Edgar Filing: PORTLAND GENERAL ELECTRIC CO /OR/

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2008
		OR
¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission File Number: 1-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Oregon

93-0256820

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨		Smaller reporting company ¨

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, 2008 is 62,532,232 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2008

TABLE OF CONTENTS


		Page Number
Definitions		3

PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements.

	Condensed Consolidated Statements of Income	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	39

Item 4.	Controls and Procedures.	39

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.	40

Item 1A.	Risk Factors.	41

Item 5.	Other Information.	41

Item 6.	Exhibits.	42

SIGNATURE		43

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:


Abbreviation or Acronym		Definition
AFDC		Allowance for funds used during construction
Beaver		Beaver generating plant
Biglow Canyon		Biglow Canyon Wind Farm
Boardman		Boardman coal plant
BPA		Bonneville Power Administration
CERS		California Energy Resources Scheduling
Colstrip		Colstrip Units 3 and 4 coal plant
Coyote Springs		Coyote Springs Unit 1 generating plant
CUB		Citizens’ Utility Board
DEQ		Oregon Department of Environmental Quality
EITF		Emerging Issues Task Force of the Financial Accounting Standards Board
EPA		U.S. Environmental Protection Agency
ESS		Electricity Service Supplier
FERC		Federal Energy Regulatory Commission
IRP		Integrated Resource Plan
ISFSI		Independent Spent Fuel Storage Installation
kWh		Kilowatt hour
MW		Megawatt
MWa		Average megawatts
MWh		Megawatt hour
NVPC		Net Variable Power Costs
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
Port Westward		Port Westward generating plant
SB 408		Oregon Senate Bill 408
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards (issued by the Financial Accounting Standards Board)
Trojan		Trojan Nuclear Plant
URP		Utility Reform Project

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2008		2007

Revenues	$	471	$	436

Operating expenses:
Purchased power and fuel		250		203
Production and distribution		39		32
Administrative and other		47		45
Depreciation and amortization		50		45
Taxes other than income taxes		22		21

Total operating expenses		408		346

Income from operations		63		90

Other income (expense):
Allowance for equity funds used during construction		2		5
Miscellaneous income (expense)		(3)		4

Other income (expense)		(1)		9
Interest expense		23		17

Income before income taxes		39		82
Income taxes		11		27

Net income	$	28	$	55


Weighted-average shares outstanding (in thousands):
Basic		62,530		62,505

Diluted		62,571		62,525


Earnings per share - basic and diluted	$	0.44	$	0.88


Dividends declared per share	$	0.235	$	0.225

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)


	March 31, 2008		December 31, 2007

ASSETS

Current assets:
Cash and cash equivalents	$	51	$	73
Accounts and notes receivable, net		233		178
Unbilled revenues		79		92
Assets from price risk management activities		202		64
Inventories, at average cost		60		64
Other current assets		53		67

Total current assets		678		538
Electric utility plant, net		3,147		3,066
Other property and investments:
Nuclear decommissioning trust		46		46
Non-qualified benefit plan trust		63		69
Miscellaneous		17		19

Total other property and investments		126		134
Regulatory assets		252		304
Other noncurrent assets		66		66

Total assets	$	4,269	$	4,108


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	273	$	227
Liabilities from price risk management activities		99		101
Other current liabilities		49		40
Deferred income taxes		40		-
Accrued taxes		28		23

Total current liabilities		489		391
Long-term debt		1,256		1,313
Regulatory liabilities		727		574
Deferred income taxes		234		279
Non-qualified benefit plan liabilities		88		86
Accumulated asset retirement obligations		88		91
Other noncurrent liabilities		57		58

Total liabilities		2,939		2,792
Commitments and contingencies (see notes)
Shareholders’ equity:
Common stock, no par value, 80,000,000 shares authorized; 62,532,232 and 62,529,787 shares issued and outstanding as of March 31, 2008 and December 31, 2007, respectively		647		646
Accumulated other comprehensive loss		(4)		(4)
Retained earnings		687		674

Total shareholders’ equity		1,330		1,316

Total liabilities and shareholders’ equity	$	4,269	$	4,108

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Three Months Ended March 31,
	2008		2007

Cash flows from operating activities:
Net income	$	28	$	55
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		50		45
Net assets from price risk management activities		(141)		(41)
Regulatory deferral - price risk management activities		141		41
Deferred income taxes		10		5
Senate Bill 408 deferrals		3		-
Allowance for equity funds used during construction		(2)		(5)
Power cost deferrals		-		(23)
Other non-cash income and expenses, net		11		(5)
Changes in working capital:
Net margin deposit activity		22		38
Increase in receivables		-		(1)
Increase in payables		13		23
Other working capital items, net		(13)		(14)
Other, net		(5)		4

Net cash provided by operating activities		117		122

Cash flows from investing activities:
Capital expenditures		(71)		(67)
Sales of nuclear decommissioning trust securities		7		6
Purchases of nuclear decommissioning trust securities		(6)		(7)
Insurance proceeds		3		-
Other, net		(1)		(1)

Net cash used in investing activities		(68)		(69)

Cash flows from financing activities:
Payments on long-term debt, net of issuance costs		(56)		-
Payments on short-term debt, net		-		(52)
Dividends paid		(15)		(14)
Proceeds from issuance of long-term debt		-		6

Net cash used in financing activities		(71)		(60)

Decrease in cash and cash equivalents		(22)		(7)
Cash and cash equivalents, beginning of period		73		12

Cash and cash equivalents, end of period	$	51	$	5


Supplemental cash flow information is as follows:
Cash paid during the period for interest, net of amounts capitalized	$	12	$	10
Non-cash investing and financing activities:
Accrued capital additions		71		23
Accrued dividends payable		15		14

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power and fuel marketers located throughout the western United States. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. The Company served approximately 808,000 retail customers as of March 31, 2008.

As of March 31, 2008, PGE had 2,724 employees, with 869 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 838 and 31 employees for the five-year periods ending February 28, 2009 and August 1, 2011, respectively.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein for the three months ended March 31, 2008 and 2007 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated results of operations and condensed consolidated cash flows of the Company for these interim periods. 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. The financial information as of December 31, 2007 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2007, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 27, 2008, and should be read in conjunction with such consolidated financial statements.

Use of Estimates

The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of contingent liabilities, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

Reclassifications

Certain reclassifications have been made to the 2007 financial information to conform to the 2008 presentation. These reclassifications include the presentation of income tax expense of $27 million as one caption in the condensed consolidated statement of income for the three months ended March 31, 2007, of which $26 million was previously reported in operating expenses and $1 million was previously reported in other income (deductions), and the inclusion of long-term debt of $1,313 million in total liabilities in the condensed consolidated balance sheet as of December 31, 2007, which was previously reported in total capitalization. Additionally, the allowance for equity funds used during construction of $5 million was previously classified within other non-cash income and expenses, net in the condensed consolidated statement of cash flows for the three months ended March 31, 2007.

Recent Accounting Pronouncements

Adopted Accounting Pronouncements

On January 1, 2008, PGE adopted Statement of Financial Accounting Standards No. (SFAS) 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. In February 2008, Financial Accounting Standards Board (FASB) Staff Position 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2) was issued. FSP 157-2 delays the adoption of SFAS 157 for nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008, or January 1, 2009 for PGE. SFAS 157 does not modify any currently existing accounting pronouncements. PGE applies fair value measurements to certain assets and liabilities, including assets and liabilities from price risk management activities. The adoption of SFAS 157 did not have a material impact on the Company’s consolidated financial position or consolidated results of operations. For additional information, see Note 3.

On January 1, 2008, PGE adopted SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115 (SFAS 159), which allows eligible financial assets and liabilities to be measured at fair value that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item are reported in earnings at each reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the Company elects for similar types of assets and liabilities. The Company elected not to measure eligible financial assets and liabilities at fair value that were not otherwise measured at fair value. The adoption of SFAS 159 had no impact on PGE’s consolidated financial position or consolidated results of operations.

On January 1, 2008, PGE adopted FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39 (FSP FIN 39-1), which permits reporting entities to offset the receivable or payable recognized for derivative instruments that have been offset under a master netting arrangement. FSP FIN 39-1 requires financial statement disclosure of a reporting entity’s accounting policy (to offset or not to offset), as well as amounts recognized for the right to reclaim cash collateral, or the obligation to return cash collateral, that have been offset against net derivative positions. PGE elects to continue to not offset its exposures under master netting arrangements in accordance with FSP FIN 39-1, and therefore elects not to offset any fair value amounts recognized for the right to claim cash collateral or the obligation to return cash collateral against its derivative positions. The adoption of FSP FIN 39-1 did not have a material impact on PGE’s consolidated financial position or consolidated results of operations.

On January 1, 2008, PGE adopted Emerging Issues Task Force (EITF) Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11), which was ratified by

the EITF at its June 27, 2007 meeting and clarifies how an entity should recognize the income tax benefit received on dividends that are (1) paid to employees holding equity-classified nonvested shares and (2) charged to retained earnings under SFAS 123R, Share-Based Payment. EITF 06-11 is applied prospectively to the income tax benefits that result from dividends on equity-classified employee share-based payment awards declared in fiscal years beginning after December 15, 2007, and interim periods within those fiscal years. The adoption of EITF 06-11 did not have a material impact on PGE’s consolidated financial position or consolidated results of operations.

New Accounting Pronouncement

In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161), which requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for annual and interim periods beginning after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will not have an impact on PGE’s consolidated financial position or consolidated results of operations.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts and Notes Receivable, Net

As of March 31, 2008, the Company has a receivable from Bonneville Power Administration (BPA) in the amount of $43 million related to the Residential Exchange Program, which is included in accounts and notes receivable, net in the condensed consolidated balance sheet. The Company collected this receivable in April 2008, at which time the proceeds were placed in restricted cash accounts to be held until the corresponding credits to customers, net of $9 million previously provided, are completed. Monthly billing credits to customers began April 15, 2008.

Accounts and notes receivable is net of an allowance for uncollectible accounts of $5 million as of March 31, 2008 and December 31, 2007.

The following is the change in the allowance for uncollectible accounts (in millions):


	Three Months Ended March 31,
	2008		2007

Balance at beginning of period	$	5	$	45
Provision		1		(5)
Amounts written off, less recoveries		(1)		(1)

Balance at end of period	$	5	$	39

Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):


	March 31, 2008		December 31, 2007

Production	$	1,945	$	1,944
Transmission		328		329
Distribution		2,211		2,184
General		255		252
Intangible		194		189
Construction work in progress		202		126

Total cost		5,135		5,024
Less: accumulated depreciation and amortization		(1,988)		(1,958)

Electric utility plant, net	$	3,147	$	3,066

In March 2008, the Company entered into purchase agreements for capital expenditures in an aggregate amount of $589 million, of which $74 million and $17 million are reflected in Construction work in progress in the table above as of March 31, 2008 and December 31, 2007, respectively.

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $100 million and $96 million as of March 31, 2008 and December 31, 2007, respectively. Amortization expense related to intangible assets was $4 million for each of the three month periods ended March 31, 2008 and 2007.

Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):


	March 31, 2008		December 31, 2007

Regulatory assets:
Income taxes recoverable	$	85	$	87
Pension and other postretirement plans		57		57
Boardman power cost deferral		32		31
Debt reacquisition costs		30		28
Oregon Senate Bill 408 - 2007		15		16
Trojan decommissioning costs		13		16
Price risk management		-		37
Other		20		32

Total regulatory assets	$	252	$	304


Regulatory liabilities:
Accumulated asset retirement removal costs	$	463	$	451
Price risk management		103		-
Oregon Senate Bill 408 - 2006 and 2008		45		42
Residential Exchange Program		34		-
Asset retirement obligations		27		28
Power Cost Adjustment Mechanism		17		16
Trojan ISFSI pollution control tax credits		14		13
Other		24		24

Total regulatory liabilities	$	727	$	574

Credit Facility and Long-term Debt

PGE has a $400 million unsecured revolving credit facility (Credit Facility) with a group of commercial and investment banks. The Credit Facility, which expires in 2012, is available for general corporate purposes, with the maximum amount available to PGE for borrowings and/or the issuance of standby 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 Credit Facility. The Credit Facility provides that all outstanding loans mature on the termination date of the Credit Facility, provided that annually such date may be extended for an additional year for those lenders who agree to an extension. The Credit Facility requires annual fees based on PGE’s unsecured credit rating, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the Credit Facility agreement, to 65% of total capitalization. As of March 31, 2008, PGE was in compliance with this covenant.

The Company has a $400 million commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the Credit Facility. As of March 31, 2008, PGE had no commercial paper outstanding and had utilized $14 million in letters of credit, with $386 million of remaining borrowing capacity available.

On January 17, 2008, the Federal Energy Regulatory Commission (FERC) issued an order which authorizes the Company to issue short-term debt, including commercial paper, in an amount not to exceed $550 million outstanding at any one time, over the two-year period February 7, 2008 through February 6, 2010. The FERC’s order extended and increased its previous authorization, which covered the period February 8, 2006 through February 7, 2008 and authorized the issuance of up to $400 million in short-term debt.

PGE’s 5.6675% series First Mortgage Bonds, due 2012, with $100 million outstanding as of March 31, 2008, are insured under an agreement with a bond insurer. The insurance agreement requires that PGE maintain a common equity percentage of not less than 45%. The Company was in compliance with this requirement as of March 31, 2008.

During the first quarter of 2008, PGE repurchased and retired $50 million of its 5.279% series First Mortgage Bonds due 2013 and on April 15, 2008, the Company issued $50 million of 4.45% series First Mortgage Bonds due April 1, 2013. Additionally, during the first quarter of 2008, the Company repurchased $5.8 million of its Port of Morrow variable rate pollution control revenue bonds due 2031.

Pension and Other Postretirement Benefits

The following table provides the components of net periodic benefit cost (income) for the three months ended March 31 (in millions):


	Defined Benefit Pension Plan				Non-Qualified Benefit Plans				Other Benefits
	2008		2007		2008		2007		2008		2007

Service cost	$	3	$	3	$	-	$	-	$	-	$	-
Interest cost		7		7		-		-		1		1
Expected return on plan assets		(11)		(10)		-		-		-		-
Actual return on plan assets		-		1		2		-		-		-

Net periodic benefit cost (income)	$	(1)	$	1	$	2	$	-	$	1	$	1

NOTE 3: FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Company adopted SFAS 157, which requires, among other things, enhanced disclosures about assets and liabilities carried at fair value on a recurring basis. Pursuant to FSP 157-2, PGE will adopt SFAS 157 with respect to its nonfinancial assets and liabilities, which include asset retirement obligations, on January 1, 2009.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. However, as permitted under SFAS 157, PGE utilizes a mid-market pricing convention, the mid-point price between bid and ask prices, as a practical expedient for valuing the majority of its financial instruments.

Level 1- Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2 - Pricing inputs are other than quoted market prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter (OTC) forwards and swaps.

Level 3 - Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

The Company’s financial assets and liabilities whose fair values were accounted for on a recurring basis are as follows by level within the fair value hierarchy (in millions):


	As of March 31, 2008
	Level 1		Level 2		Level 3		Total

Assets:
Nuclear decommissioning trust *	$	46	$	-	$	-	$	46
Non-qualified benefit plan trust		41		-		-		41
Assets from price risk management activities *		-		142		60		202

	$	87	$	142	$	60	$	289

Liabilities - Liabilities from price risk management activities *	$	-	$	78	$	21	$	99

*	Activities are subject to regulation and, accordingly, gains and losses are deferred pursuant to SFAS 71 and included in regulatory assets or regulatory liabilities as appropriate.

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Nuclear decommissioning trust assets reflect the assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) and consist primarily of fixed income securities. Non-qualified benefit plan trust reflects the assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and consist primarily of marketable securities. These assets also include investments recorded at cash surrender value which are excluded from the table above as they are not subject to SFAS 157. Assets and liabilities from price risk management represent derivative transactions entered into by PGE to manage its exposure to commodity price risk and minimize

net power costs for service to the Company’s retail customers and may consist of forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas.

Changes in the fair value of assets and liabilities from price risk management activities classified as Level 3 in the fair value hierarchy were as follows for the three months ended March 31 (in millions):


	2008

Balance as of January 1, 2008	$	1
Net realized and unrealized gains		37
Purchase, issuances and settlements, net		1

Balance as of March 31, 2008	$	39

Net realized and unrealized gains are included in Purchased power and fuel in the condensed consolidated statement of income, which includes $34 million in net unrealized gains, which have been fully offset by the effects of regulatory accounting pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation.

NOTE 4: EARNINGS PER SHARE

Components of basic and diluted earnings per share were as follows:


	Three Months Ended March 31,
	2008		2007

Numerator (in millions):
Net income available for common shareholders	$	28	$	55


Denominator (in thousands):
Weighted-average common shares outstanding - basic		62,530		62,505
Dilutive effect of restricted stock units and employee stock purchase plan shares		41		20

Weighted-average common shares outstanding - diluted		62,571		62,525


Earnings per share - basic and diluted	$	0.44	$	0.88

Unvested performance stock units and related dividend equivalent rights are not included in the computation of dilutive securities because vesting of these instruments is dependent upon three-year performance periods.

Basic and diluted earnings per share amounts are calculated based on actual amounts. Accordingly, basic and diluted earnings per share amounts as presented in the table above and on the condensed consolidated statements of income may not necessarily recalculate based on the rounded amounts presented for both net income and weighted-average shares outstanding.

NOTE 5: PRICE RISK MANAGEMENT

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 and natural gas purchases and sales resulting from economic dispatch decisions for its own generation, which allows PGE to secure reasonably priced power for its customers. PGE utilizes derivative instruments, which may include forward, swap, and option contracts for electricity and natural gas, and futures contracts for natural gas, in its retail electric utility activities to manage its exposure to commodity price risk and to minimize net power costs. Under SFAS 133, derivative instruments are recorded at estimated fair value on the balance sheet as an asset or liability unless they qualify for the normal purchase, normal sale exception, with changes in estimated fair value recognized currently in earnings, unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows gains and losses on a derivative instrument to be recorded in comprehensive income until they can offset the related results on the hedged item in net income. The derivative instruments entered into to manage the Company’s future retail resource requirements are subject to regulation; accordingly, the unrealized gains and losses are deferred pursuant to SFAS 71 in both net income and comprehensive income.

PGE has elected to affirm its ongoing policy not to net on the balance sheet the positive and negative exposures resulting from derivative instruments entered into with counterparties where a master netting arrangement exists pursuant to FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.

Most of PGE’s 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 referred to as “book outs.” Only the net amount of those purchases or sales required to fulfill retail and wholesale obligations and physically delivered is recorded in Wholesale sales and Purchased power and fuel expense.

Changes in the fair value of retail derivative instruments prior to settlement that do not qualify for either the normal purchases and normal sales 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 Revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel expense. PGE records the non-physical settlement of electricity derivative activities on a net basis in Purchased power and fuel expense, in accordance with EITF 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No 02-3, as none of PGE’s derivative activities are executed for trading purposes.

During the three months ended March 31, 2008 and 2007, unrealized gains from derivative activities of $141 million and $41 million, respectively, were recorded in net income, fully offset by the recognition of SFAS 71 regulatory liabilities of $141 million and $41 million, respectively.

In 2007, PGE elected to discontinue hedge accounting for the Company’s remaining outstanding derivatives designated as cash flow hedges, in accordance with SFAS 133, which did not have a material impact on the Company’s consolidated financial position or consolidated results of operations.

Net unrealized gains of $4 million, which are fully offset by SFAS 71 regulatory accounting, will settle over the next 42 months. Of this amount, the Company estimates that substantially all of the $4 million will be reclassified into earnings within the next twelve months, fully offset by SFAS 71 regulatory accounting. These net unrealized gains, fully offset by SFAS 71 regulatory accounting, are included in Accumulated other comprehensive loss in the condensed consolidated balance sheet as of March 31, 2008.

The following table reflects derivative activities from cash flow hedges recorded in comprehensive income, before taxes (in millions):


	Three Months Ended March 31,
	2008		2007

Other unrealized holding net gains arising during the period	$	-	$	5
Reclassification to net income for contract settlements		-		(7)
Reclassification of unrealized losses to SFAS 71 regulatory asset		-		2

Net unrealized gains	$	-	$	-

NOTE 6: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):


	Three Months Ended March 31,
	2008		2007

Net income	$	28	$	55
Unrealized gains (losses) on cash flow hedges:
Other unrealized holding gains arising during the period, net of taxes of ($2) in 2007		-		3
Reclassification to net income for contracts settlements, net of taxes of $3 in 2007		-		(4)
Reclassification of unrealized losses to SFAS 71 regulatory asset, net of taxes of ($1) in 2007		-		1

Total unrealized gains on cash flow hedges		-		-

Pension and other postretirement plans’ funded position, net of taxes of $1 in 2007		-		(1)
Reclassification of defined benefit pension plan and other benefits to SFAS 71 regulatory asset, net of taxes of ($1) in 2007		-		1

Comprehensive income	$	28	$	55

NOTE 7: CONTINGENCIES

Legal Matters

Trojan Investment Recovery

Background. In 1993, PGE closed the Trojan Nuclear Plant as part of the Company’s 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 Public Utility Commission of Oregon (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.

Court Proceedings on OPUC Authority to Grant Recovery of Return on Trojan Investment. 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).

Settlement of Court Proceedings on OPUC Authority. 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 Corp. The settlement 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 was substantially recovered from PGE customers by the end of 2006. After offsetting the investment in Trojan with these credits and prior tax benefits, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan is no longer included in prices 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.

Challenge to Settlement of Court Proceeding. 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 prices or order refunds (2003 Remand). The opinion does not specify the amount or timeframe of any reductions or refunds. PGE and the OPUC appealed the 2003 Remand to the Oregon Court of Appeals. On October 10, 2007, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration because the 2002 Order was based, in part, on an incorrect understanding of Section 757.225 of the Oregon Revised Statutes. The Oregon Court of Appeals also vacated the 2003 Remand finding error in the Circuit Court’s specific instructions to the OPUC to revise the rate structure.

Remand of 2002 Order. As a result of the Oregon Court of Appeals remand of the 2002 Order, the OPUC is considering the following issues:

—

What prices would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment; and

—

Whether the OPUC has authority to engage in retroactive ratemaking.

On January 14, 2008, the plaintiffs in the class action proceedings described below filed a motion asking the OPUC to issue an order on the OPUC’s remedial authority prior to addressing the other issues and the URP permission to address all issues it previously raised on appeal to the Circuit Court and on cross-appeal to the Court of Appeals in URP, et al. v. PUC, with an opportunity to present new evidence with full evidentiary hearings. On February 13, 2008, the OPUC issued an order denying this motion. In the order, the OPUC expressed its desire to avoid future piecemeal litigation by resolving all of these issues in one comprehensive order, including the issue of the OPUC’s remedial authority. The OPUC further stated that it has come to the preliminary conclusion that the OPUC has refund authority under limited circumstances. The OPUC emphasized that this is a preliminary determination and stated that it has not yet determined whether it is necessary to exercise that authority in this case and that it cannot make such a determination until it has decided all phases of the proceedings. On February 22, 2008, the administrative law judge issued a Ruling and Notice of Conference, which established the scope for further proceedings prior to issuance of the OPUC order.

On March 12, 2008, the administrative law judge established a procedural schedule for the remainder of the proceedings before the OPUC relating to PGE’s recovery of its investment in the Trojan plant. The schedule indicates an expected OPUC order on September 12, 2008.

Class Actions. 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 plus interest for the Current Class and $70 million plus interest for the Former Class, as a result of the inclusion of a return on investment of Trojan in the prices 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, 2005, 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 price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1995 through October 2000. The Oregon 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 Oregon 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, but inviting motions to lift the abatement after one year. On October 17, 2007, the plaintiffs filed a motion to lift the abatement. A hearing on this motion was held on April 10, 2008. At the hearing, the Circuit Court declined to lift the abatement. The Circuit Court scheduled a status conference for June 3, 2008 and encouraged the parties to meet in order to attempt to agree on what steps might be taken in preparation for a trial in the event the Circuit Court lifts the abatement following the OPUC order expected on September 12, 2008.

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.

Regulatory Matters

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 coal plant (Colstrip), 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 (USDI) 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 USDI. 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 USDI. In late September 2006, WECO received an additional order from the Office of Minerals Revenue Management to report and pay additional royalties for the period January 2002 through December 2004. On September 12, 2007, the Interior Board of Land Appeals issued a decision affirming the March 28, 2005 MMS decision. WECO has filed a Complaint for Declaratory and Injunctive Relief with the U.S. District Court for the District of Columbia challenging the decision of the Interior Board of Land Appeals.

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 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. PGE believes that the owners of Colstrip have reasonable defenses in this matter. However, if the USDI and Montana Department of Revenue prevail, and WECO were to prevail in seeking reimbursement from the owners, PGE’s share of the royalties and taxes owed, plus interest and future royalty and tax expenses related to coal transportation, would be 20 percent. If WECO were successful in passing all of these costs to the owners of Colstrip, PGE estimates that its share of the royalties, taxes and interest alleged by the USDI and Montana Department of Revenue through March 31, 2008 would be approximately $8 million.

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, PGE does not expect that these issues will have a material adverse effect on its financial condition, but may have a material adverse impact on the results of operations and cash flows in a future reporting period. If WECO is able to pass any of these costs on to the owners, the Company would likely seek recovery through the ratemaking process. However, there can be no assurance that such recovery would be granted.

Refunds on Wholesale Market Transactions

Pacific Northwest Refund Proceeding. On July 25, 2001, the FERC 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 (Pacific Northwest Refund proceeding). 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 November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision on appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest Refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC (i) to address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) to include sales to CERS in its analysis, and (iii) to further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and declined to reach the merits of the FERC’s ultimate decision to deny refunds. Two requests for rehearing have been filed with the court, with a decision now pending.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, (California Refund case) et seq., approved by the FERC on May 17, 2007, resolves all claims as between PGE and the California parties named in the settlement as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001, but does not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The Lockyer Case. In a separate but potentially related action, in 2002, the California Attorney General filed a complaint (the Lockyer case) 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. Upon appeal of the FERC’s refusal to order refunds pursuant to the complaint, the Ninth Circuit remanded the case for further proceedings at the FERC to determine whether refunds should be ordered due to failure of parties to file correct and timely quarterly reports. PGE settled the Lockyer case with the California Attorney General and other California parties as part of its previously reported comprehensive settlement of the California Refund and related cases, which settlement became effective on May 17, 2007.

On December 10, 2007, the California Attorney General and others filed with the FERC a motion to suspend any Lockyer remand proceedings until the court issues mandates in the California Refund case and Pacific Northwest Refund proceeding on the basis that all three cases include similar parties and similar issues. They indicated their intent to file a motion to consolidate all three cases upon remand of the two that remain pending rehearing before the Ninth Circuit.

On March 21, 2008, the FERC issued an order on remand (Remand Order) that denied the California parties’ motion to suspend the Lockyer remand proceedings and set the case for further proceedings. On April 15, 2008, pursuant to a request for clarification filed by parties, including PGE, who had previously settled the Lockyer case with the California Attorney General and other California parties, the FERC issued an order that dismissed PGE from the Lockyer remand proceeding, which relates solely to California markets.

remands by the Ninth Circuit of the California Refund case and the Pacific Northwest proceeding. These California parties have not objected to the dismissal of PGE from the remand proceedings.

Although PGE is no longer a party to the Lockyer remand proceedings, future consolidation of the Lockyer case with the Pacific Northwest Refund proceeding, on remand, could increase the Company’s potential liability in the Pacific Northwest proceeding by extending the period for which other parties are requesting refunds back to May 1, 2000, or earlier.

Management cannot predict the outcome of the Pacific Northwest Refund proceeding or Lockyer remand, if it is ever consolidated with the Pacific Northwest Refund proceeding, or whether the FERC will order refunds in the Pacific Northwest, and if so, how such refunds would be calculated. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operations and cash flows in future reporting periods.

Complaint and Application for Deferral – Income Taxes

On October 5, 2005, the URP and Ken Lewis (together, the Complainants) filed a Complaint and an Application for Deferred Accounting with the OPUC alleging that, since the September 2, 2005 effective date of Oregon Senate Bill 408 (SB 408), PGE’s rates were not just and reasonable and were in violation of SB 408 because they contained approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any governmental entity. The Complaint and Application for Deferred Accounting requested that the OPUC order the creation of a deferred account for all amounts charged to customers 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. PGE contended that no adjustment for taxes may be made prior to the January 1, 2006 effective date of the automatic adjustment clause included in SB 408.

On August 14, 2007, the OPUC issued an order granting the Application for Deferred Accounting for the period from October 5, 2005 through December 31, 2005 (Deferral Period). The OPUC’s order also dismissed the Complaint, without prejudice, on grounds that it was superfluous to the Complainants’ request for deferred accounting. The order required that PGE calculate the amounts applicable to the Deferral Period, along with calculations of PGE’s earnings and the effect of the deferral on the Company’s return on equity. The order also provided that the OPUC would review PGE’s earnings at the time it considers amortization of the deferral. PGE understands that the OPUC will consider the potential impact of the deferral on PGE’s earnings over a relevant 12-month period, which will include the Deferral Period. On October 15, 2007, PGE filed a petition for judicial review with the Oregon Court of Appeals, seeking review of the OPUC’s August 14, 2007 order. The Court of Appeals granted PGE’s motion to stay the proceedings until May 31, 2008.

On December 1, 2007, PGE filed its report as required by the OPUC. In the report, PGE determined that (i) the amount of any deferral would be between zero and $26.6 million; (ii) a relevant 12-month period would be the 12-month period ended September 30, 2006; and (iii) PGE’s earnings over such period would preclude any refund. After consideration of these matters, the OPUC will determine whether a rate adjustment is required. The OPUC decision is expected by June 1, 2008.

Management cannot predict the ultimate outcome of this matter. However, based on information currently known to management, it believes this matter will not have a material adverse effect on PGE’s financial condition, results of operations or cash flows.

Environmental Matters

Portland Harbor

Since 1973, PGE has operated the Harborton Substation on land owned by the Company located near the Willamette River. A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a 5.5 mile segment of the river, known as the Portland Harbor Superfund Site, 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.

In December 2000, PGE received from the EPA a “Notice of Potential Liability” regarding the Harborton Substation facility. The notice listed sixty-eight companies in addition to PGE 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 Substation 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 that the Harborton Substation site does not appear to be a current source of contamination to the river.

In a December 6, 2005 letter, the DEQ notified PGE that the Harborton Substation site is not likely a current source of contamination to the river and that the site is a low priority for further action.

On January 22, 2008, PGE received a Section 104e Information Request from the EPA requiring the Company to provide information concerning its properties in or near the Portland Harbor Superfund Site, as well as several miles beyond the initial 5.5 mile segment of the river. PGE’s response is due May 16, 2008.

Sufficient information is currently not available to determine the total cost of any required investigation or remediation of the Portland Harbor 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.

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 (RI/FS) 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 an RI/FS of the Harbor Oil site. On May 31, 2007, an Administrative Order on Compliance was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site. The EPA has approved an RI/FS work plan. Site access agreements are being negotiated with surrounding properties and the site operator. On-site sampling began in April of 2008.

Sufficient information is currently not available to determine 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.

Other Matters

PGE is subject to other regulatory and legal proceedings that arise from time to time in the ordinary course of its business, which may result in adverse judgments against the Company. Although management currently believes that resolving such matters will not have a material adverse effect on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties and management’s view of these matters may change in the future.

NOTE 8: GUARANTEES

PGE enters into financial 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.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements relate to expectations, beliefs, plans, objectives for future operations, assumptions, business prospects, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “should,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” or similar expressions are intended to identify such 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 any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, 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 audits, investigations, and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, transmission of electricity, recovery of Net Variable Power Costs (NVPC) and capital investments, and current or prospective wholesale and retail competition;

•

the outcome of legal and regulatory proceedings and issues, including the Trojan Investment Recovery and the Pacific Northwest Refund proceeding, described in Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements;

•

unseasonable weather and other natural phenomena, which, in addition to affecting PGE’s customers’ demand for power, could have a serious impact on PGE’s ability and cost to procure adequate supplies of fuel or power to serve its customers;

•

operational factors affecting PGE’s power generation facilities, including outages, unplanned forced outages, hydro conditions, wind conditions, and disruption of fuel supply;

•

wholesale energy prices and their impact on the availability and price of wholesale power in the western United States;

•

residential, commercial, and industrial growth and demographic patterns in PGE’s service territory;

•

future laws, regulations, and proceedings that could affect the future operations of the Company’s thermal generating plants by imposing 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;

•

capital market conditions, including interest rate fluctuations, and changes in PGE’s credit ratings, which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;

•

the effectiveness of PGE’s risk management policies and procedures and the creditworthiness of customers and counterparties;

•

the failure to complete major generating plants on schedule and within budget;

•

the effects of Oregon law related to utility rate treatment of income taxes (SB 408), which may result in earnings volatility and adverse effects on results of operations;

•

changes in, and compliance with, environmental and endangered species laws and policies;

•

the effects of global warming or climate change, including changes in the environment that may affect energy costs or consumption and changes in laws or regulations related to greenhouse gas emissions that may increase the Company’s costs or affect its operations;

•

new federal, state, and local laws that could have adverse effects on operating results;

•

employee workforce factors, including aging, potential strikes, work stoppages, and the loss of key executives;

•

general political, economic, and financial market conditions;

•

the outcome of efforts to relicense the Company’s hydroelectric projects, as required by the FERC;

•

natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind, and fire;

•

acts of war or terrorism; and

•

financial or regulatory accounting principles or policies imposed by governing bodies.

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.

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, its Annual Report on Form 10-K for the year ended December 31, 2007, and other periodic and current reports filed with the SEC.

PGE continues to focus on its mission to be a company that its customers and communities can depend upon to provide electric service in a safe, responsible and reliable manner, with excellent customer service, at a reasonable price. The Company’s stated long-term goals are 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 active corporate responsibility.

Customers - During the first quarter of 2008, PGE served an average of 807,000 retail customers compared to an average of 795,000 during the first quarter of 2007, an increase of 1.5%. This customer growth, along with colder weather, resulted in a 4% increase in retail energy deliveries over the first quarter of 2007. On a weather adjusted basis, retail energy deliveries increased 1.0% from the first quarter of 2007. The state’s economy has slowed somewhat from last year due in part to higher oil and natural gas prices and a decline in the housing market. However, Oregon continued to perform better than the national economy, with an approximate 1% payroll growth in the first quarter of 2008. The state’s unemployment rate (seasonally adjusted) remained largely unchanged from the fourth quarter of 2007. The Company continues to project an approximate 1.9% increase in weather adjusted retail loads for 2008 due to higher commercial and industrial demand. Residential demand is expected to remain flat due to the slowing housing market as well as conservation and energy efficiency efforts.

Regulatory review of the Company’s general rate case and proposed tariffs, filed with the OPUC in late February 2008, is continuing under adopted procedural schedules that currently provide for new rates to become effective on January 1, 2009. The proposed 8.9% average price increase is the result of higher purchased power and fuel costs, increased investment in utility plant, and higher general expenses. Additional information regarding PGE’s general rate case filing, including copies of direct testimony and exhibits, is available on the Company’s Internet website at www.portlandgeneral.com. Information may also be obtained on the OPUC Internet website at www.puc.state.or.us.

In May 2008, the OPUC is expected to make a decision on the new tariff for PGE’s Advanced Metering Infrastructure (AMI) system, which will be deployed for residential and commercial customers. If approved, the tariff, to be effective from June 1, 2008 through December 31, 2010, would provide for recovery of the cost of the project, including over 800,000 new customer meters, as well as the net book value of the existing meters. PGE expects AMI to provide improved services as well as operational efficiencies and cost savings.

Power Supply - PGE utilizes its own generating resources as well as wholesale market purchases to meet the energy and capacity needs of its customers. PGE’s generating plants performed well in the first quarter of 2008, with overall plant availability at approximately 92% and provided about 66% of the Company’s retail load requirement. Energy from available hydro resources decreased 14% from the first quarter of 2007 primarily as a result of colder than normal weather, which has delayed snow melt. Current forecasts indicate continued near normal regional hydro conditions for 2008.

On March 31, 2008, the Company executed agreements to purchase 141 wind turbines to construct Phases II and III of Biglow Canyon. The completion of these two phases, with a combined installed capacity of

approximately 324 MW, will further increase the diversity of the Company’s generating resource portfolio while minimizing related environmental impacts. Completion of Phase II is expected in 2009 and Phase III in 2010 at an aggregate estimated cost of $740 million to $780 million, including allowance for funds used during construction (AFDC).

In its review of PGE’s June 2007 Integrated Resource Plan (IRP), the OPUC has stated that the Company’s proposed 218 MWa of renewable energy resources, in addition to Biglow Canyon, is reasonable. Accordingly, the Company has issued a Request For Proposals for 218 MWa of renewable resources. The OPUC has requested that PGE prepare additional long-term analysis to address resource decisions beyond 2012, which the Company plans to include in a revised IRP to be filed by October 2009. In preparing the revised IRP, the Company will further define its future energy and capacity needs.

Financing - PGE continues to maintain adequate liquidity through both its $400 million credit facility and access to the commercial paper market. In addition, the Company has authorization from the FERC to increase its short-term borrowing up to $550 million and received OPUC approval to issue an additional $250 million of First Mortgage Bonds, of which PGE issued $50 million of 4.45% First Mortgage Bonds on April 15, 2008, that mature April 2013. Also, during the first quarter of 2008, PGE repurchased and retired $50 million of its 5.279% First Mortgage Bonds and repurchased $5.8 million of its Port of Morrow, variable rate pollution control revenue bonds. The Port of Morrow bonds may be remarketed at a later date.

In addition to completion of the Biglow Canyon and AMI projects, planned capital needs through 2012 include those related to significant environmental controls for the Boardman coal plant (Boardman), hydro relicensing obligations, and upgrades to transmission, distribution and existing generation facilities to support both new and existing customers within the Company’s service territory. For further information regarding estimated future capital expenditures, see “Capital Requirements” in “Liquidity and Capital Resources” in this Item 2.

Legal, Regulatory and Environmental Matters - PGE is a party in certain proceedings that could have a material impact on the results of operations and cash flows in future reporting periods, including:

•

matters related to the OPUC’s authority to grant a return on the Company’s remaining investment in its closed Trojan plant, which the OPUC granted in a 1995 general rate order; and

•

claims for refunds related to wholesale energy sales in the Pacific Northwest during 2000 - 2001.

For further information regarding these and other matters, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

PGE is subject to state and federal environmental laws and regulations that establish air quality standards and regulate allowed emissions from thermal generating plants. Such laws and regulations, as well as federal regional haze rules that establish goals to protect visibility and remedy existing impairments resulting from man-made pollution, may affect the Company’s operations. While PGE anticipates that it will be able to comply with these standards and those imposed under the Clean Air Mercury Rule, such rules will require added costs for additional emission control equipment. In November 2007, the Company submitted to the Oregon DEQ its Best Available Retrofit Technology (BART) plan for implementing controls to meet the requirements. Final approval of the plan is expected to occur in the second half of 2009. For further information, see Air Quality Standards in “Capital Requirements” in “Liquidity and Capital Resources” in this Item 2.

As previously reported, PGE received a notice of intent to sue on January 15, 2008 from a coalition of environmental groups. The notice alleges violations of the Clean Air Act and the Oregon State

Implementation Plan relating to Boardman. The Company has not yet fully evaluated the claims referenced in the notice and cannot determine at this time its estimated exposure, if any. In April 2008, the environmental groups and PGE agreed to engage in good faith discussions to resolve the groups’ concerns without litigation.

Recently authorized rate actions that will affect future customer prices and/or revenues include:

—

A 6.3% average price decrease for residential and small farm customers, effective April 15, 2008, related to an agreement between PGE and BPA, as discussed below; and

—

A 1.4% average price decrease, reflecting SB 408 tax refunds related to the 2006 reporting year, in the amount of $37.2 million, plus interest. Such refunds, effective June 1, 2008, will take place over a two-year period.

On March 24, 2008, PGE and the BPA signed an Interim Relief agreement that temporarily restored federal hydropower benefits to the Company’s residential and small farm customers under the Residential Exchange Program administered by the BPA. Benefits under the Residential Exchange Program were suspended by the BPA in May 2007 as a result of a decision by the Ninth Circuit. Pursuant to the agreement, PGE received approximately $43 million from the BPA. PGE expects to refund the majority of this amount to customers by the end of 2008. The amount of future benefits will be determined in ongoing proceedings conducted by the BPA.

Pending rate matters that may affect future customer price and/or revenues include:

—

Refunds, in the amount of approximately $17 million, including accrued interest, related to the 2007 application of the Company’s Power Cost Adjustment Mechanism (PCAM). The amount, which is subject to review by the OPUC, is expected to be included in future prices over a period that has yet to be determined;

—

An approximate 1% average price increase to provide increased funding for energy efficiency programs, expected to begin June 1, 2008; and

—

A 0.8% average price increase, effective June 1, 2008, to recover the cost of the AMI project.

PGE has proposed that the collection of deferred replacement power costs associated with the outage of Boardman from late 2005 through early 2006 ($26.4 million plus $5.7 million of accrued interest through March 31, 2008) be offset by certain credits due to customers, with no price impact anticipated. Resolution of this matter is expected in the second half of 2008.

Critical Accounting Policies

PGE’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008.

Results of Operations

The following table contains certain financial information for the periods presented (dollars in millions):


	Three Months Ended March 31,
	2008				2007
	Amount		Percent of Revenues		Amount		Percent of Revenues
Revenues	$	471	100	%	$	436	100	%
Operating expenses:
Purchased power and fuel		250	53			203	47
Production and distribution		39	8			32	7
Administrative and other		47	10			45	10
Depreciation and amortization		50	11			45	10
Taxes other than income taxes		22	5			21	5

Total operating expenses		408	87			346	79

Income from operations		63	13			90	21
Other income (expense):
Allowance for equity funds used during construction		2	-			5	1
Miscellaneous		(3)	(1)			4	1

Other income (expense)		(1)	-			9	2
Interest expense		23	5			17	4

Income before income taxes		39	8			82	19
Income taxes		11	2			27	6

Net income	$	28	6	%	$	55	13	%

Percentages may not add due to rounding.

PGE’s net income was $28 million, or $0.44 per diluted share, for the three months ended March 31, 2008 compared to $55 million, or $0.88 per diluted share, for the three months ended March 31, 2007. Results for the first quarter of 2008 reflect an increase in retail energy deliveries, due to both an increase in the number of customers served and cooler weather compared to the first quarter of 2007. The Company’s return on its investment in the new Port Westward plant and Phase I of the Biglow Canyon wind project, two significant additions to PGE’s portfolio of generating assets, also contributed to results for the first quarter of 2008. Offsetting these positive results was the impact of reduced hydro generation, a reduction in income from non-qualified benefit plan assets, increased legal settlement expense, and the effect of adjustments related to SB 408.

Results for the first quarter of 2007 included a positive $14 million after-tax impact of the deferral of a portion of Boardman replacement power costs (including accrued interest) for potential future recovery, as approved by OPUC. First quarter 2007 results also included a positive $4 million after-tax impact of a settlement between PGE and certain California parties related to wholesale energy transactions in the western energy markets during 2000-2001.

Revenues, energy sold and delivered (based in megawatt hours), and retail customers are comprised of the following:


	Three Months Ended March 31,
	2008				2007
	Amount		Percent of Total		Amount		Percent of Total
Revenues (dollars in millions):
Retail sales:
Residential	$	235	50	%	$	192	44	%
Commercial		149	32			139	32
Industrial		38	8			37	8

Total retail sales		422	90			368	84
Direct access customers		(2)	-			(3)	(1)
Other retail revenues		(3)	(1)			28	6

Total retail revenues		417	89			393	90
Wholesale revenues		48	10			37	8
Other operating revenues		6	1			6	1

Total revenues	$	471	100	%	$	436	100	%


Energy sold and delivered (MWhs in thousands):
Retail energy sales:
Residential		2,358	39	%		2,270	37	%
Commercial		1,791	29			1,746	29
Industrial		568	9			578	9

Total retail energy sales		4,717	77			4,594	75
Delivery to direct access customers		587	10			506	8

Total retail energy deliveries		5,304	87			5,100	83
Wholesale sales		806	13			1,023	17

Total energy sold and delivered		6,110	100	%		6,123	100	%


	As of March 31,
	2008	2007
Retail customers:
Residential	709,725	699,845
Commercial	98,063	96,317
Industrial	260	261

Total retail customers	808,048	796,423

Percentages may not add due to rounding.

Total revenues increased $35 million, or 8%, in the first quarter of 2008 compared to the first quarter of 2007 as a result of the following factors:

—

Total retail revenues increased $24 million, or 6%, due primarily to:

^¡

A 4% increase in total retail energy deliveries, primarily from an approximate 12,300 increase in the average number of customers served from the first quarter of 2007 and cooler weather in the first quarter of 2008;

^¡

An approximate 2.8% price increase for cost recovery of Port Westward, which became effective in June 2007; and

^¡

An approximate 0.6% price increase for cost recovery of Biglow Canyon Phase I, which became effective January 1, 2008.

Partially offsetting the above increases were:

^¡

An approximate 0.3% price decrease, effective January 1, 2008, for changes in forecasted 2008 power and fuel costs under PGE’s Annual Power Cost Update Tariff; and

^¡

A $3 million decrease related to SB 408, with an estimated $2 million future customer refund recorded in the first quarter of 2008 compared to an estimated $1 million collection recorded in the first quarter of 2007.

Lower energy sales to industrial customers resulted from an increase in the number of customers that purchase their energy requirements from an Electricity Service Supplier (ESS). Revenues from these direct access customers include “transition adjustment” credits, reflecting the difference between the cost and market value of PGE’s power supply portfolio, as provided by Oregon’s electricity restructuring law.

On a weather adjusted basis, retail energy deliveries to PGE and ESS customers increased 1.0% in the first quarter of 2008, with deliveries to residential, commercial, and industrial customers increasing by 0.4%, 0.2%, and 4.2%, respectively. Increased residential and commercial sales resulted primarily from increases of 10,500 and 1,800, respectively, in the average number of customers served during the first quarter of 2008 compared to the first quarter of 2007. PGE forecasts an approximate 1.9% increase in total weather adjusted energy deliveries to PGE and ESS customers in 2008.

Other retail revenues in the first quarter of 2007 included $26 million in customer credits under the Residential Exchange Program administered by the BPA, with such amount fully offset within Retail sales to residential and commercial customers. As a result of a decision by the Ninth Circuit, the BPA suspended such benefits in May 2007. In April 2008, benefits were temporarily restored under an Interim Relief agreement with the BPA. The resumption of customer credits, as approved by the OPUC, resulted in an average price reduction of approximately 6.3% for residential and small farm customers, effective April 15, 2008.

—

Wholesale revenues result from sales of electricity to utilities and power marketers. Such sales, which are made in conjunction with the Company’s efforts to secure reasonably priced power for its retail customers, manage risk and administer its current long-term wholesale contracts, can vary significantly between periods. Wholesale revenues increased $11 million, or 30%, in the first quarter of 2008 compared to the first quarter of 2007 due to the net effect of the following:

^¡

A $19 million increase resulting from a 68% increase in average price, caused by both higher natural gas prices and lower hydro availability; partially offset by

^¡

An $8 million decrease resulting from a 21% reduction in wholesale energy sales.

Purchased power and fuel expense in the first quarter of 2008 increased $47 million, or 23%, from the first quarter of 2007. Information about PGE’s total system load and retail load requirement for the three month periods ended March 31, 2008 and 2007 is as follows (in thousands of MWh):


	2008	2007

Generation	3,329	2,310
Term purchases	2,237	3,133
Spot purchases	305	555

Total system load	5,871	5,998

Wholesale sales	(806)	(1,023)

Retail load requirement	5,065	4,975

The average variable power cost of the above total system loads was $42.63 per MWh in the first quarter of 2008 and $38.12 in the first quarter of 2007, an increase of 12%. Averages exclude the effect of amounts related to regulatory power cost deferrals and wholesale credit provisions.

The increase in Purchased power and fuel expense was due primarily to the following factors:

—

A $59 million increase in the cost of thermal (primarily natural gas-fired) production, due to increases in both generation and natural gas prices;

—

A $20 million increase related to the deferral of excess Boardman power costs in the first quarter of 2007;

—

A $15 million increase related to settled natural gas swap agreements entered into in conjunction with PGE’s management of its net power costs. These agreements are among those financial instruments in the Company’s diversified power supply portfolio used to manage market risk, with activities reflected in Wholesale revenues, Purchased power and fuel expense, and Other operating revenues;

—

A $6 million increase due to a reduction in the Company’s wholesale credit reserve, recorded in the first quarter of 2007, related to a settlement with certain California parties involving transactions in 2000-2001; and

—

A $2 million increase due to a 2% increase in the average cost of purchased power.

Partially offsetting the above increases was a $55 million decrease resulting from a 31% reduction in electricity purchases, related primarily to an increase in thermal generation.

Under the PCAM, the Company can adjust future prices to reflect a portion of the difference between each year’s forecasted NVPC included in customer prices (the baseline) and actual NVPC, to the extent that such difference exceeds a pre-determined “deadband”. For 2008, the deadband ranges from $14 million below, to $28 million above, the baseline NVPC. For the first quarter of 2008, the difference between forecasted and actual NVPC was within the established deadband. Accordingly, no amount was recorded for refund or collection from retail customers as of March 31, 2008.

Generation activities - In the first quarter of 2008, PGE generated 66% of its retail load requirement, with 56% from thermal generation and 10% from hydro production. In the first quarter of 2007, the Company generated 46% of its retail load requirement, with 34% from thermal generation and 12% from hydro production. Short- and long-term purchases were utilized to meet the remaining load.

The addition of Port Westward in June 2007, along with increased production at all of PGE’s other thermal generating plants, combined to increase thermal production by 61% from the first quarter of 2007. Such increase, along with new wind generation from Biglow Canyon Phase I, resulted in reduced reliance on higher cost purchases in the wholesale market.

Partially offsetting the increase in thermal production was a 17% decrease in Company-owned hydro production, resulting from lower stream flows. Energy received from hydro facilities on the mid-Columbia River under long-term purchase power agreements decreased 12% from the first quarter of 2007.

Current forecasts indicate that regional hydro conditions in 2008 will be near normal levels. Volumetric water supply data for the Pacific Northwest region is prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies. The April-to-September 2008 runoff forecast compared to the actual runoff for 2007 is as follows (as a percentage of normal):


Location	2008 Forecast *	2007 Actual
Columbia River at The Dalles, Oregon	99%	97%
Mid-Columbia River at Grand Coulee, Washington	100%	102%
Clackamas River	130%	100%
Deschutes River	97%	91%

As of May 1, 2008.

Production and distribution expense increased $7 million, or 22%, in the first quarter of 2008 compared to the first quarter of 2007. The increase was due primarily to a $5 million increase in operating costs at the Company’s generating facilities, including Port Westward, which was completed in June 2007, and Biglow Canyon Phase I, which was completed in December 2007. The remaining increase was due to higher distribution-related labor costs, including those related to line repair and restoration activities.

Administrative and other expense increased $2 million, or 4%, in the first quarter of 2008 compared to the first quarter of 2007, which is primarily due to increased legal settlement expense.

Depreciation and amortization expense increased $5 million, or 11%, in the first quarter of 2008 compared to the first quarter of 2007 primarily due to increased depreciation as a result of the completion of Port Westward and Biglow Canyon Phase I.

Taxes other than income taxes increased $1 million, or 5%, in the first quarter of 2008 compared to the first quarter of 2007. The increase is due primarily to higher property taxes and city franchise fees resulting from increases in assessed values and retail revenues, respectively.

Other income (expense) decreased $10 million in the first quarter of 2008 compared to the first quarter of 2007. The decrease is due to the following:

—

A $5 million decrease in income from non-qualified benefit plan trust assets resulting from the recognition of a $4 million unrealized loss on the plan assets in the first quarter of 2008, compared to a $1 million unrealized gain in the first quarter of 2007;

•

A $3 million decrease in the allowance for equity funds used during construction, which resulted from a lower construction work in progress balance during the first quarter of 2008 due to the completion of both Port Westward and Biglow Canyon Phase I; and

•

A $2 million decrease in interest income on regulatory assets.

Interest expense increased $6 million, or 35%, in the first quarter of 2008 compared to the first quarter of 2007. The increase is due primarily to a higher level of outstanding long-term debt resulting from the issuance of First Mortgage Bonds during the last seven months of 2007. During the first quarter of 2008, the average balance of outstanding debt was $1,285 million, compared to $1,061 million for the first quarter of 2007, which resulted in an increase to interest expense of approximately $4 million. Additionally, the credit to interest expense for the allowance for funds used during construction decreased $2 million as a result of lower construction work in progress balances during the first quarter of 2008 compared to the first quarter of 2007.

Income taxes decreased $16 million from the first quarter of 2007 and the effective tax rate decreased to 28% in the first quarter of 2008 from 33% in the first quarter of 2007. These decreases are primarily the result of lower taxable income and an increase of $2 million in federal energy tax credits generated from the operation of Biglow Canyon Phase I in the first quarter of 2008.

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated cash requirements for the years indicated (in millions):


	2008		2009	2010	2011	2012

Capital expenditures	$	223	$200-$220	$215-$235	$240-$260	$230-$250
Biglow Canyon		90	$590 - $630
Hydro relicensing		56	$65 - $105
Advanced Metering Infrastructure		23	$100 - $110
Boardman emissions controls *	2		$125 - $165

Total capital expenditures	$	394


Long-term debt maturities	$	-	$ -	$ 186	$ -	$ 100

*	See Air Quality Standards below.

Capital Expenditures - Consists of upgrades to and replacement of transmission, distribution and generation infrastructure, as well as new customer connections.

Biglow Canyon - In the first quarter of 2008, PGE entered into various purchase agreements for Phases II and III of the project. The estimated total cost of Phases II and III is $740 million to $780 million, including AFDC of approximately $42 million, with Phases II and III expected to be completed by the end of 2009 and 2010, respectively.

Hydro relicensing - As required under the 50-year license that the FERC issued to PGE in 2004 for its Pelton/Round Butte project on the Deschutes River, PGE began construction of a selective water withdrawal system in late 2007 in an effort to restore fish passage on the upper portion of the river. The system will collect juvenile salmon and steelhead, allowing them to bypass the dam when migrating to the Pacific Ocean, and will regulate downstream water temperature. The system is expected to be completed

in 2009. Amounts presented in the table above represent PGE’s portion of the estimated total cost to complete the project, as well as other relicensing costs.

Advanced Metering Infrastructure (AMI) - PGE plans to install, subject to OPUC approval, over 800,000 new customer meters that will enable daily, two-way remote communications with the Company. AMI is expected to provide improved services, operational efficiencies, and a reduction in future expenses.

Air Quality Standards - The Boardman and Beaver generating plants may cause or contribute to visibility impairment in several federally protected areas. In November 2007, the Company submitted a BART Determination to the DEQ for Boardman that stated the BART for Boardman is a combination of New Low NOx Burners, Modified Over Fire Air System, Selective Non-Catalytic Reduction (SNCR), and Semi-dry Flue Gas Desulphurization, and that mercury emission regulations should be addressed through a Mercury Sorbent Injection System. The total cost for these controls is estimated to be in the range of $300 million to $400 million (100% of total costs). While the Company believes that these controls meet BART requirements, regulatory agencies could require Selective Catalytic Reduction rather than SNCR, which would increase the total estimated cost to a range of $470 million to $620 million (100% of total costs). The Company has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. Final approval of the plan is expected to occur in the second half of 2009.

In April 2008, PGE submitted an application for a modification of its Beaver generating plant operating permit, pursuant to the BART process. The proposed permit modifications would restrict oil burning to reduce emissions below the BART threshold. The operational restrictions would not impact the plant’s capacity to burn natural gas.

Liquidity

PGE’s access to short-term debt markets provides necessary liquidity to support the Company’s current operating activities, including the purchase of electricity and fuel for the generation of electricity. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, as well as debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposits related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

As of March 31, 2008, the Company has financial assets of $60 million and financial liabilities of $21 million included in the Level 3 category pursuant to SFAS 157. See Note 3, Financial Instruments, in the Notes to Condensed Consolidated Financial Statements. These financial instruments are recorded at fair value and may consist of forward, swap and option contracts for electricity and natural gas and futures contracts for natural gas. Fair value of forward, swap and futures contracts is calculated using forward price curves, which are not currently validated against independent publications for contracts that deliver beyond 24 months from the balance sheet date. For option contracts, fair value is calculated using standard financial models that utilize interest rate and price curves, time to expiration, and internally developed price volatility and correlation curves. Any change in the assumptions used to determine fair value of these financial instruments, including market conditions which vary significantly depending on the weather and the economy, would not have an impact on the financial condition or results of operations of the Company as changes in the fair value of these financial instruments are fully offset by the effects of regulatory accounting pursuant to SFAS 71.

PGE’s cash flows were as follows (in millions):


	Three Months Ended March 31,
	2008		2007
Cash and cash equivalents at January 1	$	73	$	12
Net cash provided by (used in):
Operating activities		117		122
Investing activities		(68)		(69)
Financing activities		(71)		(60)

Net decrease in cash and cash equivalents		(22)		(7)

Cash and cash equivalents at March 31	$	51	$	5

Net cash provided by operating activities decreased $5 million in the first quarter of 2008 compared to the first quarter of 2007. This decrease is primarily due to the following offsetting factors:

—

A $16 million decrease in margin deposits made with certain wholesale customers;

—

A $7 million increase in fuel purchases relative to the first quarter of 2007; and

—

A $7 million increase in employee incentive payments relative to the first quarter of 2007.

A significant portion of cash provided by operations consists of depreciation and amortization of electric utility plant, which is recovered in prices with no current direct cash outlay as it represents the recovery of prior investments. PGE estimates recovery of such charges to approximate $210 million in 2008. Combined with all other sources, cash provided by operations is estimated to approximate $404 million in 2008.

Net cash used in investing activities decreased $1 million in the first quarter of 2008 compared to the first quarter of 2007. This decrease is primarily due to the net effect of the following factors:

—

An $11 million decrease in construction costs for Port Westward, which was completed in June 2007;

—

A $4 million increase in expenditures for the Biglow Canyon project;

—

Insurance proceeds of $3 million received in 2008 related to storm damage to substations in 2006; and

—

Increased expenditures related to the expansion of PGE’s distribution system to support both new and existing customers within the Company’s service territory.

See “Capital Requirements” section above for further information.

Net cash used in financing activities increased $11 million in the first quarter of 2008 compared to the first quarter of 2007. 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. During the first quarter of 2008, net cash used in financing activities consisted of the repayment of long-term debt of $56 million and the payment of dividends of $15 million. During the first quarter of 2007, net cash used in financing activities consisted of the net repayment of short-term debt of $52 million and the payment of dividends of $14 million, partially offset by the issuance of long-term debt of $6 million.

Dividends on Common Stock

While the Company expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deem relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

During the first quarter of 2008, the Board of Directors declared a dividend of $0.235 per common share to shareholders of record on March 25, 2008, which was paid April 15, 2008.

Debt and Equity Financings

PGE has a $400 million revolving credit facility with a group of commercial and investment banks that supplements operating cash flow and provides a primary source of liquidity. The facility expires in 2012 and 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.

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, alternatives available to investors, and the condition of the capital markets. The Company’s ability to obtain and renew such financing depends on its credit ratings as well as on capital markets, both generally and for electric utilities in particular. Management believes that the availability of the credit facility and the expected ability to issue long-term debt and equity securities provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. The Company anticipates issuing a total of approximately $250 million of debt and $200 million of equity over the period of 2008 and 2009.

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. The Company attempts 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 51.4% and 50.0% at March 31, 2008 and December 31, 2007, respectively.

For further information regarding PGE’s credit facility and debt financing activities, see Note 2, Balance Sheet Components, in the Notes to Condensed Consolidated Financial Statements.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). PGE’s current credit ratings and outlook are as follows:


	Moody’s	S&P
First Mortgage Bonds	Baa1	A
Senior unsecured debt	Baa2	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

Should Moody’s and/or S&P reduce their 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, 2008, PGE had posted approximately $12 million of collateral, consisting of $7 million in cash and $5 million in letters of credit, none of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of March 31, 2008, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $40 million and decreases to approximately $4 million by December 31, 2008. The approximate amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $52 million and decreases to approximately $5 million by December 31, 2008.

PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade.

The issuance of additional First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Company’s Amended and Restated Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on March 31, 2008 it could issue up to approximately $651 million of additional First Mortgage Bonds under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust. Any issuances would 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 Indenture of Mortgage and Deed of Trust on the basis of property additions, bond credits, and/or deposits of cash.

PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. As of March 31, 2008, the Company’s consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 48.5%.

Off Balance Sheet Arrangements

PGE has no off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on its consolidated financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Contractual Obligations

PGE’s contractual obligations for 2008 and beyond are included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008. As of March 31, 2008, PGE has additional purchase commitments for capital expenditures that require future payments of $347 million in 2009 and $166 million in 2010, totaling $513 million.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

The Company is subject to various market risks which include commodity price risk, credit risk, foreign currency exchange rate risk, and interest rate risk. There have been no material changes to market risks affecting the Company set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008.

Item 4.

Controls and Procedures.

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2008, these disclosure controls and procedures were effective at the reasonable assurance level to ensure that information required to be disclosed by PGE in reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There have been no changes in the Company’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings.

For further information regarding the following legal proceedings, see PGE’s Legal Proceedings set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 27, 2008.

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, Public Utility Commission of Oregon Docket Nos. DR10, UE 88, and UM 989, Marion County Oregon Circuit Court, Case No. 94C-10417, the Court of Appeals of the State of Oregon, the Oregon Supreme Court, Case No. SC S45653.

On March 12, 2008, the administrative law judge established a procedural schedule for the remainder of the proceedings before the OPUC. The schedule indicates an expected OPUC order on September 12, 2008. The OPUC has indicated that this order will address all issues before the OPUC on the matter of PGE’s recovery of its remaining investment in the Trojan plant.

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

Puget Sound Energy, Inc. v. All Jurisdictional Sellers of Energy and/or Capacity at Wholesale Into Electric Energy and/or Capacity Markets in the Pacific Northwest, Including Parties to the Western System Power Pool Agreement, Federal Energy Regulatory Commission, Docket Nos. EL01-10-000, et seq. (Pacific Northwest Refund proceeding)

The disclosure in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 references the complaint filed by the California Attorney General on March 20, 2002 with the FERC (the Lockyer case) against various sellers in the wholesale power market.

On March 21, 2008, the FERC issued an order on remand (Remand Order) that denied the California parties’ motion to hold the Lockyer remand proceeding in abeyance and set for hearing the issue of whether the failure by any individual seller to properly file quarterly transaction reports masked an accumulation of market power that could cause the prices it charged in the California markets to be unjust and unreasonable.

On April 15, 2008, pursuant to a request for clarification filed by parties, including PGE, who had previously settled the complaint proceeding with the California Attorney General and other California parties, the FERC issued an order that dismissed PGE, along with the other settled parties, from this remand proceeding relating solely to the California markets.

On April 21, 2008, certain California parties filed a request for rehearing of the Remand Order, arguing, among other things, that the FERC should have held the Lockyer remand proceeding in abeyance pending remands by the Ninth Circuit of the California Refund case and the Pacific Northwest Refund proceeding. These California parties have not objected to the dismissal of PGE from the remand proceedings.

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, 2007, filed with the SEC on February 27, 2008.

Item 5.

Other Information.

Pursuant to paragraph (e) of Item 5.02 of Form 8-K, Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On May 6, 2008, the Company entered into an agreement with Stephen M. Quennoz, Vice President, Nuclear and Power Supply/Generation. The agreement provides that the Company will continue to employ Mr. Quennoz through March 31, 2013, provided that the Company will retain its right to terminate Mr. Quennoz’ employment for cause at any time. The agreement does not provide any assurance that Mr. Quennoz’ employment during the agreement period will be in his current position or at his current rate of pay, but does provide that, during the agreement period, his annual base salary will not be below the base salary range for an EX-17 General Manager. As of May 6, 2008, the annual base salary range for an EX-17 General Manager was $116,487 to $174,730. The agreement also provides that Mr. Quennoz will be employed in a position that is based within a 30-mile radius of the Company’s headquarters in Portland, Oregon. The Company entered into the agreement to help ensure that the Company will continue to receive the benefit of Mr. Quennoz’ knowledge and experience through the completion of the decommissioning of the Company’s Trojan nuclear plant, and in recognition of his past contributions to the Company – in particular his management of the decommissioning process, as well as his management of the dry cask storage for the spent fuel. The foregoing summary of the agreement is qualified in its entirety by the full text of the agreement which is attached to this report as Exhibit 10.3 and is incorporated herein by reference.

Item 6.

Exhibits.


3.1		Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 3, 2006).

3.2		Fifth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 8, 2007).

10.1		Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 26, 2008).

10.2		Form of Officers’ Performance Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 13, 2008).

10.3		Employment Agreement dated and effective May 6, 2008 between Stephen M. Quennoz and Portland General Electric Company.

31.1		Certification of Chief Executive Officer.

31.2		Certification of Chief Financial Officer.

32		Certifications of Chief Executive Officer and Chief Financial Officer.

Certain instruments defining the rights of holders of other long-term debt of the Company 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 consolidated assets of the Company and its subsidiaries. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.

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 7, 2008	By:	/s/ James J. Piro
			James J. Piro
			Executive Vice President, Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)