POR 10-Q Quarterly Report March 31, 2013

POR 10-Q Quarter ended March 31, 2013

PORTLAND GENERAL ELECTRIC CO /OR/

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10-Q 1 por2013033110q.htm FORM 10-Q POR 20130331 10Q

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2013



[ ]	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: 001-5532-99

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



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

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

Number of shares of common stock outstanding as of April 25, 2013 is 75,678,110 shares.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013

TABLE OF CONTENTS



Definitions		3

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Condensed Consolidated Statements of Income and Comprehensive 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	32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48

Item 4.	Controls and Procedures	48

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	48

Item 1A.	Risk Factors	49

Item 6.	Exhibits	50

SIGNATURE		50

Table of Contents

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
Cascade Crossing		Cascade Crossing Transmission Project
Colstrip		Colstrip Steam Electric Station (coal-fired generating plant)
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRP		Integrated Resource Plan
kV		Kilovolt = one thousand volts of electricity
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
PW2		Port Westward Unit 2 natural gas-fired generating plant
RFP		Request for proposal
S&P		Standard and Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
Trojan		Trojan nuclear power plant

Table of Contents

PART I — FINANCIAL INFORMATION



Item 1.	Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)



	Three Months Ended March 31,
	2013			2012
Revenues, net	$	473		$	479
Operating expenses:
Purchased power and fuel	192			195
Production and distribution	51			53
Administrative and other	54			54
Depreciation and amortization	62			62
Taxes other than income taxes	27			27
Total operating expenses	386			391
Income from operations	87			88
Other income:
Allowance for equity funds used during construction	2			1
Miscellaneous income, net	1			3
Other income	3			4
Interest expense	25			28
Income before income taxes	65			64
Income taxes	17			15
Net income and Comprehensive income	48			49
Less: net loss attributable to noncontrolling interests	(1		)	—
Net income and Comprehensive income attributable to Portland General Electric Company	$	49		$	49

Weighted-average shares outstanding (in thousands):
Basic	75,608			75,423
Diluted	75,699			75,443

Earnings per share—basic and diluted	$	0.65		$	0.65
Dividends declared per common share	$	0.270		$	0.265

See accompanying notes to condensed consolidated financial statements.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	March 31, 2013		December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	33	$	12
Accounts receivable, net	144		152
Unbilled revenues	76		97
Inventories	77		78
Margin deposits	33		46
Regulatory assets—current	96		144
Other current assets	105		93
Total current assets	564		622
Electric utility plant, net	4,449		4,392
Regulatory assets—noncurrent	524		524
Nuclear decommissioning trust	38		38
Non-qualified benefit plan trust	32		32
Other noncurrent assets	54		62
Total assets	$	5,661	$	5,670

See accompanying notes to condensed consolidated financial statements.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)



	March 31, 2013			December 31, 2012
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	77		$	98
Liabilities from price risk management activities—current	91			127
Short-term debt	—			17
Current portion of long-term debt	100			100
Accrued expenses and other current liabilities	192			179
Total current liabilities	460			521
Long-term debt, net of current portion	1,536			1,536
Regulatory liabilities—noncurrent	782			765
Deferred income taxes	586			588
Unfunded status of pension and postretirement plans	249			247
Non-qualified benefit plan liabilities	103			102
Asset retirement obligations	93			94
Liabilities from price risk management activities—noncurrent	78			73
Other noncurrent liabilities	16			14
Total liabilities	3,903			3,940
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 March 31, 2013 and December 31, 2012	—			—
Common stock, no par value, 160,000,000 shares authorized; 75,677,181 and 75,556,272 shares issued and outstanding as of March 31, 2013 and December 31, 2012, respectively	841			841
Accumulated other comprehensive loss	(6		)	(6		)
Retained earnings	922			893
Total Portland General Electric Company shareholders’ equity	1,757			1,728
Noncontrolling interests’ equity	1			2
Total equity	1,758			1,730
Total liabilities and equity	$	5,661		$	5,670

See accompanying notes to condensed consolidated financial statements.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net income	$	48		$	49
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	62			62
(Decrease) increase in net liabilities from price risk management activities	(37		)	21
Regulatory deferral—price risk management activities	37			(22		)
Deferred income taxes	13			24
Pension and other postretirement benefits	10			7
Regulatory deferral of settled derivative instruments	5			2
Decoupling mechanism deferrals, net of amortization	(5		)	3
Power cost deferrals, net of amortization	(2		)	3
Allowance for equity funds used during construction	(2		)	(1		)
Other non-cash income and expenses, net	10			7
Changes in working capital:
Decrease in receivables	29			9
Decrease (increase) in margin deposits, net	13			(18		)
Income tax refund received	—			8
Decrease in payables and accrued liabilities	(4		)	(18		)
Other working capital items, net	(12		)	(24		)
Other, net	—			(2		)
Net cash provided by operating activities	165			110
Cash flows from investing activities:
Capital expenditures	(108		)	(69		)
Proceeds from sale of solar power facility	—			10
Sales of nuclear decommissioning trust securities	8			7
Purchases of nuclear decommissioning trust securities	(9		)	(7		)
Other, net	2			1
Net cash used in investing activities	(107		)	(58		)

See accompanying notes to condensed consolidated financial statements.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)



	Three Months Ended March 31,
	2013			2012
Cash flows from financing activities:
Maturities of commercial paper, net	$	(17	)	$	(30	)
Dividends paid	(20		)	(20		)
Net cash used in financing activities	(37		)	(50		)
Increase in cash and cash equivalents	21			2
Cash and cash equivalents, beginning of period	12			6
Cash and cash equivalents, end of period	$	33		$	8

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	13		$	13
Non-cash investing and financing activities:
Accrued dividends payable	20			21
Accrued capital additions	11			8
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	4			—

See accompanying notes to condensed consolidated financial statements.

Table of Contents

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 March 31, 2013 , PGE served 829,898 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 United States 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 month periods ended March 31, 2013 and 2012 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, 2012 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2012 , included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 22, 2013 , and should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income

PGE had no material components of other comprehensive income to report for the three month periods ended March 31, 2013 and 2012.

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 2013 presentation, PGE has separately presented Pension and other postretirement benefits of $7 million from Other non-cash income and expenses, net, and separately presented Decoupling mechanism deferrals, net of amortization of $3 million and Regulatory deferral of settled derivative instruments of $2 million from Other, net in the operating activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2012.

Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2011-11, Balance Sheet (Topic 210) - Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In addition, ASU 2013-01, Balance Sheet (Topic 210) - Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), was issued in January 2013 and clarifies that the scope of ASU 2011-11 applies to financial instruments accounted for in accordance with Topic 815, Derivatives and Hedging . Both ASUs are effective January 1, 2013 for the Company, and require retrospective application. PGE adopted the amendments contained in ASU 2011-11 and ASU 2013-01 on January 1, 2013, which did not have an impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows. See Note 4, Price Risk Management, for the additional disclosures made pursuant to the adoption of these ASUs.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million as of March 31, 2013 and $5 million as of December 31, 2012 .

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



	Three Months Ended March 31,
	2013			2012
Balance as of beginning of period	$	5		$	6
Provision, net	2			1
Amounts written off, less recoveries	(1		)	(1		)
Balance as of end of period	$	6		$	6

Inventories

PGE inventories are recorded at average cost and 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.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Other Current Assets

Other current assets consist of the following (in millions):



	March 31, 2013		December 31, 2012
Prepaid expenses	$	51	$	37
Current deferred income tax asset	38		51
Assets from price risk management activities	11		4
Other	5		1
Other current assets	$	105	$	93

Electric Utility Plant, Net

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



	March 31, 2013			December 31, 2012
Electric utility plant	$	6,850		$	6,811
Construction work in progress	201			140
Total cost	7,051			6,951
Less: accumulated depreciation and amortization	(2,602		)	(2,559		)
Electric utility plant, net	$	4,449		$	4,392

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $156 million and $151 million as of March 31, 2013 and December 31, 2012 , respectively. Amortization expense related to intangible assets was $5 million for the three months ended March 31, 2013 and 2012 .

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.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Regulatory Assets and Liabilities

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



	March 31, 2013					December 31, 2012
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	80		$	77	$	123		$	71
Pension and other postretirement plans	—			314		—			321
Deferred income taxes	—			78		—			80
Deferred broker settlements	15			1		20			1
Debt reacquisition costs	—			20		—			22
Deferred capital projects	—			19		—			16
Other	1			15		1			13
Total regulatory assets	$	96		$	524	$	144		$	524
Regulatory liabilities:
Asset retirement removal costs	$	—		$	706	$	—		$	692
Asset retirement obligations	—			40		—			39
Power cost adjustment mechanism	4			—		6			—
Other	7			36		6			34
Total regulatory liabilities	$	11	⁽¹⁾	$	782	$	12	⁽¹⁾	$	765

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

Accrued expenses and other current liabilities

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



	March 31, 2013		December 31, 2012
Accrued employee compensation and benefits	$	36	$	46
Accrued interest payable	33		23
Accrued taxes payable	30		21
Accrued dividends payable	20		21
Regulatory liabilities—current	11		12
Other	62		56
Total accrued expenses and other current liabilities	$	192	$	179

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Credit Facilities

PGE has the following unsecured revolving credit facilities as of March 31, 2013 :


•	A $400 million syndicated credit facility, which is scheduled to terminate in November 2017 ; 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 March 31, 2013 , PGE was in compliance with this requirement with a 48.2% 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 March 31, 2013 , PGE had no borrowings or commercial paper outstanding, $52 million of letters of credit issued, and aggregate unused credit available of $648 million under the credit facilities.

Pension and Other Postretirement Benefits

Components of net periodic benefit cost are as follows (in millions):



	Three Months Ended March 31,
	Defined Benefit Pension Plan						Other Postretirement Benefits				Non-Qualified Benefit Plans
	2013			2012			2013		2012		2013		2012
Service cost	$	4		$	3		$	1	$	1	$	—	$	—
Interest cost	8			8			1		1		—		1
Expected return on plan assets	(10		)	(10		)	—		—		—		—
Amortization of net actuarial loss	6			4			—		—		—		—
Net periodic benefit cost	$	8		$	5		$	2	$	2	$	—	$	1

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 March 31, 2013 and December 31, 2012 , 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.

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 month periods ended March 31, 2013 and 2012.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 March 31, 2013
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	9		7		—		16
Corporate credit	—		8		—		8
Non-qualified benefit plan trust: ⁽²⁾
Equity securities—Domestic	3		3		—		6
Debt securities—Domestic government	2		—		—		2
Assets from price risk management activities: ^{(1) (3)}
Electricity	—		5		—		5
Natural gas	—		6		1		7
	$	14	$	43	$	1	$	58
Liabilities from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	42	$	36	$	78
Natural gas	—		81		10		91
	$	—	$	123	$	46	$	169


(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 $24 million , which are recorded at cash surrender value.


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

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)



	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	15	$	—	$	15
Debt securities:
Domestic government	7		8		—		15
Corporate credit	—		8		—		8
Non-qualified benefit plan trust: ⁽²⁾
Money market funds	—		2		—		2
Equity securities:
Domestic	2		2		—		4
International	1		—		—		1
Debt securities—Domestic government	2		—		—		2
Assets from price risk management activities: ^{(1) (3)}
Electricity	—		1		—		1
Natural gas	—		3		2		5
	$	12	$	39	$	2	$	53
Liabilities — Liabilities from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	72	$	10	$	82
Natural gas	—		110		8		118
	$	—	$	182	$	18	$	200


(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 invested in securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 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 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

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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.

Equity securities —Certain equity mutual fund and common stock 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. 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 condensed 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.

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities as of March 31, 2013 is presented below:



	Fair Value						Price per Unit
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(in millions)
Natural gas financial swaps	$	1	$	10	Discounted cash flow	Natural gas forward price (per Decatherm)	$	3.58	$	5.02	$	4.20
Electricity financial swaps	—		12		Discounted cash flow	Electricity forward price (per MWh)	7.32		48.59		39.65
Electricity physical forward purchase	—		24		Discounted cash flow	Electricity forward price (per MWh)	41.22		43.74		42.60
	$	1	$	46

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	Fair Value						Price per Unit
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(in millions)
Natural gas financial swaps	$	2	$	8	Discounted cash flow	Natural gas forward price (per Decatherm)	$	3.67	$	5.21	$	4.28
Electricity financial swaps	—		10		Discounted cash flow	Electricity forward price (per MWh)	7.12		51.72		41.14
	$	2	$	18

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 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 Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying 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. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

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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 March 31,
	2013		2012
Balance as of the beginning of the period	$	16	$	79
Net realized and unrealized losses ⁽¹⁾	5		18
Purchases	24		—
Issuances	—		(1		)
Transfers out of Level 3 to Level 2	—		(1		)
Balance as of the end of the period	$	45	$	95


(1)	Contains nominal amounts of realized 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 three month period ended March 31, 2013 , 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 March 31, 2013 , the estimated aggregate fair value of PGE’s long-term debt was $1,921 million , compared to its $1,636 million carrying amount. As of December 31, 2012, the estimated aggregate fair value of PGE’s long-term debt was $1,949 million , compared to its $1,636 million carrying amount.

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, futures, 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 Public Utility Commission of Oregon (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

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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’s Assets and Liabilities from price risk management activities consist of the following (in millions):



	March 31, 2013			December 31, 2012
Current assets:
Commodity contracts:
Electricity	$	5		$	1
Natural gas	6			3
Total current derivative assets	11		⁽¹⁾	4		⁽¹⁾
Noncurrent assets:
Commodity contracts—Natural gas	1		⁽²⁾	2		⁽²⁾
Total derivative assets not designated as hedging instruments	$	12		$	6
Total derivative assets	$	12		$	6
Current liabilities:
Commodity contracts:
Electricity	$	31		$	44
Natural gas	60			83
Total current derivative liabilities	91			127
Noncurrent liabilities:
Commodity contracts:
Electricity	47			38
Natural gas	31			35
Total noncurrent derivative liabilities	78			73
Total derivative liabilities not designated as hedging instruments	$	169		$	200
Total derivative liabilities	$	169		$	200


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


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

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 2016, were as follows (in millions):



	March 31, 2013			December 31, 2012
Commodity contracts:
Electricity	13		MWh	11		MWh
Natural gas	87		Decatherms	86		Decatherms
Oil	3		Gallons	—		Gallons
Foreign currency	$	8	Canadian	$	7	Canadian

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PGE has elected to report gross on the balance sheet the positive and negative exposures resulting from derivative instruments with counterparties under agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit, which are excluded from the offsetting table presented below.

Information related to Price risk management assets and liabilities subject to master netting agreements is as follows (in millions):



	Gross		Gross		Net		Gross Amounts Not Offset in
	Amounts		Amounts		Amounts		Consolidated Balance Sheet
	Recognized		Offset		Presented		Derivatives			Cash Collateral ⁽¹⁾		Net Amount
As of March 31, 2013:
Assets:
Commodity contracts:
Electricity ⁽²⁾	$	1	$	—	$	1	$	(1	)	$	—	$	—
Natural gas ⁽²⁾	1		—		1		(1		)	—		—
	$	2	$	—	$	2	$	(2	)	$	—	$	—
Liabilities:
Commodity contracts:
Electricity ⁽³⁾	$	12	$	—	$	12	$	(12	)	$	—	$	—
Natural gas ⁽³⁾	5		—		5		(5		)	—		—
	$	17	$	—	$	17	$	(17	)	$	—	$	—

As of December 31, 2012:
Liabilities:
Commodity contracts:
Electricity ⁽³⁾	$	20	$	—	$	20	$	(20	)	$	—	$	—
Natural gas ⁽³⁾	7		—		7		(7		)	—		—
	$	27	$	—	$	27	$	(27	)	$	—	$	—


(1)	As of March 31, 2013 and December 31, 2012 , the Company had collateral posted of $11 million and $18 million , respectively, which consists entirely of letters of credit.


(2)	Included in Other current assets and Other noncurrent assets on the condensed consolidated balance sheets.


(3)	Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.

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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 March 31,
	2013			2012
Commodity contracts:
Electricity	$	8		$	53
Natural Gas	(8		)	36

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 March 31, 2013 and 2012 , net losses of $3 million and $81 million , respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2013 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):



	2013		2014		2015		2016		Total
Commodity contracts:
Electricity	$	20	$	30	$	18	$	5	$	73
Natural gas	50		25		6		3		84
Net unrealized loss	$	70	$	55	$	24	$	8	$	157

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 March 31, 2013 was $145 million , for which PGE has posted $27 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2013 , the cash requirement to either post as collateral or settle the instruments immediately would have been $136 million .

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Counterparties representing 10% or more of Assets and Liabilities from price risk management activities as of March 31, 2013 or December 31, 2012 were as follows:



	March 31, 2013		December 31, 2012
Assets from price risk management activities:
Counterparty A	16	%	3	%
Counterparty B	15		11
Counterparty C	9		13
Counterparty D	9		21
Counterparty E	3		10
	52	%	58	%
Liabilities from price risk management activities:
Counterparty F	20	%	24	%
Counterparty G	14		—
Counterparty H	10		14
Counterparty I	7		10
	51	%	48	%

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

NOTE 5: EARNINGS PER SHARE

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



	Three Months Ended March 31,
	2013		2012
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	49	$	49
Denominator (in thousands):
Weighted-average common shares outstanding—basic	75,608		75,423
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	91		20
Weighted-average common shares outstanding—diluted	75,699		75,443
Earnings per share—basic and diluted	$	0.65	$	0.65

In addition to unvested time-based restricted stock units and employee stock purchase plan shares, unvested performance-based restricted stock units and related dividend equivalent rights are included in the computation of dilutive securities when the required performance goals are met at the end of a three-year performance period. For the three months ended March 31, 2013 and 2012, unvested performance-based restricted stock units and related dividend equivalent rights of 430,824 and 462,413, respectively, were excluded from the dilutive calculation because the performance goals had not been met.

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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.

NOTE 6: EQUITY

The activity in equity during the three month periods ended March 31, 2013 and 2012 is as follows (dollars in millions):



	Portland General Electric Company Shareholders’ Equity
	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
	Common Stock
	Shares	Amount
Balances as of December 31, 2012	75,556,272	$	841	$	(6	)	$	893		$	2
Issuance of shares pursuant to equity-based plans	120,909	—		—			—			—
Dividends declared	—	—		—			(20		)	—
Net income (loss)	—	—		—			49			(1		)
Balances as of March 31, 2013	75,677,181	$	841	$	(6	)	$	922		$	1

Balances as of December 31, 2011	75,362,956	$	836	$	(6	)	$	833		$	3
Issuance of shares pursuant to equity-based plans	141,624	—		—			—			—
Dividends declared	—	—		—			(20		)	—
Net income	—	—		—			49			—
Balances as of March 31, 2012	75,504,580	$	836	$	(6	)	$	862		$	3

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. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

Loss contingencies are accrued, and disclosed if material, 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.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company (i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or (ii) discloses that an estimate cannot be made.

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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 subsequent 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 where it is uncertain how liability, if any, will 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 power 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. In 1995, 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 settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining investment in Trojan as of September 30, 2000, along with several largely offsetting regulatory liabilities. After offsetting the investment in Trojan with these liabilities, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan was no longer included in prices charged to customers, either through a return of or a return on that investment. 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.

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. The Company 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. On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. However, on April 3, 2013, the plaintiffs filed for reconsideration of the Court of Appeals’ February 6, 2013 decision.

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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 totaling $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 can be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.

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.

As noted above, on February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. On April 3, 2013, the plaintiffs filed for reconsideration of the Court of Appeals’ February 6, 2013 decision. Because the plaintiffs’ request for reconsideration, and the class actions described above, remain pending, management believes that it is reasonably possible that the regulatory proceedings and class actions could result in a loss to the Company in excess of the amounts previously recorded and discussed above. Because these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine PGE’s potential liability, if any, or to estimate a range of potential loss.

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 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

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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.

In December 2012, the FERC issued an order granting an interlocutory appeal of the trial judge’s ruling on the scope of the remand proceeding. In this order, the FERC held that its Order on Remand was not intended to alter the general state of the law regarding the Mobile-Sierra presumption. The FERC clarified that the Mobile-Sierra presumption could be overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest.

On April 5, 2013, and subject to its December 2012 clarification in the interlocutory appeal, the FERC denied rehearing requests from refund proponents that had contested the FERC’s use of the Mobile-Sierra standard in the remand proceeding, its denial of a market-wide remedy, and the restraints in the Order on Remand that limited the types of evidence that could be introduced in the hearing. However, the FERC granted rehearing on the issue of the appropriate refund period, holding that parties could pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule or of a statutory requirement. On April 11, 2013, the California Attorney General and the California Public Utilities Commission filed an appeal of the Order on Remand and the Order on Rehearing with the Ninth Circuit.

In its October 2011 Order on Remand, the FERC ordered settlement discussions to 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 claims for an immaterial amount. The FERC approved both settlements during 2012.

Additionally, 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 PGE 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.

The above-referenced settlements resulted in a release for the Company as a named respondent in the ongoing remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in future proceedings if refunds are ordered against current respondents.

Management believes that this matter could result in a loss to the Company in future proceedings. However, management cannot predict whether the FERC will order refunds, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss.

EPA Investigation of Portland Harbor

A 1997 investigation by the United States 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

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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 additional properties in or near the original segment of the river under investigation as well as several miles beyond. 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.

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 or 2016.

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 on the selected remedial action levels and the choice of remedy. 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.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, 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.

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 by the end of 2013 or early 2014.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, because the feasibility study continues, 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.

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 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

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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 RI report was submitted to the EPA.

In March 2012, the EPA approved the RI 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 and comment period, the EPA was expected to issue a final Record of Decision in March 2013, although, to date, it has not done so.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, sufficient information is currently not available to determine PGE’s liability for the cost of any remediation of the Harbor Oil site or to estimate a range of potential loss.

Alleged Violation of Environmental Regulations at Colstrip

On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (Colstrip) 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 - 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 2012, the Sierra Club and MEIC have amended their Notice three times. 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). The third amendment, received in December 2012, does not materially alter the prior assertions.

On March 6, 2013, the Sierra Club and MEIC sued the Colstrip co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating Colstrip except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company.

Challenge to AOC Related to Colstrip Wastewater Facilities

In August 2012, the operator of Colstrip 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 Colstrip. Within five years, under this AOC, the operator of Colstrip 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 the operator of Colstrip is unable at this time to estimate these costs, which will require both public and agency review.

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In September 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. In September 2012, the operator of Colstrip filed an election with the BER to have this proceeding conducted in Montana state district court as contemplated by the MFSA. In October 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 MFSA and the Montana Water Quality Act with respect to groundwater seepage from the wastewater facilities at Colstrip.

Revenue Bonds

In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow, Oregon. 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 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.

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.

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. The Oregon Department of Revenue has appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court. It is uncertain whether the ruling will be upheld, or if the ruling would apply retroactively to all open tax years, which, for PGE, include 2006 through 2012.

If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $12 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.

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Complaint Against U.S. Department of Energy

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the U.S. Department of Energy (USDOE) for failure to accept spent nuclear fuel by January 31, 1998. PGE had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs were seeking approximately $112 million in damages incurred through 2009.

A trial before the U.S. Court of Federal Claims commenced in the fourth quarter of 2011 and concluded in early 2012. On November 30, 2012, the U.S. Court of Federal Claims issued a judgment awarding certain damages to the Plaintiffs. The judgment does not state the precise amount of the damages award, but directs the parties to consult and propose a final amount for the Plaintiffs’ recovery that is based on certain adjustments specified in the court’s ruling. The parties continue discussions to determine such final amount. PGE estimates that the total amount of the award, as calculated pursuant to the judgment, will range from approximately $65 million to $75 million . Any award amount would be allocated among the Plaintiffs. The judgment includes damages incurred through 2009. The Plaintiffs may seek damages for subsequent years through a separate legal proceeding. Any proceeds received related to this legal matter would flow to the benefit of customers to offset amounts previously collected from customers in relation to Trojan decommissioning activities.

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 business, which may result in judgments against the Company. Although management currently believes that resolution of such matters will not have a material impact 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 March 31, 2013 , 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.

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

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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 sheets are LLC net assets of $5 million as of March 31, 2013 , consisting of Electric utility plant, net, and $6 million as of December 31, 2012 , consisting of Cash and cash equivalents of $1 million and Electric utility plant, net of $5 million . 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, 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;

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•	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 could affect customers’ demand for power and 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;


•	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 debt and 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;


•	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;


•	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.

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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, 2012 , 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— The seasonally adjusted unemployment rate for March 2013 was 7.3% in the Portland, Oregon metropolitan area, down from 7.5% for March 2012. Retail energy deliveries for the first quarter of 2013 decreased 1.3% from the comparable period of 2012 largely as a result of 2013 having one less day in the quarter due to the leap year in 2012 and the impact of relatively warmer weather during the first quarter of 2013 compared to the first quarter of 2012 reducing residential and commercial customer demand. The decline was partially offset by an increase of 4,900 in the average number of total retail customers served since the first quarter of 2012. Energy efficiency and conservation efforts by retail customers continue to influence total deliveries, although the financial impacts to the Company of such efforts are mitigated by the decoupling mechanism.

The following table indicates the average number of retail customers, and corresponding energy deliveries, by customer class, for the periods indicated and includes customers purchasing their energy from Electricity Service Suppliers (ESSs):



	Three Months Ended March 31,
	2013		2012		% 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	726,451	2,229	722,197	2,259	(1.3	)%
Commercial	102,765	1,787	102,169	1,839	(2.8	)
Industrial	272	1,024	266	1,006	1.8
Total	829,488	5,040	824,632	5,104	(1.3	)

____________________


*	In thousands of MWh.

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The effects of weather had a minimal impact on energy deliveries when comparing first quarter of 2013 to first quarter of 2012. The additional day due to leap year in 2012 had the effect of decreasing retail deliveries in the first quarter of 2013 by slightly over 1% when compared to the comparable period of 2012. PGE expects an increase in retail energy deliveries toward the lower end of 0.5% to 1.0% for 2013 compared to weather adjusted 2012 level. This includes the effects of 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 first quarter s of 2013 and 2012 , availability of the plants PGE operates approximated 97% and 99% , respectively, with the availability of Colstrip Units 3 and 4, in which PGE has a 20% ownership interest but does not operate, approximating 97% and 96% for the same periods, respectively.

During the first quarter of 2013 , the Company’s generating plants provided approximately 62% of its retail load requirement, compared with 59% in the first quarter of 2012 . The increase in the relative volume of power generated to meet the Company’s retail load requirement was primarily due to a decrease in the demand for energy. Decreases in energy received from natural gas-fired and hydro generating resources were more than offset by an increase in coal-fired generation.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects decreased 12% in the first quarter of 2013 compared with the first quarter of 2012 . These resources provided approximately 18% of the Company’s retail load requirement for the first quarter of 2013 , compared with 19% for the first quarter of 2012 . Through March, energy received from these sources fell below projections included in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 3% during 2013, compared with exceeding such projections by 6% during the comparable period of 2012. 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. Based on recent forecasts of regional hydro conditions for 2013, energy from hydro resources is expected to be below projections included in the AUT for 2013.

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 11% and 12% in the first quarter s of 2013 and 2012 , respectively, and provided approximately 5% of the Company’s retail load requirement for both periods.

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. The deadband range is from $15 million below to $30 million above baseline NVPC.

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For the first quarter of 2013 , actual NVPC was approximately $1 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2013 is currently estimated to be below the baseline NVPC, but within the deadband range; accordingly, no estimated refund to customers is expected for 2013.

For the first quarter of 2012 , actual NVPC was approximately $5 million below baseline NVPC. For 2012, actual NVPC was $17 million below baseline NVPC, and $2 million below the lower deadband threshold, resulting in a potential refund due to customers. However, based on results of the regulated earnings test, no estimated refund to customers was recorded for 2012.

General Rate Case —On February 15, 2013, PGE filed with the OPUC a general rate case, which is based on a 2014 test year (2014 GRC). PGE requested a $105 million increase in annual revenues, representing an approximate 6% overall increase in customer prices. The requested increase includes improvements to existing power plants and wind forecasting, new Clackamas River fish-sorting facilities, a new disaster-preparedness center, technology investments, employee benefits costs and compliance with new federal regulations. In addition, PGE is proposing a capital structure of 50% debt and 50% equity, a return on equity of 10%, a cost of capital of 7.86%, and an average rate base of approximately $3.1 billion.

Regulatory review of the 2014 GRC will continue throughout 2013, with a final order expected to be issued by the OPUC in mid-December 2013. New customer prices are expected to become effective January 1, 2014.

Capital Requirements and Financing —PGE’s capital requirements for 2013 are related primarily to construction costs for Port Westward Unit 2 and 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 approximate $520 million in 2013 , which includes $162 million related to the new natural gas-fired capacity resource, Port Westward Unit 2 (PW2), and $8 million related to the Cascade Crossing Transmission Project (Cascade Crossing). This estimate excludes additional costs, described below, that may be required in connection with the outcome of the Company’s request for proposals (RFPs) for energy and renewable resources:

Power Resources —In accordance with PGE’s Integrated Resource Plan (IRP) and pursuant to the OPUC’s competitive bidding guidelines, the Company issued two RFPs during 2012 for additional generation resources—one for capacity and energy (baseload) resources, and one for renewable resources.

In January 2013, PGE’s PW2 flexible generating resource, with an estimated total cost of $300 million to $310 million, excluding the Allowance for funds used during construction (AFDC), was selected as the successful bid for the capacity resource in the RFP for capacity and energy resources. The RFP for capacity and energy resources is also seeking approximately 300 MW to 500 MW of baseload energy resources. PGE is in the process of negotiations with the top bidder from the final short list for baseload energy resources. The bids on the final short list include power purchase agreements and PGE-ownership options. The final baseload energy resource selection is expected by mid-2013 and the resource is expected to be available in the 2014 to 2017 timeframe.

In addition, the Company is in the process of negotiating power purchase agreements for seasonal peaking capacity, all pursuant to the capacity and energy RFP in accordance with PGE’s IRP.

The RFP for renewable resources is seeking approximately 100 MWa of renewable resources, which is expected to be available to help meet PGE’s 2015 requirements under Oregon’s renewable energy standard. The Company is in the process of negotiations to secure a renewable power resource from the final short list, with the final resource selection expected by mid-2013. The final short list of bids include both power purchase agreements and PGE-ownership options.

Transmission Capacity —Pursuant to the Company’s IRP, PGE has been in the process of developing new transmission capacity from Boardman, Oregon to Salem, Oregon, under a project known as Cascade Crossing. This project was originally proposed as a 215-mile, 500 kV transmission project to help meet

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future electricity demand. As PGE worked with the Bonneville Power Administration (BPA) in the formulation of the project and potential partnerships, the scope of the project has evolved. In January 2013, the Company entered into a Memorandum of Understanding (MOU) with BPA to pursue modifications to PGE’s originally proposed project. Under the MOU proposal, the transmission line would terminate at a new substation called Pine Grove, near Maupin, Oregon (approximately midway between Boardman and Salem), eliminating the need for construction of approximately 101 miles of the originally proposed transmission line. The MOU also provides that the parties will: (i) explore opportunities for PGE to invest in upgrades to BPA’s system; (ii) analyze the possibility of asset exchanges; and (iii) work together to determine the feasibility of additional transmission projects under which PGE could obtain additional capacity between Boardman, Oregon and the Willamette Valley. Subject to the outcome of negotiations with BPA and continued evaluation of regional transmission needs and timing, such investments and conveyances could provide a total of up to 2,600 MWs of transmission capacity that could be staged to come on-line in phases as needed. Because the discussions between PGE and BPA under the MOU are not binding and involve complex issues and the considerations of various options, there is no assurance that the project will be constructed, or will contain all of, or be limited by, the elements described in the MOU.

Construction of the new transmission line from Boardman to the Pine Grove substation could start as early as 2017, with an estimated construction period of at least two years. Because the modified proposal remains under discussion, the estimated total costs and timeline of the project have not yet been determined. However, PGE expects the cost of the full project scope, as described in the MOU, would be at least $800 million. As of March 31, 2013, approximately $50 million is included in Construction work in progress (CWIP) related to this project. For further information related to Cascade Crossing, see “ Integrated Resource Plan ” within the Liquidity and Capital Resources section this Item 2.

For 2013, PGE expects to fund estimated capital requirements and contractual maturities of $100 million of long-term debt with cash from operations, short-term debt, or long-term financings. Cash from operations is expected to range from $425 million to $435 million for 2013. The Company expects to issue between $50 million and $100 million of First Mortgage Bonds during the second quarter of 2013. The timing and amount of any additional issuances of debt and equity securities will depend primarily on the outcome of the Company’s RFPs for energy and renewable resources, as well as the timing and scope of Cascade Crossing. For further 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 three months ended March 31, 2013 compared to the three months ended March 31, 2012 or affected retail customer prices, as authorized by the OPUC. In some cases, the Company has 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.


•	Power Costs—Pursuant to the AUT process, PGE files annually an estimate of power costs for the following year. The OPUC issued an order on the 2013 AUT resulting in an estimated 2% decrease in customer prices as a result of expected lower power costs. The new prices became effective January 1, 2013

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and are expected to result in a decrease of approximately $36 million in annual revenues when compared to revenues resulting from prices in effect for 2012.

In July 2012, the Company submitted to the OPUC the results of its PCAM for 2011 based on a regulated earnings test, which resulted in a revised refund to customers of approximately $6 million. In October 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. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in customer prices until the January 1st effective date.

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.

PGE did not submit a RAC filing to the OPUC in 2013 as it is not anticipated that the Company will place renewable resources into service during 2013 beyond any that may result from the still pending Renewable RFP.

•

Decoupling—The decoupling mechanism is intended to provide for recovery of margin lost as a result of any reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The Company has requested in its 2014 GRC filing that the OPUC extend authorization of the mechanism, which currently expires at the end of 2013, to continue on a permanent basis. The mechanism provides for collection from (or refund to) customers if weather adjusted use per customer is less (or more) than the levels projected in the Company’s most recent general rate case.


•	For the three months ended March 31, 2013 , the Company has recorded an estimated collection of $4 million. Any resulting refund to, or collection from, customers for the 2013 year would begin June 1, 2014.


•	During 2012, PGE recorded an estimated refund of $1 million that is expected to be provided to customers over a one year period that would begin June 1, 2013, as weather adjusted use per customer was greater than levels projected in the 2011 General Rate Case.


•	During 2011, PGE recorded an estimated refund of $2 million that is being provided to customers over a one year period that began June 1, 2012, as weather adjusted use per customer was greater than projected levels.

•

Capital deferral—In the 2011 General Rate Case, the OPUC authorized the Company to defer the costs associated with four capital projects that were not completed at the time the 2011 General Rate Case was approved. A regulatory asset of $15 million was recorded in 2012, for potential recovery in customer prices, subject to an earnings test, with an offsetting credit to Depreciation and amortization expense. The Company expects to submit a filing to the OPUC by mid-2013 for recovery of the deferral, with a resulting tariff effective January 1, 2014. In the first quarter of 2013, the Company deferred an additional $5 million of costs.

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, 2012 , filed with the SEC on February 22, 2013 .

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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 March 31,
	2013					2012
Revenues, net	$	473		100	%	$	479	100	%
Purchased power and fuel	192			41		195		41
Gross margin	281			59		284		59
Operating expenses:
Production and distribution	51			11		53		11
Administrative and other	54			11		54		11
Depreciation and amortization	62			13		62		13
Taxes other than income taxes	27			6		27		6
Total operating expenses	194			41		196		41
Income from operations	87			18		88		18
Other income:
Allowance for equity funds used during construction	2			—		1		—
Miscellaneous income, net	1			—		3		1
Other income	3			—		4		1
Interest expense	25			5		28		6
Income before income taxes	65			13		64		13
Income taxes	17			3		15		3
Net income	48			10		49		10
Less: net loss attributable to noncontrolling interests	(1		)	—		—		—
Net income attributable to Portland General Electric Company	$	49		10	%	$	49	10	%

Net income attributable to Portland General Electric Company was $49 million , or $0.65 per diluted share, for each of the first quarter s of 2013 and 2012 . Declines in retail energy deliveries were largely offset by lower power costs and a decrease in storm restoration costs. In addition, lower interest expense in the first quarter of 2013 was offset by an increase in PGE’s effective tax rate.

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



	Three Months Ended March 31,
	2013				2012
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	246	52	%	$	256		53	%
Commercial	149		32		156			33
Industrial	51		11		53			12
Subtotal	446		95		465			98
Other accrued (deferred) revenues, net	4		1		(3		)	(1	)
Total retail revenues	450		96		462			97
Wholesale revenues	16		3		10			2
Other operating revenues	7		1		7			1
Total revenues	$	473	100	%	$	479		100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	2,229		40	%	2,259			42	%
Commercial	1,787		32		1,839			33
Industrial	1,024		18		1,006			18
Total retail energy deliveries	5,040		90		5,104			93
Wholesale energy deliveries	540		10		388			7
Total energy deliveries	5,580		100	%	5,492			100	%
Average number of retail customers:
Residential	726,451		88	%	722,197			88	%
Commercial	102,765		12		102,169			12
Industrial	272		—		266			—
Total	829,488		100	%	824,632			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 decreased $6 million , or 1%, for the first quarter of 2013 compared with the first quarter of 2012 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 directly from ESSs. Retail revenues also include certain deferred revenues, primarily related to the PCAM and decoupling mechanisms. Retail revenues decreased $12 million , or 3%, in the first quarter of 2013 compared with the first quarter of 2012 , resulting primarily from the combination and net effect of the following items:


•	A $13 million decrease resulting from lower average prices due primarily to the reduction in power costs as forecasted in the Company’s 2013 AUT and a slightly larger portion of energy deliveries going to customers who purchase their energy from ESSs; and


•	A $6 million decrease related to lower volumes of energy delivered driven in part by 2013 having one less day in the quarter due to the leap year in 2012 and by warmer temperatures in the first quarter of 2013 compared with the first quarter of 2012. After removing the impact of the leap year, residential deliveries

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were fairly flat period over period, commercial deliveries declined 2%, and industrial deliveries increased 3% on strength in the high tech sector; partially offset by


•	A $5 million increase related to the decoupling mechanism, with a $4 million potential recovery recorded in the first quarter of 2013 compared with a $1 million potential refund recorded in the first quarter of 2012; and


•	A $3 million increase related to the Company’s PCAM, as a potential refund was recorded in the first quarter of 2012 related to the 2011 PCAM, with no comparable refund recorded in the first quarter of 2013.

Total heating degree-days in the first quarter of 2013 were 3% below those of the comparable period of 2012 and 3% above historical averages. The following table indicates the number of heating 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
	2013	2012
January	835	740
February	569	618
March	498	609
First quarter	1,902	1,967
15-year average for the year-to-date	1,850	1,848

Wholesale revenues result from sales of electricity to utilities and power marketers that are made in the Company’s efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from period to period as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand. In the first quarter of 2013 , wholesale revenues increased $6 million , or 60% , compared to the comparable period of 2012 , primarily consisting of a $4 million increase resulting from a 39% increase in sales volume. In addition, a $2 million increase resulted from an average sales price increase of 12%, which is attributed to higher natural gas prices and less hydro power generation in the region in the first quarter of 2013 compared to the first quarter of 2012.

Purchased power and fuel expense was $192 million for the first quarter of 2013 compared with $195 million for the first quarter of 2012 . The $3 million , or 2% , decrease is largely related to a 2% decrease in the average variable power cost, which decreased to $34.79 per MWh in the first quarter of 2013 compared with $35.49 per MWh in the first quarter of 2012 . Such decrease primarily resulted from an increase in lower-cost coal-fired generation, which was partially offset by an increase in the average cost of purchased power and a decrease in energy received from hydro resources. For the first quarter of 2013 , actual NVPC was $1 million below baseline NVPC, compared with $5 million below baseline NVPC for the first quarter of 2012 . Total system load for the first quarter of 2013 was comparable to the first quarter of 2012.

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



	Three Months Ended March 31,
	2013				2012
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	1,361		25	%	1,077		20	%
Natural gas	976		18		1,130		20
Total thermal	2,337		43		2,207		40
Hydro	481		9		583		11
Wind	245		4		246		4
Total generation	3,063		56		3,036		55
Purchased power:
Term	1,310		24		1,216		22
Hydro	393		7		414		8
Wind	66		1		74		1
Spot	684		12		783		14
Total purchased power	2,453		44		2,487		45
Total system load	5,516		100	%	5,523		100	%
Less: wholesale sales	(540	)			(388	)
Retail load requirement	4,976				5,135

Energy from PGE-owned wind generating resources (Biglow Canyon) was comparable in the first quarter of 2013 to the first quarter of 2012 , and represented 5% of the Company’s retail load requirement for both periods. Energy received from Biglow Canyon fell short of that projected in PGE’s AUT by 11% and 12% in the first quarter of 2013 and 2012 , respectively.

Energy received from hydro resources during the first quarter of 2013 , from both PGE-owned generating plants and purchased from mid-Columbia projects, decreased 12% compared with the first quarter of 2012 primarily due to less favorable hydro conditions in 2013. These resources provided approximately 18% of the Company’s retail load requirement during the first quarter of 2013 , compared with 19% during the first quarter of 2012 . During the first quarter , total hydro generation fell below projected levels included in the AUT for 2013 by 3% , compared with the first quarter of 2012 which exceeded such projected levels included in the AUT for 2012 by 6% .

The following table indicates the forecast of the April-to-September 2013 (issued April 26, 2013) compared to the actual 2012 runoff 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	2013 Forecast		2012 Actual
Columbia River at The Dalles, Oregon	96	%	126	%
Mid-Columbia River at Grand Coulee, Washington	104		129
Clackamas River at Estacada, Oregon	98		133
Deschutes River at Moody, Oregon	92		118

* 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.

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Production and distribution expense decreased $2 million , or 4% , in the first quarter of 2013 compared with the first quarter of 2012 . The decrease is primarily due to lower delivery system costs resulting from higher storm restoration costs incurred during the first quarter of 2012.

Administrative and other expense in the first quarter of 2013 was comparable to the first quarter of 2012 , as a $2 million increase in employee pension expense resulting from a lower discount rate was offset by lower other employee benefit costs during the first quarter of 2013.

Other income, net decreased $1 million , or 25% , in the first quarter of 2013 compared with the first quarter of 2012 , primarily due to lower earnings from non-qualified benefit plan trust assets during the first quarter of 2013 .

Interest expense decreased $3 million , or 11% , in the first quarter of 2013 compared to the first quarter of 2012 , primarily due to lower interest resulting from the redemption of $100 million of First Mortgage Bonds in October 2012.

Income taxes increased $2 million in the first quarter of 2013 compared with the first quarter of 2012 , with effective tax rates of 26.2% and 23.4% , respectively. The increase in the effective tax rate is primarily due to a reduction of production tax credits (PTC) resulting from lower forecasted wind generation for 2013, partially offset by an increase in the PTC rate.

Liquidity and Capital Resources

Capital Requirements

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



	2013			2014		2015		2016		2017
Ongoing capital expenditures	$	333		$	273	$	241	$	258	$	241
Port Westward Unit 2	162			119		21		—		—
Hydro licensing and construction	17			31		33		1		—
Cascade Crossing	8			—		—		—		—
Total capital expenditures	$	520	⁽¹⁾	$	423	$	295	$	259	$	241
Long-term debt maturities	$	100		$	—	$	70	$	67	$	58


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

Ongoing capital expenditures —Consists primarily of upgrades to, and replacement of, transmission, distribution, and generation infrastructure, as well as new customer connections. Approximately $13 million is included in 2013 for emissions controls at the Company’s Boardman coal-fired generating plant.

Preliminary engineering costs are also included in Ongoing capital expenditures. Such costs consist of expenditures for preliminary 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, and approximate $3 million for 2013. Once a project is approved for construction, such costs are reclassified to CWIP within Electric utility plant. As of March 31, 2013 and December 31, 2012 , preliminary engineering costs of $7 million and $14 million, respectively, are included in Other noncurrent assets in PGE’s condensed consolidated balance sheets.

Port Westward Unit 2 —In January 2013, PGE’s PW2 flexible generating resource was selected as the successful bid for the capacity resource in the Company’s RFP for energy and capacity resources. PW2 is a 220 MW natural gas-fired plant that will be located near PGE’s Port Westward and Beaver natural gas-fired plants near Clatskanie,

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Oregon. The total cost of PW2 is estimated between $300 million and $310 million, excluding AFDC, and the facility is expected to be online in the first quarter of 2015.

Hydro licensing and construction —PGE ’ s hydroelectric projects are operated pursuant to FERC licenses issued under the Federal Power Act, which expire as follows: Clackamas River, 2055; Willamette River, 2035; and Deschutes River, 2055. 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.

Integrated Resource Plan —The Company’s IRP, acknowledged by the OPUC in November 2010, included the following energy resource 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 energy and renewable resources described in the IRP; and

•

The construction of the Cascade Crossing transmission project at an estimated total cost of at least $800 million. The Company continues to work with other stakeholders in planning the project and potential project partnerships. As of March 31, 2013 , the Company has recorded $50 million in costs, primarily related to environmental assessments and permitting activities, included in CWIP, in Electric utility plant, net in its condensed consolidated balance sheets.

Due to the uncertainty of the IRP projects, the Capital Requirements table above does not include estimates for any amounts related to these projects, other than PW2, beyond 2013. If PGE moves forward with the projects for which preliminary engineering costs are recorded, such costs would be transferred to CWIP. If the projects are abandoned, such costs, including those already in CWIP, would be expensed to Production and distribution expense in the period such determination is made. If any costs associated with the projects 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.

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The following summarizes PGE’s cash flows for the periods presented (in millions):



	Three Months Ended March 31,
	2013			2012
Cash and cash equivalents, beginning of period	$	12		$	6
Net cash provided by (used in):
Operating activities	165			110
Investing activities	(107		)	(58		)
Financing activities	(37		)	(50		)
Increase in cash and cash equivalents	21			2
Cash and cash equivalents, end of period	$	33		$	8

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 $55 million increase in cash provided by operating activities for the first quarter of 2013 when compared with the first quarter of 2012 was primarily due to the change in margin deposit requirements. During the first quarter of 2013, margin deposit requirements decreased $13 million from the beginning of the quarter, compared to increasing $18 million during the first quarter of 2012. These collateral requirements are based on the contract terms for transactions entered into in connection with the Company’s price risk management activities and commodity prices, which vary period to period.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that such charges will range from $240 million and $250 million in 2013 , with total cash provided by operations anticipated to range from $425 million to $435 million. The remaining estimated cash flows from operations in 2013 is expected from normal operating activities.

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 $49 million increase in net cash used in investing activities in the first quarter of 2013 compared with the first quarter of 2012 was due primarily to a $39 million increase in capital expenditures, largely due to the construction of PW2, and proceeds received in the first quarter of 2012 from the sale of a solar power facility.

The Company plans a total of approximately $520 million in capital expenditures for 2013 related to upgrades and replacement of transmission, distribution, and generation infrastructure. See the 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 first quarter s of 2013 and 2012 , cash used in such activities consisted of the repayment of commercial paper in the amount of $17 million and $30 million , respectively, and the payment of dividends of $20 million during each of the periods.

During April 2013, the Company repaid the 4.45% Series of First Mortgage Bonds in the amount of $50 million, which will be reflected as cash used in financing activities in PGE’s consolidated statement of cash flows for the six months ending June 30, 2013.

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

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results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

During the first quarter of 2013, the Board of Directors declared a quarterly common stock dividend of $0.27 per common share for a total of $20 million, with payments made on April 15, 2013 to shareholders of record at the close of business on March 25, 2013.

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.

For 2013, PGE expects to fund estimated capital requirements and contractual maturities of $100 million of long-term debt with cash from operations, short-term debt, or long-term financings. The Company expects to issue between $50 million and $100 million of First Mortgage Bonds during the second quarter of 2013. The timing and amount of any additional issuances of debt and equity securities over the next five years will depend primarily on the outcome of the Company’s RFPs for energy and renewable resources under its IRP, as well as the timing and scope of Cascade Crossing.

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 $400 million syndicated credit facility scheduled to terminate November 2017 ; 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 March 31, 2013 , PGE had no borrowings outstanding under the credit facilities, no commercial paper outstanding, and $52 million of letters of credit issued. As of March 31, 2013 , the aggregate unused credit available under the credit facilities was $648 million .

Long-term Debt. As of March 31, 2013 , total long-term debt outstanding was $1,636 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 51.8% and 51.1% as of March 31, 2013 and December 31, 2012 , respectively.

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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

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 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 March 31, 2013 , PGE had posted approximately $64 million of collateral with these counterparties, consisting of $33 million in cash and $31 million in letters of credit, $11 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 March 31, 2013 , the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $68 million and decreases to approximately $29 million by December 31, 2013 , and $14 million by December 31, 2014. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $198 million at March 31, 2013 and decreases to approximately $103 million by December 31, 2013 , and $60 million by December 31, 2014.

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 March 31, 2013 , under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $734 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 March 31, 2013 , the Company’s debt ratio, as calculated under the credit agreements, was 48.2% .

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.

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Contractual Obligations

PGE’s contractual obligations for 2013 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, 2012 , filed with the SEC on February 22, 2013 . Such obligations have not changed materially as of March 31, 2013 , with the following exception. During the first quarter of 2013, PGE entered into agreements totaling $258 million for the construction of PW2. Pursuant to the terms of the agreements, PGE is required to make progress payments of $143 million in 2013, $101 million in 2014, and $14 million in 2015.



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, 2012 , filed with the SEC on February 22, 2013 .



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 March 31, 2013 , these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2013 , 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 further 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, 2012 , filed with the SEC on February 22, 2013 .

Citizens’ Utility Board of Oregon v. Public Utility Commission of Oregon and Utility Reform Project and Colleen O’Neill v. Public Utility Commission of Oregon , Public Utility Commission of Oregon Docket Nos. DR 10, UE 88, and UM 989, Marion County Oregon Circuit Court, Case No. 94C-10417, the Court of Appeals of the State of Oregon, the Oregon Supreme Court, Case No. SC S45653.

As a result of its reconsideration of the Settlement Order, the OPUC issued an order in September 2008 that required PGE to refund $33.1 million to customers. The Company completed the distribution of the refund to customers, plus accrued interest, as required.

In October 2008, the URP and the Class Action Plaintiffs separately appealed the September 2008 OPUC order to the Oregon Court of Appeals. On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the

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September 2008 OPUC order. On April 3, 2013, the plaintiffs filed for reconsideration of the Court of Appeals February 6, 2013 decision.

Sierra Club and Montana Environmental Information Center v. PPL Montana LLC, Avista Corporation, Puget Sound Energy, Portland General Electric Company, Northwestern Corporation, and PacifiCorp , U.S. District Court for the District of Montana, Case No. 1:13-cv-00032-RFC.

On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (Colstrip) 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 - 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 stated that the Sierra Club and MEIC would: 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.

On March 6, 2013, the Sierra Club and MEIC sued the Colstrip co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes civil penalties and an injunction preventing the co-owners from operating Colstrip except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.



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, 2012 , filed with the SEC on February 22, 2013 .

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Item 6.	Exhibits.



Exhibit Number	Description
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.

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:	April 30, 2013	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)

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Part I Item 1. Financial Statements Note 1: Basis Of Presentation Note 2: Balance Sheet Components Note 3: Fair Value Of Financial Instruments Note 4: Price Risk Management Note 5: Earnings Per Share Note 6: Equity Note 7: Contingencies Note 8: Guarantees Note 9: Variable Interest Entities Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II - Other Information Part II Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

Significant Unobservable Input

Change to Input

Impact on Fair Value Measurement

Market price

Increase (decrease)

Gain (loss)

Market price

Increase (decrease)

Loss (gain)