Edgar Filing: PORTLAND GENERAL ELECTRIC CO /OR/

POR 20120930 10Q

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, 2012



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________________ to ____________________

Commission File Number: 1-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)



Oregon	93-0256820
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). [x] Yes x [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer [x]	Accelerated filer [ ]	Non-accelerated filer [ ]	Smaller reporting company [ ]

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

Number of shares of common stock outstanding as of November 2, 2012 is 75,534,708 shares.

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PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS



Definitions		3

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Condensed Consolidated Statements of Income	4

	Condensed Consolidated Balance Sheets	5

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51

Item 4.	Controls and Procedures	51

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 6.	Exhibits	52

SIGNATURE		53

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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:



Abbreviation or Acronym		Definition
AUT		Annual Power Cost Update Tariff
Biglow Canyon		Biglow Canyon Wind Farm
Boardman		Boardman coal-fired generating plant
Cascade Crossing		Cascade Crossing Transmission Project
Colstrip		Colstrip Units 3 and 4 coal-fired generating plant
EPA		U.S. Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRP		Integrated Resource Plan
ISFSI		Independent Spent Fuel Storage Installation
kV		Kilovolt = one thousand volts of electricity
LLC		Limited Liability Company
Moody’s		Moody’s Investors Service
MW		Megawatts
MWa		Average megawatts
MWh		Megawatt hours
NVPC		Net Variable Power Costs
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
S&P		Standard & Poor’s Ratings Services
SEC		Securities and Exchange Commission
Trojan		Trojan Nuclear Plant
VIE		Variable Interest Entity

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PART I — FINANCIAL INFORMATION



Item 1.	Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues, net	$	450		$	439		$	1,342		$	1,334
Operating expenses:
Purchased power and fuel	182			182			533			545
Production and distribution	49			50			153			147
Administrative and other	50			55			160			158
Depreciation and amortization	63			59			188			170
Taxes other than income taxes	24			25			77			74
Total operating expenses	368			371			1,111			1,094
Income from operations	82			68			231			240
Other income (expense):
Allowance for equity funds used during construction	1			1			4			3
Miscellaneous income (expense), net	—			(4		)	2			(1		)
Other income (expense), net	1			(3		)	6			2
Interest expense	27			27			82			82
Income before income taxes	56			38			155			160
Income taxes	19			11			43			42
Net income	37			27			112			118
Less: net loss attributable to noncontrolling interests	(1		)	—			(1		)	—
Net income attributable to Portland General Electric Company	$	38		$	27		$	113		$	118

Weighted-average shares outstanding (in thousands):
Basic	75,528			75,342			75,486			75,329
Diluted	75,541			75,358			75,500			75,345

Earnings per share—basic and diluted	$	0.50		$	0.36		$	1.49		$	1.57
Dividends declared per common share	$	0.270		$	0.265		$	0.805		$	0.790

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	September 30, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	156	$	6
Accounts receivable, net	129		144
Unbilled revenues	75		101
Inventories	78		71
Margin deposits	53		80
Regulatory assets—current	154		216
Deferred income tax assets	40		33
Other current assets	99		65
Total current assets	784		716
Electric utility plant, net	4,351		4,285
Regulatory assets—noncurrent	490		594
Nuclear decommissioning trust	37		37
Non-qualified benefit plan trust	32		36
Other noncurrent assets	63		65
Total assets	$	5,757	$	5,733

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)



	September 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	76		$	111
Liabilities from price risk management activities—current	147			216
Short-term debt	—			30
Current portion of long-term debt	200			100
Accrued expenses and other current liabilities	225			157
Total current liabilities	648			614
Long-term debt, net of current portion	1,536			1,635
Regulatory liabilities—noncurrent	760			720
Deferred income taxes	598			529
Liabilities from price risk management activities—noncurrent	90			172
Unfunded status of pension and postretirement plans	201			195
Non-qualified benefit plan liabilities	102			101
Other noncurrent liabilities	103			101
Total liabilities	4,038			4,067
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2012 and December 31, 2011	—			—
Common stock, no par value, 160,000,000 shares authorized; 75,534,386 and 75,362,956 shares issued and outstanding as of September 30, 2012 and December 31, 2011, respectively	838			836
Accumulated other comprehensive loss	(6		)	(6		)
Retained earnings	885			833
Total Portland General Electric Company shareholders’ equity	1,717			1,663
Noncontrolling interests’ equity	2			3
Total equity	1,719			1,666
Total liabilities and equity	$	5,757		$	5,733

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	112		$	118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	188			170
Decrease in net liabilities from price risk management activities	(142		)	(26		)
Regulatory deferral—price risk management activities	140			26
Deferred income taxes	70			40
Pension and other postretirement benefits	22			3
Renewable adjustment clause deferrals	1			16
Regulatory deferral of settled derivative instruments	1			15
Power cost deferrals, net of amortization	(4		)	17
Allowance for equity funds used during construction	(4		)	(3		)
Other non-cash income and expenses, net	15			21
Changes in working capital:
Decrease in receivables	41			22
Decrease in margin deposits, net	27			—
Income tax refund received	8			8
(Decrease) increase in payables and accrued liabilities	(42		)	3
Other working capital items, net	23			13
Contribution to pension plan	—			(26		)
Contribution to voluntary employees’ beneficiary association trust	(2		)	(14		)
Other, net	(4		)	(4		)
Net cash provided by operating activities	450			399
Cash flows from investing activities:
Capital expenditures	(218		)	(215		)
Proceeds from sale of solar power facility	10			—
Sales of nuclear decommissioning trust securities	18			39
Purchases of nuclear decommissioning trust securities	(19		)	(41		)
Other, net	—			3
Net cash used in investing activities	(209		)	(214		)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)



	Nine Months Ended September 30,
	2012			2011
Cash flows from financing activities:
Payments on long-term debt	$	—		$	(10	)
Maturities of commercial paper, net	(30		)	(19		)
Dividends paid	(61		)	(59		)
Noncontrolling interests’ capital distributions	—			(4		)
Net cash used in financing activities	(91		)	(92		)
Increase in cash and cash equivalents	150			93
Cash and cash equivalents, beginning of period	6			4
Cash and cash equivalents, end of period	$	156		$	97

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	61		$	66
Cash paid for income taxes	6			3
Non-cash investing and financing activities:
Accrued dividends payable	21			21
Accrued capital additions	15			22
Increase to Boardman’s asset retirement obligation and cost basis of plant for updated depreciation study	—			23
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	—			7

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in order to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters are located in Portland, Oregon and its service area is located entirely within the state of Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of September 30, 2012, PGE served 829,280 retail customers with a service area population of approximately 1.7 million, comprising approximately 44% of the state’s population.

Condensed Consolidated Financial Statements

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

The financial information included herein for the three and nine month periods ended September 30, 2012 and 2011 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated results of operations, and condensed consolidated cash flows of the Company for these interim periods. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year. The financial information as of December 31, 2011 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2011, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 24, 2012, and should be read in conjunction with such consolidated financial statements.

Comprehensive Income

PGE had no material components of other comprehensive income to report for the three and nine month periods ended September 30, 2012 and 2011.

Use of Estimates

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Reclassifications

To conform with the 2012 presentation, PGE has separately presented Deferred income tax assets from Other current assets, and reclassified Regulatory liabilities—current of $6 million to Accrued expenses and other current liabilities, in the condensed consolidated balance sheet as of December 31, 2011. In addition, PGE has separately presented Pension and other postretirement benefits of $3 million from Other non-cash income and expenses, net and reclassified Senate Bill 408 deferrals, net of $5 million to Other non-cash income and expenses, net in the condensed consolidated statement of cash flows for the nine months ended September 30, 2011.

Recent Accounting Pronouncement

In May 2011, Accounting Standards Update (ASU) 2011-04, Fair Value Measurements and Disclosures (Topic 820) - Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04) was issued. Many of the amendments in ASU 2011-04 change the wording used to describe principles and requirements to align with International Financial Reporting Standards as issued by the International Accounting Standards Board, and are not intended to change the application of Topic 820. Some of the amendments clarify the Financial Accounting Standards Board’s intent on the application of existing fair value guidance or change a particular principle or requirement for measuring fair value or fair value disclosures. PGE adopted the amendments contained in ASU 2011-04 on January 1, 2012, which did not have an impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million as of September 30, 2012 and December 31, 2011.

The activity in the allowance for uncollectible accounts is as follows (in millions):



	Nine Months Ended September 30,
	2012			2011
Balance as of beginning of period	$	6		$	5
Provision, net	6			6
Amounts written off, less recoveries	(6		)	(6		)
Balance as of end of period	$	6		$	5

Inventories

PGE inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Electric Utility Plant, Net

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



	September 30, 2012			December 31, 2011
Electric utility plant	$	6,726		$	6,596
Construction work in progress	168			120
Total cost	6,894			6,716
Less: accumulated depreciation and amortization	(2,543		)	(2,431		)
Electric utility plant, net	$	4,351		$	4,285

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $169 million and $153 million as of September 30, 2012 and December 31, 2011, respectively. Amortization expense related to intangible assets was $5 million for the three months ended September 30, 2012 and 2011, and $17 million and $14 million for the nine months ended September 30, 2012 and 2011, respectively.

In January 2012, PGE completed construction of a $10 million, 1.75 MW solar powered electric generating facility, which was sold to, and simultaneously leased-back from, a financial institution. The Company operates the facility and receives 100% of the power generated by the facility.

Regulatory Assets and Liabilities

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



	September 30, 2012					December 31, 2011
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	142		$	85	$	194		$	172
Pension and other postretirement plans	—			280		—			295
Deferred income taxes	—			78		—			87
Deferred broker settlements	9			1		11			—
Debt reacquisition costs	—			23		—			28
Other	3			23		11			12
Total regulatory assets	$	154		$	490	$	216		$	594
Regulatory liabilities:
Asset retirement removal costs	$	—		$	678	$	—		$	637
Asset retirement obligations	—			39		—			36
Power cost adjustment mechanism	—			6		—			10
Other	4			37		6			37
Total regulatory liabilities	$	4	⁽¹⁾	$	760	$	6	⁽¹⁾	$	720

(1) Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consist of the following (in millions):



	September 30, 2012		December 31, 2011
Accrued taxes payable	$	65	$	22
Accrued employee compensation and benefits	44		44
Accrued interest payable	35		24
Accrued dividends payable	21		21
Other	60		46
Total accrued expenses and other current liabilities	$	225	$	157

Credit Facilities

PGE has the following unsecured revolving credit facilities as of September 30, 2012:


•	A $360 million syndicated credit facility, which is scheduled to terminate in July 2013; and


•	A $300 million syndicated credit facility, which is scheduled to terminate in December 2016.

Pursuant to the individual terms of the agreements, both credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both credit facilities require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreements, to 65% of total capitalization. As of September 30, 2012, PGE was in compliance with this requirement with a 50.3% debt to total capital ratio.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the credit facilities.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt up to $700 million through February 6, 2014. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

PGE classifies borrowings under the revolving credit facilities and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. As of September 30, 2012, PGE had no borrowings or commercial paper outstanding, $61 million of letters of credit issued, and aggregate unused credit available of $599 million under the credit facilities.

Long-term Debt

In accordance with the terms of the debt agreement, PGE repaid on October 22, 2012 the 5.6675% Series of First Mortgage Bonds in the amount of $100 million.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Pension and Other Postretirement Benefits

Components of net periodic benefit cost are as follows for the three and nine months ended September 30 (in millions):



	Three Months Ended September 30,
	Defined Benefit Pension Plan						Other Postretirement Benefits				Non-Qualified Benefit Plans
	2012			2011			2012		2011		2012		2011
Service cost	$	3		$	3		$	—	$	1	$	—	$	—
Interest cost	8			7			1		1		—		1
Expected return on plan assets	(10		)	(10		)	—		—		—		—
Amortization of prior service cost	—			—			1		—		—		—
Amortization of net actuarial loss	4			2			—		—		—		—
Net periodic benefit cost	$	5		$	2		$	2	$	2	$	—	$	1



	Nine Months Ended September 30,
	Defined Benefit Pension Plan						Other Postretirement Benefits				Non-Qualified Benefit Plans
	2012			2011			2012		2011		2012		2011
Service cost	$	9		$	9		$	1	$	2	$	—	$	—
Interest cost	24			21			3		3		1		2
Expected return on plan assets	(30		)	(30		)	—		—		—		—
Amortization of prior service cost	—			—			1		—		—		—
Amortization of net actuarial loss	12			6			—		—		—		—
Net periodic benefit cost	$	15		$	6		$	5	$	5	$	1	$	2

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of September 30, 2012 and December 31, 2011, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy, which contains three broad classification levels, is used to prioritize the inputs to the valuation techniques used to measure fair value. The levels and application to the Company are discussed below.


Level 1	Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.


Level 2	Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date.


Level 3	Pricing inputs include significant inputs that are unobservable for the asset or liability.

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

PGE recognizes any transfers between levels in the fair value hierarchy as of the end of the reporting period. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels, except those transfers out of Level 3 to Level 2 presented in this note, during the three and nine month periods ended September 30, 2012 and 2011.

The Company’s financial assets and liabilities recognized at fair value are as follows by level within the fair value hierarchy (in millions):



	As of September 30, 2012
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	5		10		—		15
Corporate credit	—		8		—		8
Non-qualified benefit plan trust: ⁽²⁾
Equity Securities:
Domestic	3		2		—		5
International	1		—		—		1
Debt securities—Domestic government	3		—		—		3
Assets from price risk management activities: ^{(1) (3)}
Electricity	—		1		1		2
Natural gas	—		4		4		8
	$	12	$	39	$	5	$	56
Liabilities from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	63	$	33	$	96
Natural gas	—		90		51		141
	$	—	$	153	$	84	$	237


(1)	Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.


(2)	Excludes insurance policies of $23 million, which are recorded at cash surrender value.


(3)	For further information, see Note 4, Price Risk Management.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)



	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	3		9		—		12
Corporate credit	—		11		—		11
Non-qualified benefit plan trust: ⁽²⁾
Equity securities:
Domestic	7		2		—		9
International	1		—		—		1
Debt securities—Domestic government	3		—		—		3
Assets from price risk management activities: ^{(1) (3)}
Electricity	—		2		—		2
Natural gas	—		17		—		17
	$	14	$	55	$	—	$	69
Liabilities from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	108	$	29	$	137
Natural gas	—		201		50		251
	$	—	$	309	$	79	$	388


(1)	Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.


(2)	Excludes insurance policies of $23 million, which are recorded at cash surrender value.


(3)	For further information, see Note 4, Price Risk Management.

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and allocated to securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within the fair value hierarchy based on the following factors:

Money market funds — PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds held in the Nuclear decommissioning trust are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices.

Debt securities — PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.

Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Equity securities — Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace as of the reporting date.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 4, Price Risk Management.

For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as quoted forward prices for commodities and interest rates. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include over-the-counter forwards and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term over-the-counter swap derivatives. Commodity option contracts whose fair value is derived using standardized valuation techniques, such as Black-Scholes, are also classified as Level 3 and represent an immaterial portion of the Company’s Level 3 fair value measurements. Inputs into the valuation of commodity option contracts include forward commodity prices, forward interest rates, and historic volatility and correlation factors.

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities as of September 30, 2012 is presented below:



			Range and Weighted Average Price per Unit
	Fair Value ⁽¹⁾		Low		High		Weighted Average		Unit
Assets from price risk management activities:⁽²⁾	(in millions)
Natural gas financial swaps	$	4	$	3.70	$	5.41	$	4.33	Dth
Liabilities from price risk management activities:
Electricity financial swaps	33		6.05		51.68		39.44		MWh
Natural gas financial swaps	51		3.29		4.94		4.03		Dth


(1)	Determined using a discounted cash flow technique in which long-term quoted forward prices are unobservable inputs.


(2)	Assets from price risk management activities related to commodity option contracts are considered immaterial for this disclosure.

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. These inputs employ the mid-point of the market’s bid-ask spread and are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These inputs are validated against nonbinding quotes from brokers with whom the Company transacts. In addition, changes in the fair value measurement from price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company’s Risk Management group. This

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process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods.

The Company’s assets and liabilities from price risk management activities are sensitive to changes in the underlying market prices of the related commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. As the buyer of a commodity financial swap, an increase in the underlying commodity price would result in a favorable change to the Company’s fair value measurement. Conversely, a decrease in the underlying commodity price to buy a commodity financial swap would result in an unfavorable change to the Company’s fair value measurement. As the seller of a commodity financial swap, the Company’s fair value measurements are sensitive to price changes in a manner opposite to the buy side relationship discussed above.

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Balance as of the beginning of the period	$	88		$	127	$	79		$	120
Net realized and unrealized (gains) losses ⁽¹⁾	(7		)	21		4			29
Purchases	(2		)	1		(2		)	1
Issues	—			—		(1		)	—
Settlements	—			—		—			(1		)
Transfers out of Level 3 to Level 2	—			—		(1		)	—
Balance as of the end of the period	$	79		$	149	$	79		$	149


(1)	Contains nominal amounts of realized (gains) losses, net. Both realized and unrealized (gains) losses are recorded in Purchased power and fuel expense in the condensed consolidated statements of income of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the nine month period ended September 30, 2012, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its financial instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of long-term debt is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of September 30, 2012, the estimated aggregate fair value of PGE’s long-term debt was $2,059 million, compared to its $1,736 million carrying amount. As of December 31, 2011, the estimated aggregate fair value of PGE’s long-term debt was $2,091 million, compared to its $1,735 million carrying amount.

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NOTE 4: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Such activities include fuel and power purchases and sales resulting from economic dispatch decisions for Company-owned generation. As a result, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in net power costs for its retail customers. These derivative instruments may include forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, which are recorded at fair value on the condensed consolidated balance sheets, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery process authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative instruments until realized. This accounting treatment defers the fair value gains and losses on derivative instruments until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as purely economic hedges. The Company does not engage in trading activities for non-retail purposes.

PGE has elected to report gross on the balance sheet the positive and negative exposures resulting from derivative instruments. As of September 30, 2012 and December 31, 2011, the Company had $15 million and $26 million, respectively, in collateral posted with counterparties under an agreement that meets the definition of a master netting arrangement. This collateral consists entirely of letters of credit.

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle through 2015, were as follows (in millions):



	September 30, 2012			December 31, 2011
Commodity contracts:
Electricity	10		MWh	13		MWh
Natural gas	85		Decatherms	79		Decatherms
Foreign currency	$	8	Canadian	$	6	Canadian

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The fair value of PGE’s Assets and Liabilities from price risk management activities consists of the following (in millions):



	September 30, 2012			December 31, 2011
Current assets:
Commodity contracts:
Electricity	$	2		$	2
Natural gas	3			17
Total current derivative assets	5		⁽¹⁾	19		⁽¹⁾
Noncurrent assets:
Commodity contracts—Natural gas	5		⁽²⁾	—
Total derivative assets not designated as hedging instruments	$	10		$	19
Total derivative assets	$	10		$	19
Current liabilities:
Commodity contracts:
Electricity	$	54		$	66
Natural gas	93			150
Total current derivative liabilities	147			216
Noncurrent liabilities:
Commodity contracts:
Electricity	42			71
Natural gas	48			101
Total noncurrent derivative liabilities	90			172
Total derivative liabilities not designated as hedging instruments	$	237		$	388
Total derivative liabilities	$	237		$	388


(1)	Included in Other current assets on the condensed consolidated balance sheets.


(2)	Included in Other noncurrent assets on the condensed consolidated balance sheet.

Net realized and unrealized (gains) losses on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Commodity contracts:
Electricity	$	(3	)	$	44	$	40	$	75
Natural Gas	(19		)	30		6		41

Net unrealized and certain net realized (gains) losses presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net (gains) losses recognized in Net income for the three months ended September 30, 2012 and 2011, net gains of $30 million and net losses of $72 million, respectively, have been offset, with net losses of $14 million and $107 million offset for the nine months ended September 30, 2012 and 2011, respectively.

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Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss (gain) recorded as of September 30, 2012 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):



	2012		2013		2014		2015		2016			Total
Commodity contracts:
Electricity	$	13	$	46	$	24	$	11	$	—		$	94
Natural gas	35		72		24		4		(2		)	133
Net unrealized loss (gain)	$	48	$	118	$	48	$	15	$	(2	)	$	227

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s Ratings Services (S&P). Should Moody’s and/or S&P reduce their rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of September 30, 2012 was $190 million, for which PGE has posted $40 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, 2012, the cash requirement to either post as collateral or settle the instruments immediately would have been $183 million.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities as of September 30, 2012 or December 31, 2011 were as follows:



	September 30, 2012		December 31, 2011
Assets from price risk management activities:
Counterparty A	15	%	19	%
Counterparty B	12		2
Counterparty C	11		16
Counterparty D	6		13
	44	%	50	%
Liabilities from price risk management activities:
Counterparty E	22	%	23	%
Counterparty F	13		10
	35	%	33	%

See Note 3 for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

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NOTE 5: EARNINGS PER SHARE

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	38	$	27	$	113	$	118
Denominator (in thousands):
Weighted-average common shares outstanding—basic	75,528		75,342		75,486		75,329
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	13		16		14		16
Weighted-average common shares outstanding—diluted	75,541		75,358		75,500		75,345

Earnings per share—basic and diluted	$	0.50	$	0.36	$	1.49	$	1.57

Unvested performance stock units and related dividend equivalent rights are not included in the computation of dilutive securities because vesting of these instruments is dependent upon three-year performance periods and the vesting criteria has not been met as of the end of the reporting period presented.

Basic and diluted earnings per share amounts are calculated based on actual amounts rather than the rounded amounts presented in the table above and on the condensed consolidated statements of income. Accordingly, calculations using the rounded amounts presented for net income and weighted average shares outstanding may yield results that vary from the earnings per share amounts presented in the table above.

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NOTE 6: EQUITY

The activity in equity during the nine month periods ended September 30, 2012 and 2011 is as follows (dollars in millions):



	Portland General Electric Company Shareholders’ Equity
				Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
	Common Stock
	Shares	Amount
Balances as of December 31, 2011	75,362,956	$	836	$	(6	)	$	833		$	3
Issuance of shares pursuant to equity-based plans	171,430	—		—			—			—
Stock-based compensation	—	2		—			—			—
Dividends declared	—	—		—			(61		)	—
Net income (loss)	—	—		—			113			(1		)
Balances as of September 30, 2012	75,534,386	$	838	$	(6	)	$	885		$	2

Balances as of December 31, 2010	75,316,419	$	831	$	(5	)	$	766		$	7
Issuance of shares pursuant to equity-based plans	28,932	—		—			—			—
Stock-based compensation	—	2		—			—			—
Dividends declared	—	—		—			(59		)	—
Noncontrolling interests’ capital distributions	—	—		—			—			(4		)
Net income	—	—		—			118			—
Balances as of September 30, 2011	75,345,351	$	833	$	(5	)	$	825		$	3

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NOTE 7: CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired, or a liability incurred, as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

Loss contingencies are also disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred. If a probable or reasonably possible loss can be reasonably estimated, then the Company discloses an estimate of such loss or the range of such loss. If a reasonable estimate cannot be made, disclosure will include the reason for such determination.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the appropriate reporting period.

The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which (i) the damages sought are indeterminate or the basis for the damages claimed is not clear, (ii) the proceedings are in the early stages, (iii) discovery is not complete, (iv) the matters involve novel or unsettled legal theories, (v) there are significant facts in dispute, (vi) there are a large number of parties (including cases in which it is uncertain how liability, if any, would be shared among multiple defendants), or (vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Trojan Investment Recovery

Regulatory Proceedings. In 1993, PGE closed the Trojan Nuclear Plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. The OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 1998, the Oregon Court of Appeals upheld the OPUC’s order authorizing PGE’s recovery of the Trojan investment, but held that the OPUC did not have the authority to allow the Company to recover a return on the Trojan investment and remanded the case to the OPUC for reconsideration.

In 2000, PGE entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration.

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The OPUC then issued an order in 2008 (2008 Order) that required PGE to provide refunds, including interest from September 30, 2000, to customers who received service from the Company during the period from October 1, 2000 to September 30, 2001. PGE recorded a charge of $33.1 million in 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below separately appealed the 2008 Order to the Oregon Court of Appeals. Oral arguments in the appeal occurred in February 2012 and a decision by the Oregon Court of Appeals remains pending.

Class Actions. In two separate legal proceedings, lawsuits were filed in Marion County Circuit Court against PGE in 2003 on behalf of two classes of electric service customers. The class action lawsuits seek damages of $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings until the OPUC responded to the 2002 Order (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 the Company collected in prices for the period from April 1, 1995 through October 1, 2000.

The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court.

Because the above matters involve unsettled legal theories and have a broad range of potential outcomes, management cannot estimate a range of potential loss. However, management believes that these matters will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods.

Pacific Northwest Refund Proceeding

In 2001, the FERC called for a hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. In 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. Parties appealed various aspects of the FERC order to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

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

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deny refunds. After denying requests for rehearing, the Ninth Circuit in April 2009 issued a mandate giving immediate effect to its August 2007 order remanding the case to the FERC.

In October 2011, the FERC issued an Order on Remand, establishing an evidentiary hearing to determine whether any seller had engaged in unlawful market activity in the Pacific Northwest spot markets during the December 25, 2000 through June 20, 2001 period by violating specific contracts or tariffs, and, if so, whether a direct connection existed between the alleged unlawful conduct and the rate charged under the applicable contract. The FERC held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome before a refund could be ordered. The FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Certain parties claiming refunds filed requests for rehearing of the Order on Remand, contesting, among other things, the applicable refund period reflected in the Order, the use of the Mobile-Sierra standard, any restraints in the Order on the type of evidence that could be introduced in the hearing, and the lack of a market-wide remedy. The rehearing requests remain pending.

In its October 2011 Order on Remand, the FERC held the hearing procedures in abeyance pending the results of settlement discussions, which it ordered be convened before a FERC settlement judge. Pursuant to the settlement proceedings, the Company received notice of two claims and has reached agreements to settle both of these claims for an immaterial amount. The first settlement was approved by the FERC in June 2012, while the second settlement received FERC approval in September 2012. There remains a possibility that additional claims could be asserted against the Company in the future.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between the Company and the California parties named in the settlement (including CERS) as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

Management cannot predict whether the FERC will order refunds in the Pacific Northwest Refund proceeding, which contracts would be subject to refunds, or how such refunds, if any, would be calculated. Accordingly, management cannot estimate a range of potential loss. However, management believes that the outcome will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods.

EPA Investigation of Portland Harbor

A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In January 2008, the EPA requested information from various parties, including PGE, concerning properties near the river. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.

The Portland Harbor site is currently undergoing a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.

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In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is expected to issue in 2015.

The draft FS evaluates several alternative clean-up approaches. These approaches would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending primarily on the selected remedial action levels. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA’s selected clean-up will be determined after the issuance of the Record of Decision.

Due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss. Management believes, however, that the outcome will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods.

DEQ Investigation of Downtown Reach

The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the “Downtown Reach”). In January of 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation in December 2011 and entered into a consent order with the DEQ in July 2012 to conduct a feasibility study of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation. It is expected that the feasibility study will be completed within the next two years.

Sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Downtown Reach site or to estimate a range of potential loss. However, management believes that the outcome will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods.

EPA Investigation of Harbor Oil

Harbor Oil, Inc. operated an oil reprocessing business on a site located in north Portland (Harbor Oil) until about 1999. Subsequently, other companies have continued to conduct operations on the site. Until 2003, PGE contracted with the operators of the site to provide used oil from the Company’s power plants and electrical distribution system to the operators for use in their reprocessing business. Other entities continue to utilize Harbor Oil for the reprocessing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyls, have been detected at the site. In September 2003, the EPA included the Harbor Oil site on the National Priority List as a federal Superfund site.

PGE received a Notice from the EPA in 2005, in which the Company was named as one of fourteen PRPs with respect to Harbor Oil. Subsequently, an AOC was signed by the EPA and six other parties, including PGE, to implement an RI/FS at Harbor Oil. In 2011, the final draft of the remedial investigation report was submitted to the EPA.

In March 2012, the EPA approved the remedial investigation and stated that it intends to recommend no action on the site, based on the conclusions of the risk assessment conducted under the CERCLA. Following a public notice

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and comment period, the EPA is expected to issue a final Record of Decision in early 2013.

Based on information currently available, management cannot estimate a range of potential loss with respect to this matter. However, management believes that the outcome will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods.

Alleged Violation of Environmental Regulations at Colstrip

On July 30, 2012, PGE received a Notice of Intent to Sue for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (Notice) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other Colstrip co-owners, including PPL Montana, LLC (PPL Montana) - the operator of Colstrip. PGE has a 20% ownership interest in Units 3 and 4 of Colstrip. The Notice alleges certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and states that the Sierra Club and MEIC will: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees. Since July, the Sierra Club and MEIC have twice amended their Notice. The first amendment, contained in a letter dated August 30, 2012, asserts that the Colstrip owners violated the Title V air quality operating permit during portions of 2008 and 2009. The second amendment, contained in a letter dated September 27, 2012, asserts that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). Due to the uncertainty concerning this matter, PGE cannot predict the outcome or determine whether it is reasonably possible that the claims, if asserted, would have a material impact on the Company.

Challenge to AOC Related to Colstrip Wastewater Facilities

In August 2012, PPL Montana entered into an AOC with the MDEQ, which established a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at the Colstrip power plant. Within five years, under this AOC, PPL Montana is required to provide financial assurance to MDEQ for the costs associated with closure of the waste water treatment facilities. This will establish an obligation for asset retirement, but PPL Montana is unable at this time to estimate these costs, which will require both public and agency review.

On September 4, 2012, Earthjustice filed an affidavit pursuant to Montana’s Major Facility Siting Act (MFSA) that sought review of the AOC by Montana’s Board of Environmental Review (BER), on behalf of environmental groups Sierra Club, the MEIC, and the National Wildlife Federation. On September 18, 2012, PPL Montana filed an election with the BER to have this proceeding conducted in Montana state district court as contemplated by the MFSA. On October 26, 2012, Earthjustice, on behalf of Sierra Club, the MEIC and the National Wildlife Federation, filed with the Montana state district court a petition for a writ of mandamus and a complaint for declaratory relief alleging that the AOC fails to require the necessary actions under the Major Facility Siting Act and the Montana Water Quality Act with respect to groundwater seepage from the wastewater facilities at Colstrip. PGE cannot at this time predict the outcome of this matter or determine whether it is reasonably possible that it would have a material impact on the Company.

Revenue Bonds

In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow. In connection with the repurchase, PGE paid the $5.8 million repurchase price to Lehman Brothers Inc. (Lehman) as remarketing agent for the Bonds, who in turn paid off the beneficial owner of the Bonds. As a

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

result of the payment, PGE became the beneficial owner of the Bonds and requested that Lehman safe-keep the Bonds in Lehman’s Depository Trust Company participant account until such time as the Bonds could be remarketed. After repurchase of the Bonds, PGE removed the liability for the Bonds from its financial statements.

In September 2008, Lehman filed for protection under Chapter 11 of the U.S. Bankruptcy Code. PGE subsequently filed a claim for return of the Bonds from Lehman. In November 2009, the trustee appointed to liquidate the assets of Lehman (Trustee) allowed PGE’s claim as a net equity claim for securities. At the time, PGE believed it would receive back the entire amount of the Bonds at some point during the bankruptcy proceedings.

It is not certain that the Company will receive the full amount of the Bonds but could, along with other claimants, potentially receive a pro-rata share of certain assets. The timing and extent of distributions on claims are subject to the ultimate disposition of numerous claims in the proceedings and certain major contingencies which the Trustee must resolve. PGE cannot currently estimate how much of the value of the Bonds will ultimately be returned to the Company or the timing of the distribution from Lehman. Management does not expect the outcome of this matter to have a material impact on the Company’s financial condition, but it may have a material impact on the results of operations and cash flows in a future interim reporting period.

Oregon Tax Court Ruling

On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue interpretation and a current Oregon administrative rule, regarding the treatment of wholesale electricity sales. The underlying issue is whether electricity should be treated as tangible or intangible property for state income tax apportionment purposes. It is uncertain whether the ruling will be appealed, or if the ruling would apply retroactively to PGE for all open tax years, which include 2006 through 2012. If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $17 million due to the impact of the increased assessment of prior years’ liability and an increase in the tax rate at which deferred tax liabilities would be recognized in future years. Due to the uncertainty concerning the resolution of this matter, PGE cannot predict the outcome. The Company may seek regulatory recovery of any incremental tax, although there can be no guarantee that such recovery would be granted.

Other Matters

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

NOTE 8: GUARANTEES

PGE enters into financial agreements and power and natural gas 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 based on the Company’s historical experience and the evaluation of the specific indemnities. As of September 30, 2012, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 9: VARIABLE INTEREST ENTITIES

PGE has determined that it is the primary beneficiary of three variable interest entities (VIEs) and, therefore, consolidates the VIEs within the Company’s condensed consolidated financial statements. All three arrangements were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating, and financing photovoltaic solar power facilities located on real property owned by third parties, and selling the energy generated by the facilities. PGE is the Managing Member in each of the Limited Liability Companies (LLCs), holding less than 1% equity interest in each entity, and a financial institution is the Investor Member, holding more than 99% equity interest in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

Determining whether PGE is the primary beneficiary of a VIE is complex, subjective, and requires the use of judgments and assumptions. Significant judgments and assumptions made by PGE in determining it is the primary beneficiary of these LLCs include the following: (i) PGE has the expertise to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements, and, therefore, PGE has control over the most significant activities of the LLCs; (ii) PGE expects to own 100% of the LLCs shortly after five years have elapsed, at which time the facilities will have approximately 75% of their estimated useful life remaining; and (iii) based on projections prepared in accordance with the operating agreements, PGE expects to absorb a majority of any expected losses of the LLCs.

Included in PGE’s condensed consolidated balance sheet are LLC assets of $5 million of Electric utility plant, net as of September 30, 2012 and December 31, 2011 and $1 million of Cash and cash equivalents as of December 31, 2011. These assets can only be used to settle the obligations of the consolidated VIEs.



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

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future operations, business prospects, expected changes in future loads, 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,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and 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 facilities and other assets, construction and operation of plant facilities,

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transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;


•	economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts;


•	the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements;


•	unseasonable or extreme weather and other natural phenomena, which can affect customers’ demand for power and could significantly affect PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company’s costs to maintain its generating facilities and transmission and distribution systems;


•	operational factors affecting PGE’s power generation facilities, including forced outages, hydro and wind conditions, and disruption of fuel supply, which may cause the Company to incur repair costs, as well as increased power costs for replacement power;


•	the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, which could result in the Company's inability to recover project costs;


•	volatility in wholesale power and natural gas prices, which could require the Company to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to existing power and natural gas purchase agreements;


•	capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayments of maturing debt;


•	future laws, regulations, and proceedings that could increase the Company’s costs or affect the operations of the Company’s thermal generating plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, in order to mitigate carbon dioxide, mercury and other gas emissions;


•	changes in wholesale prices for fuels, including natural gas, coal, and oil, and the impact of such changes on the Company’s power costs, and changes in the availability and price of wholesale power in the western United States;


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


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


•	declines in the fair value of equity securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;


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


•	the effects of climate change, including changes in the environment, which may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;


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

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•	cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer and proprietary information;


•	employee workforce factors, including a significant number of employees approaching retirement, potential strikes, work stoppages, and transitions in senior management;


•	general political, economic, and financial market conditions;


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


•	financial or regulatory accounting principles or policies imposed by governing bodies; and


•	acts of war or terrorism.

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

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2011, and other periodic and current reports filed with the SEC.

Operating Activities — PGE is a vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity, as well as the wholesale purchase and sale of electricity and natural gas. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues and income from operations to fluctuate from period to period. PGE is a winter-peaking utility that typically experiences its highest retail energy sales during the winter heating season, although a slightly lower peak occurs in the summer that generally results from air conditioning demand. Price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while the availability and price of purchased power and fuel can affect income from operations.

Customers and Demand — Retail energy deliveries for the nine months ended September 30, 2012 decreased approximately one-half of one percent from the comparable period of 2011 largely as a result of the impact of relatively warmer weather during the heating season early in 2012 reducing residential customer demand, and the loss of demand from one large paper customer in early 2011. The decline was partially offset by an increase in the average number of total retail customers served.

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The following table indicates the average number of retail customers, including those direct access customers who chose to purchase their energy from an Electricity Service Supplier (ESS), and energy deliveries, by customer class, for the periods indicated:



	Nine Months Ended September 30,
	2012		2011		% Increase /(Decrease)in Energy Deliveries
	Average Number of Customers	Retail Energy Deliveries *	Average Number of Customers	Retail Energy Deliveries *	% Increase /(Decrease)in Energy Deliveries
Residential	722,884	5,506	719,809	5,604	(1.7	)%
Commercial	103,798	5,566	102,911	5,560	0.1
Industrial	261	3,180	255	3,156	0.8
Total	826,943	14,252	822,975	14,320	(0.5	)

____________________


*	In thousands of MWh.

On a weather adjusted basis, total retail energy deliveries for the nine months ended September 30, 2012 increased approximately one-half of one percent compared to the same period of 2011. PGE expects the increase in total retail energy deliveries on a weather adjusted basis for the year ending December 31, 2012 to approximate the increase for the nine months ended September 30, 2012, after allowing for energy efficiency and conservation efforts.

Power Operations — To meet the energy needs of its retail customers, the Company utilizes a combination of its own generating resources and wholesale market transactions. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, PGE makes economic dispatch decisions continuously in an effort to obtain reasonably-priced power for its retail customers. In addition, PGE’s thermal generating plants require varying levels of annual maintenance, during which the respective plant is unavailable to provide power. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period.

During the second quarters of 2012 and 2011, such annual maintenance was performed, with more extensive, planned service maintenance completed in 2011 compared to 2012. The work performed during 2011 included planned emissions control retrofits at Boardman and the replacement of the cooling tower structure and upgrading of the gas turbine and exhaust system components at Coyote Springs. Availability of the plants PGE operates approximated 93% and 92%, for the nine months ended September 30, 2012 and 2011, respectively, with the availability of Colstrip, which PGE does not operate, approximating 92% and 80%, for the same periods, respectively.

During the nine months ended September 30, 2012, the Company’s generating plants provided approximately 47% of its retail load requirement, compared with 44% in the nine months ended September 30, 2011. The increase in the relative volume of power generated to meet the Company’s retail load requirement was primarily due to the economic displacement of a greater amount of thermal generation by lower cost purchased power during 2011.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects decreased 30% in the nine months ended September 30, 2012 compared with the same period of 2011. These resources provided approximately 20% of the Company’s retail load requirement for the nine months ended September 30, 2012, compared with 28% for the same period of 2011. Through September, energy received from these sources exceeded projections included in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 12% during 2012, compared with 17% during the comparable period of 2011. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year and are based, in part, on average regional hydro conditions. Any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy from hydro resources is expected to be

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approximately 9% above projections included in the AUT for 2012.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon) is projected annually in the AUT and is based on wind studies completed in connection with the permitting of the wind farm. Any excess in wind generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy received from Biglow Canyon fell short of that projected in PGE’s AUT by 17% and 11%, in the nine months ended September 30, 2012 and 2011, respectively, and provided approximately 7% of the Company’s retail load requirement for the nine months ended September 30, 2012 and 2011.

Pursuant to the Company’s power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC for the year. To the extent actual NVPC is above or below the deadband, the PCAM provides for 90% of the variance to be collected from or refunded to customers, respectively, subject to a regulated earnings test. Pursuant to the regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE of 10%, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For 2012 and 2011, the deadband range is from $15 million below to $30 million above baseline NVPC.

For the nine months ended September 30, 2012, actual NVPC was approximately $14 million below baseline NVPC due to strong power supply operations and above average hydro generation, partially offset by lower than expected wind generation. Based on forecast data, NVPC for the year ending December 31, 2012 is currently estimated to be below the baseline NVPC, but within the deadband range; accordingly, no estimated refund to customers is expected for 2012.

For the nine months ended September 30, 2011, actual NVPC was approximately $36 million below baseline NVPC, which is $21 million below the lower deadband threshold, with PGE recording an estimated refund to customers in the amount of $17 million during the period. Upon application of the regulated earnings test, the estimated refund to customers was reduced to $10 million as of December 31, 2011.

Capital Requirements and Financing — PGE’s capital requirements for 2012 are related primarily to ongoing expenditures for the upgrade, replacement, and expansion of transmission, distribution, and generation infrastructure, as well as technology enhancements and expenditures related to hydro licensing and construction. Capital expenditures are expected to be approximately $328 million in 2012, of which $218 million was incurred through September 30, 2012. For further information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

For 2012, the Company expects to meet capital requirements with cash from ongoing operations, with no issuances of long-term debt or equity. In subsequent years, the Company expects to fund its capital requirements with a combination of cash from operations and funds from the capital markets, depending on the outcome of the Integrated Resource Plan (IRP) process outlined below, PGE’s liquidity needs, and market conditions. The Company also expects that the borrowing capacity under its credit facilities will continue to be available to manage working capital requirements for the foreseeable future. For further information, see the Debt and Equity Financings section of Liquidity and Capital Resources in this Item 2.

PGE’s 2009 IRP, acknowledged by the OPUC in November 2010 and updated in November 2011, includes the Company’s strategy for acquiring new resources over the next several years and a 20-year strategy outlining long-term expectations for resource needs and portfolio management. To meet projected energy requirements, the IRP includes energy efficiency measures, additional renewable resources, new transmission capability, new generation, and improvements to existing generating plants. The Company expects to file with the OPUC another update to the

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IRP by the end of November 2012.

In June 2012, in accordance with the IRP and pursuant to the OPUC’s competitive bidding guidelines, the Company issued a request for proposals (RFP) for additional resources seeking a combination of capacity and energy resources. The RFP seeks approximately:


•	300 to 500 MW of base load energy resources;


•	200 MW of year-round flexible and peaking resources;


•	200 MW of bi-seasonal (winter and summer) peaking supply; and


•	150 MW of winter-only peaking supply.

This RFP closed to proposals in August 2012, with PGE receiving proposals consisting of a mix of projects to be sold to the Company pursuant to asset purchase agreements and projects that would sell power to the Company under long-term power purchase agreements. PGE, with the oversight of an independent evaluator, is in the process of evaluating the bids, which include Company benchmark proposals. A final short list of projects is expected by the end of 2012. Negotiations with final short listed bidders are expected to start in late 2012 or early 2013. The flexible and peaking resources are expected to be available in the 2013 to 2015 time frame and the base load energy resources expected to be available in the 2014 to 2017 time frame.

A second RFP, which was issued in October 2012, is seeking approximately 100 MWa of renewable resources in order to help meet PGE’s 2015 requirements under Oregon’s Renewable Portfolio Standard. Sources proposed must meet a minimum size of at least 10 MW and can represent a variety of technologies including wind, geothermal, biomass, biogas, solar, and hydroelectric power. PGE may acquire a single resource or a mix of resources to achieve the total desired renewable energy target. The Company submitted a benchmark proposal at the end of October and all other proposals are due by November 13, 2012. PGE expects to identify an initial short list of projects by January 2013, with a final short list expected in early February 2013. The renewable resources are anticipated to be in service in the 2013 to 2017 time frame.

The IRP includes a proposal for an approximately 215-mile, 500 kV transmission line referred to as the Cascade Crossing Transmission Project, or Cascade Crossing, that would help meet future electricity demand and improve regional grid reliability. The project would transmit power from new and existing energy resources in northeastern Oregon to the Company’s service territory. PGE continues to work with other stakeholders in the region in planning the project and is actively engaged in the federal, state, and tribal permitting processes. Subject to obtaining all necessary approvals, the in-service date is not expected before 2017.

For additional information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

Legal, Regulatory, and Environmental Matters — PGE is a party to certain proceedings, the ultimate outcome of which may have a material impact on the results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, the following matters:


•	Challenges to recovery of the Company’s investment in its closed Trojan plant;


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


•	An investigation of environmental matters regarding Portland Harbor.

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

The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 or affected retail customer prices, as authorized by the OPUC. In some cases, the Company

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deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

•

Boardman Operating Life Adjustment — In PGE’s 2011 General Rate Case, the OPUC approved a tariff that provides a mechanism for future consideration of customer price changes related to the recovery of the Company’s remaining investment in the Boardman generating plant over a shortened operating life. Pursuant to the tariff, the OPUC approved recovery of increased depreciation expense reflecting a change in the retirement date of Boardman from 2040 to 2020, with new prices effective July 1, 2011, which provided incremental revenues for the last six months of 2011 of $7 million. In 2012, the annual revenue requirement for the full year is expected to be $13 million.

•

Power Costs — Pursuant to the AUT process, PGE files annually an estimate of power costs for the following year. In November 2011, the OPUC issued an order on the 2012 AUT resulting in an estimated 1% decrease in customer prices as a result of expected lower power costs. The new prices became effective January 1, 2012 and are expected to result in a decline of approximately $22 million in annual revenues compared to 2011.

The Company submitted an updated forecast of 2013 power costs to the OPUC in October 2012. Based on the latest estimate, which will be updated and finalized in November 2012, power costs for 2013 are expected to be lower than 2012, with a corresponding decrease in customer prices between 1% and 2% becoming effective January 1, 2013. The resulting annual revenue requirement is expected to decrease by approximately $27 million from 2012.

On July 1, 2012, the Company submitted to the OPUC the results of its PCAM for 2011 based on an updated regulated earnings test, which resulted in a revised refund to customers of approximately $6 million. On October 24, 2012, the OPUC issued an order approving the refund, with the impact to customer prices effective January 1, 2013. For further information, see Power Operations, within the Operating Activities section of this Overview, above.


•	Renewable Resource Costs — Pursuant to a renewable adjustment clause mechanism (RAC), PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. The Company may submit a filing to the OPUC by April 1st each year, with prices expected to become effective January 1st of the following year.

In March 2012, PGE submitted a filing for the installation of a small solar facility, which requested a nominal credit to customer prices for a one-year period beginning January 1, 2013, resulting from the gain on the sale and lease-back transaction directly related to the project.

The Company collected $22 million under the RAC as a result of a tariff the OPUC had previously approved for recovery over a one-year period that ended December 31, 2011 for eligible deferred costs and a return on the Company’s investment related to Biglow Canyon Phase III and a residual balance from the previous deferral of Biglow Canyon Phase II.

•

Decoupling — The decoupling mechanism is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The mechanism provides for customer collection (or refund) if weather adjusted use per customer is less (or more) than the levels approved in the Company’s most recent general rate case.


•	For the nine months ended September 30, 2012, the Company has recorded an estimated collection of $1 million. Any estimated refund to, or collection from, customers for the 2012 year would begin June 1, 2013.


•	During 2011, PGE recorded an estimated refund of $2 million that is being provided to customers

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over a one year period that began June 1, 2012, as weather adjusted use per customer was greater than levels projected in the 2011 General Rate Case.


•	For 2010, the Company recorded an estimated collection of $8 million, as weather adjusted use per customer was less than levels included in the 2009 General Rate Case. After review, the OPUC approved collections from customers over a one-year period that ended May 31, 2012.


•	Refund of tax credits — In 2011, PGE provided credits to customers for accumulated tax credits related to the Independent Spent Fuel Storage Installation (ISFSI) located at the Trojan site. The discontinuance of the customer credits on January 1, 2012 had the effect of increasing the Company’s annual revenues by approximately $18 million.

Critical Accounting Policies

PGE’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10‑K for the year ended December 31, 2011, filed with the SEC on February 24, 2012.

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Results of Operations

The following table contains condensed consolidated statements of income information for the periods presented (dollars in millions):



	Three Months Ended September 30,										Nine Months Ended September 30,
	2012					2011					2012					2011
Revenues, net	$	450		100	%	$	439		100	%	$	1,342		100	%	$	1,334		100	%
Purchased power and fuel	182			40		182			41		533			40		545			41
Gross margin	268			60		257			59		809			60		789			59
Operating expenses:
Production and distribution	49			11		50			11		153			11		147			11
Administrative and other	50			11		55			13		160			12		158			12
Depreciation and amortization	63			14		59			13		188			14		170			13
Taxes other than income taxes	24			6		25			6		77			6		74			5
Total operating expenses	186			42		189			43		578			43		549			41
Income from operations	82			18		68			16		231			17		240			18
Other income (expense):
Allowance for equity funds used during construction	1			—		1			—		4			—		3			—
Miscellaneous income (expense), net	—			—		(4		)	(1	)	2			—		(1		)	—
Other income (expense), net	1			—		(3		)	(1	)	6			—		2			—
Interest expense	27			6		27			6		82			6		82			6
Income before income taxes	56			12		38			9		155			11		160			12
Income taxes	19			4		11			3		43			3		42			3
Net income	37			8		27			6		112			8		118			9
Less: net loss attributable to noncontrolling interests	(1		)	—		—			—		(1		)	—		—			—
Net income attributable to Portland General Electric Company	$	38		8	%	$	27		6	%	$	113		8	%	$	118		9	%

Net income attributable to Portland General Electric Company was $38 million, or $0.50 per diluted share, for the third quarter of 2012 compared with $27 million, or $0.36 per diluted share, for the third quarter of 2011, an increase of $11 million, or 41%. The increase in Net income was due to several items including: an increase in residential energy deliveries; nominal gains on non-qualified benefit plan trust assets in 2012 compared to losses in 2011; and a reduction to the estimated customer refund related to the PCAM for 2011 recorded in 2012.

Net income attributable to Portland General Electric Company was $113 million, or $1.49 per diluted share, for the nine months ended September 30, 2012 compared with $118 million, or $1.57 per diluted share, for the nine months ended September 30, 2011, a decrease of $5 million, or 4%. The decrease in Net income was predominately driven by the decrease in residential energy deliveries, primarily due to warmer temperatures during the heating season, a substantial reduction in energy received from lower cost hydro resources, increased pension expense resulting from lower discount rates and returns on trust assets, and higher employee benefit costs driven by an increase in medical premiums. These items were partially offset by the impact of the PCAM, as a reduction to the estimated customer refund related to 2011 was recorded in the nine months ended September 30, 2012 in the amount of $4 million.

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Three Months Ended September 30, 2012 Compared with the Three Months Ended September 30, 2011

Revenues, energy deliveries (presented in MWh), and the average number of retail customers were as follows for the periods presented:



	Three Months Ended September 30,
	2012				2011
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	187	42	%	$	184		42	%
Commercial	168		37		167			38
Industrial	57		13		59			14
Subtotal	412		92		410			94
Other accrued (deferred) revenues, net	10		2		(4		)	(1	)
Total retail revenues	422		94		406			93
Wholesale revenues	19		4		24			5
Other operating revenues	9		2		9			2
Total revenues	$	450	100	%	$	439		100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	1,626		30	%	1,598			30	%
Commercial	1,963		36		1,970			36
Industrial	1,096		20		1,089			20
Total retail energy deliveries	4,685		86		4,657			86
Wholesale energy deliveries	771		14		780			14
Total energy deliveries	5,456		100	%	5,437			100	%
Average number of retail customers:
Residential	723,569		87	%	719,978			87	%
Commercial	105,100		13		104,471			13
Industrial	259		—		253			—
Total	828,928		100	%	824,702			100	%


(1)	Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.


(2)	Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

Total revenues increased $11 million, or 3%, in the third quarter of 2012 compared with the third quarter of 2011 primarily as a result of the items described below.

Retail revenues are generated by the sale and delivery of energy to retail customers as well as from the delivery of energy that certain commercial and industrial customers purchase from ESSs. Retail revenues also include certain deferred revenues, primarily related to the PCAM, decoupling mechanism, and RAC filings.

Total retail revenues increased $16 million, or 4%, in the third quarter of 2012 compared to the third quarter of 2011, primarily from the net effect of the following items:


•	An $11 million increase resulting from the PCAM, as a $7 million reduction in the estimated refund under the PCAM related to 2011 was recorded in the third quarter of 2012, compared with a $4 million estimated refund recorded in the third quarter of 2011;


•	A $4 million increase as a result of credits provided to customers during 2011 related to the ISFSI that were

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not applicable in 2012;


•	A $4 million increase resulting from several items, the largest of which amounted to just over $1 million, including the recovery of costs for the solar feed-in tariff, local taxes, and the decoupling mechanism; and


•	A $3 million increase as a result of increased volumes and prices for deliveries to direct access customers; partially offset by


•	A $4 million decrease from a lower volume of energy sold as a large industrial customer transitioned to direct access in 2012, the effect of which was partially offset by increased demand by another large industrial customer, higher residential demand due to warmer temperatures in 2012, and the increased number of customers; and


•	A $4 million decrease related to changes in the average retail price, resulting primarily from tariff changes effective January 1, 2012 as authorized by the OPUC.

Heating and cooling degree-days are an indication of the likelihood that customers will use electricity for heating and cooling, respectively, and are used to measure the effects of weather on the demand for electricity. Total cooling degree-days in the third quarter of 2012, while near historical averages, were 14% more than 2011 levels. Heating degree-days were comparable to the third quarter of 2011, with both years below the 15-year averages. The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:



	Heating Degree-days		Cooling Degree-days
	2012	2011	2012	2011
July	14	13	115	72
August	3	2	201	160
September	41	36	79	114
Third Quarter	58	51	395	346
15-year average for the third quarter	81	87	387	393

Wholesale revenues result from sales of electricity to utilities and power marketers in conjunction with the Company’s effort to secure reasonably priced power for retail customers, manage risk, and administer long-term wholesale contracts. Such sales can vary significantly period to period. Wholesale revenues in the third quarter of 2012 declined $5 million, or 21%, compared to the third quarter of 2011, primarily consisting of $5 million related to a 22% decrease in average sales price and a 1% decrease in the volume of wholesale energy sold.

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Purchased power and fuel expense for the third quarter of 2012 was comparable with the third quarter of 2011. A 1% increase in average variable power cost was substantially offset by a 1% decrease in total system load. The average variable power cost increased to $33.89 per MWh in the third quarter of 2012 compared with $33.49 per MWh in the third quarter of 2011 primarily driven by decreases in energy received from hydro and wind generating resources.

The sources of energy for the PGE’s total system load, as well as its retail load requirement, are as follows for the periods presented:



	Three Months Ended September 30,
	2012				2011
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	995		18	%	1,200		22	%
Natural gas	856		16		723		13
Total thermal	1,851		34		1,923		35
Hydro	331		6		345		6
Wind	341		7		379		7
Total generation	2,523		47		2,647		48
Purchased power:
Term	1,895		35		1,337		25
Hydro	422		8		766		14
Wind	95		2		95		2
Spot	460		8		617		11
Total purchased power	2,872		53		2,815		52
Total system load	5,395		100	%	5,462		100	%
Less: wholesale sales	(771	)			(780	)
Retail load requirement	4,624				4,682

Energy received from PGE-owned wind generating resources (Biglow Canyon) decreased 10% and represented 7% of the Company’s retail load requirement in the third quarter of 2012, compared with 8% in the third quarter of 2011. The decrease was due to less favorable wind conditions in the third quarter of 2012 compared with the same period last year.

Energy received from hydro resources during the third quarter of 2012, from both PGE-owned generating plants and purchased from mid-Columbia projects, decreased 32% compared with the third quarter of 2011 primarily due to more favorable hydro conditions in 2011, and the expiration at the end of 2011 of an agreement to purchase a portion of the output of one mid-Columbia project. These resources provided approximately 16% of the Company’s retail load requirement for the third quarter of 2012, compared with 24% for the third quarter of 2011. Total hydro generation in the third quarter of 2012 exceeded projected levels included in the AUT for 2012 by 14%, compared with 16% for the same period last year.

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The following table presents the actual of the April-to-September 2012 and 2011 runoffs at particular points of major rivers relevant to PGE’s hydro resources (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):



	Runoff as a Percent of Normal *
Location	2012		2011
Columbia River at The Dalles, Oregon	126	%	135	%
Mid-Columbia River at Grand Coulee, Washington	129		123
Clackamas River at Estacada, Oregon	133		135
Deschutes River at Moody, Oregon	118		120

* Volumetric water supply for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.

For the third quarter of 2012, actual NVPC was approximately $4 million below baseline NVPC compared with $7 million below baseline NVPC for the third quarter of 2011.

Gross margin, which represents the difference between Revenues, net and Purchased power and fuel expense, is among those performance indicators utilized by management in the analysis of financial and operating results. It provides a measure of income available to support other operating activities and expenses of the Company and serves as a useful measure for understanding and analyzing changes in operating performance between reporting periods. It is considered a “non-GAAP financial measure,” as defined in accordance with SEC rules, and is not intended to replace operating income as determined in accordance with GAAP.

Gross margin was 60% in the third quarter of 2012, compared with 59% in the third quarter of 2011. The increase in gross margin is largely due to the impact of the PCAM and the impact of the ISFSI tax credits, which were refunded to customers in 2011.

Production and distribution expense decreased $1 million, or 2%, in the third quarter of 2012 compared with the third quarter of 2011, primarily due to decreases in delivery system costs related to information technology upgrades, partially offset by higher maintenance expense at the Company’s Boardman thermal generating plant.

Administrative and other expense decreased $5 million, or 9%, in the third quarter of 2012 compared with the third quarter of 2011. The decrease was primarily due to a reduction in legal fees and decreased employee compensation and benefit costs, partially offset by increased employee pension expenses resulting from a lower discount rate and return on pension trust assets.

Depreciation and amortization expense increased $4 million, or 7%, in the third quarter of 2012 compared with the third quarter of 2011. The increase was primarily due to the amortization of ISFSI tax credits in 2011 (offset in Revenues) and increased depreciation expense related to capital additions, partially offset by a deferral of costs related to certain capital projects as approved in the 2011 General Rate Case.

Other income, net was $1 million in the third quarter of 2012 compared to Other expense, net of $3 million in the third quarter of 2011. The change is primarily due to unrealized losses in the third quarter of 2011 on the non-qualified benefit plan trust assets in the amount of $4 million.

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Income taxes increased $8 million in the third quarter of 2012 compared with the third quarter of 2011. The effective tax rates are 33.9% and 28.9% in the third quarters of 2012 and 2011, respectively. The increase in the effective tax rate is due to the reduced income tax rate benefit from production tax credits (PTCs) and state income tax credits resulting from the increase in pre-tax income during the third quarter of 2012.

Nine Months Ended September 30, 2012 Compared with the Nine Months Ended September 30, 2011

Revenues, energy deliveries (presented in MWh), and the average number of retail customers were as follows for the periods presented:



	Nine Months Ended September 30,
	2012				2011
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	630	47	%	$	635		47	%
Commercial	476		36		474			35
Industrial	166		12		168			13
Subtotal	1,272		95		1,277			95
Other accrued (deferred) revenues, net	6		—		(18		)	(1	)
Total retail revenues	1,278		95		1,259			94
Wholesale revenues	38		3		49			4
Other operating revenues	26		2		26			2
Total revenues	$	1,342	100	%	$	1,334		100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	5,506		34	%	5,604			35	%
Commercial	5,566		34		5,560			34
Industrial	3,180		20		3,156			20
Total retail energy deliveries	14,252		88		14,320			89
Wholesale energy deliveries	1,861		12		1,848			11
Total energy deliveries	16,113		100	%	16,168			100	%
Average number of retail customers:
Residential	722,884		87	%	719,809			87	%
Commercial	103,798		13		102,911			13
Industrial	261		—		255			—
Total	826,943		100	%	822,975			100	%


(1)	Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.


(2)	Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

Total revenues increased $8 million, or less than 1% for the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011 primarily as a result of the items described below.

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Retail revenues increased $19 million, or 2%, in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011. The increase resulted primarily from the combination and net effect of the following items:

•

A $21 million increase related to the PCAM, as an estimated refund to customers in the amount of $17 million was recorded in the nine months ended September 30, 2011 (reduced to $10 million in the fourth quarter 2011) compared to a $4 million reduction in the refund recorded in the comparable period of 2012 related to the PCAM for 2011. No estimated refund or collection has been recorded under the PCAM related to 2012;


•	A $13 million increase as a result of credits provided to customers during 2011 related to the ISFSI that were not applicable in 2012;


•	A $9 million increase as a result of increased volumes and prices for deliveries to direct access customers; and


•	An $11 million increase resulting from several items, the largest of which amounted to just under $4 million for the recovery of costs under the solar feed-in tariff; partially offset by


•	A $23 million decrease from a lower volume of energy sold as one large industrial customer transitioned to direct access in 2012 while residential deliveries were also down. Lower than comparable load demand in the residential class in 2012 was caused by cooler weather during the heating season in early 2011; and


•	A $12 million decrease related to changes in the average retail price, resulting primarily from tariff changes effective January 1, 2012 as authorized by the OPUC.

Total heating degree-days in the nine months ended September 30, 2012 were 8% below those of the comparable period of 2011 but still 3% above historical averages. Cooling degree-days were higher in the nine months ended September 30, 2012 than in the comparable period of 2011, but remain below the 15-year averages. The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:



	Heating Degree-days		Cooling Degree-days
	2012	2011	2012	2011
First Quarter	1,967	1,974	—	—
Second Quarter	709	946	40	16
Third Quarter	58	51	395	346
Year-to-date	2,734	2,971	435	362
15-year average for the year-to-date	2,643	2,630	455	462

Wholesale revenues in the nine months ended September 30, 2012 declined $11 million, or 22%, compared to the comparable period of 2011, primarily consisting of a 22% decrease in average sales price, while sales volume increased 1%. Lower wholesale market prices were driven by low natural gas prices.

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Purchased power and fuel expense was $533 million for the nine months ended September 30, 2012, a decrease of $12 million, or 2%, compared with $545 million for the nine months ended September 30, 2011, largely due to $9 million related to a 2% decrease in total system load and $2 million related to a 1% decrease in average variable power cost. The average variable power cost decreased to $33.41 per MWh in the nine months ended September 30, 2012 compared with $33.58 per MWh in the nine months ended September 30, 2011, which consisted of a 4% decrease in the average cost of purchased power offset by an 8% increase in the average cost of power generated.

The sources of energy for PGE’s total system load, as well as its retail load requirement, are as follows for the periods presented:



	Nine Months Ended September 30,
	2012				2011
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	2,280		14	%	2,708		17	%
Natural gas	1,993		13		1,058		6
Total thermal	4,273		27		3,766		23
Hydro	1,461		9		1,524		10
Wind	964		6		1,025		6
Total generation	6,698		42		6,315		39
Purchased power:
Term	6,042		38		5,057		31
Hydro	1,358		8		2,489		15
Wind	272		2		203		1
Spot	1,641		10		2,200		14
Total purchased power	9,313		58		9,949		61
Total system load	16,011		100	%	16,264		100	%
Less: wholesale sales	(1,861	)			(1,848	)
Retail load requirement	14,150				14,416

Energy received from PGE-owned wind generating resources (Biglow Canyon) decreased 6% compared with the nine months ended September 30, 2011, and represented 7% of the Company’s retail load requirement in each of the nine month periods ended September 30, 2012 and 2011. The decrease in these resources was due to less favorable wind conditions in 2012 compared with 2011.

Energy received from hydro resources during the nine months ended September 30, 2012, from both PGE-owned generating plants and purchased from mid-Columbia projects, decreased 30% compared with the nine months ended September 30, 2011 primarily due to more favorable hydro conditions in 2011 and the expiration of an agreement at the end of 2011 to purchase a portion of the output of one mid-Columbia project. These resources provided approximately 20% of the Company’s retail load requirement during the nine months ended September 30, 2012, compared with 28% during the nine months ended September 30, 2011. Through September 30, 2012, total hydro generation exceeded projected levels included in the AUT for 2012 by 12%, compared with 17% for the same period of 2011.

For the nine months ended September 30, 2012, actual NVPC was approximately $14 million below baseline NVPC and approximately $36 million below baseline NVPC for the nine months ended September 30, 2011.

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Gross margin was 60% for the nine months ended September 30, 2012, compared with 59% for the nine months ended September 30, 2011. The increase in gross margin is largely due to the impact of the PCAM. During the nine months ended September 30, 2012, PGE reduced the estimated refund to customers related to the PCAM for 2011, compared to an estimated refund to customers recorded in the same period of 2011. Additionally, the impact of the ISFSI tax credits refunded to customers in 2011 contributed to the increase in gross margin. Gross margin was negatively impacted by a decrease in residential energy deliveries during the nine months ended September 30, 2012 relative to the comparable period in 2011.

Production and distribution expense increased $6 million, or 4%, in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011, primarily due to increases in delivery system costs related to information technology upgrades, and a $3 million insurance recovery related to the Selective Water Withdrawal project recorded in 2011. Partially offsetting the above increases was a net decrease in operating and maintenance expenses at the Company’s thermal generating plants resulting from higher planned maintenance expenses in 2011 compared to 2012.

Administrative and other expense increased $2 million, or 1%, in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011. The increase was primarily due to increased employee pension expenses resulting from a lower discount rate and lower return on pension trust assets, and employee benefit costs resulting from higher medical premiums. Partially offsetting the above increase was a decrease in legal fees.

Depreciation and amortization expense increased $18 million, or 11%, in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011. The increase was primarily due to the amortization of ISFSI tax credits in 2011 (offset in Revenues), increased depreciation expense related to capital additions, and a shorter operating life for the Boardman plant effective July 2011, partially offset by a deferral of costs related to certain capital projects as approved in the 2011 General Rate Case.

Taxes other than income taxes increased $3 million, or 4%, in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011, primarily due to higher property taxes, resulting from both increased property values and tax rates. Also contributing to the increase were higher franchise fees.

Other income, net increased $4 million in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011, primarily due to higher earnings from non-qualified benefit plan trust assets.

Income taxes increased $1 million in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011, with effective tax rates of 27.7% and 26.3%, respectively. The increase in the effective tax rate is primarily due to a decrease in income tax benefit of PTCs and state income tax credits in the current period.

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Liquidity and Capital Resources

Capital Requirements

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



	2012			2013		2014		2015		2016
Ongoing capital expenditures	$	266		$	317	$	288	$	255	$	255
Hydro licensing and construction	24			23		34		37		1
Boardman emissions controls ⁽¹⁾	10			13		—		—		—
Cascade Crossing	28			—		—		—		—
Total capital expenditures	$	328	⁽²⁾	$	353	$	322	$	292	$	256
Long-term debt maturities	$	100		$	100	$	—	$	70	$	67

(1)

Represents 80% of estimated total costs based on installation of emissions controls to meet regulatory requirements. In 1985, PGE sold an undivided 15% interest in Boardman to a third party, reducing the Company’s ownership interest from 80% to 65%. The purchaser has certain rights to participate in the financing of the portion of the total capital cost attributable to its interest. If the purchaser does not exercise its rights to finance the portion of the total cost attributable to its interest, PGE’s share of the total cost for the emissions controls at Boardman is expected to be 80%.


(2)	Amounts shown include preliminary engineering and removal costs, which are included in other net operating activities in the condensed consolidated statements of cash flows.

Ongoing capital expenditures — Capital spending requirements consist primarily of upgrades to, and replacement of, transmission, distribution, and generation infrastructure, as well as new customer connections. Preliminary engineering costs, which consist of expenditures for surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects, including certain projects discussed in the Integrated Resource Plan section below, are included in Ongoing capital expenditures. As of September 30, 2012 and December 31, 2011, preliminary engineering costs of $13 million and $10 million, respectively, are included in Other noncurrent assets in PGE’s condensed consolidated balance sheets. The Company expects that it will incur a total of approximately $4 million for preliminary engineering on major projects during 2012.

Hydro licensing and construction — PGE’s hydroelectric projects are operated pursuant to FERC licenses issued under the Federal Power Act. Capital spending requirements reflected in the table above relate primarily to modifications to the Company’s hydro facilities to enhance fish passage and survival, as required by conditions contained in the operating licenses.

Emissions controls — In June 2011, the EPA approved revised rules that established new emissions limits at Boardman and provide for coal-fired operation to cease no later than December 31, 2020. The emissions limits imposed under the revised rules require the addition of certain controls. PGE’s portion of capital spending on the Boardman emissions controls through September 30, 2012 was approximately $29 million.

In December 2011, the EPA issued new emissions limits under the Clean Air Act’s National Emission Standards for Hazardous Air Pollutants (NESHAP) regulating hazardous air pollutant emissions, from coal- and oil-fired electric generating units. Emissions limits included in the NESHAP are based on the application of maximum achievable control technology (MACT). Based on its review of the rules and the preliminary full-scale test results, PGE believes Boardman should be able to meet the MACT requirements with the installation of the currently planned controls.

The operator of Colstrip has provided PGE with estimated costs for emissions control modifications to Units 3 and 4 that may be necessary to meet the MACT requirements. Based on this estimate, the Company expects that its share of these costs, as a 20% owner of Units 3 and 4, will be approximately $10 million.

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Integrated Resource Plan — The Company’s IRP, acknowledged by the OPUC in November 2010, included the following resource, capacity, and transmission projects:


•	The addition of new generating plants and improvements to existing plants. The related RFP processes will determine the successful bidders and clarify the timing and total cost for the new capacity, energy, and renewable resources described in the IRP; and

•

The construction of the Cascade Crossing transmission line at an estimated total cost of $800 million to $1.0 billion. The Company continues to work with other stakeholders in planning the project and potential project partnerships. As of September 30, 2012, the Company has recorded $39 million in costs, primarily related to environmental assessments and permitting activities, included in Construction work in progress (CWIP), in Electric utility plant, net in its condensed consolidated balance sheets.

Due to the uncertainty of these projects, the Capital Requirements table above does not include estimates for any amounts related to these projects beyond 2012. If PGE moves forward with the projects for which preliminary engineering costs are recorded, such costs are transferred to CWIP. If the projects are abandoned, such costs, including those already in CWIP related to Cascade Crossing, would be expensed in the period such determination is made. If any costs associated with the new generating plants acknowledged in the IRP are expensed, the Company may seek regulatory recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted.

For further information on the Company’s IRP and the projects subject to the RFP process, see Capital Requirements and Financing in the Overview section of this Item 2.

Liquidity

PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. 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 deposit requirements related to wholesale market 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 periods presented (in millions):



	Nine Months Ended September 30,
	2012			2011
Cash and cash equivalents, beginning of period	$	6		$	4
Net cash provided by (used in):
Operating activities	450			399
Investing activities	(209		)	(214		)
Financing activities	(91		)	(92		)
Increase in cash and cash equivalents	150			93
Cash and cash equivalents, end of period	$	156		$	97

Cash Flows from Operating Activities — Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, such as depreciation and amortization and deferred income taxes, included in net income during a given period. The $51 million increase in cash provided by operating activities for the nine months ended September 30, 2012 when compared with the nine months ended September 30, 2011 was primarily due to a decrease in margin deposit requirements and the impact of a combined contribution of $40 million to the pension

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plan and voluntary employees’ beneficiary association trust in 2011, partially offset by changes in working capital items.

A significant portion of cash provided by operations consists of the recovery in customer prices of non-cash charges for depreciation and amortization, which PGE expects to be approximately $249 million in 2012, with total cash provided by operations anticipated to be approximately $474 million.

Cash Flows from Investing Activities — Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities. The $5 million decrease in net cash used in investing activities in the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011 was due primarily to a small increase in capital expenditures partially offset by proceeds received from the sale of a solar power facility in the first quarter of 2012.

The Company plans a total of approximately $328 million in capital expenditures for 2012 related to upgrades and replacement of transmission, distribution, and generation infrastructure. See Capital Requirements section above for additional information.

Cash Flows from Financing Activities — Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the nine months ended September 30, 2012, cash used in such activities consisted of the repayment of commercial paper of $30 million and the payment of dividends of $61 million. During the nine months ended September 30, 2011, cash used by financing activities consisted of the payment of dividends of $59 million, the repayment of commercial paper of $19 million, the repayment of long-term debt of $10 million, and capital distributions to noncontrolling interests of $4 million.

During October 2012, the Company repaid the 5.6675% Series of First Mortgage Bonds in the amount of $100 million, which will be reflected as cash used in financing activities in PGE’s consolidated statement of cash flows for the year ending December 31, 2012.

Dividends on Common Stock

While the Company expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant, which may include, among other things, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

Common stock dividends declared during 2012 consist of the following:



			Dividends
			Declared Per
Declaration Date	Record Date	Payment Date	Common Share
February 22, 2012	March 26, 2012	April 16, 2012	$	0.265
May 23, 2012	June 25, 2012	July 16, 2012	0.270
August 2, 2012	September 25, 2012	October 15, 2012	0.270
November 7, 2012	December 26, 2012	January 15, 2013	0.270

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Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, alternatives available to investors, and other factors. The Company’s ability to obtain and renew such financing depends on its credit ratings, as well as on credit markets, both generally and for electric utilities in particular. Management believes that the availability of credit facilities, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. PGE currently does not expect to issue debt or equity securities in 2012.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $700 million through February 6, 2014 and currently has the following unsecured revolving credit facilities:


•	A $360 million syndicated credit facility scheduled to terminate July 2013; and


•	A $300 million syndicated credit facility scheduled to terminate December 2016.

These credit facilities supplement operating cash flow and provide a primary source of liquidity. Pursuant to the terms of the agreements, the credit facilities may be used for general corporate purposes, backup for commercial paper borrowings, and the issuance of standby letters of credit. As of September 30, 2012, PGE had no borrowings outstanding under the credit facilities, no commercial paper outstanding, and $61 million of letters of credit issued. As of September 30, 2012, the aggregate unused credit available under the credit facilities was $599 million.

Long-term Debt. As of September 30, 2012, total long-term debt outstanding was $1,736 million. In addition, PGE owns $21 million of its Pollution Control Revenue Bonds, which may be remarketed at a later date, at the Company’s option, through 2033.

Capital Structure. 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 49.8% and 48.6% as of September 30, 2012 and December 31, 2011, respectively.

Credit Ratings and Debt Covenants

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



	Moody’s	S&P
First Mortgage Bonds	A3	A-
Senior unsecured debt	Baa2	BBB
Commercial paper	Prime-2	A-2
Outlook	Positive	Stable

Moody’s Investors Service (Moody’s) changed the Company’s rating outlook to ‘positive’ from ‘stable’ during the quarter ended June 30, 2012. The change in the outlook reflects Moody’s expectations for PGE’s financial metrics to improve to levels more commensurate with the Baa1 rating category over the intermediate-term.

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale, commodity and related transmission

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counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. These cash deposits are classified as Margin deposits on PGE’s condensed consolidated balance sheet, while any letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

As of September 30, 2012, PGE had posted approximately $93 million of collateral with these counterparties, consisting of $53 million in cash and $40 million in letters of credit, $15 million of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of September 30, 2012, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $85 million and decreases to approximately $55 million by December 31, 2012, and $20 million by December 31, 2013. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $260 million at September 30, 2012 and decreases to approximately $189 million by December 31, 2012, and $84 million by December 31, 2013.

PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing under the credit facilities would increase.

The issuance of First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimated that on September 30, 2012, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $585 million of additional First Mortgage Bonds. Any issuance of First Mortgage Bonds would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt ratio). As of September 30, 2012, the Company’s debt ratio, as calculated under the credit agreements, was 50.3%.

Off-Balance Sheet Arrangements

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

Contractual Obligations

PGE’s contractual obligations for 2012 and beyond are set forth in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 24, 2012. Such obligations have not changed materially as of September 30, 2012, with the exception of the following:

Future pension contribution obligations outlined in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 were estimated using the funding level calculated with discount rates determined by the Internal Revenue Service and the guidelines of the Pension Protection Act. On July 6, 2012 the President signed the “Moving Ahead for Progress in the 21^st Century Act.” The effect of this legislation on the Pension Protection Act was to increase the discount rate used in determining the funded status of the pension plan, increasing the plan’s overall funded status for 2013. Pursuant to this new legislation, PGE expects its pension plan contribution obligation to approximate the following: $0 in 2013; $15 million in 2014; $32 million in 2015; and $43 million in 2016.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 24, 2012.



Item 4.	Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2012, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2012, there were no changes in the Company’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

PART II - OTHER INFORMATION



Item 1.	Legal Proceedings.

For information regarding PGE’s legal proceedings, see Legal Proceedings set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 24, 2012.



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, 2011, filed with the SEC on February 24, 2012.

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Item 6.	Exhibits.



3.1	Second Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10‑Q filed August 3, 2009).
3.2	Ninth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed October 27, 2011).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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

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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 7, 2012	By:	/s/ Maria M. Pope
			Maria M. Pope
			Senior Vice President, Finance, Chief Financial Officer, and Treasurer
			(duly authorized officer and principal financial officer)