UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2007
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from _____v___________ to _______________     Commission File Number 1-5532-99
	PORTLAND GENERAL ELECTRIC COMPANY
	(Exact name of registrant as specified in its charter)

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

 

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    X      No ___

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer

[  ]

Accelerated filer

[X]

Non-accelerated filer

[ ]

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

Number of shares of Common Stock outstanding as of October 31, 2007: 62,519,160 shares of common stock, no par value.

Table of Contents

 

	Page Number
Definitions	3
PART I. Financial Information
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	4
Condensed Consolidated Statements of Retained Earnings	5
Condensed Consolidated Statements of Comprehensive Income	6
Condensed Consolidated Balance Sheets	7
Condensed Consolidated Statements of Cash Flows	8
Notes to Condensed Consolidated Financial Statements	9
Item 2.  Management's Discussion and Analysis of
Financial Condition and Results of Operations	26
Item 3.  Quantitative and Qualitative Disclosures
About Market Risk	46
Item 4. Controls and Procedures	49
PART II. Other Information
Item 1. Legal Proceedings	50
Item 1A. Risk Factors	51
Item 6. Exhibits	52
Signature	53

 

 

Definitions

Biglow Canyon	Biglow Canyon Wind Farm
Boardman	Boardman Coal Plant
Colstrip	Colstrip Units 3 and 4 Coal Plant
DEQ	Oregon Department of Environmental Quality
EPA	Environmental Protection Agency
ESS	Electricity Service Supplier
FERC	Federal Energy Regulatory Commission
kWh	Kilowatt-Hour
Mill	One tenth of one cent
MW	Megawatt
MWh	Megawatt-hour
NVPC	Net variable power costs
OPUC	Public Utility Commission of Oregon
PCAM	Power Cost Adjustment Mechanism
PGE or the Company	Portland General Electric Company
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

 

PART I

Financial Information

Item 1. Financial Statements

 

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Income (Unaudited)
		Three Months Ended September 30,					Nine Months Ended September 30,
		2007		2006				2007		2006
	(In Millions, Except per Share Amounts)
Operating Revenues	$	435	$	372		$		1,273	$	1,104
Operating Expenses
Purchased power and fuel		242		198				620		573
Production and distribution		36		34				109		103
Administrative and other		46		40				136		119
Depreciation and amortization		46		55				134		165
Taxes other than income taxes		20		19				60		57
Income taxes		10		6				59		20
		400		352				1,118		1,037
Net Operating Income		35		20				155		67
Other Income (Deductions)
Allowance for equity funds used during construction		4		4				13		11
Miscellaneous		2		3				10		1
Income taxes		(2)		-				(3)		1
		4		7				20		13
Interest Charges
Interest on long-term debt and other		19		17				54		49
Net Income	$	20	$	10		$		121	$	31
Common Stock:
Weighted-average shares outstanding (thousands), Basic		62,516		62,500				62,509		62,500
Weighted-average shares outstanding (thousands), Diluted		62,542		62,505				62,534		62,502
Earnings per share, Basic and Diluted	$	0.32	$	0.16		$		1.93	$	0.50
Dividends declared per share	$	0.235	$	0.225		$		0.695	$	0.45
The accompanying notes are an integral part of these condensed consolidated financial statements.

 

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Retained Earnings (Unaudited)
		Three Months Ended September 30,					Nine Months Ended September 30,
		2007		2006			2007		2006
	(In Millions)
Balance at Beginning of Period	$	659	$	565		$	587	$	558
Net Income		20		10			121		31
		679		575			708		589
Dividends Declared - Common Stock		15		14			44		28
Balance at End of Period	$	664	$	561		$	664	$	561
The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Comprehensive Income (Unaudited)
	Three Months Ended September 30,					Nine Months Ended September 30,
		2007		2006			2007		2006
	(In Millions)
Accumulated other comprehensive income (loss) - Beginning of Period
Unrealized gain (loss) on derivatives classified as cash flow hedges	$	-	$	(2)		$	-	$	-
Minimum pension liability adjustment		*		(3)			*		(3)
Pension and other post-retirement plan's funded position		(6)		*			(6)		*
Total	$	(6)	$	(5)		$	(6)	$	(3)
Net Income	$	20	$	10		$	121	$	31
Other comprehensive income, net of tax
Unrealized gains (losses) on derivatives classified as cash flow hedges:
Other unrealized holding net gains (losses) arising during the period, net of related taxes of $2 and $5 for the three months ended September 30, 2007 and 2006 and $2 and $17 for the nine months ended September 30, 2007 and 2006		(3)		(7)			(3)		(27)
Reclassification adjustment for contract settlements included in net income, net of related taxes of $(1) and $1 for the three months ended September 30, 2007 and 2006 and $2 and $5 for the nine months ended September 30, 2007 and 2006		1		(1)			(3)		(7)
Reclassification of unrealized gains (losses) to SFAS No. 71 regulatory (liability) asset, net of related taxes of $(1) and $(5) for the three months ended September 30, 2007 and 2006 and $(4) and $(21) for the nine months ended September 30, 2007 and 2006		2		8			6		32
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges		-		-			-		(2)
Minimum pension liability adjustment		*		-			*		-
Pension and other post-retirement plan's funded position, net of related taxes of $(1) for the three months ended September 30, 2007 and $(1) for the nine months ended September 30, 2007		1		*			1		*
Reclassification of defined benefit pension plan and other benefits to SFAS No. 71 regulatory asset, net of related taxes of $1 for the three months ended September 30, 2007 and $1 for the nine months ended September 30, 2007		(1)		*			(1)		*
Total Other comprehensive income (loss)		-		-			-		(2)
Comprehensive income	$	20	$	10		$	121	$	29
Accumulated other comprehensive income (loss) - End of Period
Unrealized gain (loss) on derivatives classified as cash flow hedges	$	-	$	(2)		$	-	$	(2)
Minimum pension liability adjustment		*		(3)			*		(3)
Pension and other post-retirement plan's funded position		(6)		*			(6)		*
Total	$	(6)	$	(5)		$	(6)	$	(5)
* With the adoption of SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, at December 31, 2006, certain information is no longer applicable. Similarly, certain information for 2007 was not previously applicable.
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited)
		September 30,			December 31,
		2007			2006
	(In Millions, Except Share Amounts)
Assets
Electric Utility Plant - Original Cost
Utility plant (includes construction work in progress of $357 and $412)	$	4,942		$	4,582
Accumulated depreciation		(1,936)			(1,864)
		3,006			2,718
Other Property and Investments
Nuclear decommissioning trust, at market value		45			42
Non-qualified benefit plan trust		71			70
Miscellaneous		22			26
		138			138
Current Assets
Cash and cash equivalents		60			12
Accounts and notes receivable (less allowance for uncollectible accounts of $5 and $45)		172			177
Unbilled revenues		64			88
Assets from price risk management activities		65			93
Inventories, at average cost		63			64
Margin deposits		39			46
Prepayments and other		40			25
Deferred income taxes		20			22
		523			527
Deferred Charges
Regulatory assets		385			351
Miscellaneous		36			33
		421			384
	$	4,088		$	3,767
Capitalization and Liabilities
Capitalization
Common stock equity:
Common stock, no par value, 80,000,000 shares authorized; 62,519,160 and 62,504,767 shares outstanding at September 30, 2007 and December 31, 2006, respectively	$	645		$	643
Retained earnings		664			587
Accumulated other comprehensive income (loss):
Pension and other post-retirement plans		(6)			(6)
Long-term debt		1,238			937
		2,541			2,161
Commitments and Contingencies (see Notes)
Current Liabilities
Long-term debt due within one year		-			66
Short-term borrowings		-			81
Accounts payable and other accruals		215			212
Liabilities from price risk management activities		121			155
Customer deposits		5			5
Accrued interest		21			15
Accrued taxes		59			14
Dividends payable		15			14
		436			562
Other
Deferred income taxes		275			251
Deferred investment tax credits		4			7
Trojan asset retirement obligation		111			108
Accumulated asset retirement obligation		21			26
Regulatory liabilities:
Accumulated asset retirement removal costs		445			411
Other		118			112
Non-qualified benefit plan liabilities		87			84
Miscellaneous		50			45
		1,111			1,044
	$	4,088		$	3,767
The accompanying notes are an integral part of these condensed consolidated financial statements.

Portland General Electric Company and Subsidiaries Condensed Consolidated Statements of Cash Flows (Unaudited)
			Nine Months Ended
			September 30,
			2007				2006
			(In Millions)
Cash Flows From Operating Activities:
Reconciliation of net income to net cash provided by operating activities
Net income			$	121			$	31
Non-cash items included in net income:
Depreciation and amortization					134			165
Deferred income taxes					20			(35)
Net assets from price risk management activities					(16)			138
Power cost deferrals					(10)			-
Regulatory deferrals - price risk management activities					16			(125)
Allowance for equity funds used during construction					(13)			(11)
Senate Bill 408 deferrals					(9)			32
Other non-cash income and expenses (net)					(5)			13
Changes in working capital:
Net margin deposit activity					7			(71)
Decrease in receivables					29			56
Increase (Decrease) in payables					41			(62)
Other working capital items - net					(15)			(27)
Other - net					(9)			6
Net Cash Provided by Operating Activities					291			110
Cash Flows From Investing Activities:
Capital expenditures					(351)			(269)
Purchases of nuclear decommissioning trust securities					(19)			(30)
Sales of nuclear decommissioning trust securities					17			16
Other - net					2			3
Net Cash Used in Investing Activities					(351)			(280)
Cash Flows From Financing Activities:
Short-term borrowings (repayments) - net					(81)			-
Repayment of long-term debt					(71)			(161)
Issuance of long-term debt (net of issuance costs of $3 and $2)					303			273
Dividends paid					(43)			(14)
Net Cash Provided by Financing Activities					108			98
Increase (Decrease) in Cash and Cash Equivalents					48			(72)
Cash and Cash Equivalents, Beginning of Period					12			122
Cash and Cash Equivalents, End of Period			$	60			$	50
Supplemental disclosures of cash flow information
Cash paid during the period:
Interest, net of amounts capitalized			$	37			$	38
Income taxes				30				73
Non-cash activities:
Accrued capital additions				33				23
Common stock dividends declared but not paid				15				14
The accompanying notes are an integral part of these condensed consolidated financial statements.

Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 1 - Principles of Interim Statements

The interim financial statements have been prepared by Portland General Electric Company (PGE or the Company) and, in the opinion of management, reflect all adjustments which are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Such statements, which are unaudited, are presented in accordance with the interim reporting requirements of the Securities and Exchange Commission (SEC), which do not include all the disclosures required by accounting principles generally accepted in the United States of America for annual financial statements. Certain information and footnote disclosures made in the last annual report on Form 10-K have been condensed or omitted for the interim statements. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, interim financial results do not necessarily represent those to be expected for the year. It is management's opinion that, when the interim statements are read in conjunction with the Company's 2006 Annual Report on Form 10-K filed with the SEC, the disclosures are adequate to make the information presented not misleading.

Reclassifications - Certain amounts in the financial statements have been reclassified for comparative purposes. Specifically, "Allowance for equity funds used during construction," previously classified within "Other Income (Deductions) - Miscellaneous" on the Condensed Consolidated Statements of Income, is now reported separately. In addition, "Allowance for equity funds used during construction" and "Senate Bill 408 deferrals," previously classified within "Other non-cash income and expenses (net)" on the Condensed Consolidated Statements of Cash Flows, are now reported separately. These reclassifications had no material effect on PGE's previously reported consolidated financial position, results of operations, or cash flows.

 

Note 2 - Employee Benefits

Pension and Other Post-Retirement Plans

Defined Benefit Pension Plan - PGE sponsors a non-contributory defined benefit pension plan, the assets of which are held in a trust. Pension plan calculations include several assumptions which are reviewed annually and updated as appropriate.

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

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

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

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

Three Months Ended September 30:		Defined Benefit Pension Plan								Non-Qualified Benefit Plans				Other Benefits
		2007					2006			2007		2006		2007			2006
Components of net periodic benefit cost:
Service cost	$	3		$			3	$		-	$	-	$	-	$		-
Interest cost on benefit obligation		7					7			-		1		1			1
Expected return on plan assets		(11)					(10)			(2)		(1)		-			-
Amortization of transition assets		-					-			1		-		-			-
Amortization of prior service cost		1					-			-		-		-			-
Recognized (gain) loss		1					1			-		-		-			-
Net periodic benefit cost (income)	$	1		$			1	$		(1)	$	-	$	1	$		1
Nine Months Ended September 30:		Defined Benefit Pension Plan							Non-Qualified Benefit Plans					Other Benefits
		2007				2006			2007			2006		2007		2006
Components of net periodic benefit cost:
Service cost	$	9	$			9		$		-	$	-	$	1	$	-
Interest cost on benefit obligation		21			21					1		1		3		3
Expected return on plan assets		(32)			(30)					(3)		(2)		-		-
Amortization of transition assets		-				-				1		-		-		-
Amortization of prior service cost		1				-				-		-		-		-
Recognized (gain) loss		3				3				-		1		-		-
Net periodic benefit cost (income)	$	2	$			3		$		(1)	$	-	$	4	$	3

 

Note 3 - Price Risk Management

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

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

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

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

Prior to December 2006, PGE recorded a regulatory asset or regulatory liability under SFAS No. 71 to offset unrealized gains and losses on certain non-trading contracts recorded prior to settlement to the extent that such contracts were included in the Company's Resource Valuation Mechanism (RVM). Upon settlement, the regulatory asset or regulatory liability was reversed. In its January 2007 general rate order, the Public Utility Commission of Oregon (OPUC) approved a new Annual Power Cost Update Tariff, which replaced the RVM, and a new Power Cost Adjustment Mechanism (PCAM) by which PGE can adjust future prices to reflect the difference between each year's forecasted and actual net variable power costs (NVPC) on a settlement basis. As a result, a regulatory asset or regulatory liability is now recorded to offset changes in fair value of derivative instruments.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Non-Trading Activities
Unrealized gains (losses)	$	(18)		$	(46)		$	16		$	(138)
SFAS No. 71 regulatory asset (liability)		18			58			(16)			125
Net unrealized gains (losses)	$	-		$	12		$	-		$	(13)

 

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Derivative Activities Recorded in OCI
Unrealized holding net gains (losses) arising during the period	$	(5)		$	(12)		$	(5)		$	(44)
Reclassification adjustment for contract settlements included in net income		2			(2)			(5)			(12)
Reclassification of unrealized (gains) losses to SFAS No. 71 regulatory (liability) asset		3			13			10			53
Total - Unrealized gains (losses) on derivatives classified as cash flow hedges	$	-		$	(1)		$	-		$	(3)

 

Hedge ineffectiveness from cash flow hedges was not material in the first nine months of 2007 and 2006. As of September 30, 2007, the maximum length of time over which PGE is hedging its exposure to such transactions is approximately 48 months. The Company estimates that of the $5 million of net unrealized losses in OCI at September 30, 2007, $7 million in net unrealized losses will be reclassified into earnings within the next twelve months (fully offset by SFAS No. 71 regulatory assets) and $2 million in net unrealized gains will be reclassified over the remaining 36 months (fully offset by SFAS No. 71 regulatory liabilities).

 

Note 4 - Contingencies

Legal Matters

Trojan Investment Recovery - 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 OPUC. In 1995, the OPUC issued a general rate order which granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs, and full recovery of its estimated decommissioning costs through 2011.

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

In 2000, while the petitions for review of the 1998 Oregon Court of Appeals decision were pending at the Oregon Supreme Court, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE's recovery of, and return on, its investment in the Trojan plant. The URP did not participate in the settlement. The settlement, which was approved by the OPUC in September 2000, allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities. The largest of such amounts consisted of before-tax credits of approximately $79 million in customer benefits related to the previous settlement of power contracts with two other utilities and the approximately $80 million remaining credit due customers under terms of the 1997 merger of the Company's parent corporation at the time (Portland General Corporation) with Enron 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.

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 have appealed the 2003 Remand to the Oregon Court of Appeals. On October 10, 2007, the Oregon Court of Appeals issued an opinion that vacated the 2003 Remand and remanded the 2002 Order to the OPUC for reconsideration.

Prior to the October 10, 2007 opinion of the Court of Appeals, the OPUC combined the 1998 Remand and the 2003 Remand into one proceeding and has been considering the matter in two phases. The first phase involves a determination of what prices would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. The second phase involves a determination of whether the OPUC has authority to engage in retroactive ratemaking.

In Order No. 07-157 (the Order), entered on April 19, 2007, the OPUC denied the motion PGE filed in November 2006 to consolidate phases and re-open the record. In addition, the Order abated the first phase of the proceeding pending a decision by the Oregon Court of Appeals on the 2003 Remand, and ordered that the second phase of the remand proceeding be immediately commenced to investigate the OPUC's authority to engage in retroactive ratemaking. The Order further stated that parties not now participating in the joint remand proceedings will be allowed to intervene and participate in the second phase. Oral argument was held on August 9, 2007.

In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers. One case seeks to represent current PGE customers that were customers during the period from April 1, 1995 to October 1, 2000 (Current Class) and the other case seeks to represent PGE customers that were customers during the period from April 1, 1995 to October 1, 2000, but who are no longer customers (Former Class, together with the Current Class, the Class Action Plaintiffs). The suits seek damages of $190 million for the Current Class and $70 million for the Former Class, as a result of the inclusion of a return on investment of Trojan in the 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 Supreme Court further stated that if the OPUC determines that it can provide a remedy to PGE's customers, then the class action proceedings may become moot in whole or in part, but if the OPUC determines that it cannot provide a remedy, and that decision becomes final, the court system may have a role to play. The Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. On October 5, 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions, but inviting motions to lift the abatement after one year. On October 17, 2007, the plaintiffs filed a motion to lift the abatement. PGE's response is due on November 5, 2007.

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

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

Regulatory Matters

Port Westward Generating Plant - In January 2007, the OPUC issued an order approving a 2.8% price increase related to cost recovery of PGE's Port Westward Generating Plant (Port Westward), a 400 MW natural gas-fired facility located in Clatskanie, Oregon, to be effective when the plant was placed in service. In the order, the OPUC also established a process for re-examining the price increase if the plant's in service date was on or after May 2, 2007. The OPUC staff and intervenors were permitted, within 15 days of the in service date of the plant, to request a re-examination of the costs of Port Westward reflected in PGE's prices. On June 11, 2007, Port Westward was placed into service at a total cost of approximately $280 million (including allowance for funds used during construction), and the new prices went into effect on June 15, 2007. CUB had requested a re-examination of the new prices. On October 22, 2007, the OPUC issued an order denying the request for re-examination and allowing the prices to go into effect on a permanent basis.

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 (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 which asserted underpayment of royalties and taxes by WECO related to transportation of coal from the mine to Colstrip during the period October 1991 through December 2001. WECO subsequently appealed the two orders to the Minerals Management Service (MMS) of the U.S. Department of the Interior. On March 28, 2005, the appeal by WECO was substantially denied. On April 28, 2005, WECO appealed the decision of the MMS to the Interior Board of Land Appeals of the U.S. Department of the Interior. In late September 2006, WECO received an additional order from the Office of Minerals Revenue Management to report and pay additional royalties for the period 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.

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. The owners of Colstrip advised WECO that their position would be that these claims are not allowable costs under either the Coal Supply Agreement or the Transportation Agreement.

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

Refunds on Wholesale Market Transactions in the Pacific Northwest - On July 25, 2001, the Federal Energy Regulatory Commission (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. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision on appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC (i) to address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) to include sales to CERS in its analysis, and (iii) to further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC's findings based on the record established by the administrative law judge and declined to reach the merits of the FERC's ultimate decision to deny refunds. On September 18, 2007, the Ninth Circuit deferred the deadline for parties to file for rehearing until November 16, 2007.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, 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.

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

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 contends 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. For further information, see Note 5, Utility Rate Treatment of Income Taxes.

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 is superfluous to the Complainants' request for deferred accounting. The order requires 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. PGE is to submit these calculations to the OPUC by December 1, 2007. The order also provides that the OPUC will 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 its earnings over a relevant twelve-month period, which will include the Deferral Period. After consideration of these matters, the OPUC will determine whether a rate adjustment is required. The OPUC decision is expected prior to June 1, 2008. 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.

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

Environmental Matters

Harborton - Since 1973, PGE has operated the Harborton Substation on land owned by the Company located near the Willamette River. A 1997 investigation by the Environmental Protection Agency (EPA) of a 5.5 mile segment of the river, known as the Portland Harbor, revealed significant contamination of sediments within the harbor. The EPA subsequently included the Portland Harbor on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund).

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

In February 2002, PGE provided a report on its remedial investigation of the Harborton Substation site to the Oregon Department of Environmental Quality (DEQ). The report concluded that there is no likely present or past source or pathway for release of hazardous substances to surface water or sediments in the Portland Harbor Superfund Site at or from the site and that the site does not present a high priority threat to present and future public health, safety, welfare, or the environment. The DEQ submitted the report to the EPA and, in a May 18, 2004 letter, the EPA notified the DEQ that, based on the summary information from the DEQ and the stage of the process, the EPA, as of that time, agreed that the Harborton Substation site does not appear to be a current source of contamination to the river.

In a December 6, 2005 letter, the DEQ notified PGE that the site is not likely a current source of contamination to the river and that the site is a low priority for further action. On October 17, 2007, the EPA notified PGE of a meeting to be held on November 7, 2007 regarding the convening of the process for allocation of costs for investigation and remediation activities. Management believes that the Company's contribution to the sediment contamination, if any, from the Harborton Substation site would qualify it as a de minimis PRP.

Sufficient information is currently not available to determine the total cost of any required investigation or remediation of the Portland Harbor or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, it believes this matter will not have a material adverse impact on the Company's financial condition, results of operations or cash flows.

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

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

PGE received a Special Notice Letter for Remedial Investigation/Feasibility Study (RI/FS) from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. The letter started a period for the PRPs to participate in negotiations with the EPA to reach a settlement to conduct or finance an RI/FS of the Harbor Oil site. On May 31, 2007, an Administrative Order on Compliance was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site.

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.

 

Note 5 - Utility Rate Treatment of Income Taxes

An Oregon law, commonly referred to as SB 408, attempts to more closely match income tax amounts forecasted to be collected in revenues with the amount of income taxes paid to governmental entities by investor-owned utilities or their consolidated group. The law requires that utilities file a report with the OPUC each year regarding the amount of taxes paid by the utility or its consolidated group (with certain adjustments), as well as the amount of taxes authorized to be collected in rates, as defined by the statute. This report is to be filed by October 15th of the year following the reporting year.

If the OPUC determines that the difference between the two amounts is greater than $100,000, the utility is required to establish an "automatic adjustment clause" to adjust rates. The first adjustment under the automatic adjustment clause applies to taxes paid to units of government and collected from customers on or after January 1, 2006.

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

In accordance with the statute, PGE filed a report with the OPUC on October 15, 2007 for the 2006 tax year, reflecting the amount of taxes paid by the Company as well as the amount of taxes authorized to be collected in rates, as defined by the statute. As of September 30, 2007, PGE has recorded a refund to customers of approximately $44 million for the 2006 tax year, including $4 million of accrued interest. This amount also includes a $1 million third quarter 2007 true up to reduce the estimated refund for 2006. The regulatory liability includes $17 million paid to Enron Corp. for net current taxes payable for the first quarter of 2006 when PGE was included in its former parent's consolidated group for filing consolidated federal and state income tax returns. Under the OPUC rules, refunds to customers for the 2006 tax year will begin June 1, 2008.

For the year 2007, PGE estimates a collection from customers of approximately $14 million. Based on a percentage of estimated annual revenues collected in the first nine months of the year, PGE has recorded credits to income and a regulatory asset of approximately $10 million, including $0.4 million of accrued interest through September 30, 2007. Any collections from, or refunds to, customers for the 2007 tax year will be reported in the Company's October 15, 2008 filing with the OPUC.

 

Note 6 - Common Stock

Employee Stock Purchase Plan

In May 2007, PGE shareholders approved the Portland General Electric Company 2007 Employee Stock Purchase Plan (ESPP). A total of 625,000 shares have been registered for future issuance pursuant to the ESPP. The ESPP permits all eligible Company employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 worth of stock (based on fair market value on the purchase date) or 1,500 shares, whichever is less. Each year during the term of the ESPP there will be two six-month offering periods, during which eligible employees will have the right to purchase shares of PGE common stock at a price per share equal to 95% of the fair market value of the stock on the purchase date. The offering periods will run from January 1 through June 30 and from July 1 through December 31, with shares purchased at the end of each offering period. The first offering period began on July 1, 2007.

Dividends on Common Stock

The following table indicates common stock dividends declared through September 30, 2007:

Declaration Date		Record Date		Payment Date		Dividends Declared per Common Share
February 22, 2007		March 26, 2007		April 16, 2007		$0.225
May 2, 2007		June 25, 2007		July 16, 2007		$0.235
August 2, 2007		September 25, 2007		October 15, 2007		$0.235

 

Note 7 - Stock-Based Compensation

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

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

Performance Stock Units granted to both officers and key employees vest if performance goals related to overall customer satisfaction, electric service power quality and reliability, generating plant availability, and net income (compared to budget) are met at the end of a three-year performance period. Vesting of Performance Stock Units will be calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE's Board of Directors. The performance percentage will be calculated based on whether and to what extent the performance goals have been met. In accordance with the Plan, however, in determining results relative to these goals, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

Outstanding Restricted and Performance Stock Units provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. A DER entitles the grantee to receive an amount equal to dividends paid on a share of PGE's common stock. The Performance Stock Unit DERs vest on the same schedule as the Performance Stock Units and are settled in shares of PGE common stock valued at the closing stock price on the vesting date. The Restricted Stock Unit DERs vest on the same schedule as the Restricted Stock Units and are settled in shares of PGE common stock valued at the closing stock price on the dividend payment date.

Restricted Stock Units granted to non-employee directors vest over a one-year period in equal installments on the last day of each calendar quarter and are settled exclusively in shares of the Company's common stock, provided that the director remains a member of the Board of Directors. The non-employee director grants also provide for the quarterly payment of DERs on the outstanding Restricted Stock Units. The DERs are settled in cash on the date that the related dividends are paid to holders of PGE's common stock. The cash from the settlement of the DERs may also be deferred under the terms of the Portland General Electric Company 2006 Outside Directors' Deferred Compensation Plan.

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

	Non-employee Directors						Officers and Key Employees
	Units			Weighted Average Grant Date Fair Value			Units			Weighted Average Grant Date Fair Value
Restricted Stock Units:
Stock units outstanding - December 31, 2006	4,741			$25.31			86,201			$24.96
Stock units granted:
March 15, 2007	525			28.55			5,600			28.55
June 13, 2007	9,801			27.54			1,089			27.54
Stock units forfeited	-			-			(6,244)			25.19
Stock units vested	(7,714)			25.63			(9,998)			24.96
Stock units outstanding - September 30, 2007	7,353			27.54			76,648			25.24

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

	Officers and Key Employees
	Units		Weighted Average Grant Date Fair Value
Performance Stock Units:
Stock units outstanding - December 31, 2006	89,238		$24.96
Stock units granted - March 15, 2007	83,410		28.55
Stock units forfeited	-		-
Stock units vested	-		-
Stock units outstanding - September 30, 2007	172,648		26.69

The weighted average fair value is measured based on the closing price of PGE common stock on the date of grant. A total of 4,408,372 shares remain available for future grants. The Plan had no material impact on cash flow for the nine months ended September 30, 2007.

For the nine months ended September 30, 2007, PGE recorded $2.0 million of stock-based compensation expense (included in Administrative and other expense in the Condensed Consolidated Statements of Income), with a corresponding credit to common stock equity. No equity compensation costs were capitalized. Based upon the attainment of performance goals that would allow the vesting of 100% and 115% of awarded Performance Stock Units for 2007 and 2006 grants, respectively, and utilizing an estimated forfeiture rate of 3%, unrecognized compensation expense related to unvested Stock Units was $4.5 million at September 30, 2007, of which $0.6 million, $2.6 million, and $1.3 million is expected to be expensed in 2007, 2008, and 2009, respectively.

PGE expects to grant Restricted Stock Units to non-employee directors as part of their annual compensation arrangement. It is also anticipated that Restricted Stock Unit or Performance Stock Unit grants will be made to PGE officers and key employees in future years, resulting in "overlapping" vesting periods and an increase in recorded compensation expense and common stock equity.

Note 8 - Earnings Per Share

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

		Three Months Ended September 30,					Nine Months Ended September 30,
		2007		2006			2007		2006
Numerator:
Net Income (in millions)	$	20	$	10		$	121	$	31
Denominator (in thousands):
Weighted-average common shares outstanding-basic		62,516		62,500			62,509		62,500
Effect of dilutive securities:
Restricted Stock*		26		5			25		2
Weighted-average common shares outstanding-diluted		62,542		62,505			62,534		62,502
Earnings per share - basic and diluted	$	0.32	$	0.16		$	1.93	$	0.50
* Restricted Stock Units and related Dividend Equivalent Rights granted under the Portland General Electric Company 2006 Stock Incentive Plan are discussed in Note 7, Stock-Based Compensation. Unvested Performance Stock Units are not included in the computation of dilutive securities because the units are subject to a three-year performance period.

 

Note 9 - Credit Facility and Debt

To meet short-term cash requirements, PGE has established a program under which it may from time to time issue commercial paper for terms of up to 270 days. The commercial paper program is supported by the Company's $400 million five-year unsecured revolving credit facility, which has been extended for one additional year, to July 13, 2012. The amount available under the program is limited to the unused line of credit under the facility. In addition to borrowings, the credit facility also allows PGE to issue standby letters of credit. At September 30, 2007, PGE had $14 million of outstanding letters of credit backed by the facility, with $386 million of remaining borrowing capacity available, compared to $313 million at December 31, 2006. The facility contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. At September 30, 2007, PGE was in compliance with these covenants.

Although the commercial paper program subjects the Company to fluctuations in interest rates, reflecting current market conditions, individual instruments carried a fixed rate during their respective terms.

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

		September 30,			December 31,
		2007			2006
Aggregate short-term debt outstanding -
Commercial paper			$ -			$    81
Weighted average interest rate -
Commercial paper*			-			5.5%

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007					2006
Average daily amounts of short-term debt outstanding -
Commercial paper	$	32		$	-		$	29				$	11
Weighted daily average interest rate -
Commercial paper*		5.9%			-			5.6%					4.9%
Maximum amount outstanding during the period -
Commercial paper	$	86		$	-		$	93				$	57

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

PGE has authorization from the FERC to issue short-term debt, in an amount not to exceed $400 million outstanding at any one time, over the two-year period through February 7, 2008. The Company intends to seek extension of the FERC authorization during the fourth quarter of 2007. In addition, PGE filed a shelf registration statement with the SEC in June 2007 for the purpose of issuing common stock and first mortgage bonds from time to time as determined in light of market conditions and other factors, the proceeds from which will be used to fund planned capital and other expenditures.

On September 19, 2007, PGE received $130 million from the sale of 5.81% First Mortgage Bonds, which mature on October 1, 2037, to certain institutional buyers in the private placement market, pursuant to an agreement entered into in April 2007. Proceeds from the sale of the bonds will be used for general corporate purposes, which may include capital expenditures and/or the repayment of existing debt.

On October 4, 2007, PGE and certain institutional buyers in the private placement market entered into an agreement under which the Company will sell to the buyers $75 million of 5.80% First Mortgage Bonds, which mature on March 1, 2018. The bonds are expected to be issued on December 12, 2007, but may be issued on another date if mutually agreed upon by the buyers and PGE.

 

Note 10 - Guarantees

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

 

Note 11 - Income Taxes

PGE adopted FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109, on January 1, 2007. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. It requires that a tax position meet a "more-likely-than-not" threshold before the benefit of an uncertain tax position can be recognized in the financial statements. FIN 48 requires recognition in the financial statements of the largest amount of benefit that has a greater than 50% probability of being realized and sustained on audit by the appropriate taxing authorities, based solely on its technical merits. Based on such assessment, PGE has not recorded any liability for uncertain tax positions.

PGE files income tax returns in the U.S federal jurisdiction, the states of Oregon and Montana, and certain local jurisdictions. The Company is not currently under examination by federal, state or local tax authorities. Open tax years include 2004 and subsequent years for federal tax purposes and 2003 and subsequent years for state and local tax purposes.

 

Note 12 - New Accounting Standards

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

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115, was issued in February 2007 and is effective for fiscal years beginning after November 15, 2007. SFAS No. 159 provides entities the option to report most financial assets and liabilities at fair value, with changes in fair value recorded in earnings. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. PGE is evaluating the application of SFAS No. 159 with respect to its financial assets and liabilities.

FASB Staff Position No. 39-1 (FSP FIN 39-1), Amendment of FASB Interpretation No. 39 (FIN 39), was issued in April 2007 and is effective for fiscal years beginning after November 15, 2007. FSP FIN 39-1 modifies FIN 39, Offsetting of Amounts Related to Certain Contracts, and permits reporting entities to offset the receivable or payable recognized upon payment or receipt of cash collateral against fair value amounts 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 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 is evaluating the application of FSP FIN 39-1 with respect to its assets and liabilities.

Item 2. Management's Discussion and Analysis of Financial

Condition and Results of Operations

Information Regarding 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 identify forward-looking statements.

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

In addition to 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 NVPC and other capital investments, and current or prospective wholesale and retail competition;
• the outcome of legal and regulatory proceedings and issues, including the Trojan Investment Recovery and the Pacific Northwest Refunds proceedings, described in Note 4, 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 potentially serious impact on PGE's ability and cost to procure adequate supplies of fuel or purchased power to serve its customers;
• operational factors affecting PGE's power generation facilities including outages, unplanned forced outages, hydro conditions, wind conditions, and disruption of fuel supply;
• wholesale energy prices (including the effect of FERC price controls) 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 result in requirements for additional pollution control equipment or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, to mitigate carbon dioxide and other gas emissions, including regional haze and mercury emissions, affecting the future operations of the Company's thermal generating plants;
• capital market conditions, including interest rate fluctuations, and changes in PGE's credit ratings, which could have an impact on the cost of capital and the ability of PGE to access the capital markets to support requirements for working capital, construction costs, and the repayment of maturing debt;
• the effectiveness of PGE's risk management policies and procedures and the creditworthiness of customers and counterparties;
• the failure to complete major generating plants on schedule and within budget;
• the effects of Oregon law related to utility rate treatment of income taxes (SB 408), which may result in earnings volatility and adverse effects on results of operations;
• changes in, and compliance with, environmental and endangered species laws and policies;
• the effects of global warming or climate change, including changes in the environment that may affect energy costs or consumption and changes in laws or regulations related to greenhouse gas emissions that may increase the Company's costs or affect its operations;
• new federal, state, and local laws that could have adverse effects on operating results;
• employee workforce factors, including strikes, work stoppages, and the loss of key executives;
• general political, economic, and financial market conditions;
• the outcome of efforts to relicense the Company's hydroelectric projects, as required by the FERC;
• natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind, and fire;
• acts of war or terrorism; and
• financial or regulatory accounting principles or policies imposed by governing bodies.

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

 

Overview

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. The 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, 2006, and other periodic and current reports filed with the Securities and Exchange Commission.

PGE is a vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon, as well as the wholesale sale of electricity and natural gas in the western United States and Canada. PGE generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The Company's revenues and operating income are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, and customer usage patterns. PGE is a winter peaking utility typically experiencing its highest retail energy sales in response to the winter heating season, with a slightly lower peak in the summer which generally results from the demand for air conditioning.

PGE utilizes its own generating resources, along with wholesale market purchases, to meet the energy needs of its customers. In June 2007, the Company added the 400 MW capacity Port Westward plant to its generating portfolio, reducing PGE's dependence on the wholesale energy market. The Company has a generation excellence program that focuses on cost effective and reliable plant operations.

Factors that can affect the availability and price of purchased power and fuel include weather conditions in the Northwest and Southwest, the performance of major generating facilities in both regions, regional hydro conditions, and prices of natural gas and coal used to fuel thermal generating plants. Market prices of natural gas can also be affected by destructive storms and extreme weather in other regions of the United States.

PGE periodically evaluates the need to align its general rate structure to sufficiently cover its operating costs and provide a reasonable rate of return. Preliminary indications are that the Company may file a general rate case in early 2008, based on a 2009 test year, with new prices to be effective beginning in January 2009.

Oregon's economy continued to expand in the first nine months of 2007, as the state's non-farm employment (seasonally adjusted) grew 1.4% and reached a new record level in August. The state's 5.2% seasonally adjusted unemployment rate in 2007 is below last year's 5.4% average rate. The ongoing strength of Oregon's economy has contributed to customer growth that is expected to require continued investment in generation, transmission and distribution facilities to meet increased energy requirements of PGE's customers. As of September 30, 2007, the Company served approximately 804,000 retail customers. Load growth forecasts provided to the OPUC in October indicate an overall 3%, weather adjusted, increase in energy deliveries in 2008. Higher commercial demand and increased deliveries to industrial customers, including new pharmaceutical and solar panel manufacturers, are expected to more than offset a slowdown in the housing market and lower residential use due to conservation and energy efficiency efforts.

The Company's 2007 Integrated Resource Plan (IRP) describes the Company's strategy to meet the long-term electric energy needs of its customers, with emphasis on supply reliability and price stability. The plan includes additional renewable resources, energy efficiency, demand-side resources, power purchase agreements of varying terms, and the acquisition of additional peaking capacity. Implementing the IRP will provide opportunities to grow the Company through investments that benefit customers by securing future power supplies at the lowest possible cost and risk. New Renewable Energy Standards adopted by the 2007 Oregon legislature require that PGE and other large electricity providers serve at least 25% of their retail load within the state from renewable resources by the year 2025. The Company continues with construction of new wind generation facilities at the Biglow Canyon Wind Farm (Biglow Canyon), which is expected to have a total installed capacity of 400 to 450 MW. The project is to be completed in three phases with Phase I expected to be completed by the end of 2007. Phases II and III are expected to be completed by the end of 2009 and 2010, respectively.

PGE is currently engaged in two major efforts that it expects will benefit customers. First, the Company has a customer focus initiative that seeks to meet customer expectations for service and reliability. Second, during the third quarter of 2007, the Company signed contracts with vendors for the purchase and installation of an Advanced Metering Infrastructure (AMI) system. Subject to Board of Directors and regulatory approvals, PGE will deploy AMI for residential and commercial customers between 2008 and 2010, achieving operational savings through increased efficiencies along with providing new services for customers. Customer benefits would include the ability to curtail usage during peak periods, remote interaction with smart appliances, and access to usage patterns.

The Company issued $130 million of First Mortgage Bonds in the third quarter of 2007, and expects to issue an additional $75 million of First Mortgage Bonds in the fourth quarter of 2007, to help provide sufficient liquidity. PGE expects increased capital expenditures for Phases II and III of Biglow Canyon, hydro relicensing, and the AMI project during the next few years. The Company's ability to execute its capital investment plan will depend on continued strength in the economy and access to capital markets.

PGE is a party in several legal and regulatory proceedings that could have a material impact on the results of operations and cash flows of future reporting periods, including:

• challenges, appeals and reviews on the issue of the OPUC's authority to grant recovery of, and 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 OPUC order granting an Application for Deferred Accounting to defer the difference between amounts charged to customers for state and federal income taxes and amounts actually paid to these governmental entities for the period from October 5, 2005 through December 31, 2005. The OPUC will consider whether rates were just and reasonable or were in violation of the provisions of SB 408, as alleged by the complainants.

For further information regarding these and other items, see Note 4, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

PGE is subject to state and federal environmental laws and regulations that govern air quality standards, including emissions from thermal power plants. The Company's operations may also be affected by the federal regional haze rules, which establish goals to protect visibility and remedy existing impairments resulting from man-made pollution. While PGE anticipates that it will be able to comply with these restrictions and those imposed under the Clean Air Mercury Rule, such rules may require added costs to purchase and install additional emission control equipment. In addition, increasing local, national and international concerns regarding global warming and climate change may result in future laws or regulations that require additional pollution control equipment or significant emissions fees or taxes. For further information regarding estimated future capital expenditures related to emission control laws and regulations, see "Capital Requirements" in "Liquidity and Capital Resources" in this Item 2.

In May 2007, the Bonneville Power Administration suspended Residential Exchange Program payments to investor-owned utilities, including PGE, as a result of a decision by the U.S. Ninth Circuit Court of Appeals. The removal of exchange program credits from PGE customers' bills has resulted in an approximate 14% average price increase for the Company's residential and small farm customers. PGE is participating with other investor-owned utilities to pursue available options - judicial, regulatory, and legislative - to restore their customers' federal power benefits.

For a discussion of new accounting standards that have been issued but not yet adopted by the Company, see Note 12, New Accounting Standards, in the Notes to Condensed Consolidated Financial Statements.

 

 

Results of Operations

The following review of PGE's results of operations should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas costs, quarterly operating earnings are not necessarily indicative of results to be expected for calendar year 2007.

2007 Compared to 2006 for the Three Months Ended September 30

PGE's net income in the third quarter of 2007 was $20 million, or $0.32 per diluted share, compared to $10 million, or $0.16 per diluted share, in the third quarter of 2006. The improved results were primarily attributable to the approximate $18 million after tax impact of SB 408, with an estimated amount to be collected from customers recorded in the third quarter of 2007 compared to a refund to customers recorded in the same period of 2006. Higher power costs and administrative and general expenses during the third quarter partially offset the impact of SB 408.

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

	Three Months Ended September 30,
	2007			2006			Increase/ (Decrease)
Operating revenues (millions)
Retail sales
Residential	$	160		$	134		$	26
Commercial		157			143			14
Industrial		41			53			(12)
Total retail sales		358			330			28
Direct access customers
Commercial		-			(2)			2
Industrial		(3)			(1)			(2)
Tariff revenues		355			327			28
Regional Power Act credits		-			4			(4)
Provision for collection (refund) - SB 408		6			(22)			28
Accrued revenues		1			-			1
Total retail revenues		362			309			53
Wholesale revenues		68			60			8
Other operating revenues		5			3			2
Total Operating Revenues	$	435		$	372		$	63

 

	Three Months Ended September 30,
	2007			2006			Increase/ (Decrease)
Energy sold and delivered - MWhs (thousands)
Retail energy sales
Residential		1,602			1,630			(28)
Commercial		1,910			1,939			(29)
Industrial		632			895			(263)
Total retail energy sales		4,144			4,464			(320)
Delivery to direct access customers
Commercial		135			110			25
Industrial		432			143			289
Total retail energy deliveries		4,711			4,717			(6)
Wholesale sales		1,221			1,119			102
Total energy sold and delivered		5,932			5,836			96
Customers - end of period
Residential		703,272			693,772			9,500
Commercial		100,110			98,964			1,146
Industrial		257			259			(2)
Total retail customers		803,639			792,995			10,644

 

Total Operating Revenues in the third quarter of 2007 increased 17% from last year's third quarter due to the following significant factors:

• Total Retail Revenues increased $53 million, or 17%, due primarily to:

• A $28 million increase related to SB 408, with an estimated collection (related to the 2007 tax year) recorded in this year's third quarter compared to an estimated refund (related to the 2006 tax year) recorded in last year's third quarter. For further information, see Note 5, Utility Rate Treatment of Income Taxes, in the Notes to Condensed Consolidated Financial Statements;
• Price increases of 6.4% related to higher power and fuel costs and cost recovery of Port Westward;
• Discontinuance of subscription power benefits under the Residential Exchange Program (fully offset by increased Purchased Power costs).

Total retail energy deliveries remained nearly unchanged from last year's third quarter. Cooler-than-normal weather in the third quarter of 2007, compared to warmer-than-normal weather in the third quarter of 2006, resulted in reduced electricity use by customers. This was largely offset by an 11,000 increase in the average number of customers served during this year's third quarter.

• Wholesale Revenues increased $8 million, or 13%, due to:

• A 9% increase in energy sales;
• A 2% increase in average prices, primarily due to increased prices for natural gas.

Purchased Power and Fuel expenses in the third quarter of 2007 increased $44 million, or 22%, from last year's third quarter.

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

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)						Average Variable Power Cost (Mills/kWh)
	2007		2006				2007		2006
Generation	3,265		2,364				37.5		17.3
Term Purchases	1,984		2,821				38.6		47.1
Spot Purchases	397		702				39.1		28.9
Total System Load	5,646		5,887				40.9		35.7

The increase in Purchased Power and Fuel expenses was due to the net effect of:

• An increase in the average cost of generation as a result of higher costs of settled natural gas hedging transactions;
• An $11.5 million reduction in unrealized gains on derivative activities (results of such activities are fully deferred in 2007 as a result of OPUC approval of the PCAM);
• The displacement of power purchases with lower-cost power from Port Westward;
• A 4% decrease in total system load;
• Discontinuance of subscription power benefits under the Residential Exchange Program (fully offset by increased Revenues above).

A new Power Cost Adjustment Mechanism was approved by the OPUC, effective January 17, 2007. Under the PCAM, PGE can adjust future prices to reflect the difference between each year's forecasted NVPC included in prices (the baseline), and actual NVPC on a settlement basis. Under the PCAM, PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and that included in base prices by application of an asymmetrical deadband within which PGE absorbs cost increases or decreases, with a 90/10 sharing of costs and benefits between customers and the Company outside of the deadband. For 2007, the deadband ranges from $11.7 million below, to $23.4 million above, the baseline. PGE's actual NVPC for the first nine months of 2007 were less than the established baseline by $27.9 million. Accordingly, an estimated $14.6 million refund to customers was recorded as a regulatory liability; of this amount, $11.8 million was recorded in the third quarter and is reflected as an increase to Purchased Power and Fuel expenses. Any regulatory asset or liability arising from 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 determined by the OPUC through a public filing and review.

Generation from company-owned facilities increased 38% from last year's third quarter and met approximately 74% of PGE's retail load during this year's third quarter compared to 50% in the same period of 2006. The increases reflect the availability of Port Westward starting in June 2007.

Thermal generation increased 42% in the third quarter of 2007 over the third quarter of 2006, resulting in reduced reliance on higher cost wholesale market purchases. A 7% increase in Company-owned hydro production was due to slightly higher stream flows in the third quarter of 2007. Energy received under long-term purchase agreements from mid-Columbia River hydro facilities in the State of Washington increased 1% in the third quarter of 2007 compared to the same period last year.

Production, distribution, administrative and other expenses increased $8 million from last year's third quarter due primarily to operating expenses at the new Port Westward generating plant and higher employee benefit and customer support expenses in 2007.

Depreciation and amortization expenses decreased $9 million from the third quarter of 2006 due primarily to the net effect of the following:

• A $7 million decrease resulting from reductions in both depreciation rates for utility plant assets and the authorized recovery of Trojan decommissioning costs, both of which became effective in January 2007 pursuant to the OPUC order in PGE's general rate case;
• A $3 million decrease in the amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues);
• A $2 million increase in depreciation expense due to the addition of Port Westward.

Income taxes increased $4 million due primarily to higher taxable income in the third quarter of 2007.

Other Income decreased $3 million primarily due to reduced income from non-qualified benefit plan trust assets and higher taxes on non-utility income.

2007 Compared to 2006 for the Nine Months Ended September 30

PGE's net income was $121 million, or $1.93 per diluted share, in the first nine months of 2007 compared to $31 million, or $0.50 per diluted share, in the first nine months of 2006. The improved results were attributable to increased retail energy deliveries and the return of Boardman to full operation. In 2006, the Company's results included a $32 million after tax impact of incremental power costs required to replace the output of Boardman during its extended repair outage. Results for 2007 include a positive $13 million after tax impact of the deferral of a portion of the Boardman replacement power costs for future recovery, as approved by the OPUC.

Also contributing to the increase in earnings was a $26 million after tax impact from SB 408, with an amount to be collected from customers recorded in the first nine months of 2007 compared to a refund to customers recorded in the same period of 2006. This positive impact on comparable earnings reflects in part the so-called "double whammy" effect of the law that can result in unusual outcomes in certain situations. Under the provisions of SB 408, if the utility incurs lower expenses or receives higher revenues, resulting in higher income taxes paid than the OPUC assumed the utility would incur in the last rate case, customers would be surcharged for the increase in income taxes, further increasing the utility's earnings. Conversely, if the utility incurs higher expenses or receives lower revenues, resulting in lower income taxes paid than the OPUC assumed the utility would incur in the last rate case, customers would receive refunds for the decrease in income taxes, further decreasing the utility's earnings. PGE's lower earnings in 2006, resulting primarily from incremental replacement power costs related to the Boardman outage, were further reduced by SB 408 refunds to customers; conversely, the Company's higher earnings in 2007 were further increased by SB 408 collections from customers. For further information, see Note 5, Utility Rate Treatment of Income Taxes, in the Notes to Condensed Consolidated Financial Statements.

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

	Nine Months Ended September 30,
	2007			2006			Increase/ (Decrease)
Operating revenues (millions)
Retail sales
Residential	$	501		$	448		$	53
Commercial		440			407			33
Industrial		119			153			(34)
Total retail sales		1,060			1,008			52
Direct access customers
Commercial		-			(4)			4
Industrial		(9)			(5)			(4)
Tariff revenues		1,051			999			52
Regional Power Act credits		42			9			33
Provision for collection (refund) - SB 408		11			(31)			42
Accrued revenues		1			2			(1)
Total retail revenues		1,105			979			126
Wholesale revenues		149			114			35
Other operating revenues		19			11			8
Total Operating Revenues	$	1,273		$	1,104		$	169

 

 

	Nine Months Ended September 30,
	2007			2006			Increase/ (Decrease)
Energy sold and delivered - MWhs (thousands)
Retail energy sales
Residential		5,504			5,448			56
Commercial		5,442			5,460			(18)
Industrial		1,875			2,641			(766)
Total retail energy sales		12,821			13,549			(728)
Delivery to direct access customers
Commercial		376			331			45
Industrial		1,236			432			804
Total retail energy deliveries		14,433			14,312			121
Wholesale sales		3,161			2,628			533
Total energy sold and delivered		17,594			16,940			654

Total Operating Revenues in the first nine months of 2007 increased 15% from last year's first nine months due to the following significant factors:

• Total Retail Revenues increased $126 million, or 13%, due primarily to:

• Price increases related to higher power and fuel costs and cost recovery of Port Westward (overall $94.6 million, or 6.4%, increase in annual revenues);
• A $42 million increase related to SB 408, with an estimated collection recorded in the first nine months of 2007 and a refund recorded in the same period last year;
• A 1% increase in total retail energy deliveries, primarily from an increase of approximately 11,600 in the average number of customers served in the first nine months of 2007;
• Discontinuance of subscription power benefits under the Residential Exchange Program (fully offset by increased Purchased Power costs).

Lower retail energy sales to industrial customers resulted from an increase in direct access customers that now purchase their energy requirements from an Electricity Service Supplier (ESS). Revenue reductions for these customers were attributable to "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.

Weather adjusted retail energy deliveries to PGE customers, including those purchasing energy from an ESS, increased 1.1% in the first nine months of 2007, compared to the same period last year. Deliveries to residential, commercial and industrial customers increased by 0.6%, 1.3%, and 1.6%, respectively.

PGE forecasts 2007 weather adjusted energy deliveries to customers, including those purchasing energy from an ESS, to increase by approximately 1% from last year.

• Wholesale revenues increased $35 million, or 31%, due to:

• A 20% increase in energy sales;
• A 9% increase in the average sales price, resulting from higher natural gas prices and lower regional hydro availability.

• Other Operating Revenues increased from last year's first nine months primarily as the result of increased gains from the sale of natural gas in excess of generating plant requirements.

Pending regulatory matters that could have an effect on future revenues include the following:

• Biglow Canyon - New prices are expected to become effective January 1, 2008 for cost recovery of Phase I of the project. In a stipulation filed with the OPUC on June 20, 2007, PGE, OPUC Staff, and other parties agreed to certain adjustments that would reduce the annual revenue requirements for Biglow Phase I to approximately $9.4 million, pending final OPUC approval. Further adjustments to Biglow's annual revenue requirements are expected in November 2007, concurrent with the Annual Power Cost Update Tariff filing, described below.
• Annual Power Cost Update Tariff - On October 1, 2007, PGE submitted to the OPUC an update of its 2008 NVPC forecast, with a final forecast to be submitted in mid-November 2007. Price changes, to be effective January 1, 2008, are expected to be minimal. The approved tariff will establish a new baseline NVPC for purposes of the PCAM calculation for 2008.
• "Energy Efficiency" Tariffs - On October 26, 2007, PGE filed proposed tariffs with the OPUC to implement demand-side programs outlined in the Company's 2007 IRP. The requested effective date of the tariffs is January 1, 2008. If approved, the tariffs would provide an additional $14 million to the Energy Trust of Oregon as well as the recovery of future lost revenues and incremental customer service expenses related to the achievement of energy savings targets.
• Boardman Deferral Amortization - On October 9, 2007, PGE filed a request with the OPUC to amortize the deferral of $26.4 million of replacement power costs associated with the outage of Boardman from November 18, 2005 through February 5, 2006. In its filing, the Company proposed that $31.4 million (including $5.0 million of accrued interest) be offset with certain credits due to customers, with no price impact anticipated.
• Advanced Metering Infrastructure - PGE is seeking OPUC approval of a new tariff that includes an approximate $13 million increase in annual revenue requirements to recover the costs of the AMI project, including recovery of the undepreciated cost of existing meters. The proposed tariff would run for approximately two and a half years, coinciding with the period over which PGE completes systems acceptance testing and installation of the new meters, which is expected to begin in mid-2008. In its filing, the Company proposed that the effect of the new tariff be offset with certain credits due to customers.

Purchased Power and Fuel expenses in the first nine months of 2007 increased $47 million, or 8%, from last year's first nine months.

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

	Megawatt/Variable Power Costs
	Megawatt-Hours (thousands)						Average Variable Power Cost (Mills/kWh)
	2007		2006				2007		2006
Generation	7,176		4,816				26.4		11.2
Term Purchases	8,709		10,567				41.9		38.6
Spot Purchases	1,014		1,776				28.0		27.7
Total System Load	16,899		17,159				37.4		32.6

 

The increase in Purchased Power and Fuel expense was due primarily to the net effect of the following factors:

• An increase in the average cost of purchased power;
• Higher natural gas prices;
• Higher costs of settled natural gas hedging transactions;
• Discontinuance of subscription power benefits under the Residential Exchange Program (fully offset by increased Revenues above);
• Expenses for the first nine months of 2007 include approximately $14.6 million that has been recorded for future refund to customers under the PCAM, based upon the difference between actual NVPC and those forecasted and included in retail prices.

Offsetting the increases were:

• The deferral, for future recovery, of $20.4 million of excess Boardman power costs (approved by the OPUC in February 2007);
• Unrealized losses on derivative activities of $13.3 million in 2006. Results of these activities are fully deferred in 2007 as a result of OPUC approval of the PCAM;
• A $6 million reduction in the Company's wholesale credit reserve related to the settlement with certain California parties involving wholesale energy transactions in 2000-2001;
• Reduced electricity purchases to serve retail load, related to both the return of Boardman to full operation and to generation from Port Westward;
• Lower commercial and industrial energy sales, resulting from an increase in direct access customers that purchase energy from an ESS.

In the first nine months of 2007, PGE generated 52% of its retail load requirement compared to 33% in the first nine months of 2006. Short- and long-term purchases were utilized to meet the remaining load. The Company met 42% of its retail load requirement from thermal generation and 10% from hydro generation in the first nine months of 2007.

The addition of Port Westward in June 2007 and the return of Boardman to full operation in the second half of 2006 combined to increase thermal production by 76% in the first nine months of 2007, resulting in reduced reliance on higher cost purchases in the wholesale market.

Partially offsetting the increase in thermal production was a 10% decrease in Company-owned hydro production, resulting from lower stream flows. PGE has long-term agreements to purchase power generated from hydro facilities on the mid-Columbia River. Energy received under these agreements increased 5% in the first nine months of 2007 compared to the same period last year.

Current forecasts indicate that regional hydro conditions for the full year 2007 will be somewhat below normal levels. Volumetric water supply forecasts for the Pacific Northwest region, prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies, indicate the April-to-September runoff forecast for 2007 compared to the actual runoffs for 2006 as follows:

Location	2007 Forecast	2006 Actual
Columbia River at The Dalles, Oregon ....	86%	107%
Mid-Columbia River at Grand Coulee, Washington ..............................	99%	101%
Clackamas River ..............................	68%	92%
Deschutes River ...............................	89%	100%

Production, distribution, administrative and other expenses increased $23 million from last year's first nine months due primarily to higher employee benefit and customer support expenses, new operating costs at Port Westward, and increased maintenance activities at Boardman and Colstrip.

Depreciation and amortization expenses decreased $31 million from the first nine months of 2006 due primarily to:

• A $19 million decrease resulting from reductions in depreciation rates for utility plant assets and the authorized recovery of Trojan decommissioning costs, both of which became effective in January 2007 pursuant to the OPUC order in PGE's general rate case;
• A $9 million decrease in the amortization of regulatory assets (fully offset within Net Operating Income due to a corresponding decrease in Operating Revenues);
• A $3 million reduction in the deferral of certain tax credits for future ratemaking treatment.

Income taxes increased $39 million due primarily to higher taxable income in the first nine months of 2007.

Other Income increased $7 million in the first nine months of 2007 due primarily to the following items:

• A $4 million interest accrual (retroactive to January 2006) on $26.4 million of excess power costs associated with Boardman's repair outage, which has been deferred for future recovery, as approved by the OPUC;
• A $2 million increase in income from non-qualified benefit plan trust assets;
• A $2 million increase in the allowance for equity funds used during construction, related primarily to Port Westward and Biglow Canyon.

Interest Charges increased $5 million in the first nine months of 2007, primarily due to a higher level of outstanding long-term debt resulting from the issuance of additional First Mortgage Bonds during 2006 and 2007.

 

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE's projected primary cash requirements, excluding AFDC, for the years indicated (in millions):

	2007	2008	2009	2010	2011
Ongoing Capital Expenditures(a)	$ 178	$ 220-240	$ 220-240	$ 250-270	$ 230-250
Biglow Canyon Wind Farm:
Phase I	203
Phases II and III(b)	19	530-630
Hydro Relicensing	52	110-120
Port Westward	16
Advanced Metering Infrastructure(c)	3	130-135
Boardman Emissions Controls(d)	-	170-180
Total Capital Expenditures	$ 471
Long-term debt maturities	$   66	-	-	$  186	-

1. Upgrades to transmission, distribution and existing generation, as well as new customer connections.
2. Phases II and III timing subject to turbine availability and project economics.
3. Under review by OPUC.
4. See Air Quality Standards, below, for further discussion of emission controls.

Biglow Canyon Wind Farm - In accordance with PGE's plan to acquire additional wind generation, as outlined in its IRP, the Company is proceeding with construction of Biglow Canyon, located in Sherman County, Oregon.

The first phase of the project, which is expected to have an installed capacity of 125 MW, began supplying limited amounts of energy into the Pacific Northwest energy grid in mid-October 2007, and is expected to be completed by the end of the year at a total estimated cost of $255 million to $265 million, including AFDC. Phases II and III of the project are currently in the advanced stages of planning. In the second quarter of 2007, PGE paid $17 million to a vendor towards wind turbines for Phases II and III. The payment is non-refundable if PGE and the vendor do not execute a definitive agreement after good faith efforts to negotiate and execute such agreement within a specified time period. The payment will be returned to PGE if the vendor fails to negotiate the definitive agreement in good faith. The estimated total cost of Phases II and III is $600 million to $700 million, including AFDC, with Phase II expected to be completed by the end of 2009 and Phase III expected to be completed by the end of 2010. Total installed capacity of all three phases is expected to be between 400 and 450 MW.

Advanced Metering Infrastructure - PGE is planning to install over 800,000 new advanced meters that would facilitate daily, two-way remote communications between the Company and customer meters. AMI is expected to provide improved services while achieving operational efficiencies and cost reductions at an estimated capital cost of $130 million to $135 million.

Air Quality Standards - As a result of the EPA's regional haze rules, the Company volunteered to participate in a DEQ pilot project to analyze information about air emissions from Boardman. An exemption modeling analysis for identified sources, which began in September 2006, has indicated that the Boardman and Beaver generating plants may cause or contribute to visibility impairment in several federally protected areas. In addition, the federal government and the states in which PGE operates have adopted the following regulations concerning mercury emissions:

• In May 2005, the EPA established the Clean Air Mercury Rule that establishes a cumulative total ("cap") of mercury emissions from all electric generating plants in the United States and assigns to each state a mercury emissions "budget."
• The Montana Board of Environmental Review adopted final rules on mercury emissions from coal-fired generating units in Montana, including Colstrip, which set strict mercury emission limits by 2010.
• The Oregon Environmental Quality Commission adopted the Utility Mercury Rule, which requires installation of mercury control technology at Boardman, requiring that the plant reduce its mercury emission by 90% by July 1, 2012.

The ultimate impact that regulations on air quality standards will have on future operations, operating costs, or generating capacity of PGE's thermal generating plants is not yet determinable. However, the Company estimates that the range of capital costs required to meet regional haze rules and install mercury controls at Boardman alone could vary significantly, depending upon the technology utilized to achieve the reductions. PGE will seek to recover its share of any costs through the ratemaking process.

The Company believes that the Best Available Retrofit Technology (BART) for Boardman is a combination of New Low NO_x Burners, Modified Over Fire Air System, Selective Non-Catalytic Reduction (SNCR), and Semi-dry Flue Gas Desulphurization, and that mercury emission regulations should be addressed through a Mercury Sorbent Injection System. The total cost for these controls is estimated to be in the range of $300 million to $400 million (100% of total costs). While the Company believes that these controls meet BART requirements, it is possible that the regulatory agencies could require the replacement of SNCR with Selective Catalytic Reduction. This change would increase the total estimated costs to a range of $470 million to $620 million (100% of total costs). The Company has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. As the regulatory requirements are clarified by the relevant agencies and the related costs can be estimated with greater precision, the Company will further evaluate the economic prudency of these 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 new legislation that may be enacted in the future, including legislation dealing with climate change. However, in conjunction with these additional costs, the requirement to install Selective Catalytic Reduction controls could require an investment in excess of what the plant can economically support.

Future Cash Payments for Contractual Obligations

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

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 trading activities, which can vary depending upon the Company's forward positions and the corresponding price curves.

The following summarizes PGE's cash flows for the nine months ended September 30, 2007 and 2006 (in millions):

		2007		2006		Increase/ (Decrease)
Cash and cash equivalents at January 1,		$  12		$  122		$  (110)
Cash flows provided by (used in):
Operating activities		291		110		181
Investing activities		(351)		(280)		(71)
Financing activities		108		98		10
Net increase (decrease) in cash and cash equivalents		48		(72)		120
Cash and cash equivalents at September 30,		$  60		$    50		$      10

Cash Flows from Operating Activities - Cash flows from operating activities are used to meet the day-to-day cash requirements of PGE.

The $181 million increase in cash provided by operating activities was primarily attributable to:

• A $78 million decrease in wholesale margin deposits with certain wholesale customers;
• A $54 million decrease in power purchases from the first nine months of last year, when the Company was required to replace the output of Boardman during the plant's extended repair outage;
• A $28 million cash payment received from the California Power Exchange resulting from a settlement related to wholesale energy transactions in 2000-2001.

A significant portion of cash provided by operations consists of depreciation and amortization of utility plant which is recovered in prices with no current direct outlay of cash since it represents the recovery of prior investments. PGE estimates recovery of such charges to be approximately $180 million to $240 million annually over the period 2007-2011. Combined with all other sources, cash provided by operations is estimated to range from $360 million to $460 million annually during the period 2007-2011.

Cash Used in Investing Activities - Investing activities consist of new construction and improvements to PGE's distribution, transmission, and generation facilities.

The $71 million increase in cash used in investing activities was primarily attributable to the net effect of:

• A $160 million increase in expenditures for Biglow Canyon;
• A $122 million reduction in construction costs for Port Westward;
• Expenditures related to the expansion of PGE's distribution system to support both new and existing customers within the Company's service territory.

Cash Flows from Financing Activities - Financing activities provide supplemental cash for both day-to-day operating and capital requirements. 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.

Significant financing activities for the first nine months of 2007 included:

Issuances -

• Private placement sale of $170 million of 5.80% First Mortgage Bonds, to mature in 2039;
• Private placement sale of $130 million of 5.81% First Mortgage Bonds, to mature in 2037;
• Remarketing of $5.8 million of variable interest rate Port of Morrow Pollution Control Bonds due in 2031 under a new agreement.

Payments/Redemptions -

• Repayment of $81 million in short-term debt;
• Redemption of $50 million of 7.15% First Mortgage Bonds at maturity;
• Redemption of remaining $16 million of 7.75% Series Cumulative Preferred Stock;
• Early redemption of $5.1 million of 7 1/8% Port of St. Helens Pollution Control Bonds due in 2014;
• Payment of $43 million of common stock dividends.

Dividends on Common Stock

The following table indicates common stock dividends declared in 2007:

Declaration Date		Record Date		Payment Date		Dividends Declared per Common Share
February 22, 2007		March 26, 2007		April 16, 2007		$0.225
May 2, 2007		June 25, 2007		July 16, 2007		$0.235
August 2, 2007		September 25, 2007		October 15, 2007		$0.235
October 25, 2007		December 26, 2007		January 15, 2008		$0.235

The Company expects to pay regular quarterly dividends on its common stock; however, the declaration of such dividends is at the discretion of the Company's Board of Directors and is not guaranteed. The amount of common dividends will depend upon PGE's results of operations and financial condition, future capital expenditures and investments, any applicable regulatory and contractual restrictions, and other factors that the Board of Directors considers relevant.

Debt and Equity Financings

PGE has a $400 million five-year revolving credit facility with a group of commercial banks that supplements operating cash flow and provides a primary source of liquidity. The facility, which is unsecured, is used as backup for commercial paper borrowings and is available for general corporate purposes, with the maximum amount available to PGE for borrowings and/or the issuance of standby letters of credit.

PGE's ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, and alternatives available to investors. The Company's ability to obtain and renew such financing depends on its credit ratings as well as on bank credit markets, both generally and for electric utilities in particular. Based on the availability of the short-term credit facility and the expected ability to issue long-term debt and equity securities, management believes there is sufficient liquidity to meet the Company's anticipated capital and operating requirements.

PGE's financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company's financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE's common equity ratios were 51.3% and 53.0% at September 30, 2007 and December 31, 2006, respectively.

For further information regarding PGE's credit facility and debt financing activities, see Note 9, Credit Facility and Debt, in the Notes to Condensed Consolidated Financial Statements.

Credit Ratings and Debt Covenants

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

PGE's current credit ratings, with outstanding balances at the dates indicated, are as follows (dollars in millions):

		Moody's		S&P		September 30, 2007		December 31, 2006
First Mortgage Bonds		Baa1		A		$1,037		$787
Senior unsecured debt		Baa2		BBB		201		201
Commercial paper		Prime-2		A-2		-		81
Outlook:		Stable		Negative

On September 6, 2007, S&P raised its First Mortgage Bond ratings for PGE from 'BBB+' to 'A', as a result of a change in their methodology used to determine such ratings.

Should Moody's or S&P (or both) reduce the credit rating on PGE's unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale counterparties to post additional performance assurance collateral. On September 30, 2007, PGE had posted approximately $43 million of collateral, consisting of $4 million in letters of credit and $39 million in cash, none of which is affiliated with master netting agreements. Based on the Company's non-trading portfolio, estimates of current energy market prices, and the current level of collateral outstanding, as of September 30, 2007, the approximate amount of additional collateral that could be requested upon a single agency downgrade event to below investment grade is approximately $36 million and decreases to approximately $8 million by year-end 2007. The approximate amount of additional collateral that could be requested upon a dual agency downgrade event to below investment grade is approximately $89 million and decreases to approximately $20 million by year-end 2007.

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

The issuance of additional First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Company's Articles of Incorporation and the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on September 30, 2007 it could issue up to approximately $726 million of First Mortgage Bonds under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust. Any issuances would also be subject to market conditions and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust on the basis of property additions, bond credits, and/or deposits of cash.

PGE's credit facility contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the facility, to 65% of total capitalization. At September 30, 2007, the Company's consolidated indebtedness to total capitalization ratio, as calculated under the facility, was 48.7%.

Critical Accounting Policies and Estimates

PGE's critical accounting policies that require the use of estimates and assumptions are discussed further in the Company's Annual Report on Form 10-K for the year ended December 31, 2006. As of September 30, 2007, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2006. The policies disclosed included regulatory accounting, asset retirement obligations, loss contingency reserves, price risk management, pension accounting, and income taxes.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

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

PGE actively manages its risk to ensure compliance with its energy portfolio risk management policies. The Company monitors open commodity positions in its energy portfolio using a value at risk methodology, which measures the potential impact of market movements over a one-day holding period using a variance/covariance approach at a 95% confidence interval. The portfolio is modeled using net open power and natural gas positions, with power averaged over peak and off-peak periods by month, and includes all financial and physical positions for the next 24 months, including estimates of retail load and plant generation in the non-trading portfolio. The risk factors include commodity prices for power and natural gas at various locations and do not include volumetric variability. Based on this methodology, the average, high, and low value at risk on the Company's non-trading portfolio in the first nine months of 2007 were $5.5 million, $7.6 million, and $2.8 million, respectively, and in the first nine months of 2006 were $6.1 million, $9.9 million, and $3.8 million, respectively.

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

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

Foreign Currency Exchange Rate Risk

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

At September 30, 2007, a 10% change in the value of the Canadian dollar would result in an immaterial change in pre-tax income for transactions that will settle over the next 12 months.

Interest Rate Risk

To meet short-term cash requirements, PGE has established a program under which it may from time to time issue commercial paper for terms of up to 270 days; such issuances are supported by the Company's $400 million five-year unsecured revolving credit facility. Although the commercial paper program subjects the Company to fluctuations in interest rates, reflecting current market conditions, individual instruments carry a fixed rate during their respective terms. At September 30, 2007, PGE had no short-term debt outstanding through the issuance of commercial paper.

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

Credit Risk

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

The large number and diversified base of residential, commercial, and industrial customers, combined with the Company's ability to discontinue service, contribute to reduced credit risk with respect to trade accounts receivable from retail electricity sales. Estimated provisions for uncollectible accounts receivable related to retail electricity sales are provided for such risk. At September 30, 2007, the likelihood of significant losses associated with credit risk in trade accounts receivable is remote.

The following table presents PGE's credit exposure for commodity non-trading activities and their subsequent maturity as of September 30, 2007. The table reflects credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities (dollars in millions):

										Maturity of Credit Risk Exposure
Rating	Credit Risk Before Collateral			Percentage of Total Exposure			Credit Collateral			2007			2008			2009			2010			2011			After 2011
Investment Grade	$	102		98%			$	27		$	37		$	12		$	15		$	13		$	12		$	13
Non-Investment Grade		1		1%				-			1			-			-			-			-			-
Internally Rated - Non-Investment Grade		1		1%				-			1			-			-			-			-			-
Total	$	104		100%			$	27		$	39		$	12		$	15		$	13		$	12		$	13

Investment Grade includes those counterparties with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody's) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. Non-Investment Grade includes those counterparties with below investment grade credit ratings on senior unsecured debt. For non-rated counterparties, PGE performs credit analysis to determine an internal credit rating that approximates investment or non-investment grade. Included in this analysis is a review of counterparty financial statements, specific business environment, access to capital, and indicators from debt and capital markets. The credit exposure includes activity for electricity and natural gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit and may represent prepayment or credit exposure assurance. As of September 30, 2007, there was no posted collateral subject to be returned to a counterparty that is affiliated with master netting agreements.

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

Risk Management Committee

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

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

Item 4. Controls and Procedures

(a) Disclosure Controls and Procedures. Management of the Company, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report pursuant to Rule 13a-15(b) under the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, the Company's disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, the information relating to the Company (including its consolidated subsidiaries) required to be disclosed by the Company in the reports that it files or submits under the Exchange Act and are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II

Other Information

 

Item 1. Legal Proceedings

For further information regarding the following proceedings, see PGE's 2006 Annual Report on Form 10-K.

Citizens' Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O'Neill v. Public Utility Commission of Oregon, Marion County Oregon Circuit Court, the Court of Appeals of the State of Oregon, the Oregon Supreme Court.

Oral argument was held on August 9, 2007, with a decision by the OPUC pending.

On October 10, 2007, the Oregon Court of Appeals issued an opinion that reversed the 2002 Order approving the 2000 settlement agreements and remanded the 2002 Order to the OPUC for reconsideration. The Oregon Court of Appeals also vacated the 2003 Remand.

On October 17, 2007, the plaintiffs in the class action suits filed a motion with the Marion County Circuit Court to lift the abatement ordered by the Circuit Court in October of 2006. PGE's response is due on November 5, 2007.

For further information, see PGE's Quarterly Report on Form 10-Q for the quarters ended March 31 and June 30, 2007.

 

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

On October 25, 2007, the parties reached a settlement agreement, which provides, among other things, for the disclosure by PGE of certain documents requested pursuant to the subpoena. Subject to the performance by each party of obligations under the settlement agreement, the City of Portland will agree that the subpoena has been satisfied and PGE will dismiss the Petition for Writ of Review and the Complaint for Declaratory Judgment.

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

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. During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In December 2002, the FERC re-opened the case to allow parties to conduct further discovery. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. In November 2003 and February 2004, the FERC denied all requests for rehearing of its June 2003 decision. Parties appealed various aspects of these FERC orders to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision on appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy made by the California Energy Resources Scheduling (CERS) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC (i) to address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) to include sales to CERS in its analysis, and (iii) to further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC's findings based on the record established by the administrative law judge and declined to reach the merits of the FERC's ultimate decision to deny refunds. On September 18, 2007, the Ninth Circuit deferred the deadline for parties to file for rehearing until November 16, 2007.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, 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.

 

Item 1A. Risk Factors

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

Item 6. Exhibits

(3) Articles of Incorporation and Bylaws

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

3.2 * Portland General Electric Company Fifth Amended and Restated Bylaws [Form 8-K filed August 8, 2007, Exhibit (3.1)].

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

4.1 * Fifty-ninth Supplemental Indenture dated October 1, 2007 [Form 8-K filed October 5, 2007, Exhibit (4)].

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

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

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

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

(32) Section 1350 Certifications

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

* Incorporated by reference as indicated.

 

 

 

SIGNATURE

 

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

 

PORTLAND GENERAL ELECTRIC COMPANY

(Registrant)

 

 

Date:	November 2, 2007		By:	/s/ James J. Piro
				James J. Piro Executive Vice President, Finance Chief Financial Officer and Treasurer (duly authorized and principal financial officer)