UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended ~~September 30, 2013~~March 31, 2014



[ ]	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 ~~October 28, 2013~~April 24, 2014 is ~~78,067,553~~78,182,356 shares.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED ~~SEPTEMBER 30, 2013~~MARCH 31, 2014

TABLE OF CONTENTS

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
Carty		Carty Generating Station natural gas-fired generating plant
~~Cascade Crossing~~		~~Cascade Crossing Transmission Project~~
Colstrip		Colstrip ~~Steam Electric Station~~Units 3 and 4 coal-fired generating plant
CWIP		Construction work-in-progress
EFSA		Equity forward sale agreement
EPA		United States Environmental Protection Agency
ESS		Electricity Service Supplier
FERC		Federal Energy Regulatory Commission
~~FMB~~FMBs		First Mortgage ~~Bond~~Bonds
IRP		Integrated Resource Plan
kV		Kilovolt = one thousand volts of electricity
Moody’s		Moody’s Investors Service
MW		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
Tucannon River		Tucannon River wind farm
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 September 30,					Nine Months Ended September 30,						Three Months Ended March 31,
	2013		2012			2013			2012			2014			2013
Revenues, net	$	435	$	450		$	1,311		$	1,342		$	493		$	473
Operating expenses:
Purchased power and fuel	190		182			538			533			184			192
Production and distribution	54		49			169			153			54			51
Cascade Crossing transmission project	—		—			52			—
Administrative and other	49		50			158			160			54			54
Depreciation and amortization	62		63			186			188			75			62
Taxes other than income taxes	27		24			79			77			28			27
Total operating expenses	382		368			1,182			1,111			395			386
Income from operations	53		82			129			231			98			87
Interest expense	25		27			75			82			25			25
Other income (expense):
Allowance for equity funds used during construction												6			2
Miscellaneous income (expense), net												(1		)	1
Other income, net	7		1			13			6			5			3
Income before income tax expense	35		56			67			155			78			65
Income tax expense	4		19			10			43			20			17
Net income and Comprehensive income	31		37			57			112			58			48
Less: net loss attributable to noncontrolling interests	—		(1		)	(1		)	(1		)	—			(1		)
Net income and Comprehensive income attributable to Portland General Electric Company	$	31	$	38		$	58		$	113		$	58		$	49

Weighted-average shares outstanding (in thousands):
Basic	77,637		75,528			76,401			75,486			78,992			75,608
Diluted	78,330		75,541			76,703			75,500			80,156			75,699

Earnings per share—basic and diluted	$	0.40	$	0.50		$	0.76		$	1.49
Earnings per share:
Basic												$	0.74		$	0.65
Diluted												$	0.73		$	0.65

Dividends declared per common share	$	0.275	$	0.270		$	0.820		$	0.805		$	0.275		$	0.270

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)


	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	91	$	12	$	64	$	107
Accounts receivable, net	137		152		158		146
Unbilled revenues	67		97		77		104
Inventories	72		78		64		65
Margin deposits	36		46		17		9
Regulatory assets—current	99		144		55		66
Other current assets	63		93		114		94
Total current assets	565		622		549		591
Electric utility plant, net	4,659		4,392		5,009		4,880
Regulatory assets—noncurrent	504		524		448		464
Nuclear decommissioning trust	82		38		83		82
Non-qualified benefit plan trust	34		32		33		35
Other noncurrent assets	47		62		47		49
Total assets	$	5,891	$	5,670	$	6,169	$	6,101

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)


	September 30, 2013			December 31, 2012			March 31, 2014			December 31, 2013
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	99		$	98		$	147		$	173
Liabilities from price risk management activities—current	89			127			52			49
Short-term debt	—			17
Current portion of long-term debt	—			100			70			—
Accrued expenses and other current liabilities	192			179			182			171
Total current liabilities	380			521			451			393
Long-term debt, net of current portion	1,761			1,536			1,846			1,916
Regulatory liabilities—noncurrent	852			765			899			865
Deferred income taxes	565			588			605			586
Unfunded status of pension and postretirement plans	253			247			157			154
Non-qualified benefit plan liabilities	103			102			102			101
Asset retirement obligations	96			94			101			100
Liabilities from price risk management activities—noncurrent	71			73			126			141
Other noncurrent liabilities	17			14			25			25
Total liabilities	4,098			3,940			4,312			4,281
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2013 and December 31, 2012	—			—
Common stock, no par value, 160,000,000 shares authorized; 78,067,299 and 75,556,272 shares issued and outstanding as of September 30, 2013 and December 31, 2012, respectively	910			841
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2014 and December 31, 2013							—			—
Common stock, no par value, 160,000,000 shares authorized; 78,182,056 and 78,085,559 shares issued and outstanding as of March 31, 2014 and December 31, 2013, respectively							912			911
Accumulated other comprehensive loss	(6		)	(6		)	(5		)	(5		)
Retained earnings	888			893			949			913
Total Portland General Electric Company shareholders’ equity	1,792			1,728			1,856			1,819
Noncontrolling interests’ equity	1			2			1			1
Total equity	1,793			1,730			1,857			1,820
Total liabilities and equity	$	5,891		$	5,670		$	6,169		$	6,101
													See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2013			2012			2014			2013
Cash flows from operating activities:
Net income	$	57		$	112		$	58		$	48
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	186			188			75			62
Cascade Crossing transmission project	52			—
Decrease in net liabilities from price risk management activities							(19		)	(37		)
Regulatory deferrals—price risk management activities							19			37
Deferred income taxes							15			13
Pension and other postretirement benefits	28			22			8			10
Decrease in net liabilities from price risk management activities	(35		)	(142		)
Regulatory deferral—price risk management activities	35			140
Allowance for equity funds used during construction							(6		)	(2		)
Regulatory deferral of settled derivative instruments	13			1			5			5
Decoupling mechanism deferrals, net of amortization	(5		)	1			(4		)	(5		)
Allowance for equity funds used during construction	(8		)	(4		)
Power cost deferrals, net of amortization	(4		)	(4		)
Deferred income taxes	(2		)	70
Other non-cash income and expenses, net	18			15			7			8
Changes in working capital:
Decrease in receivables	47			41
Decrease in margin deposits, net	10			27
Income tax refund received	—			8
Increase (decrease) in payables and accrued liabilities	13			(42		)
Decrease in accounts receivable and unbilled revenues							14			29
(Increase) decrease in margin deposits, net							(8		)	13
Decrease in accounts payable and accrued liabilities							(6		)	(4		)
Other working capital items, net	24			23			(13		)	(12		)
Proceeds received from Trojan spent fuel legal settlement	44			—
Cash received to be returned to customers pursuant to the Residential Exchange Program							15			2
Other, net	(14		)	(6		)	(2		)	(2		)
Net cash provided by operating activities	459			450			158			165
Cash flows from investing activities:
Capital expenditures	(453		)	(218		)	(185		)	(108		)
Proceeds from sale of solar power facility	—			10
Contribution to nuclear decommissioning trust	(44		)	—
Sales of nuclear decommissioning trust securities	20			18			6			8
Purchases of nuclear decommissioning trust securities	(21		)	(19		)	(6		)	(9		)
Proceeds received from insurance recovery	3			—
Proceeds from sale of property							4			—
Other, net	4			—			2			2
Net cash used in investing activities	(491		)	(209		)	(179		)	(107		)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2013			2012			2014			2013
Cash flows from financing activities:
Proceeds from issuance of long-term debt	$	225		$	—
Payments on long-term debt	(100		)	—
Proceeds from issuance of common stock, net of issuance costs	67			—
Borrowings on short-term debt	35			—
Payments on short-term debt	(35		)	—
Maturities of commercial paper, net	(17		)	(30		)	$	—		$	(17	)
Dividends paid	(62		)	(61		)	(22		)	(20		)
Debt issuance costs	(2		)	—
Net cash provided by (used in) financing activities	111			(91		)
Increase in cash and cash equivalents	79			150
Net cash used in financing activities							(22		)	(37		)
(Decrease) increase in cash and cash equivalents							(43		)	21
Cash and cash equivalents, beginning of period	12			6			107			12
Cash and cash equivalents, end of period	$	91		$	156		$	64		$	33

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	57		$	61		$	10		$	13
Cash paid for income taxes	9			6
Non-cash investing and financing activities:
Accrued dividends payable	22			21			22			20
Accrued capital additions	23			15			69			11
Preliminary engineering costs transferred to Construction work in progress from Other noncurrent assets	9			—
Preliminary engineering costs transferred to Construction work-in-progress from Other noncurrent assets							—			4
													See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of ~~electricity.~~electricity in the state of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort 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 approximately 4,000 square mile, state-approved service area allocation is located entirely within the state of ~~Oregon. PGE’s service area includes~~Oregon, encompassing 52 incorporated cities, of which Portland and Salem are the ~~largest, within a state-approved service area allocation of approximately 4,000 square miles.~~largest. As of ~~September 30, 2013~~March 31, 2014, PGE served ~~835,540~~838,283 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~~note 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.

To conform with the ~~2013~~2014 presentation, PGE has separately presented ~~Decoupling mechanism~~Cash received to be returned to customers pursuant to the Residential Exchange Program of $2 million from Other, net and collapsed Power cost deferrals, net of amortization of $1$2 million ~~from~~ with Other non-cash income and expenses, net ~~and collapsed Contribution to voluntary employees’ beneficiary association trust of~~ ~~$2 million~~ ~~to Other, net and Renewable adjustment clause deferrals of~~ ~~$1 million~~ ~~to Other non-cash income and expenses, net, all of which are included~~ in the operating activities section of the condensed consolidated statement of cash flows for the ~~nine~~three months ended ~~September 30, 2012~~.March 31, 2013.

The financial information included herein for the three ~~and~~ ~~nine~~ ~~month periods~~months ended ~~September 30, 2013~~March 31, 2014 and ~~2012~~2013 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 income and comprehensive income, 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~~2013 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, ~~2012~~2013, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February ~~22, 2013~~14, 2014, 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 or ~~nine~~ ~~month periods~~months ended ~~September 30, 2013~~March 31, 2014 and ~~2012~~2013.

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

~~Customer Billing Matter~~

In May 2013, PGE discovered that it had over-billed an industrial customer during a period of several years as a result of a meter configuration error. An analysis of the data determined that the Company’s revenues were overstated by approximately ~~$3 million~~ ~~in 2012 and in 2011,~~ ~~$2 million~~ ~~in 2010, and~~ ~~$1 million~~ in 2009. PGE believes the customer billing error is not material to any annual reporting period. The Company corrected this matter in the second quarter of 2013 as an out of period adjustment, and recorded, as a reduction to Revenues, net, a refund to the customer in the amount of ~~$9 million~~.

~~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.

~~New Tax Regulation~~

On September 13, 2013, the U.S. Department of Treasury issued final regulations related to the deductibility and capitalization of expenditures on tangible property. The regulations give a general framework to distinguish capital expenditures from supplies, repairs, maintenance and other deductible business expenses that apply to amounts paid or incurred on or after January 1, 2014 with the option to early adopt for earlier tax periods. The U.S. Department of Treasury is expected to provide further guidance on the new regulations during the fourth quarter of 2013.

Based on an initial analysis, the Company does not believe that the new regulations have a material impact to the consolidated financial statements. PGE will complete a more detailed assessment in the fourth quarter of 2013 to determine the impact of each specific provision and evaluate potential options for the adoption of the new regulations. The impact, if any, would occur between balance sheet classification of current and noncurrent deferred tax balances and taxes currently payable, but would not impact income tax expense.

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $57 million and $6 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013., respectively.

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


	Nine Months Ended September 30,						Three Months Ended March 31,
	2013			2012			2014			2013
Balance as of beginning of period	$	5		$	6		$	6		$	5
Provision, net	4			6			2			2
Amounts written off, less recoveries	(4		)	(6		)	(1		)	(1		)
Balance as of end of period	$	5		$	6		$	7		$	6

Inventories

PGE inventories, which 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~~The Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.

Other Current Assets

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


	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
Prepaid expenses	$	25	$	37	$	53	$	38
Current deferred income tax asset	37		51		43		42
Assets from price risk management activities	1		4		18		13
Other	—		1		—		1
Other current assets	$	63	$	93	$	114	$	94

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Electric Utility Plant, Net

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

September 30,
2013 December 31,
2012
Electric utility plant $ 6,975
$ 6,811
Construction work in progress 377
140
Total cost 7,352
6,951
Less: accumulated depreciation and amortization (2,693 ) (2,559 )
Electric utility plant, net $ 4,659
$ 4,392

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

~~As of December 31, 2012, Construction work in progress included~~ ~~$46 million~~ related to the Cascade Crossing Transmission Project (Cascade Crossing), which was originally proposed as a 215-mile, 500 kV transmission project between Boardman, Oregon and Salem, Oregon. Based on subsequent analysis and an updated forecast of demand and future transmission capacity in the region, PGE determined in the second quarter of 2013 that the original projections of transmission capacity limitations contemplated in the Integrated Resource Plan (IRP) process were not likely to fully materialize. As a result, PGE and Bonneville Power Administration (BPA) worked toward refining the scope of the project and executed a non-binding memorandum of understanding (MOU) in May 2013. In connection with the MOU, the parties explored a new option under which BPA could provide PGE with ownership of approximately 1,500 MW of transmission capacity rights. As a result of the changed conditions reflected in the MOU, PGE also suspended permitting and development of Cascade Crossing and charged ~~$52 million~~ of capitalized costs related to Cascade Crossing to expense in the second quarter of 2013. Additionally, in June 2013, the Company filed with the Public Utility Commission of Oregon (OPUC) seeking deferral of these costs for future recovery in customer prices. In October 2013, the parties determined that they would not be able to reach an agreement on the financial terms for the proposed ownership of transmission capacity rights and, therefore, agreed to discontinue discussions on this option. The Company has determined that, under current conditions, the best option for meeting its transmission needs is to continue to acquire transmission service offered under BPA’s Open Access Transmission Tariff. In light of this development, the Company intends to withdraw the deferral application previously filed with the OPUC.

~~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 in January 2012. The Company operates the facility and receives 100% of the power generated by the facility. This transaction is reflected as an investing activity in the condensed consolidated statement of cash flows for the ~~nine months~~ ~~ended~~ ~~September 30, 2012~~.



	March 31, 2014			December 31, 2013
Electric utility plant	$	7,144		$	7,095
Construction work-in-progress	633			508
Total cost	7,777			7,603
Less: accumulated depreciation and amortization	(2,768		)	(2,723		)
Electric utility plant, net	$	5,009		$	4,880

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $~~167~~176 million and $~~151~~170 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively. Amortization expense related to intangible assets was$6 million and $5 million for the three months ended ~~September 30, 2013~~March 31, 2014 and ~~2012, and~~ ~~$16 million~~ ~~and~~ ~~$17 million~~ ~~for the~~ ~~nine months~~ ~~ended~~ ~~September 30,~~ 2013 ~~and~~ ~~2012~~, respectively.

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~~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):


	September 30, 2013					December 31, 2012					March 31, 2014					December 31, 2013
	Current			Noncurrent		Current			Noncurrent		Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	88		$	71	$	123		$	71	$	34		$	123	$	36		$	140
Pension and other postretirement plans	—			301		—			321		—			189		—			194
Deferred income taxes	—			74		—			80		—			78		—			76
Deferred broker settlements	8			—		20			1		8			—		12			1
Debt reacquisition costs	—			18		—			22		—			16		—			17
Deferred capital projects	—			29		—			16		11			19		16			18
Other	3			11		1			13		2			23		2			18
Total regulatory assets	$	99		$	504	$	144		$	524	$	55		$	448	$	66		$	464
Regulatory liabilities:
Asset retirement removal costs	$	—		$	733	$	—		$	692	$	—		$	762	$	—		$	747
Trojan decommissioning activities ⁽¹⁾	—			41		—			—		—			42		—			41
Asset retirement obligations	—			39		—			39		—			39		—			39
Other	4			39		12			34		2			56		1			38
Total regulatory liabilities	$	4	⁽²⁾	$	852	$	12	⁽¹⁾	$	765	$	2	^*	$	899	$	1	^*	$	865


~~(1)~~	During the third quarter of 2013, PGE received a settlement for the reimbursement of certain monitoring costs incurred related to spent nuclear fuel at the Company’s Trojan nuclear power plant. See Complaint Against U.S. Department of Energy in Note 7, Contingencies, for additional information.


~~(2)~~*	Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

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(Unaudited)

Accrued Expenses and Other Current Liabilities

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


	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
Accrued employee compensation and benefits	$	44	$	46	$	38	$	46
Accrued interest payable	33		23		36		23
Accrued taxes payable	35		21		28		21
Accrued dividends payable	22		21		22		22
Regulatory liabilities—current	4		12		2		1
Other	54		56		56		58
Total accrued expenses and other current liabilities	$	192	$	179	$	182	$	171

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~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

Credit Facilities

PGE has the following unsecured revolving credit facilities as of ~~September 30, 2013~~March 31, 2014:

A $400 million syndicated credit facility, which is scheduled to terminate in November ~~2017~~2018; and

A $300 million syndicated credit facility, which is scheduled to terminate in December ~~2016~~2017.

Pursuant to the ~~individual~~ terms of the agreements, both revolving 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 revolving credit facilities contain provisions for two, one-year extensions that are subject to approval by the banks, require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreements, to 65% of total capitalization. As of ~~September 30, 2013~~March 31, 2014, PGE was in compliance with this ~~requirement~~covenant with a ~~49.6%~~50.8% debt to total capital ratio. ~~The Company also has two letter of credit facilities under which it may obtain letters of credit in an aggregate amount not to exceed~~ ~~$51.5 million. In October 2013, one of the letter of credit facilities was increased from~~ ~~$21.5 million~~ to ~~$30 million, thereby increasing the total capacity under the letter of credit facilities to~~ ~~$60 million~~.

PGE 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~~900 million through February 6, ~~2014~~2016. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

PGE classifies borrowings under the revolving credit facilities and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. As of ~~September 30, 2013~~March 31, 2014, PGE had no borrowings oroutstanding under the revolving credit facilities, no commercial paper outstanding, ~~$56~~and $15 million of letters of credit issued. As of March 31, 2014, the aggregate available capacity under the credit facilities was $685 million.

In addition, the Company has two, one-year $30 million letter of credit facilities, which are scheduled to terminate in September and October 2014. As of March 31, 2014, PGE had issued ~~and~~$45 million of letters of credit under these facilities, with an aggregate available capacity of ~~$696 million~~ ~~under the credit facilities.~~

~~Long-term Debt~~

~~During the~~ ~~nine months ended September 30, 2013, PGE had the following long-term debt transactions:~~

~~In August, the Company repaid~~ ~~$50 million~~ ~~of 5.625% Series First Mortgage Bonds (FMBs) in accordance with the scheduled maturity and issued~~ ~~$75 million~~ of ~~4.47%~~ ~~Series FMBs due~~ ~~2043, with interest due and payable semi-annually in February and August;~~

~~In June, PGE issued~~ ~~$150 million~~ of ~~4.47%~~ ~~Series FMBs due~~ ~~2044, with interest due and payable semi-annually in June and December; and~~

~~In April, the Company repaid~~ ~~$50 million~~ of ~~4.45%~~ ~~Series FMBs in accordance with the scheduled maturity.~~

~~In October 2013, PGE entered into a bond purchase agreement with certain institutional buyers under which the Company agreed to sell to these buyers an aggregate principal amount of~~ ~~$155 million~~ ~~of FMBs in two tranches, with interest due and payable semi-annually. The first tranche of~~ ~~$105 million~~ of ~~4.74%~~ ~~Series FMBs due~~ ~~2042~~ ~~is expected to be issued in November 2013, with the second tranche of~~ ~~$50 million~~ of ~~4.84%~~ ~~Series FMBs due~~ ~~2048~~ ~~expected to be issued in December 2013.~~$15 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Pension and Other Postretirement Benefits

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

Three Months Ended September 30,

Defined Benefit
Pension Plan

Other Postretirement
Benefits

Non-Qualified
Benefit Plans
2013 2012 2013 2012 2013 2012
Service cost $ 4
$ 3
$ 1
$ —
$ —
$ —
Interest cost 7
8
1
1
—
—
Expected return on plan assets (10 ) (10 ) —
—
—
—
Amortization of prior service cost —
—
—
1
—
—
Amortization of net actuarial loss 6
4
—
—
—
—
Net periodic benefit cost $ 7
$ 5
$ 2
$ 2
$ —
$ —


	Nine Months Ended September 30,															Three Months Ended March 31,
	Defined Benefit Pension Plan						Other Postretirement Benefits					Non-Qualified Benefit Plans				Defined Benefit Pension Plan						Other Postretirement Benefits
	2013			2012			2013			2012		2013		2012		2014			2013			2014		2013
Service cost	$	12		$	9		$	2		$	1	$	—	$	—	$	4		$	4		$	—	$	1
Interest cost	23			24			3			3		1		1		9			8			1		1
Expected return on plan assets	(30		)	(30		)	(1		)	—		—		—		(10		)	(10		)	—		—
Amortization of prior service cost	—			—			1			1		—		—
Amortization of net actuarial loss	18			12			—			—		—		—		4			6			—		—
Net periodic benefit cost	$	23		$	15		$	5		$	5	$	1	$	1	$	7		$	8		$	1	$	2

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, 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~~These three levels and application to the Company are discussed below.


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


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


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

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

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

PGE recognizes ~~any~~ transfers between levels in the fair value hierarchy as of the end of the reporting ~~period.~~period for all its financial instruments. 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 during the three ~~and nine month periods~~months ended ~~September 30, 2013~~March 31, 2014 and ~~2012.~~2013, except those transfers from Level 3 to Level 2 presented in this note.

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(Unaudited)

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


	As of September 30, 2013								As of March 31, 2014
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	59	$	—	$	59	$	—	$	59	$	—	$	59
Debt securities:
Domestic government	6		9		—		15		8		6		—		14
Corporate credit	—		8		—		8		—		10		—		10
Non-qualified benefit plan trust: ⁽²⁾
Equity securities—Domestic	5		3		—		8
Debt securities—Domestic government	1		—		—		1
Assets from price risk management activities ^{(1) (3)}—Natural gas	—		1		—		1
	$	12	$	80	$	—	$	92
Liabilities from price risk management activities: ^{(1) (3)}
Equity Securities:
Domestic									5		2		—		7
Debt securities—domestic government									1		—		—		1
Assets from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	39	$	39	$	78	—		4		—		4
Natural gas	—		57		25		82		—		16		1		17
	$	—	$	96	$	64	$	160	$	14	$	97	$	1	$	112
Liabilities—Liabilities from price risk management activities:^{(1) (3)}
Electricity									$	—	$	20	$	115	$	135
Natural gas									—		26		17		43
									$	—	$	46	$	132	$	178


(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 $25 million, which are recorded at cash surrender value.


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

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(Unaudited)


	As of December 31, 2012								As of December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	15	$	—	$	15	$	—	$	59	$	—	$	59
Debt securities:
Domestic government	7		8		—		15		6		8		—		14
Corporate credit	—		8		—		8		—		9		—		9
Non-qualified benefit plan trust: ⁽²⁾
Money market funds	—		2		—		2
Equity securities:
Domestic	2		2		—		4		4		3		—		7
International	1		—		—		1		1		—		—		1
Debt securities—Domestic government	2		—		—		2
Debt securities—domestic government									1		—		—		1
Assets from price risk management activities: ^{(1) (3)}
Electricity	—		1		—		1		—		9		1		10
Natural gas	—		3		2		5		—		4		—		4
	$	12	$	39	$	2	$	53	$	12	$	92	$	1	$	105
Liabilities — Liabilities from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	72	$	10	$	82	$	—	$	10	$	117	$	127
Natural gas	—		110		8		118		—		40		23		63
	$	—	$	182	$	18	$	200	$	—	$	50	$	140	$	190


(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 $2326 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 condensed 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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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Equity securities—~~Certain equity~~Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock ~~Exchange (NYSE).~~Exchange. 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.~~marketplace.

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 its 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 commodity prices ~~for commodities~~ and interest rates. Substantially all of these ~~assumptions~~inputs 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~~consist of forwards, futures 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.~~forwards, futures and swaps.

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(Unaudited)

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities ~~as of~~ ~~September 30, 2013~~is presented below:

Significant Price per Unit
Fair Value Valuation Unobservable Weighted
Commodity Contracts Assets Liabilities Technique Input Low High Average
(in millions)
Natural gas financial swaps $ —
$ 25
Discounted cash flow Natural gas forward price (per Decatherm) $ 3.22
$ 4.71
$ 3.87
Electricity financial swaps —
13
Discounted cash flow Electricity forward price (per MWh) 8.91
48.28
36.23
Electricity physical forward purchase —
26
Discounted cash flow Electricity forward price (per MWh) 8.11
50.49
32.67
$ —
$ 64

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

~~Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities as of~~ ~~December 31, 2012~~ ~~is presented below:~~


						Significant	Price per Unit											Significant	Price per Unit
	Fair Value				Valuation	Unobservable					Weighted		Fair Value				Valuation	Unobservable					Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Low		High		Average		Assets		Liabilities		Technique	Input	Low		High		Average
	(in millions)												(in millions)
As of March 31, 2014:
Electricity physical forward													$	—	$	102	Discounted cash flow	Electricity forward price (per MWh)	$	4.50	$	81.20	$	36.81
Natural gas financial swaps	$	2	$	8	Discounted cash flow	Natural gas forward price (per Decatherm)	$	3.67	$	5.21	$	4.28	1		17		Discounted cash flow	Natural gas forward price (per Decatherm)	3.32		5.38		3.87
Electricity financial swaps	—		10		Discounted cash flow	Electricity forward price (per MWh)	7.12		51.72		41.14
Electricity financial futures													—		13		Discounted cash flow	Electricity forward price (per MWh)	9.50		46.62		33.07
	$	2	$	18									$	1	$	132
As of December 31, 2013:
Electricity physical forward													$	—	$	103	Discounted cash flow	Electricity forward price (per MWh)	$	9.63	$	77.95	$	40.18
Natural gas financial swaps													—		23		Discounted cash flow	Natural gas forward price (per Decatherm)	3.16		4.49		3.71
Electricity financial futures													1		14		Discounted cash flow	Electricity forward price (per MWh)	9.63		46.07		33.01
													$	1	$	140

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~~For shorter term contracts, the Company employs the mid-point of the market’s bid-ask spread and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against ~~nonbinding quotes~~independent market data aggregated from ~~brokers with whom~~multiple sources. For certain long term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company ~~transacts.~~uses internally developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the ~~Company’s Risk Management group.~~Company. 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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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


	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
	2013		2012			2013		2012			2014			2013
Balance as of the beginning of the period	$	56	$	88		$	16	$	79		$	139		$	16
Net realized and unrealized losses (gains) ⁽¹⁾	8		(7		)	48		4
Net realized and unrealized (gains) losses^*											(11		)	5
Purchases	—		(2		)	—		(2		)	—			24
Issuances	—		—			—		(1		)
Transfers out of Level 3 to Level 2	—		—			—		(1		)	3			—
Balance as of the end of the period	$	64	$	79		$	64	$	79		$	131		$	45


~~(1)~~	* Contains nominal amounts of realized (gains) and losses, net. Both realized and unrealized losses (gains) 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.

~~Table~~ of ~~Contents~~
realized losses. 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.

~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the ~~nine month periods~~three months ended ~~September 30,~~March 31, 2014 and 2013, ~~and 2012,~~ there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its financial instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s condensed 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 the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of ~~September 30, 2013~~March 31, 2014, the estimated aggregate fair value of PGE’s long-term debt was $~~1,927~~2,186 million, compared to its $~~1,761~~1,916 million carrying amount. As of December 31, ~~2012,~~2013, the estimated aggregate fair value of PGE’s long-term debt was $~~1,949~~2,074 million, compared to its $~~1,636~~1,916 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 forwards, futures, swaps, 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~~processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from ~~derivative instruments until realized. This accounting treatment defers the fair value gains and losses on~~ derivative instruments until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as ~~purely~~ economic hedges. The Company does not engage in trading activities for non-retail purposes.

2018

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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


	September 30, 2013			December 31, 2012			March 31, 2014			December 31, 2013
Current assets:
Commodity contracts:
Electricity	$	—		$	1		$	4		$	9
Natural gas	1			3			14			4
Total current derivative assets	1		⁽¹⁾	4		⁽¹⁾	18		⁽¹⁾	13		⁽¹⁾
Noncurrent assets:
Commodity contracts—Natural gas	—		⁽²⁾	2		⁽²⁾
Commodity contracts:
Electricity							—			1
Natural gas							3			—
Total noncurrent derivative assets							3		⁽²⁾	1		⁽²⁾
Total derivative assets not designated as hedging instruments	$	1		$	6		$	21		$	14
Total derivative assets	$	1		$	6		$	21		$	14
Current liabilities:
Commodity contracts:
Electricity	$	42		$	44		$	33		$	20
Natural gas	47			83			19			29
Total current derivative liabilities	89			127			52			49
Noncurrent liabilities:
Commodity contracts:
Electricity	36			38			102			107
Natural gas	35			35			24			34
Total noncurrent derivative liabilities	71			73			126			141
Total derivative liabilities not designated as hedging instruments	$	160		$	200		$	178		$	190
Total derivative liabilities	$	160		$	200		$	178		$	190


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


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

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 ~~2017,~~2035, were as follows (in millions):


	September 30, 2013				December 31, 2012			March 31, 2014			December 31, 2013
Commodity contracts:
Electricity	12			MWh	11		MWh	22		MWh	14		MWh
Natural gas	104			Decatherms	86		Decatherms	104		Decatherms	106		Decatherms
Oil	(1		)	Gallons	—		Gallons
Foreign currency	$	7		Canadian	$	7	Canadian	$	2	Canadian	$	7	Canadian

PGE has elected to report gross on the condensed consolidated balance ~~sheet~~sheets the positive and negative exposures resulting from derivative instruments ~~with counterparties under~~pursuant to 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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.

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

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


								Gross Amounts Not Offset in													Gross Amounts Not Offset in
		Gross		Gross		Net		Condensed Consolidated							Gross		Gross		Net		Condensed Consolidated
		Amounts		Amounts		Amounts		Balance Sheets							Amounts		Amounts		Amounts		Balance Sheets
		Recognized		Offset		Presented		Derivatives			Cash Collateral⁽¹⁾		Net Amount		Recognized		Offset		Presented		Derivatives			Cash Collateral⁽¹⁾		Net Amount
As of September 30, 2013:
As of March 31, 2014:
Liabilities:	��
Commodity contracts:
Electricity⁽²⁾		$	14	$	—	$	14	$	(14	)	$	—	$	—	$	90	$	—	$	90	$	(90	)	$	—	$	—
Natural gas⁽²⁾		3		—		3		(3		)	—		—		1		—		1		(1		)	—		—
		$	17	$	—	$	17	$	(17	)	$	—	$	—	$	91	$	—	$	91	$	(91	)	$	—	$	—

As of December 31, 2012:
As of December 31, 2013:
Liabilities:
Commodity contracts:
Electricity⁽²⁾		$	20	$	—	$	20	$	(20	)	$	—	$	—	$	91	$	—	$	91	$	(91	)	$	—	$	—
Natural gas⁽²⁾		7		—		7		(7		)	—		—		1		—		1		(1		)	—		—
		$	27	$	—	$	27	$	(27	)	$	—	$	—	$	92	$	—	$	92	$	(92	)	$	—	$	—


(1)	As of ~~September 30, 2013~~ ~~and~~ ~~December~~March 31, ~~2012~~2014, the Company had nocollateral ~~posted~~posted. As of ~~$6 million~~December 31, 2013 ~~and~~, PGE had posted collateral in the amount of $187 million, ~~respectively,~~ which ~~consists~~consisted entirely of letters of credit.


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

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


	Three Months Ended September 30,						Nine Months Ended September 30,				Three Months Ended March 31,
	2013			2012			2013		2012		2014			2013
Commodity contracts:
Electricity	$	(1	)	$	(3	)	$	17	$	40	$	9		$	8
Natural Gas	10			(19		)	30		6		(36		)	(8		)

Net unrealized and certain net realized (gains) losses presented in the table above are offset within the condensed consolidated statements of income by the effects of regulatory accounting. Of the net (gains) losses recognized in Net income for the three months ended ~~September 30, 2013~~March 31, 2014 and ~~2012~~2013, net losses of $712 million and ~~net gains of~~ $303 million, respectively, have been ~~offset, with net losses of~~ ~~$66 million~~ ~~and~~ ~~$14 million~~ ~~offset for the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013~~ ~~and~~ ~~2012, respectively.~~offset.

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Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of ~~September 30, 2013~~March 31, 2014 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

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~~(Unaudited)~~


	2013		2014		2015		2016		2017		Total		2014		2015		2016		2017		2018		Thereafter		Total
Commodity contracts:
Electricity	$	8	$	40	$	23	$	7	$	—	$	78	$	28	$	23	$	13	$	5	$	5	$	57	$	131
Natural gas	21		34		11		11		4		81		7		3		10		6		—		—		26
Net unrealized loss	$	29	$	74	$	34	$	18	$	4	$	159	$	35	$	26	$	23	$	11	$	5	$	57	$	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 ~~September 30, 2013~~March 31, 2014 was $~~138~~166 million, for which PGE has posted $267 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at ~~September 30, 2013~~March 31, 2014, the cash requirement to either post as collateral or settle the instruments immediately would have been $~~138~~151 million. As of ~~September 30, 2013~~March 31, 2014, PGE has posted an additional $3617 million in cash collateral, which is classified as Margin deposits on the Company’s condensed consolidated balance sheet, for derivative instruments with no credit-risk related contingent features.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities ~~as of~~ ~~September 30, 2013~~ or ~~December 31, 2012~~were as follows:


	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
Assets from price risk management activities:
Counterparty A	21	%	—	%	20	%	5	%
Counterparty B	14		—		18		53
Counterparty C	11		—		15		6
Counterparty D	9		21		10		5
					63	%	69	%
Liabilities from price risk management activities:
Counterparty E	4		11		46	%	43	%
Counterparty F	1		13		12		11
Counterparty G	—		10
	60	%	55	%	58	%	54	%
Liabilities from price risk management activities:
Counterparty H	16	%	—	%
Counterparty I	14		24
Counterparty A	10		14
Counterparty E	10		8
Counterparty J	9		10
	59	%	56	%

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

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NOTE 5: EARNINGS PER SHARE

Basic earnings per share is computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: ~~(1)~~i) employee stock purchase plan shares; ~~(2)~~ii) unvested time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and ~~(3)~~iii) shares issuable pursuant to an equity forward sale agreement (EFSA). See Note 6, Equity, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria ~~has~~have been met. For the three months ended March 31, 2014 and ~~nine month periods ended September 30,~~ 2013, ~~and 2012,~~ unvested performance-based restricted stock units and associated dividend equivalent rights of ~~439,891~~approximately 363,000 and ~~469,149~~,431,000, respectively, were excluded from the dilutive calculation because the performance goals had not been met.

~~Components of~~Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share ~~were as follows:~~

Three Months Ended
September 30, Nine Months Ended September 30,
2013 2012 2013 2012
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders $ 31
$ 38
$ 58
$ 113
Denominator (in thousands):
Weighted-average common shares outstanding—basic 77,637
75,528
76,401
75,486
Dilutive effect of potential common shares 693
13
302
14
Weighted-average common shares outstanding—diluted 78,330
75,541
76,703
75,500

Earnings per share—basic and diluted $ 0.40
$ 0.50
$ 0.76
$ 1.49

~~Basic~~computations. The reconciliations of the denominators of the basic and diluted earnings per share ~~amounts~~computations are ~~calculated based on actual amounts rather than~~as follows (in thousands):



	Three Months Ended March 31,
	2014	2013
Weighted-average common shares outstanding—basic	78,992	75,608
Dilutive effect of potential common shares	1,164	91
Weighted-average common shares outstanding—diluted	80,156	75,699

NOTE 6: EQUITY

The activity in equity during the ~~rounded amounts presented~~three months ended March 31, 2014 and 2013 is as follows (dollars 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.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, 2013	78,085,559	$	911	$	(5	)	$	913		$	1
Issuances of shares pursuant to equity-based plans	96,497	—		—			—			—
Stock-based compensation	—	1		—			—			—
Dividends declared	—	—		—			(22		)	—
Net income	—	—		—			58			—
Balances as of March 31, 2014	78,182,056	$	912	$	(5	)	$	949		$	1

Balances as of December 31, 2012	75,556,272	$	841	$	(6	)	$	893		$	2
Issuances 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

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~~NOTE 6: EQUITY~~

~~The activity in equity during the~~ ~~nine~~ ~~month periods ended~~ ~~September 30, 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

Shares Amount
Balances as of December 31, 2012 75,556,272
$ 841
$ (6 ) $ 893
$ 2
Issuances of common stock, net of issuance costs of $3 2,365,000
67
—
—
—
Issuance of shares pursuant to equity-based plans 146,027
—
—
—
—
Stock-based compensation —
2
—
—
—
Dividends declared —
—
—
(63 ) —
Net income (loss) —
—
—
58
(1 )
Balances as of September 30, 2013 78,067,299
$ 910
$ (6 ) $ 888
$ 1

Balances as of December 31, 2011 75,362,956
$ 836
$ (6 ) $ 833
$ 3
Issuance of shares pursuant to equity-based plans 171,430
—
—
—
—
Stock-based compensation —
2
—
—
—
Dividends declared —
—
—
(61 ) —
Net income (loss) —
—
—
113
(1 )
Balances as of September 30, 2012 75,534,386
$ 838
$ (6 ) $ 885
$ 2

~~On June 11, 2013, PGE entered into an EFSA in~~In connection with a public offering of ~~11,100,000~~shares of its common ~~stock. The underwriters exercised their over-allotment option~~stock in ~~full in connection with such public offering and on June 17,~~ 2013, PGE ~~issued~~entered into an ~~additional~~ ~~1,665,000~~ ~~shares of PGE common stock for~~ ~~$28.54~~ ~~per share, net of the underwriters’ discount, or net proceeds of~~ ~~$47 million. In August, the Company issued~~ ~~700,000~~ ~~shares for net proceeds of~~ ~~$20 million~~.

EFSA. Pursuant to the terms of the EFSA, a forward counterparty borrowed 11,100,000 shares of PGE’s common stock from third parties in the open market and sold the shares to a group of underwriters for $29.50 per share, less an underwriting discount equal to $0.96 per share. The underwriters then sold the shares in a public offering. PGE receives proceeds from the sale of common stock when the EFSA is physically settled (described below), and at that time PGE records the proceeds in equity.

Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of: ~~(1)~~i) physical; ~~(2)~~ii) cash; or ~~(3)~~iii) net share settlement, in whole or in part, at any time on or prior to June 11, 2015, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE ~~would be~~is required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $29.50 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.

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~~(Unaudited)~~

The use of the EFSA substantially eliminates future equity market price risk by fixing the common stock offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until such funds are needed in accordance with the Company’s capital requirements. The EFSA had no initial fair value since it was entered into at the then market price of the common stock. PGE concluded that the EFSA was an equity instrument and that it does not qualify as a derivative because the EFSA was indexed to the Company’s stock. PGE anticipates settling the EFSA through physical settlement on or before June 11, 2015.

At ~~September 30, 2013~~March 31, 2014, the Company could have physically settled the EFSA by delivering 10,400,000 shares to the forward counterparty in exchange for cash of $~~291~~284 million. In addition, at ~~September 30, 2013~~March 31, 2014, the Company could have elected to make a cash settlement by paying approximately $352 million, or a net share settlement by delivering approximately ~~100,037~~1,603,711 shares of common stock. To the extent that PGE makes a cash or net share settlement, the Company would receive no additional proceeds from the public offering.

Prior to settlement, the potentially issuable shares pursuant to the EFSA ~~will be~~are reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period ~~would be~~are increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period).

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

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reasonably estimated, then the ~~Company (i)~~Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an ~~estimate,~~estimate; or ~~(ii)~~ii) discloses that an estimate cannot be made.

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. On May 31, 2013, the Court of Appeals denied the appellants’ request for reconsideration of the decision. On October 18, 2013, the Oregon Supreme Court granted plaintiffs’ petition seeking review of the February 6, 2013

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Oregon Court of Appeals decision. Oral argument ~~is scheduled for~~occurred in March ~~4, 2014.~~2014 and the parties now await a Court decision.

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

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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 upheld the 2008 Order. Because the Oregon Supreme Court has granted the plaintiffs’ petition seeking review of that decision, 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~~Upon appeal of the ~~FERC order~~decision 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 CircuitCourt remanded the case to the FERC ~~to: i)~~to, among other things, 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.proceedings.

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

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~~clarifying 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

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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.

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~~(Unaudited)~~

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 of its Order on Remand 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. Refund claimants have filed petitions for 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 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)~~including the California Energy Resource Scheduling division of the California Department of Water Resources (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~~first phase of the 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~~a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents.

During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of CERS, presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of CERS’ respondents, but did find evidence of unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts by the last remaining CERS respondent. The Administrative Law Judge scheduled a second phase of the hearing to commence after a final FERC decision on the Initial Decision. In the second phase, the last respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. If the FERC requires one or more respondents to make refunds, it is possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company.

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 from any of the current respondents, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, will pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. 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.

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(Unaudited)

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 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.

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

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 a~~The draft feasibility study report, which ~~would provide~~describes possible remediation alternatives that range in estimated cost from $3 million to $8 million, was submitted to the DEQ in late February 2014. Using the Company’s best estimate of the probable cost for the remediation effort from the set of alternatives provided in the draft feasibility study report, PGE has a ~~range of potential cost estimates, will be available by the end of 2013 or early 2014.~~

~~Management believes that it is reasonably possible that~~$3 million reserve for this matter ~~could result in a loss to~~as of March 31, 2014.

Based on the ~~Company. However, because~~available evidence of previous rate recovery of incurred environmental remediation costs for PGE, as well as for other utilities operating within the ~~feasibility study continues, sufficient information is currently not available to determine PGE’s liability for~~same jurisdiction, the Company has concluded that the estimated cost of ~~any required investigation or remediation of~~$3 million to remediate the Downtown Reach ~~site or to estimate~~is probable of recovery. As a ~~range~~result, the Company also has a regulatory asset of ~~potential loss.~~$3 million for future recovery in prices as of March 31, 2014. The Company included recovery of the regulatory asset in its 2015 General Rate Case filed with the OPUC in February 2014.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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)~~(CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other ~~Colstrip~~CSES co-owners, including PPL Montana, LLC, the operator of ~~Colstrip.~~CSES. PGE has a 20% ownership interest in Units 3 and 4 of ~~Colstrip.~~CSES. 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.

The Sierra Club and MEIC asserted that the ~~Colstrip~~CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and 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 Sierra Club and MEIC also asserted violations of opacity provisions of the CAA.

On March 6, 2013, the Sierra Club and MEIC sued the ~~Colstrip~~CSES 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~~CSES 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. On May 3, 2013, the defendants filed a motion to dismiss 36 of the 39 claims in the suit. On September 27, 2013, the plaintiffs filed an amended complaint that

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

deleted the Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. This matter is scheduled for trial in ~~October 2014.~~March 2015. On March 1, 2014, the plaintiffs filed another Notice of Intent to Sue, which would amend the original suit by adding twelve projects to the case.

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

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~~CSES 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.~~CSES. On May 31, 2013, the district court judge granted the defendants’ motion to dismiss the petition for the writ of mandamus.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Oregon Tax Court Ruling

On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue (DOR) 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 DOR has appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court. It is uncertain whether the ruling will be upheld.

If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $7 million due to an increase in the tax rate at which deferred tax liabilities would be recognized in future years. For open tax years per Oregon statute, 2008 through 2012, the Company entered into a closing agreement with the DOR during the third quarter 2013 under which the DOR agreed to the tax apportionment methodology utilized on the tax returns relating to those years.

~~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

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

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 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 did not state the precise amount of the damages award, but directed the parties to consult and propose a final amount for the Plaintiffs’ recovery that was based on certain adjustments specified in the court’s ruling. In July 2013, the parties reached a settlement wherein the Trojan co-owners were to receive ~~$70 million~~ ~~for the period through 2009. PGE’s share, approximately~~ ~~$44 million~~, was received during the third quarter 2013 and deposited into the Nuclear Decommissioning Trust. The settlement agreement also provided for a process to submit claims for allowable costs for the period 2010 through 2013. Recovery of any costs for periods after 2013 will be covered in subsequent agreements. The proceeds received related to this legal matter will flow to the benefit of customers in future regulatory proceedings 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, individually and in the aggregate, 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 ~~September 30, 2013~~March 31, 2014, 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~~two variable interest entities (VIEs) and, therefore, consolidates the VIEs within the Company’s condensed consolidated financial ~~statements. All three~~statements as of March 31, 2014. Both arrangements were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating, and financing photovoltaic solar power facilities located on real property owned by third parties, and selling the energy generated by the facilities. PGE is the Managing Member in each of the Limited Liability Companies (LLCs), holding less than 1% equity interest in each entity, and a financial institution is the Investor Member, holding more than 99% equity interest in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

31
29

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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)~~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)~~ii) PGE expects to own 100% of the LLCs shortly after five years have elapsed from when the facility was placed in service, at which time the facilities will have approximately 75% of their estimated useful life remaining; and ~~(iii)~~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 as of March 31, 2014 and December 31, 2013are LLC net assets of $5$5 million, ~~as of~~ ~~September 30, 2013~~, consisting primarily of Electric utility plant, net, ~~and~~ $6with $1 million ~~as of~~ ~~December 31, 2012, consisting~~ of Cash and cash ~~equivalents of~~ ~~$1 million~~ ~~and Electric utility plant, net of~~ ~~$5 million~~.equivalents. These assets can only be used to settle the obligations of the consolidated VIEs.

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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 results of 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 ~~the Company~~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;

~~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;~~

~~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;~~

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;

~~changes in wholesale prices for fuels, including natural gas, coal, and oil, and the impact of such changes on the Company’s power costs;~~

~~changes in the availability and price of wholesale power;~~

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

the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 7, Contingencies, in the Notes to the 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

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could increase the Company’s costs to maintain its generating facilities and transmission and distribution systems;

operational factors affecting PGE’s power generating 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~~PGE to issue additional letters of credit or post additional cash as collateral with counterparties pursuant to existing power and natural gas purchase agreements;

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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;

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 of capital projects, 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 generating 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;

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;

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~~that 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 ~~earthquakes, floods, droughts,~~earthquake, flood, drought, lightning, wind, and fire;

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

acts of war or terrorism.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors

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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~~2013, and other periodic and current reports filed with the SEC.

Capital Requirements and Financing—Pursuant to PGE’s latest acknowledged IRP and the result of the Company’s request for proposal processes completed in 2013, PGE is in the process of constructing three new generation resources as follows:

Port Westward Unit 2 (PW2)—Construction commenced in May 2013 on PW2, which is a 220 MW natural gas-fired plant located adjacent to the Port Westward and Beaver natural gas-fired generating plants near Clatskanie, Oregon. This project is currently on budget at an estimated total cost of $300 million, excluding AFDC, and is expected to be online in the first quarter of 2015. The Company has requested in its 2015 General Rate Case that cost recovery for the project begin at the point at which the plant is placed into service;

Tucannon River wind farm (Tucannon River)—Construction commenced in September 2013 on Tucannon River, which is a wind farm located in southeastern Washington with a nameplate capacity of 267 MW, consisting of 116 turbines each with a generating capacity of 2.3 MW. This project is currently on budget at an estimated total cost of $500 million, excluding AFDC, and is expected to be online between December 2014 and March 31, 2015. The Company had requested recovery of costs related to the project in its 2015 General Rate Case to begin when the plant is placed into service, which at the time was expected to be in the first half of 2015. However, in March 2014, PGE submitted a renewable adjustment clause mechanism (RAC) filing to the OPUC to allow for deferral and recovery of costs to begin earlier if the project should come online earlier than contemplated in the 2015 General Rate Case; and

Carty Generating Station (Carty)—Construction commenced in January 2014 on Carty, which is a 440 MW natural gas-fired power plant located in Eastern Oregon, adjacent to Boardman. This project is currently on budget at an estimated total cost of $450 million, excluding AFDC, and is expected to be online in 2016.

The Company expects to file for recovery of costs related to this project in a future general rate case.

In total, the Company’s capital expenditures in 2014 are expected to approximate $1 billion, which includes an estimated $640 million related to the three new generation resources under construction discussed above. For additional information on these three new generation resources, see “Capital Requirements” in the Liquidity and Capital Resources section of this Item 2.

PGE expects to fund such estimated capital requirements with a combination of cash from operations, which is expected to range from $540 million to $560 million, and proceeds from long-term loans and issuances of debt securities ranging from $550 million to $600 million. For additional information, see “Liquidity” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 2.

General Rate Case—On January 1, 2014, new customer prices went into effect pursuant to the OPUC order issued on PGE’s 2014 General Rate Case. The OPUC authorized a $61 million increase in annual revenues, representing an approximate 4% overall increase in customer prices. The increase includes improvements to existing power plants and wind forecasting, new Clackamas River fish-sorting facilities, a disaster-preparedness center, technology investments, employee benefit costs and compliance with new federal regulations. In addition, the order approves a

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capital structure of 50% debt and 50% equity, a return on equity of 9.75%, a cost of capital of 7.65%, and an average rate base of approximately $3.1 billion.

On February 13, 2014, PGE filed with the OPUC a 2015 General Rate Case, which is based on a 2015 test year. PGE requested an $81 million net increase in annual revenues, representing an approximate 4.6% overall increase in customer prices. The net increase in annual revenues consists of the following (in millions):



New generating plants:
Port Westward Unit 2	$	51
Tucannon River wind farm	47
Base business cost increase	12
Less: customer credits*	(29		)
Annual revenue net increase	$	81

* Includes approximately $17 million for the return of $50 million over three years, 2015 through 2017, for the settlement of a legal matter concerning costs associated with the operation of the Independent Spent Fuel Storage Installation (ISFSI) at Trojan. Also includes credits related to the return of ISFSI tax credits to customers and additional Bonneville Power Administration (BPA) Regional Power Act refund to residential customers.

PGE is proposing a capital structure of 50% debt and 50% equity, a return on equity of 10%, a cost of capital of 7.78%, and an average rate base of approximately $3.9 billion.

Regulatory review of the 2015 General Rate Case will continue throughout 2014, with a final order expected to be issued by the OPUC by mid-December 2014. New customer prices are expected to become effective in 2015, with the first price increase effective January 1 and two additional price increases effective as two new generating plants become operational. PW2 is expected to be placed in service in the first quarter of 2015 and Tucannon River is expected to be placed in service between December 2014 and March 31, 2015.

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.

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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 ~~affect~~effect on revenues while the availability and price of purchased power and fuel can affect income from operations.

Customers and Demand—Retail energy deliveries for the ~~nine months~~ ~~ended~~ ~~September 30, 2013~~first quarter of 2014 decreased ~~0.4%~~1.7% from the ~~comparable period~~first quarter of ~~2012~~2013, which ~~can~~was primarily driven by a decline in residential energy deliveries, despite comparable weather conditions, and a decline in industrial energy deliveries largely ~~be attributed to the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013~~ ~~having one less day in the period~~ due to ~~the leap year in 2012. The decline was partially offset by an increase of 5,300 in the average number of total retail customers served.~~decreased demand from a paper production customer. Energy efficiency and conservation efforts by retail customers continue to influence total energy deliveries, although the financial impacts to the Company of such efforts are ~~intended to be~~partially mitigated by the decoupling mechanism. The decline was partially offset by the effects of a 1% increase in the average number of total retail customers served.

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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):

Nine Months Ended September 30,
2013 2012
% Increase
/(Decrease)in Energy
Deliveries

Average
Number of
Customers

Retail Energy
Deliveries*

Average
Number of
Customers

Retail Energy
Deliveries*

Residential 727,579
5,469
722,884
5,506
(0.7 )%
Commercial 104,436
5,540
103,798
5,566
(0.5 )
Industrial 264
3,186
261
3,180
0.2
Total 832,279
14,195
826,943
14,252
(0.4 )

~~____________________~~



	Three Months Ended March 31,
	2014		2013		% 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	733,719	2,174	726,451	2,229	(2.5	)%
Commercial	103,684	1,781	102,765	1,787	(0.3	)
Industrial	262	1,001	272	1,024	(2.2	)
Total	837,665	4,956	829,488	5,040	(1.7	)


*	In thousands of MWh.

~~On a weather adjusted basis, total retail energy deliveries for the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013~~ were comparable to the same period of 2012. Removing the effect of the leap year, the weather adjusted deliveries are slightly higher than the prior period due to a modest increase in industrial deliveries and the addition of residential customers. Net of the effects of energy efficiency and conservation efforts, PGE expects retail energy deliveries for 2013 to be comparable to weather adjusted 2012 levels.

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 ~~nine months ended September 30, 2013~~first quarters of 2014 and ~~2012~~2013, availability of the plants PGE operates approximated ~~90%~~95% and ~~93%~~97%, respectively, with the availability of Colstrip Units 3 and 4, in which ~~PGE~~the Company has a 20% ownership interest but does not operate, approximating ~~66%~~82% and ~~92%~~97% ~~for the same periods,~~, respectively.

~~During the third quarter of 2013, PGE experienced unplanned forced outages at three of its generating plants as follows:~~

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Colstrip Unit 4 ~~coal-fired generating plant tripped~~was off-line ~~on July 1, 2013 as~~most of the month of January 2014 due to repairs to the generator. As a result, PGE incurred approximately $2 million of damage that occurred in the unit’s generator. PGE has a 20% ownership interest in Colstrip Unit 4, which is operated by PPL Montana, LLC. The Company’s share of the net capacity of the plant is 148 MW. The total repairincremental replacement power costs ~~are estimated to range from $30 million to $35 million, the majority of which are expected to be capitalized. The plant is expected to be back online~~ in the first quarter of ~~2014. PPL Montana is working with the insurance carrier for reimbursement of the repair costs~~2014 related to this ~~event, which is subject to a $2.5 million deductible.~~

~~Boardman coal-fired generating~~ plant tripped off-line on July 1, 2013 as a result of a thermal water hammer event causing structural damage to the cold reheat piping line that runs between the turbine and the boiler. The Company has a 65% ownership interest in Boardman, which is operated by PGE. The Company’s share of the net capacity of the plant is 374 MW. The plant came back online July 31, 2013, with total repair costs approximating $10 million, the majority of which have been capitalized, net of insurance proceeds. Property damage insurance for the Boardman repair costs is subject to a $2.5 million deductible and, as of September 30, 2013, total insurance proceeds received were approximately $5 million, of which $3 million was PGE’s share.

Coyote Springs natural gas-fired generating plant has been off-line since August 24, 2013 as a result of cracks in the steam turbine rotor. Coyote Springs has a net capacity of 246 MW, which represents approximately 9% of the Company’s total net generating capacity. PGE estimates the repair costs to approximate $2 million and to be included in operating and maintenance expense, with any potential insurance recovery subject to a $2.5 million deductible for each event. The repairs are expected to be completed and the plant back online by the end of November 2013.

As a result of these unplanned outages, the Company will also incur incremental power costs to replace its share of the output of these plants over the period of time the plants are off-line. PGE estimates total incremental replacement power costs related to these unplanned plant outages to range from $16 million to $18 million for 2013, with approximately $11 million incurred during the third quarter of 2013. These incremental replacement power costs will be included in actual net variable power costs (NVPC) in the Company’s power cost adjustment mechanism (PCAM) calculation for 2013.outage.

During the ~~nine months ended September 30, 2013~~,first quarter of 2014, the Company’s generating plants provided approximately ~~54%~~59% of its retail load requirement, compared with ~~47%~~62% in the first quarter of ~~nine months ended September 30, 2012~~2013. The ~~increase~~decrease in the proportion of power generated to meet the Company’s retail load requirement was largely the result of the difference in the economic dispatch decisions made throughout the respective ~~periods. Despite~~periods, as well as the ~~unplanned plant outages, the proportion~~outage of ~~power provided by the Company’s generating plants~~Colstrip Unit 4 in 2013 increased from 2012 because a greater amount of thermal generation was economically displaced in 2012 by lower-cost purchased power and increased energy from hydro resources, both of which were driven by more favorable hydro conditions.January 2014.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects ~~decreased~~increased ~~11%~~4% in the ~~nine months ended September 30, 2013~~first quarter of 2014 compared with the first quarter of ~~nine months ended September 30, 2012~~2013. These resources provided approximately 18% of the Company’s retail load requirement for the first quarters of 2014 and ~~nine months ended September 30,~~ 2013~~, compared with~~ ~~20%~~ ~~for the~~ ~~nine months ended September 30, 2012~~. Through ~~September,~~March, energy received from these sources ~~exceeded~~approximated projections included in the Company’s Annual Power Cost Update Tariff (AUT) during 2014, compared with falling short of such projection by ~~approximately~~ 2%3% during ~~2013, compared with~~ ~~12%~~2013 during 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. Energy from hydro resources is expected to approximate projections included in the AUT for ~~2013.~~2014.

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.~~AUT. Any excess

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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 ~~14%~~ ~~and~~ ~~17%~~11% in the first quarters of 2014 and ~~nine months ended September 30,~~2013 ~~and~~ ~~2012~~, ~~respectively,~~ and provided approximately 7%4% of the Company’s retail load requirement for ~~both periods.~~the first quarter of 2014, compared with 5% for the first quarter of 2013.

Pursuant to the Company’s ~~PCAM,~~power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted ~~NVPC~~net variable power cost (NVPC) included in customer

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prices (baseline NVPC) and actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial ~~contracts. NVPC is~~contracts (all classified as Purchased power and fuel expense in the Company’s condensed consolidated statements of ~~income,~~income) and is net of wholesale ~~sales,~~revenues, which are classified as Revenues, net in the condensed consolidated statements of income. To the extent actual NVPC, subject to certain adjustments, 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 condensed consolidated 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.

For the ~~nine months ended September 30, 2013~~,first quarter of 2014, actual NVPC was approximately $53 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, ~~2013~~2014 is currently estimated to be ~~above the~~below baseline NVPC, but within the deadband range; accordingly, no estimated collection from or refund to customers is expected for ~~2013. As discussed previously, replacement power costs related to the unplanned outages of Boardman, Coyote Springs and Colstrip Unit 4 will be included in the Company’s PCAM calculation for 2013.~~2014.

For the first quarter of ~~nine months ended September 30, 2012~~2013, actual NVPC was approximately $141 million below baseline NVPC. For the full year ~~2012,~~2013, actual NVPC was ~~$17~~$11 million ~~below~~above baseline NVPC, ~~and $2 million below~~which is within the ~~lower~~established deadband ~~threshold, resulting in a potential refund due to customers. However, based on results of the regulated earnings test,~~range. Accordingly, no estimated ~~refund to~~collection from customers was recorded for ~~2012.~~

~~Transmission Capacity~~—In May 2013, PGE and Bonneville Power Administration (BPA) executed a non-binding memorandum of understanding (MOU), under which the parties explored a transmission capacity option whereby BPA could provide PGE with ownership of approximately 1,500 MW of transmission capacity rights in exchange for certain PGE assets, investments and/or PGE transfer capabilities to BPA. As a result of the changed conditions reflected in the MOU, PGE suspended permitting and development of the Cascade Crossing transmission project (Cascade Crossing) and charged $52 million of capitalized costs related to Cascade Crossing to expense in the second quarter of 2013. Additionally, in June 2013, the Company filed with the OPUC seeking deferral of these costs for future recovery in customer prices. In October 2013, the parties determined that they would not be able to reach an agreement on the financial terms for the proposed ownership of transmission capacity rights and, therefore, agreed to discontinue discussions on this option. The Company has determined that, under current conditions, the best option for meeting its transmission needs is to continue to acquire transmission service offered under BPA’s Open Access Transmission Tariff. In light of this development, the Company intends to withdraw the deferral application previously filed with the OPUC.

~~General Rate Case~~—In February 2013, PGE filed with the OPUC a general rate case based on a 2014 test year (2014 GRC). PGE’s initial filing proposed a $105 million increase in annual revenues, representing an approximate 6% overall increase in customer prices. The initial filing also included a proposed 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.

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PGE, OPUC staff, and certain customer groups have reached agreements that resolve all revenue requirement matters in the case, subject to OPUC approval. The stipulated items, along with recently filed updates of power costs and forecasted load, resulted in a revised increase of $67 million in annual revenue requirement, as illustrated in the table below. The revised revenue requirement increase represents an approximate 4% overall increase in customer prices.

General Rate Case*
Annual revenue requirement change
($ in millions)
Increase to annual revenues—Initial filing $ 105
Reduction resulting from non-power cost stipulation (42 )
Increase resulting from update to load forecast (revenue) 15
Reduction resulting from power costs stipulation and updated power costs (11 )
Increase to annual revenues—As revised $ 67


*	Forecasted 2014 NVPC and the split between cost-of-service and direct access load pursuant to the September opt-out window will be updated at various dates through November 15, 2013. These updates may change the amounts presented above.

~~The stipulated items, as filed with the OPUC in 2013, reflect the following:~~

~~A capital structure of 50% debt and 50% equity;~~

~~A return on equity of 9.75%;~~

~~A cost of capital of 7.65%, reflecting actual 2013 debt issuances;~~

~~An average rate base of $3.1 billion;~~

~~Updates to incorporate revised information regarding expected 2014 costs;~~

Allowance for PGE to collect approximately $16.5 million of certain 2014 information technology and customer service costs during a five year amortization period beginning in 2014, with rate base treatment of the uncollected balances;

~~Implementation of a historical rolling average for forecasted wind generation;~~

~~Extension of PGE’s decoupling mechanism for three years through 2016; and~~

~~Updates to incorporate revised terms and conditions for the Company’s direct access program and streetlight pricing.~~

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.

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~~Capital Requirements and Financing~~—In accordance with PGE’s Integrated Resource Plan (IRP) and pursuant to the OPUC’s competitive bidding guidelines, the Company issued two request for proposals (RFPs) during 2012 for additional generation resources—one for capacity and energy (baseload) resources, and one for renewable resources. PGE has completed the resource selections pursuant to the RFPs as follows:

~~Capacity and Energy (Baseload) Resources~~—In January 2013, PGE’s proposed Port Westward Unit 2 (PW2) flexible 220 MW generating resource was selected as the successful bid for the capacity resource. PW2, for which construction began during the second quarter of 2013, is expected to be in service in the first quarter of 2015 at an estimated cost of $300 million, excluding the Allowance for funds used during construction (AFDC). As of September 30, 2013, $107 million is included in Construction work in progress (CWIP) for PW2.

In June 2013, a proposed 440 MW natural gas-fired power plant in eastern Oregon, located adjacent to the Company’s Boardman plant, was selected as the successful bid for the energy (baseload) resource. The new facility, to be known as the Carty Generating Station (Carty), will be constructed by a third party and owned and operated by PGE. Carty is expected to be in service in 2016 at an estimated cost of $450 million, excluding AFDC. As of September 30, 2013, $62 million is included in CWIP for Carty.

PGE has also entered into two power purchase agreements for up to 100 MW of seasonal peaking capacity. One agreement covers winter from December 2014 to February 2019 and the second agreement covers summer from July 2014 to September 2018. These power purchase agreements substantially complete the resource selections pursuant to the capacity and energy resources RFP.

~~Renewable Resources~~—In June 2013, a new wind farm then under development in southeastern Washington was selected as the successful bid for the renewable resource. The closing of the asset purchase agreement, under which the Company acquired the development rights to the project occurred August 1, 2013. The new wind farm, to be known as Tucannon River Wind Farm (Tucannon River), is currently under construction by a third party and will be owned and operated by PGE upon completion. Tucannon River, with a nameplate capacity of 267 MW, consisting of 116 turbines each with a generating capacity of 2.3 MWs, is expected to be in service in the first half of 2015 at an estimated cost of $500 million, excluding AFDC. As of September 30, 2013, $63 million is included in CWIP for Tucannon River.

~~PGE’s capital requirements are expected to approximate~~ ~~$720 million~~ in ~~2013, which includes $400 million for the resources selected pursuant to the RFPs discussed above.~~

~~PGE expects to fund 2013 estimated capital requirements and contractual maturities of~~ ~~$100 million~~ of long-term debt with cash from operations and proceeds from issuances of common stock and First Mortgage Bonds (FMBs). For additional information regarding the equity and debt transactions, see Note 6, Equity, and Note 2, Balance Sheet Components, respectively, in the Notes to Condensed Consolidated Financial Statements.

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;~~Northwest Refund Proceeding; and

An investigation of environmental matters regarding Portland Harbor.

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

The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014 compared to the ~~nine~~three months ended

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~~September 30, 2012~~ March 31, 2013 or have 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 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. As part of its 2014 General Rate Case, PGE included a projected $17 million reduction in power costs in its ~~initial~~ request for ~~a $105 million~~an overall increase in revenues. The power cost portion of the request was moved to a separate docket at the OPUC and ~~has been agreed to~~was approved and included in the overall $61 million annual revenue increase authorized by ~~intervenors and~~ the OPUC ~~staff, subject to updates through November 15, 2013.~~in the Company’s 2014 General Rate Case with new prices beginning January 1, 2014.

In June 2013, the Company submitted the results of the PCAM for 2012 to the OPUC for final regulatory review and determination of any customer refund or collection. Based on a regulated earnings test, the PCAM for 2012 did not produce an anticipated refund to or collection from customers. PGE, the OPUC Staff, and other parties reached agreement that confirmed that no refunds or collections would be required, and in October 2013, the OPUC issued an order approving ~~such agreement. In 2012, the Company submitted to the OPUC~~ the results of ~~its~~the PCAM for ~~2011~~2012, which, based on a regulated earnings test, ~~which resulted in~~did not produce a refund to ~~customers~~(or collection from) customers. Consequently, no cash flow impact will occur in 2014 as a result of ~~$6 million. 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.~~PCAM.

Renewable Resource Costs—Pursuant to ~~a renewable adjustment clause mechanism (RAC),~~its 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,~~2014, 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.~~OPUC a renewable adjustment clause filing requesting deferral and recovery of the net revenue requirement of Tucannon River in the event that the facility were to come online prior to the inclusion of the project in base rates as proposed in the 2015 General Rate Case. The Company had previously reported that the facility was expected to be in service in the first half of 2015. Based on progress of the project, the Company has revised the estimated timeline for completion of the facility and believes that the project will be in service between December 2014 and March 31, 2015.

PGE did not submit a RAC filing to the OPUC in 2013 as it isdid not ~~anticipated that the Company will~~ place renewable resources into service during 2013. ~~The Company may utilize the RAC to recover costs associated with its latest announced renewable resource, Tucannon River.~~

Decoupling—The decoupling mechanism, which ~~currently expires at~~ the ~~end of 2013,~~OPUC has authorized through 2016, is intended to provide for recovery of margin lost as a result of ~~any~~a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The Company requested in its 2014 GRC filing that the OPUC extend authorization of the mechanism to continue on a permanent basis. Agreements reached in the rate case, subject to OPUC approval, provide for continuation of the mechanism through 2016. The mechanism provides for collection from (or refund to) customers if weather adjusted use per customer is less (or more) than ~~the levels~~that projected in the Company’s most recent approved general rate case.

Pursuant to the Company’s 2014 General Rate Case, the OPUC approved a change in the refund or collection period such that it will begin January 1, rather than June 1. As such, collection of the estimated $5 million recorded during 2013, which resulted from variances between actual weather adjusted use per customer and that projected in the 2011 General Rate Case, subject to OPUC approval, would occur over a one year period beginning January 1, 2015.

For the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014, the Company has recorded an estimated collection of $3$4 million. Any resulting collection from ~~or refund to,~~ customers for the ~~2013~~2014 year would begin January 1, ~~2015.~~2016.

~~OPUC review of the annual filing for 2012 resulted in a collection of approximately $1 million, which began June 1, 2013 for a one year period.~~

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During 2011, PGE recorded an estimated refund of $2 million that was provided to customers over a one year period that ended May 31, 2013, 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~~$16 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 submitted a filing to the~~ OPUC ~~in July 2013 requesting~~authorized recovery of the ~~deferral~~deferred costs over a one year period, with a resulting tariff effective January 1, 2014. ~~For the nine months ended September 30,~~During 2013, the Company deferred an additional ~~$13~~$18 million of costs associated with these ~~projects.~~projects and plans to file for recovery of these deferred costs, subject to an earnings test, in July 2014 with new customer prices expected to be effective in January 2015.

Boardman Operating Life Adjustment—As part of the 2014 General Rate Case, the incremental depreciation expense that resulted from the shortened Boardman life was included in base customer prices, while recovery of the decommissioning costs continue under this separate tariff. The OPUC is currently considering the request for recovery of additional decommissioning costs that resulted from the acquisition of the additional 15% interest in Boardman on December 31, 2013. The tariff also provides for annual updates to decommissioning revenue requirements with revised prices to take effect each January 1.

Integrated Resource Plan (IRP)—PGE’s IRP outlines how the Company will meet future customer demand and describes PGE’s future energy supply strategy, ~~reflecting~~assessing both new and existing technologies, market conditions, and regulatory requirements. ~~The Company’s most recent~~

On March 27, 2014, PGE filed a new IRP ~~was acknowledged by~~(2013 IRP) with the OPUC, ~~in November 2010. Based on an order received from~~which outlines the OPUC in October 2013, PGE is required to file its next IRP by March 30, 2014. The IRP will include projected future energy requirements and an action plan to meet such requirements, including long-termCompany’s expectations for resource needs and resource portfolio ~~performance.~~performance over the next 20 years, and includes an “Action Plan,” which covers PGE’s proposed actions over the next two to four years (through 2017). Over this time period, the Company projects energy requirements and energy available through its generation resources and long-term power purchase agreements to be in approximate balance.

The Action Plan of the 2013 IRP includes the following, among other components, between 2014 and 2017:

Seek renewal, or partial renewal, of expiring power purchase agreements for energy generated from hydroelectric projects, if available and cost-effective for our customers;

Acquire a total of 124 MWa of energy efficiency through continuation of Energy Trust of Oregon programs;

To help manage peak load conditions and other supply contingencies, acquire 48 MW of demand response and PGE dispatchable standby generation from our customers;

In preparation for the next IRP, perform various research and studies related to load forecast and energy efficiency projections, distributed photovoltaic solar application within PGE’s service territory, the viability of large-scale biomass operations, fuel supply, wind integration needs, and operational flexibility requirements; and

Retain and acquire transmission service through BPA’s Open Access Transmission Tariff to interconnect new and existing resources in eastern Oregon to PGE’s service territory.

The 2013 IRP also incorporates the three new resources that are currently under construction, which are expected to be in service between December 2014 and 2016. For additional information on these capital projects see “Capital Requirements” in the Liquidity and Capital Resources section in this Item 2.

OPUC review of the 2013 IRP will continue throughout 2014, with an acknowledgement from the OPUC not expected before September 2014.

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~~2013, filed with the SEC on February ~~22, 2013~~14, 2014.

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Results of Operations

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


	Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended March 31,
	2013				2012					2013					2012					2014					2013
Revenues, net	$	435	100	%	$	450		100	%	$	1,311		100	%	$	1,342		100	%	$	493		100	%	$	473		100	%
Purchased power and fuel	190		44		182			40		538			41		533			40		184			37		192			41
Gross margin	245		56		268			60		773			59		809			60		309			63		281			59
Other operating expenses:
Production and distribution	54		12		49			11		169			13		153			11		54			11		51			11
Cascade Crossing transmission project	—		—		—			—		52			4		—			—
Administrative and other	49		12		50			11		158			12		160			12		54			11		54			11
Depreciation and amortization	62		14		63			14		186			14		188			14		75			15		62			13
Taxes other than income taxes	27		6		24			6		79			6		77			6		28			6		27			6
Total other operating expenses	192		44		186			42		644			49		578			43		211			43		194			41
Income from operations	53		12		82			18		129			10		231			17		98			20		87			18
Interest expense	25		6		27			6		75			6		82			6
Interest expense*																				25			5		25			5
Other income (expense):
Allowance for equity funds used during construction																				6			1		2			—
Miscellaneous income (expense), net																				(1		)	—		1			—
Other income, net	7		2		1			—		13			1		6			—		5			1		3			—
Income before income tax expense	35		8		56			12		67			5		155			11		78			16		65			13
Income tax expense	4		1		19			4		10			1		43			3		20			4		17			3
Net income	31		7		37			8		57			4		112			8		58			12		48			10
Less: net loss attributable to noncontrolling interests	—		—		(1		)	—		(1		)	—		(1		)	—		—			—		(1		)	—
Net income attributable to Portland General Electric Company	$	31	7	%	$	38		8	%	$	58		4	%	$	113		8	%	$	58		12	%	$	49		10	%

* Includes an allowance for borrowed funds used during construction of $4 million and $1 million for three months ended March 31, 2014 and 2013, respectively.

Net income attributable to Portland General Electric Company was ~~$31~~$58 million,, or ~~$0.40~~$0.73 per diluted share, for the ~~third~~first quarter of 2014, compared with $49 million, or $0.65 per diluted share, for the first quarter of 2013~~, compared with~~ ~~$38 million, or $0.50 per diluted share, for the~~ ~~third quarter~~ of ~~2012~~. The ~~decrease~~$9 million, or 18%, increase in Net income ~~is largely due to~~was driven by an increase in the average ~~variable power cost, primarily due to unplanned plant outages combined with less energy received~~retail price resulting from ~~hydro resources, which was partially offset~~the January 1, 2014 price increase authorized by ~~a decrease~~the OPUC in the Company’s ~~effective tax rate~~.

~~Net income attributable to Portland~~2014 General ~~Electric Company for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2013~~ ~~was~~ ~~$58~~Rate Case, combined with a $7 million~~, or~~ ~~$0.76~~ ~~per diluted share, compared with~~ ~~$113 million, or $1.49 per diluted share, for the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2012~~. The decrease in Net income is largely due to the charge to expense of $52 million of capitalized costs related to Cascade Crossing and an industrial customer refund of $9 million related to cumulative over-billings over a period of several years. These two items are the primary drivers for the reduction in the Company’s effective tax rate for 2013, which has a favorable impact to net income when compared to 2012. In addition, an increase in the average variable power cost and higher operating and maintenance costs related to PGE’s transmission and distribution system contributed to the decrease in net income. Lower interest expense, an increase in the allowance for ~~debt~~funds used during construction (borrowed and equity funds ~~used~~combined) resulting from a higher average construction work-in-progress (CWIP) balance driven by the construction of PW2, Tucannon River, and Carty. Additionally, during the first quarter of 2013, Net income was reduced as a result of a $3 million reserve related to its benchmark bid that was ultimately not selected in the renewable resources request for ~~construction,~~ proposal process.

Partially offsetting the increases to Net income were a2.5% decline in residential energy deliveries in first quarter of 2014compared to thefirst quarter of 2013and higher ~~earnings on the Non-qualified benefit plan trust assets partially offset the decreases to net income.~~storm and service restoration costs.

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Three Months Ended~~September 30, 2013~~March 31, 2014 Compared with the Three Months Ended~~September 30, 2012~~March 31, 2013

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


	Three Months Ended September 30,								Three Months Ended March 31,
	2013				2012				2014				2013
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	186	43	%	$	187	42	%	$	257	52	%	$	246	52	%
Commercial	162		37		168		37		158		32		149		32
Industrial	55		13		57		13		52		11		51		11
Subtotal	403		93		412		92		467		95		446		95
Other retail revenues, net	—		—		10		2		2		—		4		1
Total retail revenues	403		93		422		94		469		95		450		96
Wholesale revenues	22		5		19		4		17		4		16		3
Other operating revenues	10		2		9		2		7		1		7		1
Total revenues	$	435	100	%	$	450	100	%	$	493	100	%	$	473	100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	1,660		31	%	1,626		30	%	2,174		41	%	2,229		40	%
Commercial	1,957		37		1,963		36		1,781		33		1,787		32
Industrial	1,098		21		1,096		20		1,001		19		1,024		18
Total retail energy deliveries	4,715		89		4,685		86		4,956		93		5,040		90
Wholesale energy deliveries	581		11		771		14		381		7		540		10
Total energy deliveries	5,296		100	%	5,456		100	%	5,337		100	%	5,580		100	%
Average number of retail customers:
Residential	728,816		87	%	723,569		87	%	733,719		88	%	726,451		88	%
Commercial	105,708		13		105,100		13		103,684		12		102,765		12
Industrial	259		—		259		—		262		—		272		—
Total	834,783		100	%	828,928		100	%	837,665		100	%	829,488		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~~increased $1520 million, or 3%4%, for the first quarter of 2014 compared with the first quarter of 2013, largely due to the ~~third~~$19 million increase in Retail revenues resulting from the following:

A $21 million increase in the average retail price resulting from the January 1, 2014 price increase authorized by the OPUC in the Company’s 2014 General Rate Case; and

A $5 million increase related to an increase in the average retail price for the amortization of deferred costs related to four capital projects beginning January 1, 2014 (offset in Depreciation and amortization expense); partially offset by

A $7 million decrease related to lower volumes of energy delivered largely driven by the 2.5% decline in residential energy deliveries. Additionally, commercial and industrial energy deliveries combined were down 1% in the first quarter of 2014 compared to the first quarter of 2013 ~~compared with the~~ ~~third 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 ~~$19 million, or~~ 5%~~, in the~~ ~~third quarter~~ of ~~2013~~ ~~compared with the~~ ~~third quarter~~ of ~~2012, resulting from the combination of the following items:~~

An $11 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;

43
37

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~~A $7 million decrease related to~~Total heating degree-days for the ~~Company’s PCAM, as~~first quarter of 2014 were 1% lower than the ~~potential refund to customers related to the 2011 PCAM was reduced in the~~ ~~third~~first quarter of ~~2012~~ ~~as a result of the final OPUC review, with no estimated refund to or collection from customers recorded in the~~ ~~third quarter~~ of 2013;

~~A $3 million decrease related to the decoupling mechanism, with a $1 million potential refund recorded in the~~ ~~third quarter~~ of ~~2013~~ ~~compared with a $2 million potential collection recorded in the~~ ~~third quarter~~ of ~~2012; partially offset by~~

~~A $2 million increase related to a~~ 1% ~~increase in the volume of retail energy delivered primarily due to the effects of weather. Residential energy deliveries were up~~ 2%~~, while commercial~~ and ~~industrial deliveries were comparable to the third quarter of 2012.~~

~~Total heating degree-days in the~~ ~~third quarter~~ of ~~2013~~ ~~were~~ ~~55%~~ ~~higher than the~~ ~~third quarter~~ of ~~2012~~ ~~and~~ ~~10%~~ ~~above average, and cooling degree-days were~~ ~~16%~~ ~~higher than the~~ ~~third quarter~~ of ~~2012~~ ~~and~~ ~~19%~~1% above average. The following table indicates the number of heating ~~and cooling~~ degree-days for the ~~periods presented,~~first quarters of 2014 and 2013, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

Heating Degree-days Cooling Degree-days
2013 2012 2013 2012
July 2
14
168
115
August 3
3
203
201
September 85
41
86
79
Third quarter 90
58
457
395
15-year average for the year-to-date 82
81
385
387



	Heating Degree-days
	2014	2013
January	724	835
February	683	569
March	484	498
First quarter	1,891	1,902
15-year average for the year-to-date	1,864	1,850

Wholesale revenues ~~result from sales~~for the first quarter of electricity to utilities and power marketers in conjunction with the Company’s efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. 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. The2014 increased $31 million, or ~~16%~~6%, ~~increase in Wholesale revenues for~~from the ~~third~~first quarter of 2013, ~~compared to the~~ ~~third quarter~~ of ~~2012~~, and consisted of $8$6 million related to a ~~57%~~51% increase in average wholesale ~~prices, driven by higher natural gas prices and less favorable hydro conditions,~~price partially offset by $5 million related to a ~~25%~~29% decrease in wholesale sales volume.

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Purchased power and fuel expense ~~increased~~decreased $8 million, or 4%, for the ~~third~~first quarter of ~~2013~~2014 compared towith the ~~third~~first quarter of ~~2012~~.2013. The ~~increase~~decrease consisted of $156 million related to a 9%3% ~~increase~~decrease in total system load and $2 million related to a 1% decrease in the average variable power cost ~~which is largely due~~per MWh. The decrease in the average variable power cost to $34.50 per MWh in the ~~unplanned plant outages,~~first quarter of 2014 compared with $34.79 per MWh in the first quarter of 2013 was driven by a decrease in the cost of natural-gas fired generation combined with an increase in energy received from hydro generating resources, partially offset by ~~$7 million~~ ~~related to~~an increase in the cost of purchased power and a4% decrease in ~~total system load. During the third quarter of 2013,~~energy received from wind generating resources. In addition, the Company incurred approximately ~~$11~~$2 million of incremental replacement power costs related to the ~~unplanned plant outages.~~

~~The average variable power cost increased to~~ ~~$36.79~~ ~~per MWh in the~~ ~~third quarter~~outage of ~~2013~~ ~~compared to~~ ~~$33.89~~ ~~per MWh in the~~ ~~third quarter~~ of ~~2012~~, driven by a 33% increase in the average price of purchased power combined with a decrease in energy received from hydro resources. Such increases were partially offset by a 30% decrease in the average cost of natural gas-fired generation and an increase in energy received from wind generating resources.Colstrip Unit 4 during January 2014.

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


	Three Months Ended September 30,								Three Months Ended March 31,
	2013				2012				2014				2013
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	830		16	%	995		18	%	1,233		23	%	1,361		25	%
Natural gas	1,096		21		856		16		948		18		976		18
Total thermal	1,926		37		1,851		34		2,181		41		2,337		43
Hydro	314		6		331		6		533		10		481		9
Wind	372		7		341		7		217		4		245		4
Total generation	2,612		50		2,523		47		2,931		55		3,063		56
Purchased power:
Term	940		18		1,895		35		1,220		23		1,310		24
Hydro	385		8		422		8		378		7		393		7
Wind	92		2		95		2		63		1		66		1
Spot	1,147		22		460		8		747		14		684		12
Total purchased power	2,564		50		2,872		53		2,408		45		2,453		44
Total system load	5,176		100	%	5,395		100	%	5,339		100	%	5,516		100	%
Less: wholesale sales	(581	)			(771	)			(381	)			(540	)
Retail load requirement	4,595				4,624				4,958				4,976

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Energy from PGE-owned wind generating resources (Biglow Canyon) ~~increased~~decreased 9%11% in the ~~third~~first quarter of ~~2013~~2014 compared to the ~~third~~first quarter of ~~2012~~,2013, due to less favorable wind conditions in 2014, and represented 8%4% ~~and~~ 7%~~, respectively,~~ of the Company’s retail load ~~requirement.~~requirement for the first quarter of 2014, compared with 5% for the first quarter of 2013. Energy received from Biglow Canyon fell short of that projected in PGE’s AUT by ~~20%~~ ~~and~~ ~~26%~~11% in the ~~third quarter~~sfirst quarters of ~~2013~~2014 and ~~2012, respectively.~~2013.

Energy received from hydro resources during the ~~third~~first quarter of ~~2013~~,2014, from both PGE-owned generating plants and purchased from mid-Columbia projects, ~~decreased~~increased 7%4% compared with the ~~third~~first quarter of ~~2012~~2013 primarily due to ~~less~~more favorable hydro conditions in ~~2013.~~2014. These resources provided approximately ~~15%~~18% of the Company’s retail load requirement during the ~~third quarter~~first quarters of ~~2013~~,2014 and 2013. Through March, total energy received from hydro resources approximated projected levels included in the AUT for 2014, compared with ~~16%~~ ~~during~~ the ~~third quarter~~same period of ~~2012. During the~~ ~~third quarter, total hydro generation exceeded~~2013, which fell below such projected levels included in the AUT for 2013 by 6%~~, compared with the~~ ~~third quarter~~ ~~of 2012 which exceeded such projected levels included in the AUT for 2012 by~~ ~~14%~~3%.

The following table presents the forecast of the April-to-September 2014 runoff (issued April 24, 2014), along with actual ~~April-to-September~~for 2013, ~~and 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

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through 2000):


	Actual Runoff as a Percent of Normal *				Runoff as a Percent of Normal *
Location	2013		2012		2014 Forecast		2013 Actual
Columbia River at The Dalles, Oregon	100	%	126	%	107	%	100	%
Mid-Columbia River at Grand Coulee, Washington	108		129		110		108
Clackamas River at Estacada, Oregon	102		133		91		102
Deschutes River at Moody, Oregon	98		118		97		98

* Volumetric water supply percentages 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.

Actual NVPC ~~increased~~consists of Purchased power and fuel expense net of Wholesale revenues and decreased approximately $4$9 million for the ~~third~~first quarter of ~~2013~~2014 compared with the ~~third~~first quarter of ~~2012, primarily~~2013. The decrease was due to a 9%3% decline in total system load and a 29% decrease in wholesale sales volume, partially offset by a 51% increase in the average ~~variable power cost, which is largely due to incremental replacement power costs incurred during the third quarter of 2013 related to unplanned plant outages.~~wholesale sales price. For the ~~third quarter~~first quarters of 2014 and 2013,, actual NVPC was $93 million ~~above baseline NVPC, compared with~~and $41 million, respectively, below baseline ~~NVPC for the~~ ~~third quarter~~ of ~~2012~~.NVPC.

Production and distribution expense increased $53 million, or ~~10%~~6%, in the ~~third~~first quarter of ~~2013~~2014 compared with the ~~third~~first quarter of ~~2012~~.2013. The increase is ~~primarily~~largely due to higher storm and service restoration costs and higher operating ~~and maintenance~~ costs as a result of the Company’s ownership percent of Boardman increasing to 80% from 65% on December 31, 2013. Partially offsetting the increases was a $3 million decrease due to a reserve recorded in the first quarter of 2013 related to the ~~distribution system, including increased repair and restoration work.~~

~~Administrative and other~~ ~~expense~~Company’s benchmark bid, which was not selected as a winning bid in the ~~third quarter~~ of ~~2013~~ ~~decreased~~ ~~$1 million, or~~ 2%~~, compared~~request for proposal for renewable resources pursuant to ~~the~~ ~~third quarter~~ of ~~2012~~, as the Company reduced its expense related to the reserve for uncollectible accounts by $1 million. A $2 million increase in employee pension expense resulting from a lower discount rate was largely offset by a decrease in employee incentive compensation expense.PGE’s most recent IRP.

Depreciation and amortization expense ~~decreased~~increased $113 million, or 2%21%, in the ~~third~~first quarter of ~~2013~~2014 compared with the ~~third~~first quarter of ~~2012, largely due to an increase in costs deferred~~2013, with $8 million related to timing of the deferral and amortization of costs of four capital projects as authorized in the Company’s 2011 General Rate ~~Case~~Case. In the first quarter of 2013, PGE deferred $4 million of costs related to these four projects and ~~a decrease~~ in the ~~asset retirement obligation resulting from~~first quarter of 2014, the ~~decommissioning~~Company recorded $4 million of amortization expense related to the ~~Bull Run hydro facility. The decrease was partially offset~~recovery of these costs (offset in Retail revenues). In addition, capital additions increased Depreciation and amortization expense by ~~a $2 million increase resulting from capital additions.~~$5 million.

Taxes other than income taxes expense increased $31 million, or ~~13%~~4%, primarily due to higher property taxes resulting from increased property values.

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Interest expense~~decreased~~ ~~$2 million, or~~ 7%, in the ~~third~~first quarter of ~~2013~~ ~~compared~~2014 was comparable with the first quarter of 2013. A $3 million increase related to an increase in the ~~third~~average balance of debt outstanding in the first quarter of ~~2012, due to~~2014 was largely offset by an increase in the allowance for borrowed funds used ~~for~~during construction ~~driven by~~resulting from a higher average CWIP balance ~~resulting from the commencement of~~driven by the construction of ~~Port Westward Unit 2,~~PW2, Carty ~~Generating Station~~ and Tucannon ~~River Wind Farm in 2013, as well as a decrease in interest expense driven by the timing of the maturities and issuances of long-term debt.~~River.

Other income, net increased $~~6 million~~ ~~in the~~ ~~third quarter~~ of ~~2013~~ ~~compared with the~~ ~~third quarter~~ of ~~2012, primarily due to higher earnings on the Non-qualified benefit plan trust assets, as well as an increase in the allowance for equity funds used for construction from the higher average CWIP balance.~~

~~Income tax expense~~ ~~was~~ ~~$4 million~~ ~~in the~~ ~~third quarter~~ of ~~2013~~ ~~compared with~~ ~~$19 million~~ ~~in the~~ ~~third quarter~~ of ~~2012~~. The decrease is primarily due to the decrease in the annual estimated pre-tax income for 2013 compared to 2012, which was driven by the charge to expense related to Cascade Crossing, combined with other unfavorable impacts to 2013 pre-tax income.

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~~Nine Months EndedSeptember 30, 2013~~ ~~Compared with the~~ ~~Nine Months EndedSeptember 30, 2012~~

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

Nine Months Ended September 30,
2013 2012
Revenues ⁽¹⁾ (dollars in millions):

Retail:
Residential $ 611
47 % $ 630
47 %
Commercial 461
35
476
36
Industrial 160
12
166
12
Subtotal 1,232
94
1,272
95
Other retail revenues, net (6 ) —
6
—
Total retail revenues 1,226
94
1,278
95
Wholesale revenues 59
4
38
3
Other operating revenues 26
2
26
2
Total revenues $ 1,311
100 % $ 1,342
100 %
Energy deliveries ⁽²⁾ (MWh in thousands):

Retail:
Residential 5,469
34 % 5,506
34 %
Commercial 5,540
34
5,566
34
Industrial 3,186
20
3,180
20
Total retail energy deliveries 14,195
88
14,252
88
Wholesale energy deliveries 1,892
12
1,861
12
Total energy deliveries 16,087
100 % 16,113
100 %
Average number of retail customers:
Residential 727,579
87 % 722,884
87 %
Commercial 104,436
13
103,798
13
Industrial 264
—
261
—
Total 832,279
100 % 826,943
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~~ ~~$31 million, or~~ 2%~~, for the~~ ~~nine months ended September 30, 2013~~ ~~compared with the~~ ~~nine months ended September 30, 2012~~ ~~as a result of the items described below.~~

~~Retail revenues~~ ~~decreased~~ ~~$52 million, or~~ 4%~~, in the~~ ~~nine months ended September 30, 2013~~ ~~compared with the~~ ~~nine months ended September 30, 2012, resulting primarily from the following items:~~

A $33 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;

A $9 million decrease related to an industrial customer refund for cumulative over-billings that occurred over a period of several years as a result of a meter configuration error. Management believes the customer billing error is not material to any past reporting period. The Company corrected this matter in the second quarter of 2013 through an out of period adjustment as a reduction to Other retail revenues, net in the table above;

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A $5 million decrease related to lower volumes of energy delivered driven in part by warmer temperatures during the heating season in 2013 compared with the comparable period of 2012 and by the extra day in 2012 due to the leap year. Residential energy deliveries were down 1%~~, while commercial and industrial deliveries were comparable to the same period of 2012; and~~

~~A $4 million decrease related to the Company’s PCAM, as the potential refund to customers related to the 2011 PCAM was reduced in the~~ ~~nine months ended September 30, 2012, with no estimated refund to or collection from customers recorded in the~~ ~~nine months ended September 30, 2013~~.

~~Total heating degree-days for the~~ ~~nine months ended September 30, 2013~~ ~~were~~ 5% ~~lower than the comparable period of~~ ~~2012~~ ~~and~~ 3% ~~below average, while cooling degree-days were~~ ~~24%~~ ~~higher than the comparable period of 2012 and~~ ~~19%~~ above average. The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

Heating Degree-days Cooling Degree-days
2013 2012 2013 2012
First quarter 1,902
1,967
—
—
Second quarter 593
709
82
40
Third quarter 90
58
457
395
Year-to-date 2,585
2,734
539
435
15-year average for the year-to-date 2,653
2,643
453
455

~~Wholesale revenues~~ ~~for the~~ ~~nine months ended September 30, 2013~~ ~~increased~~ ~~$21 million, or~~ ~~55%, from the~~ ~~nine months ended September 30, 2012, and consisted of $20 million related to a 51% increase in average wholesale price and $1 million related to a 2% increase in wholesale sales volume.~~

~~Table of Contents~~

~~Purchased power and fuel~~ ~~expense increased~~ ~~$5 million, or~~ 1%~~, for the~~ ~~nine months ended September 30, 2013~~ ~~compared with the~~ ~~nine months ended September 30, 2012. The increase largely consisted of~~ ~~$12 million~~ ~~related to a~~ 2% ~~increase in the average variable power cost, which is largely due to the unplanned plant outages, partially offset by~~ ~~$9 million~~ ~~related to a~~ 2% ~~decrease in total system load. During the third quarter of 2013, the Company incurred approximately $11 million of incremental replacement power costs related to the unplanned plant outages.~~

~~The average variable power cost increased to~~ ~~$34.18~~ ~~per MWh in the~~ ~~nine months ended September 30, 2013~~ ~~compared with~~ ~~$33.41~~ ~~per MWh in the~~ ~~nine months ended September 30, 2012~~, driven primarily by a 17% increase in the average price of purchased power combined with a decrease in energy received from hydro resources. The increase in average variable power cost was partially offset by a 22% decrease in the average cost of thermal generation, which resulted from a 24% decrease in the average cost of natural gas-fired generation and a 31% increase in the energy received from coal-fired generation.

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

Nine Months Ended September 30,
2013 2012
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal 2,985
19 % 2,280
14 %
Natural gas 2,300
15
1,993
13
Total thermal 5,285
34
4,273
27
Hydro 1,231
8
1,461
9
Wind 1,001
6
964
6
Total generation 7,517
48
6,698
42
Purchased power:

Term 4,821
30
6,042
38
Hydro 1,286
8
1,358
8
Wind 269
2
272
2
Spot 1,850
12
1,641
10
Total purchased power 8,226
52
9,313
58
Total system load 15,743
100 % 16,011
100 %
Less: wholesale sales (1,892 ) (1,861 )
Retail load requirement 13,851
14,150

~~Energy from PGE-owned wind generating resources (Biglow Canyon) increased~~ 4% ~~in the~~ ~~nine months ended September 30, 2013~~ ~~compared to the~~ ~~nine months ended September 30, 2012, and represented~~ 7% ~~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~~ ~~14%~~ ~~and~~ ~~17%~~ ~~in the~~ ~~nine months ended September 30,2013~~ ~~and~~ ~~2012, respectively.~~

~~Energy received from hydro resources during the~~ ~~nine months ended September 30, 2013, from both PGE-owned generating plants and purchased from mid-Columbia projects, decreased~~ ~~11%~~ ~~compared with the~~ ~~nine months ended September 30, 2012~~ ~~primarily due to less favorable hydro conditions in 2013. These resources provided approximately~~ ~~18%~~ ~~of the Company’s retail load requirement during the~~ ~~nine months ended September 30, 2013, compared with~~ ~~20%~~ ~~during the~~ ~~nine months ended September 30, 2012. Through September, total hydro generation exceeded projected levels included in the AUT for 2013 by~~ 2%~~, compared with the same period of 2012, which exceeded such projected levels included in the AUT for 2012 by~~ ~~12%~~.

~~Table of Contents~~

~~Actual NVPC~~ ~~decreased approximately $17 million for the~~ ~~nine months ended September 30, 2013~~ ~~compared with the~~ ~~nine months ended September 30, 2012, due to a 51% increase in average wholesale sales price and a 2% decrease in total system load, partially offset by a 2% increase in the average variable power cost. For the~~ ~~nine months ended September 30, 2013, actual NVPC was~~ ~~$5 million~~ ~~below baseline NVPC, compared with~~ ~~$14 million~~ ~~below baseline NVPC for the~~ ~~nine months ended September 30, 2012~~.

~~Production and distribution~~ ~~expense increased~~ ~~$16 million, or~~ ~~10%, in the~~ ~~nine months ended September 30, 2013~~ ~~compared with the~~ ~~nine months ended September 30, 2012~~. The increase is primarily due to $6 million related to planned overhaul and repair costs at Colstrip and Coyote Springs, $4 million of expense associated with the Company’s benchmark proposals that were not selected in the RFP process for new generation, $3 million related to increased delivery system repair and restoration work, and $2 million for the warranty extension for Biglow Canyon Phase III.

~~Cascade Crossing transmission project~~ ~~reflects $52 million of costs expensed in the second quarter of 2013, which were previously recorded as CWIP.~~

~~Administrative and other~~ ~~expense decreased~~ $2 million, or 1%67%, in the ~~nine months ended September 30, 2013~~ ~~compared to the~~ ~~nine months ended September 30, 2012, as a result~~first quarter of lower labor costs and a decrease in expense related to the reserve for uncollectible accounts. A $5 million increase in employee pension expense resulting from a lower discount rate was largely offset by decreases in employee incentive compensation and legal and consulting expenses.

~~Depreciation and amortization~~ ~~expense decreased~~ ~~$2 million, or~~ 1%~~, in the~~ ~~nine months ended September 30, 2013~~2014 compared with the ~~nine months ended September 30, 2012, largely due to the deferral~~first quarter of costs related to four capital projects as authorized in the Company’s 2011 General Rate Case, the decrease in the asset retirement obligation resulting from the decommissioning of the Bull Run hydro facility, as well as the deferral in 2012 of tax credits related to the Independent Spent Fuel Storage Installation located at the former Trojan nuclear power plant. The decrease was partially offset by a $3 million increase resulting from capital additions.

~~Taxes other than income taxes~~ ~~expense increased~~ ~~$2 million, or~~ 3%~~, primarily due to higher property taxes resulting from increased property values.~~

~~Interest expense~~ ~~decreased~~ ~~$7 million, or~~ 9%~~, in the~~ ~~nine months ended September 30,~~ 2013, ~~compared to the~~ ~~nine months ended September 30, 2012~~, primarily due to a decrease in the average balance of debt outstanding for 2013, as well as an increase in the allowance for borrowed funds used for construction driven by a higher average CWIP balance resulting from the commencement of the construction of Port Westward Unit 2, Carty Generating Station and Tucannon River wind farm in 2013.

~~Other income, net~~ ~~increased~~ ~~$7 million, or~~ ~~117%, in the~~ ~~nine months ended September 30, 2013~~ ~~compared with the~~ ~~nine months ended September 30, 2012~~, primarily due to an increase in the allowance for equity funds used ~~for~~during construction from the higher average CWIP balance, ~~as well as an increase~~partially offset by a decrease in earnings from the Non-qualified benefit plan trust assets.

Income tax expense ~~decreased~~increased $333 million in the ~~nine months ended September 30, 2013~~first quarter of 2014 compared with the ~~nine months ended September 30, 2012~~,first quarter of 2013, with effective tax rates of ~~14.9%~~25.6% and ~~27.7%~~26.2%, respectively. The increase in income tax expense and decrease in the effective tax rate isare primarily due to ~~a decrease~~an increase in ~~the~~ estimated annual pre-tax income for ~~2013~~2014 compared to ~~2012, which was driven~~2013 combined with a decrease in estimated annual production tax credits, partially offset by ~~the charge to expense~~a favorable income tax benefit in 2014 related to ~~Cascade Crossing, combined with other unfavorable impacts to 2013 pre-tax income.~~an increase in the allowance for equity funds used during construction.

~~Table of Contents~~

Liquidity and Capital Resources

Capital Requirements

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


	2013			2014		2015		2016		2017		2014			2015		2016		2017		2018
Ongoing capital expenditures ⁽¹⁾	$	310		$	325	$	280	$	265	$	240	$	330		$	290	$	290	$	250	$	240
Port Westward Unit 2	165			125		10		—		—		135			10		—		—		—
Tucannon River Wind Farm												390			15		—		—		—
Carty Generating Station	125			170		110		45		—		115			165		35		—		—
Tucannon River Wind Farm	110			375		15		—		—
Hydro licensing and construction ⁽²⁾	10			40		35		5		5		40			20		10		5		5
Total capital expenditures	$	720	⁽³⁾	$	1,035	$	450	$	315	$	245	$	1,010	⁽³⁾	$	500	$	335	$	255	$	245
Long-term debt maturities	$	100		$	—	$	70	$	67	$	58	$	—		$	70	$	67	$	58	$	75


(1)	Consists primarily of upgrades to, and replacement of, transmission, distribution, and generation infrastructure, as well as new customer connections.


(2)	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.


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

For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in this Item 2.

Port Westward Unit 2—PW2 is a 220 MW natural gas-fired plant that is currently under construction. PW2 will be located adjacent to the Company’s Port Westward and Beaver natural gas-fired generating plants near Clatskanie, Oregon at an estimated total cost of $300 million, excluding AFDC. Construction commenced in May 2013, with the plant expected to be online in the first quarter of 2015. As of March 31, 2014, $194 million, including AFDC, is included in CWIP for PW2.

Tucannon River Wind Farm—Tucannon River is a wind farm under construction with a nameplate capacity of 267 MW, consisting of 116 turbines each with a generating capacity of 2.3 MWs. Tucannon River will be located in southeastern Washington at an estimated cost of $500 million, excluding AFDC. Construction commenced in September 2013, with the wind farm expected to be online between December 2014 and March 31, 2015. As of March 31, 2014, $155 million, including AFDC, is included in CWIP for Tucannon River.

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Carty Generating Station—Carty is a 440 MW natural gas-fired power plant that is currently under construction. Carty will be located in Eastern Oregon, adjacent to Boardman, at an estimated total cost of $450 million, excluding AFDC. Construction commenced in January 2014, with the plant expected to be online in 2016. As of March 31, 2014, $160 million, including AFDC, is included in CWIP for Carty.

Liquidity

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

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


	Nine Months Ended September 30,						Three Months Ended March 31,
	2013			2012			2014			2013
Cash and cash equivalents, beginning of period	$	12		$	6		$	107		$	12
Net cash provided by (used in):
Operating activities	459			450			158			165
Investing activities	(491		)	(209		)	(179		)	(107		)
Financing activities	111			(91		)	(22		)	(37		)
Increase in cash and cash equivalents	79			150
(Decrease) increase in cash and cash equivalents							(43		)	21
Cash and cash equivalents, end of period	$	91		$	156		$	64		$	33

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, and pension and other postretirement benefit costs included in net income during a given ~~period, and increased~~period. The $97 million ~~for~~decrease in net cash flows from operating activities in the ~~nine months ended September 30, 2013~~first quarter of 2014 compared with the ~~nine months ended September 30, 2012. Such increase~~first quarter of 2013 was largely due to ~~the receipt of~~ ~~$44 million~~changes in ~~the third quarter of 2013 related~~PGE’s margin deposit requirements and accounts receivable and unbilled revenues balances, partially offset by an increase in Net income and cash received from Bonneville Power Administration to be returned to customers pursuant to the ~~settlement of a legal matter, offset by a 49% decrease in net income.~~Residential Exchange Program.

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Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that such charges in 2014will range from ~~$240~~$295 million to ~~$250 million in~~ ~~2013~~,$305 million. Combined with other sources, total cash expected to be provided by operations ~~anticipated~~is estimated to range from ~~$490~~$540 million to ~~$500~~$560 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 $~~282~~72 million increase in net cash used in investing activities in the ~~nine months ended September 30, 2013~~first quarter of 2014 compared with the ~~nine months ended September 30, 2012~~first quarter of 2013 was due ~~primarily~~ to a $~~235~~77 million increase in capital expenditures ~~largely due to~~driven by the construction of three new generation projects (PW2, ~~Carty~~Tucannon River and ~~Tucannon River)~~Carty), ~~and a~~ ~~$44~~partially offset by proceeds received of $4 million ~~contribution to the Nuclear decommissioning trust~~ in the ~~third~~first quarter of ~~2013.~~2014 for the sale of property.

The Company plans ~~a total of~~ approximately $~~720 million~~1 billion inof capital expenditures for 2014, which compares to 2013 capital expenditures of $656 million. PGE plans to fund the 2014 ~~related~~capital expenditures with cash expected to be generated

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from operations during 2014, as discussed above, as well as with issuances of debt securities. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the ~~construction~~Liquidity and Capital Resources section of ~~new generating facilities and upgrades and replacement of transmission, distribution, and generation infrastructure. See the Capital Requirements section above for additional information.~~this Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the ~~nine months ended September 30, 2013~~,first quarter of 2014, net cash ~~provided by~~used in such activities consisted of ~~net proceeds received from the issuance of common stock in the amount of~~ ~~$67 million~~ ~~and FMBs in the amount of~~ ~~$223 million, partially offset by the repayment of FMBs of~~ ~~$100 million~~ ~~and commercial paper of~~ ~~$17 million, and~~ the payment of dividends of $6222 million. During the ~~nine months ended September 30, 2012~~,first quarter of 2013, net cash used in financing activities consisted of the repayment of commercial paper ~~in the amount~~ of $3017 million and the payment of dividends of $6120 million.

Dividends on Common Stock

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

~~Common~~During the first quarter of 2014, the Board of Directors declared a quarterly common stock ~~dividends declared during 2013 consist~~dividend of $0.275 per common share for a total of $22 million, with payments made on April 15, 2014 to shareholders of record at the ~~following:~~

Dividends
Declared Per
Declaration Date Record Date Payment Date Common Share
February 20, 2013 March 25, 2013 April 15, 2013 $ 0.270

May 22, 2013 June 25, 2013 July 15, 2013 0.275

July 31, 2013 September 25, 2013 October 15, 2013 0.275

October 30, 2013 December 26, 2013 January 15, 2014 0.275

close of business on March 25, 2014.

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.

~~Table~~PGE expects to fund 2014 estimated capital requirements with cash from operations (which is expected to range from $540 million to $560 million) and a combination of ~~Contents~~proceeds from long-term loans and issuances of debt securities.

~~To help meet anticipated capital expenditure requirements and contractual maturities~~In mid-May 2014, PGE expects to enter into: i) an unsecured bank loan arrangement under which the Company would obtain long-term loans in an aggregate amount of ~~long-term debt~~approximately $305 million over the ~~next two years, PGE completed a public offering of its common stock~~subsequent 3-month period; and ~~entered into~~ii) a bond purchase ~~agreements~~agreement for ~~FMBs~~the issuance of approximately $280 million of First Mortgage Bonds (FMBs) with funds to be received in ~~June and October 2013.~~the second half of 2014. These ~~transactions were~~financing arrangements are subject to the Company obtaining OPUC-approval to increase its authority to issue long-term debt up to $700 million from $400 million. These financing arrangements are expected to be structured to allow for ~~funds generally to be provided to~~ the ~~Company~~receipt of funds in increments that generally align with the timing ~~and amount~~ of ~~capital expenditures and~~ the ~~contractual maturities~~Company’s cash needs.

PGE expects to issue the balance of ~~long-term debt.~~the equity securities available under the EFSA in the first half of 2015, with none expected in 2014.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $~~700~~900 million through February 6, ~~2014~~2016 and currently has the following unsecured revolving credit facilities:

A $400 million syndicated credit facility scheduled to terminate November ~~2017~~2018; and

A $300 million syndicated credit facility scheduled to terminate December ~~2016~~2017.

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These revolving credit facilities supplement operating cash flow and provide a primary source of liquidity. Pursuant to the terms of the agreements, the revolving credit facilities may be used for general corporate purposes, backup for commercial paper borrowings, and the issuance of standby letters of credit. ~~The Company also has two letter of credit facilities under which it may obtain letters of credit in an aggregate amount not to exceed $60 million.~~

As of ~~September 30, 2013~~March 31, 2014, PGE had no borrowings outstanding under the revolving credit facilities, no commercial paper outstanding, and ~~$56~~$15 million of letters of credit issued. As of ~~September 30, 2013~~March 31, 2014, the aggregate available capacity under the revolving credit facilities was $~~696~~685 million.

Additionally, the Company has two letters of credit facilities under which it may issue letters of credit in an aggregate amount not to exceed $60 million. As of March 31, 2014, the Company had $45 million of letters of credit issued, with an aggregate available capacity under the letters of credit facilities of $15 million.

Long-term Debt. ~~During the nine months ended September 30, 2013, PGE had the following long-term debt transactions:~~

~~In August, PGE repaid $50 million of 5.625% Series FMBs in accordance with the scheduled maturity and issued~~ ~~$75 million~~ of ~~4.47%~~ ~~Series FMBs due~~ ~~2043~~;

~~In June, the Company issued~~ ~~$150 million~~ of ~~4.47%~~ ~~Series FMBs due~~ ~~2044; and~~

~~In April, PGE repaid $50 million of 4.45% Series FMBs in accordance with the scheduled maturity.~~

As of ~~September 30, 2013~~March 31, 2014, total long-term debt outstanding was $~~1,761~~1,916 million., of which $70 million matures in January 2015 and is classified as current. In addition, PGE owns ~~$27~~$21 million of its Pollution Control Revenue Bonds, which may be remarketed at a later date, at the Company’s option.

~~In October 2013, PGE entered into a bond purchase agreement under which the Company agreed to sell to certain institutional buyers an aggregate principal amount of~~ ~~$155 million~~ ~~of FMBs in two tranches. PGE expects to issue~~ ~~$105 million~~ of ~~4.74%~~ ~~Series FMBs due~~ ~~2042~~ ~~and~~ ~~$50 million~~ of ~~4.84%~~ ~~Series FMBs due~~ ~~2048~~ ~~in November and December 2013, respectively. PGE does not expect to issue any additional long-term debt in 2013.~~

Equity. ~~On June 11, 2013,~~ PGE ~~entered into~~has an EFSA, ~~in connection with the public offering of 11,100,000 shares of its common stock, with an initial value of $317 million. Pursuant to the EFSA,~~whereby a forward counterparty borrowed 11,100,000 shares of ~~PGE’s~~the Company’s common stock from third parties and such borrowed shares were sold in a registered public ~~offering.~~offering in 2013. PGE receives proceeds from the sale of the common stock when the EFSA is physically settled. ~~Through September 30, 2013, the Company had the following equity transactions in connection with the offering:~~

On June 17, 2013, the underwriters exercised their over-allotment option in full and PGE issued 1,665,000 shares of common stock for proceeds of $47 million, net of an underwriters’ discount of $2 million; and

~~On August 21,~~In 2013, the Company issued 700,000 shares ~~of common stock for~~pursuant to the EFSA and received net proceeds of $20 ~~million, net of an underwriters’ discount of $1~~ million.

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As of ~~September 30, 2013,~~March 31, 2014, the Company could have physically settled the EFSA by delivering 10,400,000 shares of PGE common stock to the forward counterparty in exchange for cash of $~~291~~284 million. The Company anticipates physical settlement of the EFSA by delivery of newly issued shares on or before June 11, 2015. For additional information on the EFSA, see Note 6, Equity, in the Notes to the Condensed Consolidated Financial Statements. ~~PGE does not anticipate any additional issuances of equity through the remainder of 2013.~~

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 investment grade credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were ~~50.5%~~49.2% and ~~51.1%~~48.7% as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively.

Credit Ratings and Debt Covenants

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



	Moody’s	S&P
First Mortgage Bonds	A2A1	A-
Senior unsecured debt	~~Baa1~~A3	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

In June 2013, Moody’s upgraded their credit ratings on the Company’s First Mortgage Bonds to ‘A2’ from ‘A3’ and senior unsecured debt to ‘Baa1’ from ‘Baa2,’ with no changes to their rating on PGE’s commercial paper, and revised their outlook on PGE to ‘Stable’ from ‘Positive.’ The credit rating upgrades reflect a constructive regulatory environment with the timely recovery of prudently incurred costs, and a strong and stable financial profile with adequate liquidity to support a significant construction cycle. PGE is embarking on a significant capital plan for the construction of new natural gas-fired plants and a new wind farm, all of which are expected to be prudently financed and to provide rate base growth and enhanced cash flow over the near-term.

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale, commodity and related transmission 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 sheets, while any letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

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As of ~~September 30, 2013~~March 31, 2014, PGE had posted approximately $6224 million of collateral with these counterparties, consisting of $3617 million in cash and $267 million in letters of ~~credit,~~ ~~$6 million~~ ~~of which is affiliated with master netting agreements.~~credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of ~~September 30, 2013~~March 31, 2014, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade iswas approximately $8466 million and decreases to approximately $4333 million by December 31, ~~2013~~2014, and $2527 million by December 31, ~~2014.~~2015. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade iswas approximately $~~225~~167 million at ~~September 30, 2013~~March 31, 2014 and decreases to approximately $~~156~~102 million by December 31, ~~2013~~2014, and $9472 million by December 31, ~~2014.~~2015.

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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 FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the FMBs. PGE estimates that on ~~September 30, 2013~~March 31, 2014, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $~~189~~232 millionof additional FMBs. PGE ~~entered into a bond purchase agreement~~expects that its capacity to issue FMBs will increase when the impact of the $52 million expense related to the Cascade Crossing Transmission Project, recorded in ~~October~~June 2013, will no longer be included in this issuance test, which is expected when the Company files its Quarterly Report on Form 10-Q for the ~~issuance of $155 million in two tranches that are expected to be funded in November and December 2013. PGE does not expect to issue any additional long-term debt in 2013.~~quarterly period ending June 30, 2014. Any ~~issuance~~issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt ratio). As of ~~September 30, 2013~~March 31, 2014, the Company’s debt ratio, as calculated under the credit agreements, was ~~49.6%~~50.8%.

Off-Balance Sheet Arrangements

~~In June 2013,~~ PGE ~~entered into~~has an EFSA ~~in connection with a registered public offering of its common stock and a bond purchase agreement. The~~under which the Company may settle such agreement with the ~~EFSA with~~ issuance of PGE common stock, for cash or net share settlement from ~~time-to-time,~~time to time, in whole or part, through June 11, 2015. For additional information on the EFSA, see Note 6, Equity, in the Notes to the Condensed Consolidated Financial Statements. ~~In October 2013, the Company entered into a bond purchase agreement and agreed to sell, in two tranches, an aggregate principal amount of~~ ~~$155 million~~ ~~of FMBs to certain institutional buyers. The two tranches of~~ ~~$105 million~~ ~~and~~ ~~$50 million~~ ~~are expected to be issued in the fourth quarter of 2013.~~

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

Contractual Obligations

PGE’s contractual obligations for ~~2013~~2014 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~~2013, filed with the SEC on February ~~22, 2013~~14, 2014. Such obligations have not changed materially as of ~~September 30, 2013~~March 31, 2014~~, with the following exceptions:~~.

PGE entered into agreements for the construction of PW2, Carty and Tucannon River. As a result, capital and other purchase commitments increased by the following amounts: $148 million in 2013; $607 million in 2014; $88 million in 2015; and $29 million in 2016.

PGE issued $225 million of 4.47% Series FMBs, consisting of $150 million due 2044 and $75 million due 2043. As a result, future interest on long-term debt increased by the following amounts: $4 million for 2013; $10 million each year for 2014 through 2017; and $264 million thereafter through the 2044 maturity date referenced in the preceding sentence.



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

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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~~2013, filed with the SEC on February ~~22, 2013~~14, 2014.

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Item 4.	Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of ~~September 30, 2013~~March 31, 2014, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in PGE’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, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION



Item 1.	Legal Proceedings.

For further information regarding PGE’s legal proceedings, see “Legal ~~Proceedings~~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~~2013, filed with the SEC on February ~~22, 2013~~14, 2014 and Part II, Item 1 of the Company’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2013 and June 30, 2013, filed with the SEC on May 1, 2013 and August 2, 2013, respectively..

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, Marion

County Oregon Circuit Court, the Court of Appeals of the State of Oregon, and the Oregon Supreme Court.

On October 18, 2013, the Oregon Supreme Court ~~accepted~~granted plaintiffs’ petition seeking review of the February 6, 2013 Oregon Court of Appeals decision.Oral argument ~~is scheduled for~~occurred in March ~~4, 2014.~~2014 and the parties now await the Oregon Supreme Court’s decision.

Puget Sound Energy, Inc. v. All Jurisdictional Sellers of Energy and/or Capacity at Wholesale Into Electric Energy and/or Capacity Markets in the Pacific Northwest, Including Parties to the Western System Power Pool Agreement, Federal Energy Regulatory Commission and Ninth Circuit Court of Appeals (collectively, Pacific Northwest Refund proceeding).

~~Sierra Club~~In 2001, the FERC called for a hearing to explore whether there may have been unjust and ~~Montana Environmental Information Center v. PPL Montana LLC, Avista Corporation, Puget Sound Energy, Portland General Electric Company, Northwestern Corporation,~~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 ~~PacifiCorp, U.S. District~~purchased electricity in the Pacific Northwest. Although FERC’s original decision terminated the proceeding and denied the claims for refunds, upon appeal of this decision to the Ninth Circuit, the Court remanded the case to the FERC to, among other things, address market manipulation evidence and account for the ~~District~~evidence in any future orders regarding the award or denial of ~~Montana.~~refunds in the proceedings.

~~On July 30, 2012, PGE received a Notice of Intent~~In response to ~~Sue (Notice) for violations~~the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the ~~Clean Air Act (CAA) at Colstrip Steam Electric Station (Colstrip) from counsel on behalf~~hearing, and described the burden of proof that must be met to justify abrogation of the ~~Sierra Club~~contracts at issue and the ~~Montana Environmental Information Center (MEIC).~~imposition of refunds. The ~~Notice was also addressed~~orders held that the Mobile-Sierra public interest standard governs challenges to the ~~other Colstrip co-owners, including PPL Montana, LLC -~~bilateral contracts at issue in this proceeding, and 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, and stated~~strong presumption under Mobile-Sierra that the ~~Sierra Club~~rates charged under each contract are just and ~~MEIC would:~~reasonable would have to be specifically overcome either by: i) ~~request~~ a ~~United States District Court to impose injunctive relief and civil penalties; ii) require~~showing that 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.~~

~~The Sierra Club and MEIC asserted that the Colstrip owners~~respondent had violated ~~the Title V air quality operating permit during portions of 2008 and 2009~~a contract or tariff and that the ~~owners have violated~~violation had a direct connection to the ~~CAA by failing to timely submit~~rate charged under the applicable contract; or ii) a ~~complete air~~showing that the contract rate at issue imposed

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~~quality operating permit application to~~an excessive burden or seriously harmed the ~~Montana Department of Environmental Quality.~~public interest. The ~~Sierra Club and MEIC~~FERC also ~~asserted violations of opacity provisions of the CAA.~~

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. On May 3, 2013, the defendants filed a motion to dismiss 36 of the 39 claims in the suit. On September 27, 2013, the plaintiffs filed an amended complaint that deleted the Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of the hearing to allow parties to 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. 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. Refund claimants have filed petitions for appeal of these procedural orders with the Ninth Circuit.

Pursuant to a FERC-ordered settlement process, the Company received notice of two claims for refunds in the first phase of the remand proceeding and 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 as to ~~encompass approximately 40~~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 first phase of the remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional ~~projects. This~~claims related to this matter could be asserted against the Company in a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents.

During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of the California Energy Resource Scheduling division of the California Department of Water Resources (CERS), presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of CERS’ respondents, but did find evidence of unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts by the last remaining CERS respondent. The Administrative Law Judge scheduled a second phase of the hearing to commence after a final FERC decision on the Initial Decision. In the second phase, the last respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. If the FERC requires one or more respondents to make refunds, it is ~~scheduled for trial in October 2014.~~possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company.



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~~2013, filed with the SEC on February ~~22, 2013~~14, 2014.

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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.

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SIGNATURE

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



		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)


Date:	~~October 31, 2013~~April 28, 2014	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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General Rate Case*
Annual revenue requirement change
($ in millions)
Increase to annual revenues—Initial filing	$	105
Reduction resulting from non-power cost stipulation	(42		)
Increase resulting from update to load forecast (revenue)	15
Reduction resulting from power costs stipulation and updated power costs	(11		)
Increase to annual revenues—As revised	$	67



	Heating Degree-days		Cooling Degree-days
	2013	2012	2013	2012
July	2	14	168	115
August	3	3	203	201
September	85	41	86	79
Third quarter	90	58	457	395
15-year average for the year-to-date	82	81	385	387



			Dividends
			Declared Per
Declaration Date	Record Date	Payment Date	Common Share
February 20, 2013	March 25, 2013	April 15, 2013	$	0.270
May 22, 2013	June 25, 2013	July 15, 2013	0.275
July 31, 2013	September 25, 2013	October 15, 2013	0.275
October 30, 2013	December 26, 2013	January 15, 2014	0.275

Significant Unobservable Input

Change to Input

Impact on Fair Value Measurement

Market price

Increase (decrease)

Gain (loss)

Market price

Increase (decrease)

Loss (gain)