX markets. 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.

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. Bri efing has been completed and oral argument was held on January 8, 2007. A decision in the case is pending.

The March 12, 2007 settlement in the California refund case described above resolves all claims as between PGE and the named California Parties as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001; however, it does not settle such potential claims from other market participants.

Management cannot predict the ultimate outcome of the above matter related to wholesale transactions in 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) supplies coal from the Rosebud Mine in Montana under a Coal Supply Agreement and a 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.The owners of Colstrip Units 3 and 4 advised WECO that their position would be that these claims are not allowable costs under either the Coal Supply Agreement or the Transportation Agreement.

Management cannot predict the ultimate outcome of the above matters or estimate any potential loss. 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 Environmental Protection Agency (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 December 2000, PGE received from the EPA a "Notice of Potential Liability" regarding the Harborton Substation facility. The notice listed sixty-eight other companies that the EPA believes may be Potentially Responsible Parties (PRPs) with respect to the Portland Harbor Superfund Site.

In February 2002, PGE provided a report on its remedial investigation of the Harborton site to the Oregon Department of Environmental Quality (DEQ). The report concluded 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 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 report to the EPA and, in a May 18, 2004 letter, the EPA notified the DEQ that, based on the summary information from the DEQ and the stage of the process, the EPA, as of that time, agreed, the Harborton site does not appear to be a current source of contamination to the river.

In December 6, 2005 letter, the DEQ notified PGE 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 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 condition, results of operations or cash flows.

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 biphenyls (PCBs), have been detected at the site. On September 29, 2003, following investigation and site assessment by the EPA, 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 started 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. PGE, along with other PRPs, is negotiating an Administrative Order of Consent with the EPA to conduct a Remedial Investigation/Feasibility Study.

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 condition, results of operations or cash flows.

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, carbon monoxide, and particulate matter. PGE manages its emissions by the use of low sulfur fuel, emission controls, emission monitoring, and combustion controls. Required operating permits have been obtained for all thermal generating facilities operated by PGE.

In May 2005, the 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 had the choice of adopting this model or establishing their own programs.

In October 2006, the Montana Board of Environmental Review adopted final rules on mercury emissions from coal-fired generating units in Montana, including Colstrip, which 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 have been submitted to the EPA for review and determination of their compliance with CAMR requirements. PGE has a 20% ownership interest in Colstrip Units 3 and 4.

In December 2006, the Oregon Environmental Quality Commission adopted the Utility Mercury Rule, which limits mercury emissions from new coal-fired power plants in Oregon and requires installation of mercury technology on the Boardman plant and requires the plant to reduce its mercury emission by 90% by July 1, 2012. The rules allow limited mercury allowance trading up to 2018, after which no trading will be allowed. The rules have been submitted to the EPA for review and determination of compliance with the CAMR requirements.

On June 15, 2005, the EPA issued final amendments to its July 1999 Regional Haze Rule. The rule establishes goals to protect visibility and remedy existing impairments resulting from man made pollution. The revised guidelines require determinations of eligibility with respect to SO₂, nitrogen oxides, and particulate emissions. States must develop implementation plans by December 2007.

While it is not yet known what ultimate impact the federal and state regulations on air quality standards will have on future operations, operating costs, or generating capacity of PGE's thermal generating plants, the Company estimates that the capital cost (in 2006 dollars) to meet regional haze rules and install mercury controls at Boardman could be approximately $200 million - $300 million (100% of total project costs). PGE will seek to recover its share of such costs through the ratemaking process.

Boardman and Beaver -The SO₂ emissions allowances awarded under the CAA, along with expected future annual allowances, are sufficient to operate Boardman at a 60% to 67% capacity. PGE has acquired additional emissions allowances, which, in combination with the allowance awards, will allow the operation of Boardman at forecasted capacity for at least the next ten years.

In accordance with 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. Those sources determined to cause, or contribute to, visibility impairment at protected areas will be subject to an RH BART Determination. 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. 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. An exemption modeling analysis for identified sources, which began in September 2006, has indicated that the Boardman and Beaver generating plants may cause or contribute to visibility impairment in several protected areas.

Colstrip Plant - PPL Montana, LLC (PPL Montana), the operator of Colstrip Units 3 and 4, and the EPA are discussing possible emission control and monitoring requirements involving all Colstrip units to address certain issues that have arisen since late 2003, including those related to the CAA. Current emissions allowances are sufficient to operate Colstrip, which utilizes wet scrubbers.

In December 2003, PPL Montana received an Administrative Compliance Order from the EPA pursuant to the CAA. The EPA alleges that since 1980, Colstrip Units 3 and 4 have been in violation of the clean air permit issued under the CAA. The permit requires that Colstrip Units 3 and 4 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.

Pursuant to negotiations between PPL Montana, Colstrip owners, the EPA, and the Northern Cheyenne Tribe, an agreement has been reached to resolve the above matter, with a consent decree filed on March 19, 2007 with the U.S. District Court for the District of Montana. The consent decree is subject to a 30-day public comment period. Under the terms of the agreement, PPL Montana and the Colstrip owners will pay a non-material civil penalty to the U.S. Treasury and will implement a residential energy efficiency project valued at $100,000 on behalf of the Northern Cheyenne Tribe. The settlement requires that Colstrip Units 3 and 4 reduce NO_x emissions by approximately 55 percent. PGE anticipates that its share of the capital improvements and other costs will total approximately $5.8 million, which it will seek to recover through the ratemaking process.

Stock-Based Compensation

On March 15, 2007, PGE granted Restricted Stock Units and/or Performance Stock Units (Stock Units) to officers and certain key employees. A grant of Restricted Stock Units was awarded to a new non-employee director on the same date. 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.

For the quarter ended March 31, 2007, PGE recorded $1 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 $5.6 million at March 31, 2007, of which $1.9 million, $2.5 million and $1.2 million is expected to be expensed during the remainder 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.

New Accounting Standards

SFAS No. 157, Fair Value Measurements, was issued in September 2006 and is effective for fiscal years beginning after November 15, 2007. SFAS No. 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 No. 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 No. 157 with respect to its assets and liabilities.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, was issued in February 2007 and is effective for fiscal years beginning after November 15, 2007. SFAS No. 159 provides entities the option to report most financial assets and liabilities at fair value, with changes in fair value recorded in earnings. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. PGE is evaluating the application of SFAS No. 159 with respect to its financial assets and liabilities.

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:

• 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 the effects of Oregon law related to utility rate treatment of income taxes (SB 408), resulting in potential earnings volatility and adverse effects on operating results;
• events related to City of Portland, Oregon investigations with regard to rates charged by the Company, and any attempt by the City of Portland to set rates for PGE customers located within the City of Portland;
• 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 major generating plants 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;
• the timing of the distribution or sale of the PGE common stock currently held by the DCR;
• 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;
• new federal, state, and local laws that could have adverse effects on operating results;
• 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 quarter of 2007 were $5.1 million, $6.5 million, and $3.6 million, respectively, and in the first q uarter of 2006 were $7.9 million, $10.0 million, and $5.7 million, respectively.

In 2006, PGE adopted a "medium term" power cost strategy to better respond to changing energy market conditions. By extending the period in which the Company may take positions in power markets from 24 months to up to five years, PGE expects to reduce price volatility for its customers during the next three- to five-year period. Accordingly, PGE has amended its risk limits for the projected impact of the medium term strategy on the Company's net open position.

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 March 31, 2007, 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 March 31, 2007, PGE had $29 million 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 March 31, 2007, 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 March 31, 2007. 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		2007		2008		2009		2010		2011		After 2011
Investment Grade	$	65	88%	$	30	$	22	$	17	$	14	$	2	$	2	$	8
Non-Investment Grade		1	1%		1		1		-		-		-		-		-
Internally Rated - Investment Grade		8	10%		-		8		-		-		-		-		-
Internally Rated - Non-Investment Grade		1	1%		-		1		-		-		-		-		-
Total	$	75	100%	$	31	$	32	$	17	$	14	$	2	$	2	$	8

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 Condensed Consolidated 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 2006 Annual Report on Form 10-K.

City of Tacoma, Department of Public Utilities, Dreyer, Light division v. American Electric Power Service Corporation, Quila Holdings, LLC, Aquila Power Corporation, Arizona Public Service Company, Automated Power Exchange, Inc., Avista Corporation, et. al., United States District Court for the Western District of Washington, Case No. C07-5325 RBL.

An appeal filed with the U.S. Ninth Circuit Court of Appeals on March 10, 2005 was dismissed on March 20, 2007, pursuant to the stipulation of the parties.

Portland General Electric Company vs. City of Portland, Multnomah County Circuit Court for the State of Oregon, Declaratory Complaint Case No. 0604-04242, Writ Case No. 0604-04243.

The trial date in this case has been moved from April 2007 to September 2007 and the parties have been ordered to mediation.

Citizens' 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, the Court of Appeals of the State of Oregon, the Oregon Supreme Court.

In Order No. 07-157 (the Order) entered on April 19, 2007, the OPUC denied PGE's motion with the OPUC to Consolidate Phases and Re-Open the Record. In addition, the Order abated the Phase I proceeding pending a decision by the Oregon Court of Appeals of the 2003 Remand, and ordered that a second phase of the joint remand proceedings be immediately commenced to investigate the OPUC's delegated authority to engage in retroactive ratemaking. The Order further stated that parties not now participating in the joint remand proceedings will be allowed to intervene and participate in the second phase. A prehearing conference is set for May 9, 2007 to establish a briefing schedule.

Portland General Electric Company v. International Brotherhood of Electrical Workers, Local No. 125 (Union Grievances)

On April 24, 2007, the Oregon Supreme Court denied IBEW's petition for review.

Item 1A.Risk Factors

There have been no material changes to PGE's risk factors set forth in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2006.

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 Fourth Amended and Restated Bylaws [Form 8-K filed November 20, 2006, Exhibit (3.1)].

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

4.1 * Fifty-eighth Supplemental Indenture dated April 1, 2007 [Form 8-K filed April 12, 2007, Exhibit (4)].

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 of securities 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.

(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.

SIGNATURE

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

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

Date	May 3, 2007	By:	/s/ James J. Piro
			James J. Piro Executive Vice President, Finance Chief Financial Officer and Treasurer (duly authorized and principal financial officer)