Edgar Filing: PORTLAND GENERAL ELECTRIC CO /OR/

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

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. x Yes ¨ 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 the 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 x No

Number of shares of common stock outstanding as of July 31, 2008 is 62,555,030 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2008

TABLE OF CONTENTS


		Page Number
Definitions		3
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements.	4

	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.	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	48

Item 4.	Controls and Procedures.	48

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.	49

Item 1A.	Risk Factors.	49

Item 4.	Submission of Matters to a Vote of Security Holders.	50

Item 6.	Exhibits.	51

SIGNATURE		52

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 June 30,				Six Months Ended June 30,
	2008		2007		2008			2007
Revenues	$	425	$	402	$	896		$	838

Operating expenses:
Purchased power and fuel		185		175		435			378
Production and distribution		46		41		85			73
Administrative and other		47		45		94			90
Depreciation and amortization		50		43		100			88
Taxes other than income taxes		21		19		43			40

Total operating expenses		349		323		757			669

Income from operations		76		79		139			169

Other income (expense):
Allowance for equity funds used during construction		2		4		4			9
Miscellaneous income (expense), net		1		4		(2	)		8

Other income		3		8		2			17
Interest expense		23		18		46			35

Income before income taxes		56		69		95			151
Income taxes		17		23		28			50

Net income	$	39	$	46	$	67		$	101


Weighted-average shares outstanding (in thousands):
Basic		62,532		62,507		62,531			62,506

Diluted		62,588		62,536		62,580			62,531


Earnings per share - basic and diluted	$	0.63	$	0.73	$	1.07		$	1.61


Dividends declared per share	$	0.245	$	0.235	$	0.480		$	0.460

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)


	June 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	202		$	73
Accounts and notes receivable, net		151			178
Unbilled revenues		66			92
Assets from price risk management activities		514			64
Inventories, at average cost		72			64
Other current assets		63			67

Total current assets		1,068			538
Electric utility plant, net		3,188			3,066
Non-qualified benefit plan trust		62			69
Nuclear decommissioning trust		45			46
Regulatory assets		249			304
Other noncurrent assets		82			85

Total assets	$	4,694		$	4,108

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	170		$	227
Deferred income taxes		147			-
Current portion of long-term debt		142			-
Liabilities from price risk management activities		139			101
Customer and counterparty deposits		131			8
Accrued taxes		29			23
Other current liabilities		36			32

Total current liabilities		794			391
Long-term debt, net of current portion		1,164			1,313
Regulatory liabilities		1,012			574
Deferred income taxes		138			279
Non-qualified benefit plan liabilities		89			86
Accumulated asset retirement obligations		84			91
Other noncurrent liabilities		58			58

Total liabilities		3,339			2,792
Commitments and contingencies (see notes)
Shareholders’ equity:
Common stock, no par value, 80,000,000 shares authorized; 62,548,742 and 62,529,787 shares issued and outstanding as of June 30, 2008 and December 31, 2007, respectively		648			646
Accumulated other comprehensive loss		(4	)		(4	)
Retained earnings		711			674

Total shareholders’ equity		1,355			1,316

Total liabilities and shareholders’ equity	$	4,694		$	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)


	Six Months Ended June 30,
	2008			2007
Cash flows from operating activities:
Net income	$	67		$	101
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		100			88
Net assets from price risk management activities		(412	)		(34	)
Regulatory deferral-price risk management activities		412			34
Deferred income taxes		19			18
Senate Bill 408 deferrals		1			(3	)
Allowance for equity funds used during construction		(4	)		(9	)
Power cost deferrals		8			(21	)
Other non-cash income and expenses, net		12			(10	)
Changes in working capital:
Net margin deposit activity		147			34
Decrease in receivables		53			37
Decrease in payables		(35	)		(25	)
Other working capital items, net		(9	)		(3	)
Other, net		9			(6	)

Net cash provided by operating activities		368			201

Cash flows from investing activities:
Capital expenditures		(206	)		(159	)
Sales of nuclear decommissiong trust securities		13			9
Purchases of nuclear decommissioning trust securities		(12	)		(10	)
Insurance proceeds received		3			-
Other, net		(2	)		(5	)

Net cash used in investing activities		(204	)		(165	)

Cash flows from financing activities:
Payments on long-term debt		(56	)		(71	)
Proceeds from issuance of long-term debt		50			176
Payments on short-term debt, net		-			(81	)
Debt issuance costs		-			(2	)
Dividends paid		(29	)		(28	)

Net cash used in financing activities		(35	)		(6	)

Increase in cash and cash equivalents		129			30
Cash and cash equivalents, beginning of period		73			12

Cash and cash equivalents, end of period	$	202		$	42

Supplemental cash flow information is as follows:
Cash paid during the period for:
Interest, net of amounts capitalized	$	39		$	21
Income taxes		3			29
Non-cash investing and financing activities:
Accrued capital additions		12			84
Accrued dividends payable		15			15

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 813,000 retail customers as of June 30, 2008.

As of June 30, 2008, PGE had 2,709 employees, with 863 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 830 and 33 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 and six month periods ended June 30, 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 (1) the presentation of income tax expense as one caption in the condensed consolidated statements of income for the three and six month periods ended June 30, 2007, which was previously reported as a separate line within operating expenses and other income (deductions), and (2) 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 as a separate line within total capitalization. For the three months ended June 30, 2007, income taxes of $23 million was previously reported in operating expenses. For the six months ended June 30, 2007, income taxes of $49 million and $1 million were previously reported as operating expenses and other income (deductions), respectively.

Additionally, the allowance for equity funds used during construction of $9 million and Senate Bill 408 deferrals of $3 million were previously classified in other non-cash income and expenses (net) in the condensed consolidated statement of cash flows for the six months ended June 30, 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. PGE is in the process of determining whether the adoption of FSP 157-2 will have a material impact on its 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.

In June 2008, FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), was issued and addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in SFAS 128, Earnings per Share. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior period earnings per share data presented shall be adjusted retrospectively to conform to the provisions of this FASB Staff Position. Early application is not permitted. The adoption of FSP EITF 03-6-1 will not have a material impact on PGE’s consolidated financial position or consolidated results of operations.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts and Notes Receivable, Net

Accounts and notes receivable is net of an allowance for uncollectible accounts of $4 million and $5 million as of June 30, 2008 and December 31, 2007, respectively.

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


	Six Months Ended June 30,
	2008			2007
Balance at beginning of period	$	5		$	45
Provision		3			(37	)
Amounts written off, less recoveries		(4	)		(3	)

Balance at end of period	$	4		$	5

Inventories

Inventories consist of fuel and materials and supplies for use in operations or for the maintenance of the Company’s generating plants and transmission and distribution facilities, all of which are classified as finished goods.

Electric Utility Plant, Net

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


	June 30, 2008			December 31, 2007
Electric utility plant	$	4,960		$	4,898
Construction work in progress		233			126

Total cost		5,193			5,024
Less: accumulated depreciation and amortization		(2,005	)		(1,958	)

Electric utility plant, net	$	3,188		$	3,066

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $103 million and $96 million as of June 30, 2008 and December 31, 2007, respectively. Amortization expense related to intangible assets was $4 million and $3 million for the three months ended June 30, 2008 and 2007, respectively, and $7 million for the six months ended June 30, 2008 and 2007.

In July 2008, PGE entered into contracts totaling $68 million related to the construction of Biglow Canyon Phases II and III.

Regulatory Assets and Liabilities

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


	June 30, 2008		December 31, 2007
Regulatory assets:
Income taxes recoverable	$	85	$	87
Pension and other postretirement plans		56		57
Boardman power cost deferral		33		31
Debt reacquisition costs		29		28
Oregon Senate Bill 408		16		16
Trojan decommissioning costs		13		16
Price risk management		-		37
Other		17		32

Total regulatory assets	$	249	$	304

Regulatory liabilities:
Accumulated asset retirement removal costs	$	474	$	451
Price risk management		375		-
Oregon Senate Bill 408		44		42
Asset retirement obligations		27		28
Residential Exchange Program		24		-
Power Cost Adjustment Mechanism		24		16
Trojan ISFSI pollution control tax credits		15		13
Other		29		24

Total regulatory liabilities	$	1,012	$	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 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. On June 13, 2008, PGE received approval from seven of the eight banks in the Credit Facility to extend the termination date for an additional year. As a result, a total of $390 million was extended for an additional year to July 2013. The remaining $10 million will continue to have a termination date of July 2012.

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 June 30, 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 June 30, 2008, PGE had no commercial paper outstanding and had utilized $37 million in letters of credit, with $363 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 June 30, 2008, are insured under an agreement with a bond insurer. The insurance agreement contained a requirement that PGE maintain a common equity percentage of not less than 45%. During the second quarter of 2008, that requirement was eliminated through an amendment to the insurance agreement.

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

The current interest rate and interest period expire April 30, 2009 on $142 million of Pollution Control Revenue Bonds (Bonds), consisting of $23 million issued through the Port of Morrow, Oregon, and $119 million issued through the City of Forsyth, Montana. The owners of the Bonds are required to tender their Bonds on May 1, 2009. On May 1, 2009, PGE has the option to (a) have the Bonds remarketed or (b) redeem all or a portion of the Bonds at a redemption price equal to 100% of the principal amount of the Bonds to be redeemed plus accrued interest, if any, to the redemption date. For the Bonds that are to be remarketed, PGE can choose a new interest rate period that would be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of the remarketing. The Bonds are currently secured by a pledge of PGE First Mortgage Bonds. The Bonds could be remarketed as unsecured obligations of PGE or may be backed by PGE First Mortgage Bonds depending on market conditions. The Bonds are classified as Current portion of long-term debt in the condensed consolidated balance sheet as of June 30, 2008.

Pension and Other Postretirement Benefits

The following table provides the components of net periodic benefit cost for the three months ended June 30 (in millions):


	Defined Benefit Pension Plan						Non-Qualified Benefit Plans				Other Benefits
	2008			2007			2008		2007		2008			2007
Service cost	$	3		$	3		$	-	$	-	$	1		$	1
Interest cost		8			7			1		1		1			1
Expected return on plan assets		(11	)		(11	)		-		-		(1	)		-
Amortization of prior service cost		-			-			-		-		1			-
Amortization of net actuarial loss		-			1			-		-		-			-

Net periodic benefit cost	$	-		$	-		$	1	$	1	$	2		$	2

The following table provides the components of net periodic benefit cost (income) for the six months ended June 30 (in millions):


	Defined Benefit Pension Plan						Non-Qualified Benefit Plans				Other Benefits
	2008			2007			2008		2007		2008			2007
Service cost	$	6		$	6		$	-	$	-	$	1		$	1
Interest cost		15			14			1		1		2			2
Expected return on plan assets		(22	)		(21	)		-		-		(1	)		-
Amortization of prior service cost		-			-			-		-		1			-
Amortization of net actuarial loss		-			2			-		-		-			-

Net periodic benefit cost (income)	$	(1	)	$	1		$	1	$	1	$	3		$	3

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.

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.

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 June 30, 2008
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust *	$	45	$	-	$	-	$	45
Non-qualified benefit plan trust		38		1		-		39
Assets from price risk management activities *		-		333		181		514

	$	83	$	334	$	181	$	598

Liabilities - Liabilities from price risk management activities *	$	-	$	128	$	11	$	139

*	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.

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 activities 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 (in millions):


	Three Months Ended June 30, 2008			Six Months Ended June 30, 2008
Beginning balance	$	39		$	1
Net realized and unrealized gains		115			129
Purchases, issuances and settlements, net		17			41
Net transfers out of Level 3		(1	)		(1	)

Ending balance	$	170		$	170

Net realized and unrealized gains included in Purchased power and fuel expense in the condensed consolidated statements of income, which includes $131 million and $169 million in net unrealized gains for the three and six month periods ended June 30, 2008, respectively, 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 June 30,				Six Months Ended June 30,
	2008		2007		2008		2007

Numerator (in millions):
Net income available for common shareholders	$	39	$	46	$	67	$	101


Denominator (in thousands):
Weighted-average common shares outstanding - basic		62,532		62,507		62,531		62,506
Dilutive effect of restricted stock units and employee stock purchase plan shares		56		29		49		25

Weighted-average common shares outstanding - diluted		62,588		62,536		62,580		62,531


Earnings per share - basic and diluted	$	0.63	$	0.73	$	1.07	$	1.61

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 the attainment of specific goals during 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.

Net unrealized gains from derivative activities recorded in net income, fully offset by the recognition of SFAS 71 regulatory liabilities, were as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Unrealized gains (losses)	$	271		$	(7	)	$	412		$	34
SFAS 71 regulatory asset (liability)		(271	)		7			(412	)		(34	)

Net unrealized gains (losses)	$	-		$	-		$	-		$	-

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, substantially all of which the Company estimates will be reclassified into earnings within the next twelve months, are fully offset by SFAS 71 regulatory accounting, with the balance to settle over the next 39 months. 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 June 30, 2008.

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2008		2007			2008		2007
Other unrealized holding net losses arising during the period	$	-	$	(5	)	$	-	$	-
Reclassification to net income for contract settlements		-		-			-		(7	)
Reclassification of unrealized losses to SFAS 71 regulatory asset		-		5			-		7

Net unrealized gains (losses)	$	-	$	-		$	-	$	-

NOTE 6: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Net income	$	39		$	46		$	67		$	101
Unrealized gains (losses) on cash flow hedges:
Other unrealized holding losses 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 ($2) for the three months ended June 30, 2007 and ($3) for the six months ended June 30, 2007		-			3			-			4

Total unrealized gains on cash flow hedges		-			-			-			-

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

Comprehensive income	$	39		$	46		$	67		$	101

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 Marion County 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 Marion County Circuit Court and on cross-appeal to the Oregon 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 has encouraged the parties to attempt to agree on steps that 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. At a June 3, 2008 status conference, the Circuit Court scheduled a status conference for October 2008 and set a tentative trial date for April 2009.

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.

Management cannot predict the ultimate outcome of the above matters, but believes that if WECO were successful in passing these costs to the owners of Colstrip, the potential loss for PGE’s share of the royalties, taxes and interest alleged by the USDI and Montana Department of Revenue through June 30, 2008, would range from $1 million to $8 million. 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. As of June 30, 2008, PGE has accrued $1 million related to this matter. If WECO were able to pass such costs on to the owners, the Company would evaluate the likelihood of recovery through the ratemaking process. However, there can be no assurance that any recovery, if pursued, 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, 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 to (i) 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) include sales to CERS in its analysis, and (iii) 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 rule on 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.

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 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 has granted PGE’s request to stay the proceedings until August 12, 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. The OPUC has indicated that it will determine whether any necessary rate adjustment should be made to amortize the deferral granted in its August 14, 2007 Order.

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.

FERC Investigation

On June 2, 2006, the Division of Audits in the Office of Enforcement of the FERC commenced an audit of PGE’s compliance with: (1) the practices and procedures contained within the Company’s FERC-approved Open Access Transmission Tariff (OATT); (2) the conditions by which the FERC granted market-based rate authority to PGE; (3) FERC’s Standards of Conduct requirements; (4) FERC requirements concerning the preservation of records of public utilities; and (5) other FERC rules and regulations including, but not limited to, interlocking directorate requirements and shortages of electricity energy and capacity. On July 16, 2008, the Division of Audits issued its final Audit Report, containing recommendations (agreed to by PGE) for the Company to develop written policies, procedures, enhanced controls, internal audit processes, and training designed to correct deficiencies regarding PGE’s compliance with FERC requirements relating to (1) posting of transmission information on its “OASIS” Internet platform, (2) information contained in filed Electronic Quarterly Reports of merchant power sales activities, and (3) the filing of grandfathered contract amendments.

The Division of Audits has referred certain issues relating to PGE’s compliance with its OATT to the FERC’s Division of Investigations. In May 2008, PGE received a notice of a preliminary non-public investigation from the Division of Investigations concerning PGE’s compliance with its OATT.

The Company has cooperated with the FERC staff throughout the audit process and will continue to cooperate with FERC staff in the investigation. The investigation is in its early stages, and the process will provide the Company with an opportunity to discuss with the FERC the issues and facts relating to the investigation and to provide the Company’s views and explanations of these issues and facts.

Management cannot predict the final outcome of the investigation, or what actions, if any, the FERC will take. 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.

Environmental Matters

Portland Harbor

A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a 5.5 mile segment of the Willamette 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 Portland Harbor Superfund Site. 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.

The Portland Harbor Superfund Site is currently undergoing a remedial investigation and feasibility study (RI/FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs, not including PGE. In the AOC, the EPA determined the site for purposes of the RI/FS to be a segment of the river approximately 10 miles in length.

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

being examined in the RI/FS, as well as several miles beyond that segment. PGE’s response is due in September 2008.

The boundaries of the site for remediation purposes will be determined at the conclusion of the RI/FS in a Record of Decision, in which the EPA documents its findings and selects a preferred cleanup alternative.

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. 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.

PGE has filed an application with the OPUC requesting deferred accounting for later ratemaking treatment of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Portland Harbor site. However, there can be no assurance that any recovery of these costs will be granted.

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, 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. On-site sampling was completed during the second quarter 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.

PGE has filed an application with the OPUC requesting deferred accounting for later ratemaking treatment of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Harbor Oil site. However, there can be no assurance that any recovery of these costs will be granted.

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, the Pacific Northwest Refund proceeding, and the Portland Harbor Superfund Site investigation 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, 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 increase the Company’s costs or affect the 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, mercury, and other 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;

•

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

•

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, 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;

•

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.

Customers - During the first half of 2008, PGE served an average of 809,000 retail customers compared to 798,000 during the first half of 2007, an increase of 1.4%. This customer growth, along with generally cooler weather during the first half of 2008, resulted in a 3% increase in retail energy deliveries over the first half of 2007. On a weather adjusted basis, retail energy deliveries increased 1.3% from last year’s first half.

A slow-down in the state’s economy, including a decline in the housing market, continued through the second quarter of 2008. The unemployment rate (seasonally adjusted) rose from 5.2% for 2007 to 5.5% in 2008, approximating the national jobless rate. Despite the slow-down, Oregon had a 0.6% payroll growth in the first half of 2008 relative to the same period of 2007, compared to a 0.3% national rate. PGE projects an approximate 2% increase in weather adjusted energy deliveries for 2008, with higher use by industrial customers projected during the last half of the year.

Regulatory review of the Company’s general rate case and proposed tariffs, filed with the OPUC in late February 2008, is continuing under procedural schedules that currently provide for new rates to become effective on January 1, 2009. PGE’s initial filing proposed an 8.9% average price increase related to higher purchased power and fuel costs, increased investment in utility plant, and higher operating expenses. Due to projections of increased loads and costs of purchased power and fuel for the Company’s thermal generating plants subsequent to the initial filing, PGE has filed power cost updates reflecting an additional $113 million in projected power costs. PGE, OPUC staff, and interveners active in the case have reached stipulations on several items, including the method of determining estimated power costs and the cost of capital. The cost of capital stipulation provides for a debt-to-equity capital structure of 50/50 and a return on equity of 10.1%, with a weighted average cost of capital of 8.33%. The stipulated items and the power cost updates to date would amount to a proposed total average price increase of approximately 14%, consisting of increased revenue requirements of approximately $151 million to cover NVPC and $78 million for other costs. The proposed increases remain subject to change as the case progresses. NVPC are to be updated later this year according to a procedural schedule established by the OPUC. 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.

On May 5, 2008, the OPUC approved the Company’s Advanced Metering Infrastructure (AMI) project, which will be deployed for residential and commercial customers. A new tariff, effective from June 1, 2008 through December 31, 2010, will provide for recovery of costs, including the net book value of existing meters, during this period. Installation of a limited number of new “smart meters” has begun as part of the project’s acceptance testing phase, with the remaining meters to be installed by the end of 2010. 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 half of 2008, providing about 58% of the Company’s retail load requirement, compared to 42% in the first half of 2007, with overall plant availability at approximately 85% during the first half of 2008. Annual

maintenance requirements were completed at the Boardman coal plant during its scheduled outage from late April through May 2008. The results for the second quarter of 2008 reflect the effect of increased runoff and resulting increased hydro generation offsetting the reduced snow melt and hydro generation that resulted from cold weather in the first quarter of 2008. Current forecasts indicate near normal regional hydro conditions for 2008.

In March 2008, PGE executed agreements to purchase 141 wind turbines for Phases II and III of Biglow Canyon, and in July 2008, the Company entered into contracts for the related construction. Construction of Phase II has begun, with completion expected by the end of 2009. Phase III is expected to be completed by the end of 2010. Total cost of the two phases is expected to be $740 million to $780 million, including allowance for funds used during construction (AFDC). The two phases will have a combined installed capacity of approximately 324 MW, further increasing the diversity of the Company’s generating resource portfolio while minimizing related environmental impacts. For further information regarding estimated future capital expenditures, see “Capital Requirements” in “Liquidity and Capital Resources” in this Item 2.

In April 2008, PGE issued a request for proposals for 218 MWa of renewable energy resources and currently expects to identify a short list of bidders by September 2008. Such resources, which are in addition to Biglow Canyon and are required to become available between 2009 and 2014, were included in the Company’s June 2007 Integrated Resource Plan (IRP) and were deemed reasonable by the OPUC.

As requested by the OPUC, PGE is currently preparing 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. PGE expects the updated and revised IRP to further define the Company’s future energy and capacity needs.

PGE plans to join the Northern Tier Transmission Group (NTTG), a group of utilities that seeks to improve the high-voltage transmission network in seven western states. Formed in 2007, NTTG is one of the major regional transmission planning entities working to improve available transmission capacity, plan for grid expansion, and collaborate on control area operations. The Company has joined the NTTG Planning Committee and will become a full funding member upon the approval of the FERC.

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 OPUC approval to issue an additional $250 million of First Mortgage Bonds, of which, during April 2008, PGE issued $50 million, as discussed below. For further information, see “Credit Facility and Long-term Debt” in Note 2, Balance Sheet Components, in the Notes to Condensed Consolidated Financial Statements.

During the first half of 2008, PGE issued $50 million of 4.45% First Mortgage Bonds that mature in April 2013 and repurchased and retired $50 million of 5.279% First Mortgage Bonds. The Company also repurchased $5.8 million of its Port of Morrow, variable rate Pollution Control Revenue Bonds, which may be remarketed at a later date. In May 2008, PGE’s Board of Directors approved a 4.3% increase in the Company’s annual common stock dividend, from $0.94 per share to $0.98 per share.

Legal, Regulatory and Environmental Matters - PGE is a party in proceedings whose ultimate outcome could have a material impact on the results of operations and cash flows in future reporting periods. These include 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;

—

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

—

an audit and subsequent investigation by the FERC related to the Company’s compliance with its Open Access Transmission Tariff; and

—

an investigation by the EPA of the Portland Harbor Superfund Site.

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

Recent and pending rate actions include the following:

—

A 6.3% average price decrease for residential and small farm customers, effective April 15, 2008, related to an agreement between PGE and Bonneville Power Administration (BPA) that temporarily restored federal hydropower benefits under the Residential Exchange Program administered by the BPA. The majority of such benefits, approximately $43 million, is expected to be refunded by the end of 2008.

—

A 1.4% average price decrease, effective June 1, 2008, for refunds to retail customers of taxes pursuant to SB 408 related to the 2006 reporting year. Such refunds, in the amount of $37.2 million plus interest, will take place over an approximate two-year period.

—

An approximate 1% average price increase, effective June 1, 2008, for costs related to energy efficiency measures that enable customers to reduce their energy use.

—

A 0.8% average price increase, effective June 1, 2008, related to the AMI project discussed above.

—

An approximate $17 million refund to customers, including accrued interest, related to the 2007 application of PGE’s Power Cost Adjustment Mechanism (PCAM). The Company has requested that such amount, which is subject to review by the OPUC, be refunded over a one-year period beginning January 1, 2009.

—

The collection of deferred replacement power costs related to the outage of Boardman from late 2005 through early 2006 ($26.4 million plus $6.4 million of accrued interest through June 30, 2008). In its filing with the OPUC, PGE proposed that such collection be offset by certain credits due to customers, with no price impact anticipated. PGE’s request is subject to both a prudency review with respect to the outage and to a regulated earnings test.

—

A proposed average price increase of approximately 14%, subject to change and OPUC approval, to be effective January 1, 2009, as described above.

In May 2008, the OPUC issued an order that establishes guidelines for interest rates applied to unamortized balances of deferred assets and liabilities of the state’s investor-owned utilities. PGE has previously accrued interest at the Company’s authorized rate of return, most recently at 8.29%, until respective balances are fully amortized. Beginning July 21, 2008, the effective date of the order, a Treasury-based interest rate, currently 4.27%, will be utilized to accrue interest on deferred balances, beginning on the date that amortization is approved. Balances not yet approved for amortization will continue to accrue interest at the authorized rate of return.

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 June 30,								Six Months Ended June 30,
	2008				2007				2008					2007
	Amount		As % of Rev		Amount		As % of Rev		Amount			As % of Rev		Amount		As % of Rev
Revenues	$	425	100	%	$	402	100	%	$	896		100	%	$	838	100	%
Operating expenses:
Purchased power and fuel		185	44			175	44			435		49			378	45
Production and distribution		46	11			41	10			85		9			73	9
Administrative and other		47	11			45	11			94		10			90	11
Depreciation and amortization		50	12			43	11			100		11			88	11
Taxes other than income taxes		21	5			19	5			43		5			40	5

Total operating expenses		349	82			323	80			757		84			669	80

Income from operations		76	18			79	20			139		16			169	20
Other income (expense):
Allowance for equity funds used during construction		2	-			4	1			4		-			9	1
Miscellaneous, net		1	-			4	1			(2	)	-			8	1

Other income		3	1			8	2			2		-			17	2
Interest expense		23	5			18	4			46		5			35	4

Income before income taxes		56	13			69	17			95		11			151	18
Income taxes		17	4			23	6			28		3			50	6

Net income	$	39	9	%	$	46	11	%	$	67		7	%	$	101	12	%

Percentages may not add due to rounding.

Net income was $39 million, or $0.63 per diluted share, for the second quarter of 2008 compared to $46 million, or $0.73 per diluted share, for the second quarter of 2007. The decrease is primarily due to decreased fair market values of non-qualified benefit plan trust assets and higher operating expenses. Such results were partially offset by an increase in retail energy deliveries and the Company’s return on its investment in Phase I of the Biglow Canyon wind project.

Net income for the six months ended June 30, 2008 was $67 million, or $1.07 per diluted share, compared to $101 million, or $1.61 per diluted share, for the six months ended June 30, 2007. The decrease is primarily due to the deferral in 2007 of a portion of Boardman replacement power costs (including accrued interest) for potential future collection from customers, decreased fair market values of non-qualified benefit plan assets, a reduction in potential customer collections related to prior year income taxes (pursuant to Senate Bill 408), higher operating expenses, and a favorable impact in 2007 for the settlement between PGE and certain California parties related to wholesale energy transactions in the western energy markets during 2000-2001. Such results were partially offset by an increase in retail energy deliveries and the Company’s return on its investment in Biglow Canyon Phase I.

Second Quarter of 2008 Compared to the Second Quarter of 2007

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


	Three Months Ended June 30,
	2008					2007
	Amount			Percent of Total		Amount			Percent of Total
Revenues (dollars in millions):
Retail sales:
Residential	$	169		40	%	$	149		37	%
Commercial		145		34			144		36
Industrial		39		9			41		10

Total retail sales		353		83			334		83
Direct access customers		(2	)	-			(3	)	(1	)
Other retail revenues		12		3			19		5

Total retail revenues		363		85			350		87
Wholesale revenues		44		10			44		11
Other operating revenues		18		4			8		2

Total revenues	$	425		100	%	$	402		100	%


Energy sold and delivered (MWhs in thousands):
Retail energy sales:
Residential		1,764		33	%		1,633		29	%
Commercial		1,739		32			1,786		32
Industrial		640		12			665		12

Total retail energy sales		4,143		76			4,084		74
Delivery to direct access customers		602		11			539		10

Total retail energy delivieries		4,745		87			4,623		83
Wholesale sales		681		13			916		17

Total energy sold and delivered		5,426		100	%		5,539		100	%


	As of June 30,
	2008	2007
Retail customers:
Residential	710,819	701,697
Commercial	101,958	100,051
Industrial	261	259

Total retail customers	813,038	802,007

Percentages may not add due to rounding.

Demand for electricity by residential and commercial customers is significantly affected by weather. Heating degree-days, an indication of the likelihood that customers will use heating, and cooling degree-days, an indication of the likelihood that customers will use air conditioning, are generally used to measure the effect of weather on the demand for electricity. The following table indicates the number of heating and cooling degree-days for the months indicated, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:


	Heating		Cooling
	2008	2007	2008	2007
April	490	393	-	-
May	223	217	40	22
June	147	88	58	34

2nd quarter	860	698	98	56

15-year average for the quarter	664	664	67	67

Total revenues increased $23 million, or 6%, in the second quarter of 2008 compared to the second quarter of 2007 as a result of the following factors:

—

Total retail revenues increased $13 million, or 4%, due primarily to:

A 3% increase in total retail energy deliveries, due to both cooler weather and an approximate 11,300 increase in the average number of customers served during the second quarter of 2008, relative to the second quarter of 2007, consisting largely of an increase in residential customers. As indicated in the table above, the number of heating degree-days in each month of the second quarter of 2008 exceeded those of each corresponding month of 2007;

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 amounts due from customers under SB 408.

Other retail revenues decreased $7 million in the second quarter of 2008 compared to the second quarter of 2007, due primarily to a decrease in customer credits related to the Residential Exchange Program administered by the BPA. These amounts are fully offset in Retail sales.

—

Wholesale revenues result from sales of electricity to utilities and power marketers 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. Although such sales can vary significantly between periods, wholesale revenues in the second quarter of 2008 were comparable to the second quarter of 2007. Average sales price increased 33% due to higher natural gas prices, which was fully offset by a 26% reduction in wholesale energy sales.

—

Other operating revenues increased $10 million, due to current year sales of fuel oil, which resulted in realized gains of $7 million. Pursuant to an assessment of reliability requirements, PGE is reducing oil inventory levels at its Beaver generating plant.

Purchased power and fuel expense in the second quarter of 2008 increased $10 million, or 6%, from the second quarter of 2007. Information about PGE’s total system load and retail load requirement for the periods presented is as follows (in thousands of MWhs):


	Three Months Ended June 30,
	2008		2007
Generation	2,129		1,601
Term purchases	2,587		3,592
Spot purchases	359		61

Total system load	5,075		5,254
Less: wholesale sales	(681	)	(916	)

Retail load requirement	4,394		4,338

The average variable power cost of the above total system loads was $35.09 and $32.73 per MWh in the second quarter of 2008 and 2007, respectively, an increase of 7%. 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 net effect of the following factors:

—

A $29 million increase in the cost of natural gas-fired production, primarily due to increased generation from Port Westward, which went into service in June 2007, and higher natural gas prices;

—

A $4 million increase in the estimated amount recorded for potential future refund to customers under the PCAM. In the second quarter of 2008, PGE recorded a $7 million regulatory liability, with a corresponding increase in power costs, compared to a $3 million regulatory liability recorded in the second quarter of 2007;

Under the PCAM, the Company can adjust future prices to reflect a portion of the difference between each year’s forecasted power costs included in customers prices and actual power costs to the extent that such difference exceeds a pre-determined “deadband” which, for 2008, ranges from $14 million below, to $28 million above, baseline power costs. Any regulatory asset or liability arising from the application of the PCAM will be adjusted at year end for the results of a regulated earnings test, with final determination of any customer refund or collection to be determined by the OPUC through a public filing and review; and

—

A $23 million decrease in the cost of purchased power, resulting primarily from a 19% reduction in electricity purchases due to increased generation. During the second quarter of 2008, PGE’s generation increased by 33% relative to the second quarter of 2007.

Generation activities - In the second quarter of 2008, PGE generated 48% of its retail load requirement, with 32%, 13% and 3% from thermal, hydro, and wind resources, respectively. In the second quarter of

2007, the Company generated 37% of its retail load requirement, with 27% from thermal generation and 10% from hydro production. Short- and long-term purchases were utilized to meet the remaining load.

Primarily due to the addition of Port Westward in June 2007, production at PGE’s thermal plants increased by 22% from the second quarter of 2007. Additionally, wind generation from Biglow Canyon Phase I comprised 6% of the Company’s total generation, further reducing reliance on purchased power.

Energy from hydro resources in the second quarter of 2008 increased 2% from the second quarter of 2007. A 31% increase in Company-owned hydro production, resulting from increased stream flows, was partially offset by a 9% reduction in energy received under long-term purchase power agreements from hydro facilities on the mid-Columbia River.

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	101	%	97	%
Mid-Columbia River at Grand Coulee, Washington	102	%	102	%
Clackamas River	163	%	100	%
Deschutes River	101	%	91	%

* As of July 8, 2008.

Production and distribution expense increased $5 million, or 12%, in the second quarter of 2008 compared to the second quarter of 2007. The increase is due primarily to a $3 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 is primarily due to increased repairs and maintenance expenses incurred on the Boardman plant in connection with scheduled maintenance activities in 2008 compared to 2007.

Administrative and other expense increased $2 million, or 4%, in the second quarter of 2008 compared to the second quarter of 2007, which is primarily due to an increase in employee benefits.

Depreciation and amortization expense increased $7 million, or 16%, in the second quarter of 2008 compared to the second quarter of 2007 primarily due to increased depreciation of $5 million as a result of Port Westward and Biglow Canyon Phase I being placed in service in June 2007 and December 2007, respectively.

Taxes other than income taxes increased $2 million, or 11%, in the second quarter of 2008 compared to the second 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 decreased $5 million in the second quarter of 2008 compared to the second quarter of 2007. The decrease is primarily due to the following:

•

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

•

A $2 million decrease in the allowance for equity funds used during construction, which resulted from lower construction work in progress balances during the second quarter of 2008 due to the completion of Port Westward in June 2007.

Interest expense increased $5 million, or 28%, in the second quarter of 2008 compared to the second 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. Long-term debt outstanding has increased as a result of funding the Company’s capital projects. During the second quarter of 2008, the average outstanding balance of long-term debt was $1,281 million, compared to $1,073 million for the second quarter of 2007, which resulted in an increase to interest expense of approximately $4 million. Additionally, the credit to interest expense for AFDC decreased $1 million as a result of lower construction work in progress balances during the second quarter of 2008 compared to the second quarter of 2007.

Income taxes decreased $6 million in the second quarter of 2008, with an effective tax rate of 30%, compared to the second quarter of 2007, with an effective tax rate of 33%. These decreases are primarily the result of lower taxable income and an increase of $3 million in federal energy tax credits generated from the operation of Biglow Canyon Phase I in the second quarter of 2008.

Six Months Ended June 30, 2008 Compared to the Six Months Ended June 30, 2007

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


	Six Months Ended June 30,
	2008					2007
	Amount			Percent of Total		Amount			Percent of Total
Revenues (dollars in millions):
Retail sales:
Residential	$	404		45	%	$	341		41	%
Commercial		294		33			283		34
Industrial		77		9			78		9

Total retail sales		775		86			702		84
Direct access customers		(4	)	-			(6	)	(1	)
Other retail revenues		9		1			47		6

Total retail revenues		780		87			743		89
Wholesale revenues		92		10			81		10
Other operating revenues		24		3			14		2

Total revenues	$	896		100	%	$	838		100	%


Energy sold and delivered (MWhs in thousands):
Retail energy sales:
Residential		4,122		36	%		3,903		33	%
Commercial		3,530		31			3,532		30
Industrial		1,208		10			1,243		11

Total retail energy sales		8,860		77			8,678		74
Delivery to direct access customers		1,189		10			1,045		9

Total retail energy delivieries		10,049		87			9,723		83
Wholesale sales		1,487		13			1,939		17

Total energy sold and delivered		11,536		100	%		11,662		100	%

Percentages may not add due to rounding.

The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:


	Heating		Cooling
	2008	2007	2008	2007
1st Quarter	1,981	1,852	-	-
2nd Quarter	860	698	98	56

Year-to-date	2,841	2,550	98	56

15-year average for the year-to-date	2,504	2,504	67	67

Total revenues increased $58 million, or 7%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007 as a result of the following factors:

—

Total retail revenues increased $37 million, or 5%, due primarily to:

A 3% increase in total retail energy deliveries, due to both cooler weather and an approximate 11,800 increase in the average number of customers served in the first half of 2008 relative to the first half of 2007. As indicated in the table above, the number of heating and cooling degree-days in each of the first two quarters of 2008 exceeded those of the corresponding periods of 2007;

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 $6 million decrease related to SB 408, with an estimated refund to customers of $1 million recorded in the first half of 2008 compared to an estimated collection from customers of $5 million recorded in the first half of 2007.

Higher residential sales were attributable to the cooler weather and a 10,000, or 1.4%, increase in the average number of residential customers served during the first half of 2008 relative to the first half of 2007. The impact of an 1,800 increase in the average number of commercial and industrial customers served was offset by an increase in those customers that purchase their energy requirements from an Electricity Service Supplier. 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 increased 1.3% in the six months ended June 30, 2008, with deliveries to residential, commercial, and industrial customers increasing by 1.5%, 0.6%, and 1.9% respectively. PGE projects an approximate 2% increase in total weather adjusted energy deliveries for 2008, with higher use by industrial customers projected during the last half of the year.

Other retail revenues in the first six months of 2008 and 2007 include $9 million and $42 million, respectively, in customer credits under the Residential Exchange Program administered by the BPA, with such amounts 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 increased $11 million, or 14%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007 due to the net effect of the following:

A $30 million increase resulting from a 48% increase in average price, caused by both higher natural gas prices and lower hydro availability; partially offset by

A $19 million decrease resulting from a 23% reduction in wholesale energy sales.

—

Other operating revenues increased $10 million, or 71%, due to sales of fuel oil from the Company’s Beaver generating plant in 2008, which resulted in realized gains of $7 million.

Purchased power and fuel expense for the six months ended June 30, 2008 increased $57 million, or 15%, from the comparable period of 2007. Information about PGE’s total system load and retail load requirement for the periods presented is as follows (in thousands of MWhs):


	Six Months Ended June 30,
	2008		2007
Generation	5,458		3,911
Term purchases	4,824		6,725
Spot purchases	664		616

Total system load	10,946		11,252
Less: wholesale sales	(1,487	)	(1,939	)

Retail load requirement	9,459		9,313

The average variable power cost of the above total system loads was $39.13 and $35.60 per MWh in the first half of 2008 and 2007, respectively, an increase of 10%. 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:

—

An $88 million increase in the cost of thermal (primarily natural gas-fired) production, due to increases in both generation and natural gas prices. During the first half of 2008, PGE’s generation increased by 40% relative to the first half of 2007;

—

A $20 million increase related to the deferral of excess Boardman power costs in the first quarter of 2007, which were incurred in late 2005 and early 2006;

—

A $12 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 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 in the first half of 2007, as a result of a settlement with certain California parties involving transactions in 2000-2001; and

—

A $4 million increase in the estimated amount recorded for potential future refund to customers under the PCAM.

Partially offsetting the above increases was a $76 million decrease due to a 25% reduction in power purchases, related primarily to an increase in thermal and wind generation resulting from the addition of Port Westward and Biglow Canyon Phase I to the Company’s generation portfolio.

Generation activities - In the first half of 2008, PGE generated 58% of its retail load requirement, with 45%, 11%, and 2% from thermal, hydro and wind resources, respectively. In the first half of 2007, the Company generated 42% of its retail load requirement, with 31% from thermal generation and 11% from hydro production. Short- and long-term purchases were utilized to meet the remaining load.

Generation at PGE thermal plants increased by 45% in the first half of 2008 relative to the first half of 2007, primarily due to the addition of Port Westward in June 2007. Additionally, wind generation from Biglow Canyon Phase I contributed 4% of the Company’s generation in 2008. These increases have resulted in reduced reliance on purchased power.

Energy from hydro resources in the first six months of 2008 decreased 5% from the comparable period of 2007, with a 10% reduction in energy received under long-term purchase power agreements from hydro facilities on the mid-Columbia River. Partially offsetting the mid-Columbia reduction was increased production from Company-owned facilities that resulted from higher stream flows.

Production and distribution expense increased $12 million, or 16%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. The increase is due primarily to the following:

•

A $6 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;

•

A $3 million increase resulting from increased repairs and maintenance expenses incurred on the Boardman and Beaver plants in connection with scheduled maintenance activities; and

•

A $2 million increase in distribution labor, contractor and tree trimming costs.

Administrative and other expense increased $4 million, or 4%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007, which is primarily due to an increase in legal settlement expense, higher employee benefit expenses and an increase in the provision for uncollectible accounts during the first half of 2008, compared to a decrease in the comparable period of 2007.

Depreciation and amortization expense increased $12 million, or 14%, for the six months ended June 30, 2008 compared to the six months ended June 30, 2007 primarily due to increased depreciation of $10 million as a result of Port Westward and Biglow Canyon Phase I being placed in service in June 2007 and December 2007, respectively.

Taxes other than income taxes increased $3 million, or 8%, for the six months ended June 30, 2008 compared to the six months ended June 30, 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 decreased $15 million for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. The decrease is primarily due to the following:

•

A $10 million decrease in income from non-qualified benefit plan trust assets resulting from the recognition of a $5 million unrealized loss on the plan assets during the six months ended June 30, 2008, compared to a $5 million unrealized gain in the comparable period of 2007;

•

A $5 million decrease in the allowance for equity funds used during construction, which resulted from lower construction work in progress balance during the first half 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 $11 million, or 31%, for the six months ended June 30, 2008 compared to the six months ended June 30, 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 half of 2008, the average outstanding balance of long-term debt was $1,310 million, compared to $1,096 million for the first half of 2007, which resulted in an increase to interest expense of

approximately $8 million. Additionally, the credit to interest expense for AFDC decreased $3 million as a result of lower construction work in progress balances during the first half of 2008 compared to the first half of 2007.

Income taxes decreased $22 million for the six months ended June 30, 2008, with an effective tax rate of 29%, compared to the six months ended June 30, 2007, with an effective tax rate of 33%. These decreases are primarily the result of lower taxable income and an increase of $5 million in federal energy tax credits generated from the operation of Biglow Canyon Phase I in the first half 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	$	229	$	225-$245		$	225-$245	$	240-$260	$	230-$250
Biglow Canyon Phase II		75		235			-		-		-
Biglow Canyon Phase III		23		180			185		-		-
Hydro relicensing		62		$60 - $80
Advanced Metering Infrastructure		23		$100 - $110					-		-
Boardman emissions controls ⁽¹⁾		3		$5 - $10					$290 - $330

Total capital expenditures	$	415


Long-term debt maturities	$	-	$	142	⁽²⁾	$	186	$	-	$	100

(1) -

Represents 80% of estimated total costs, which assumes the Purchaser does not exercise certain rights pursuant to existing agreements. See Air Quality Standards below.

(2) -

For further information, see “Credit Facility and Long-term Debt” in Note 2, Balance Sheet Components, in the Notes to Condensed Consolidated Financial Statements.

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

Biglow Canyon - In 2008, PGE entered into various agreements for the construction of 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 $45 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.

The Company filed an application with the FERC in 2004 to relicense the Clackamas River hydroelectric projects. A settlement agreement, resolving most of the issues raised in the relicensing proceeding and providing for a 45-year license term, was signed by the thirty-three participating parties in March 2006 and was submitted to the FERC for review and approval. On June 20, 2008, PGE filed an application

with the Oregon Department of Environmental Quality (DEQ) proposing resolution to the final lower Clackamas River temperature issues. Pending approval of the new license, the project will operate under annual licenses issued by the FERC. It is expected that the DEQ will complete its water quality certification process in 2009 and the FERC will issue a new license for the Clackamas River projects in 2010.

In October 2002, PGE entered into an agreement with state and federal agencies, conservation groups, and others regarding removal of the Company’s 22 MW Bull Run hydroelectric project located in the Sandy River basin. During the second quarter of 2008, the project ceased generation, as planned.

Advanced Metering Infrastructure - PGE plans to install over 800,000 new customer meters that will enable two-way remote communications with the Company. On May 5, 2008, the OPUC approved PGE’s AMI project. Approximately 16,000 new meters are being installed as part of the project’s six month acceptance testing phase, with the remaining meters to be installed starting in 2009 through 2010. PGE expects the smart meter project to provide improved services, as well as 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 Best Available Retrofit Technology (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 (100% of the costs) (“Total Cost”) for these controls is estimated to be in the range of $360 million to $470 million. While the Company believes that these controls meet BART requirements, regulatory agencies could require Selective Catalytic Reduction rather than SNCR, which would increase the estimated Total Cost to a range of $570 million to $745 million. Recently the Company has increased its estimates of the Total Costs for these controls, which was primarily driven by increases in commodity prices. PGE has no commitments in place at this time, and cautions that the Total Cost estimates are preliminary and subject to change. Final approval of the plan is expected to occur in the second half of 2009 and expenditures relating to the project are anticipated to be incurred through 2014.

In 1985, PGE entered into a sale transaction in which it sold an undivided 15% interest in Boardman and a 10.714% undivided interest in the Pacific Northwest Intertie (Intertie) transmission line (jointly, the Boardman Assets) to a third party financial institution (Purchaser). The Purchaser leased the Boardman Assets to a lessee (Lessee) unrelated to PGE or the Purchaser. The term of the lease ends on December 31, 2013. Concurrently with the sale, PGE assigned to the Lessee certain agreements for the sale of power and transmission services from Boardman and the Intertie (P&T Agreements) to a regulated electric utility (Utility) unrelated to PGE, the Purchaser, or the Lessee. The payments by the Utility under the P&T Agreements generally cover the payment obligations of the Lessee under the lease, but do not cover all capital expenditures and are not expected to cover a material portion of the costs relating to the emission controls for the Boardman generating plant. The Purchaser has certain rights to finance the portion of the Total Cost attributable to its interest. As a result of these agreements, PGE’s share of the Total Cost for the emission controls on the Boardman generating plant is expected to be 80% if the Purchaser does not exercise its rights under the agreements to finance the portion of the Total Cost attributable to its interest. At the expiration of the lease, and in certain other circumstances, PGE has an option to repurchase the Boardman Assets.

As the regulatory requirements are clarified by the relevant agencies and the related costs more closely estimated, the Company will further evaluate the economic prudency of the Boardman emission control expenditures. In doing so, the Company will also consider additional costs such as taxes, emission fees

and other costs that may be imposed under any future laws related to climate change, as well as the Company’s ability to recover these costs through the ratemaking process. Such additional costs, as well as any requirement to install Selective Catalytic Reduction controls, could require an investment in excess of what the plant can economically support. The ultimate impact that the above regulatory requirements and emission controls will have on future operations, costs, or generating capacity of the Company’s thermal generating plants is not yet determinable.

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 June 30, 2008, the Company has financial assets of $181 million and financial liabilities of $11 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):


	Six Months Ended June 30,
	2008			2007
Cash and cash equivalents at January 1	$	73		$	12
Net cash provided by (used in):
Operating activities		368			201
Investing activities		(204	)		(165	)
Financing activities		(35	)		(6	)

Net increase in cash and cash equivalents		129			30

Cash and cash equivalents at June 30	$	202		$	42

Net cash provided by operating activities increased $167 million in the first half of 2008 compared to the first half of 2007. This increase is primarily due to the following offsetting factors:

—

A $113 million increase in net margin deposits received from certain wholesale customers, which is primarily driven by collateral requirements as a result of increases in power prices, as discussed below;

—

A $26 million decrease in income taxes paid;

—

A $10 million decrease in fuel purchases; and

—

A $7 million increase in employee incentive payments.

During the six months ended June 30, 2008, PGE’s net assets from price risk management activities increased $412 million. These derivative instruments are recorded at their estimated fair value (“mark-to-market”), as discussed in Note 3, Financial Instruments, in the Notes to the Condensed Consolidated Financial Statements. During the first half of 2008, the commodities market experienced significant volatility which resulted in, among other things, increased market prices for purchased power and natural gas. Pursuant to regulatory accounting under SFAS 71, the mark-to-market of PGE’s derivative instruments is deferred, and, accordingly, the Company’s net regulatory liability related to price risk management increased $412 million, with no impact to the statement of operations. The mark-to-market of PGE’s derivative instruments does not have any impact on the Company’s liquidity or cash flows.

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 $208 million in 2008. Combined with all other sources, cash provided by operations is estimated to approximate $403 million in 2008.

Net cash used in investing activities increased $39 million in the first half of 2008 compared to the first half of 2007. This increase is primarily due to the net effect of the following factors:

—

A $43 million increase in expenditures for the Biglow Canyon project;

—

An $18 million increase in expenditures for the Pelton/Round Butte selective water withdrawal system;

—

A $27 million decrease in construction costs for Port Westward, which was completed in June 2007; and

—

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

See “Capital Requirements” section above for further information.

Net cash used in financing activities increased $29 million in the first half of 2008 compared to the first half 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 half 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 $29 million. PGE also issued $50 million of long-term debt in the first half of 2008. During the same period of 2007, net cash used in financing activities primarily consisted of the net repayment of short-term debt of $81 million, the repayment of long-term debt of $71 million and the payment of dividends of $28 million, partially offset by the issuance of long-term debt of $176 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.

Common stock dividends declared during 2008 consist of the following:


Declaration	Record	Payment	Dividends Declared per Share
February 20, 2008	March 25, 2008	April 15, 2008	$	0.235
May 7, 2008	June 25, 2008	July 15, 2008		0.245
August 6, 2008	September 25, 2008	October 15, 2008		0.245

Debt and Equity Financings

PGE has an unsecured $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 is used as a 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. In June 2008, PGE extended the maturity on $390 million of the facility to July 2013 with the remaining $10 million maturing in July 2012.

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 $200 million of equity and additional new long-term debt of $275 million in either late 2008 or in 2009. Furthermore, the Company expects to remarket $142 million of tax-exempt bonds, which have a mandatory tender date of May 1, 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 50.9% and 50.0% as of June 30, 2008 and December 31, 2007, respectively.

For further information regarding PGE’s credit facility and debt financing activities, see “Credit Facility and Long-term Debt” in 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 June 30, 2008, PGE had posted approximately $32 million of collateral, consisting of $4 million in cash and $28 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 June 30, 2008, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $26 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 $39 million and decreases to approximately $4 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 June 30, 2008 it could issue up to approximately $662 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 June 30, 2008, the Company’s consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 49.1%.

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. Obligations

for 2008 and beyond have not changed materially except as presented below. As of June 30, 2008, PGE has the following additional purchase commitments:


	Payments Due
	2008 *		2009		2010		2011		2012		There- after		Total
Purchase obligations	$	-	$	347	$	166	$	-	$	-	$	-	$	513
Natural gas agreements		55		29		15		13		5		-		117
Coal and transportation agreements		-		18		13		10		-		-		41

	$	55	$	394	$	194	$	23	$	5	$	-	$	671

* - Represents the period from July 1, 2008 through December 31, 2008.

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, except as presented below.

The following table presents the credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. As of June 30, 2008, PGE’s credit risk exposure for commodity activities and their subsequent maturity is as follows:


	Credit Risk Before Collateral		As % of Total		Credit Collateral		Maturity of Credit Risk Exposure
	Credit Risk Before Collateral		As % of Total		Credit Collateral		2008 *		2009		2010		2011		2012		There- after
Externally rated:
Investment grade	$	552	99	%	$	242	$	128	$	150	$	85	$	80	$	75	$	34
Non-investment grade		1	-			1		-		1		-		-		-		-
Internally rated:
Investment grade		3	1			3		3		-		-		-		-		-

Total	$	556	100	%	$	246	$	131	$	151	$	85	$	80	$	75	$	34

* - Represents the period from July 1, 2008 through December 31, 2008.

As of June 30, 2008, there was $56 million in posted collateral subject to be returned to a counterparty that is affiliated with master netting arrangements. Posted collateral may be in the form of cash or letters of credit and may represent prepayment.

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 June 30, 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.

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.

This case remains in abatement. A status conference is now scheduled for October 2008. The Circuit Court has set a tentative trial date in April 2009 in the event the Circuit Court lifts the abatement following the OPUC order expected on September 12, 2008. The OPUC order is expected to resolve all issues before the OPUC relating to PGE’s recovery of its Trojan plant costs, including the OPUC’s remedial authority.

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 4.

Submission of Matters to a Vote of Security Holders.

PGE’s 2008 Annual Meeting of Shareholders was held May 7, 2008 to conduct the following items of business:

To elect directors for the coming year;

To ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2008;

To approve the amended and restated Portland General Electric Company 2006 Stock Incentive Plan; and

To approve the Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers.

The following nominees were elected to serve on the board of directors:


Nominee	For	Withheld
John W. Ballantine	56,103,117	817,088
Rodney L. Brown, Jr.	56,219,036	701,169
David A. Dietzler	56,220,997	699,208
Peggy Y. Fowler	56,218,896	701,309
Mark B. Ganz	56,220,525	699,679
Corbin A. McNeill, Jr.	54,219,749	2,700,456
Neil J. Nelson	56,103,539	816,666
M. Lee Pelton	56,102,778	817,427
Maria M. Pope	56,218,139	702,066
Robert T.F. Reid	56,103,311	816,894

The proposal to ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31,2008 was approved and received the following votes: For, 56,547,330; Against, 34,246; and Abstain, 338,628.

The proposal to approve the amended and restated Portland General Electric Company 2006 Stock Incentive Plan was approved and received the following votes: For, 46,913,255; Against, 5,481,607; Abstain, 353,063; and Broker non-votes, 4,172,280.

The proposal to approve the Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers was approved and received the following votes: For, 51,852,044; Against, 530,017; Abstain, 365,864; and Broker non-votes, 4,172,280.

There were no other matters submitted to a vote of shareholders during the second quarter.

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).

4.1		Sixtieth Supplemental Indenture, dated April 1, 2008 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on April 17, 2008).

10.1		Employment Agreement, dated and effective May 6, 2008, between Stephen M. Quennoz and Portland General Electric Company (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on May 7, 2008).

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: August 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)