PORTLAND GENERAL ELECTRIC CO /OR/ - Quarter Report: 2012 June (Form 10-Q)

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 June 30, 2012



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

For the transition period from ____________________ to ____________________

Commission File Number: 1-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)



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

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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

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

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



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

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

Number of shares of common stock outstanding as of July 27, 2012 is 75,527,955 shares.

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PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

TABLE OF CONTENTS



Definitions		3

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Condensed Consolidated Statements of Income and Comprehensive Income	4

	Condensed Consolidated Balance Sheets	5

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	50

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 6.	Exhibits	51

SIGNATURE		52

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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:



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

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PART I — FINANCIAL INFORMATION



Item 1.	Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)



	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012		2011
Revenues, net	$	413		$	411	$	892	$	895
Operating expenses:
Purchased power and fuel	156			169		351		363
Production and distribution	51			55		104		97
Administrative and other	56			51		110		103
Depreciation and amortization	63			55		125		111
Taxes other than income taxes	26			24		53		49
Total operating expenses	352			354		743		723
Income from operations	61			57		149		172
Other income (expense):
Allowance for equity funds used during construction	2			1		3		2
Miscellaneous income (expense), net	(1		)	1		2		3
Other income, net	1			2		5		5
Interest expense	27			28		55		55
Income before income taxes	35			31		99		122
Income taxes	9			9		24		31
Net income and Net income attributable to Portland General Electric Company	$	26		$	22	$	75	$	91
Comprehensive income and Comprehensive income attributable to Portland General Electric Company	$	26		$	22	$	75	$	91

Weighted-average shares outstanding (in thousands):
Basic	75,507			75,326		75,465		75,322
Diluted	75,517			75,401		75,479		75,369

Earnings per share—basic and diluted	$	0.34		$	0.29	$	0.99	$	1.21
Dividends declared per common share	$	0.270		$	0.265	$	0.535	$	0.525

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)



	June 30, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	74	$	6
Accounts receivable, net	133		144
Unbilled revenues	70		101
Inventories	80		71
Margin deposits	69		80
Regulatory assets—current	197		216
Deferred income tax assets	39		33
Other current assets	66		65
Total current assets	728		716
Electric utility plant, net	4,317		4,285
Regulatory assets—noncurrent	528		594
Nuclear decommissioning trust	37		37
Non-qualified benefit plan trust	34		36
Other noncurrent assets	58		65
Total assets	$	5,702	$	5,733

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)



	June 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	66		$	111
Liabilities from price risk management activities—current	193			216
Short-term debt	—			30
Current portion of long-term debt	150			100
Accrued expenses and other current liabilities	157			157
Total current liabilities	566			614
Long-term debt, net of current portion	1,586			1,635
Regulatory liabilities—noncurrent	755			720
Deferred income taxes	573			529
Liabilities from price risk management activities—noncurrent	120			172
Unfunded status of pension and postretirement plans	199			195
Non-qualified benefit plan liabilities	102			101
Other noncurrent liabilities	100			101
Total liabilities	4,001			4,067
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2012 and December 31, 2011	—			—
Common stock, no par value, 160,000,000 shares authorized; 75,527,281 and 75,362,956 shares issued and outstanding as of June 30, 2012 and December 31, 2011, respectively	837			836
Accumulated other comprehensive loss	(6		)	(6		)
Retained earnings	867			833
Total Portland General Electric Company shareholders’ equity	1,698			1,663
Noncontrolling interests’ equity	3			3
Total equity	1,701			1,666
Total liabilities and equity	$	5,702		$	5,733

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	75		$	91
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	125			111
Decrease in net liabilities from price risk management activities	(64		)	(64		)
Regulatory deferral—price risk management activities	63			64
Deferred income taxes	43			33
Pension and other postretirement benefits	14			7
Regulatory deferral of settled derivative instruments	4			12
Power cost deferrals, net of amortization	4			12
Renewable adjustment clause deferrals	—			11
Allowance for equity funds used during construction	(3		)	(2		)
Other non-cash income and expenses, net	11			4
Changes in working capital:
Decrease in receivables	42			28
Decrease in margin deposits, net	11			16
Income tax refund received	8			8
Decrease in payables and accrued liabilities	(57		)	(16		)
Other working capital items, net	(8		)	(5		)
Contribution to pension plan	—			(26		)
Other, net	(1		)	(5		)
Net cash provided by operating activities	267			279
Cash flows from investing activities:
Capital expenditures	(137		)	(138		)
Proceeds from sale of solar power facility	10			—
Sales of nuclear decommissioning trust securities	13			29
Purchases of nuclear decommissioning trust securities	(13		)	(31		)
Other, net	(1		)	1
Net cash used in investing activities	(128		)	(139		)

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)



	Six Months Ended June 30,
	2012			2011
Cash flows from financing activities:
Payments on long-term debt	$	—		$	(10	)
Maturities of commercial paper, net	(30		)	(19		)
Dividends paid	(41		)	(39		)
Noncontrolling interests’ capital distributions	—			(4		)
Net cash used in financing activities	(71		)	(72		)
Increase in cash and cash equivalents	68			68
Cash and cash equivalents, beginning of period	6			4
Cash and cash equivalents, end of period	$	74		$	72

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	48		$	51
Cash paid for income taxes	—			3
Non-cash investing and financing activities:
Accrued capital additions	14			24
Increase to Boardman’s asset retirement obligation and cost basis of plant for updated depreciation study	—			23
Accrued dividends payable	21			21
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	—			7

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in order to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters are located in Portland, Oregon and its service area is located entirely within the state of Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of June 30, 2012, PGE served 828,494 retail customers with a service area population of approximately 1.7 million, comprising approximately 44% of the state’s population.

Condensed Consolidated Financial Statements

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

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

Use of Estimates

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

Reclassifications

To conform with the 2012 presentation, PGE has separately presented Deferred income tax assets from Other current assets, and reclassified Regulatory liabilities—current, of $6 million, to Accrued expenses and other current liabilities, in the condensed consolidated balance sheet as of December 31, 2011. In addition, PGE has separately presented Pension and other postretirement benefits of $7 million from Other non-cash income and expenses, net and reclassified Senate Bill 408 deferrals, net of $4 million to Other non-cash income and expenses, net in the

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

condensed consolidated statement of cash flows for the six months ended June 30, 2011.

Recent Accounting Pronouncement

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

NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

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

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



	Six Months Ended June 30,
	2012			2011
Balance as of beginning of period	$	6		$	5
Provision, net	4			3
Amounts written off, less recoveries	(4		)	(3		)
Balance as of end of period	$	6		$	5

Inventories

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

Electric Utility Plant, Net

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



	June 30, 2012			December 31, 2011
Electric utility plant	$	6,663		$	6,596
Construction work in progress	151			120
Total cost	6,814			6,716
Less: accumulated depreciation and amortization	(2,497		)	(2,431		)
Electric utility plant, net	$	4,317		$	4,285

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $164 million and $153 million as of June 30, 2012 and December 31, 2011, respectively. Amortization expense related to intangible assets was $6 million and $5 million for the three months ended June 30, 2012 and 2011, respectively, and $11 million and $9 million for the six months ended June 30, 2012 and 2011, respectively.

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

Regulatory Assets and Liabilities

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



	June 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Price risk management	$	185	$	119	$	194	$	172
Pension and other postretirement plans	—		285		—		295
Deferred income taxes	—		82		—		87
Deferred broker settlements	7		—		11		—
Debt reacquisition costs	—		25		—		28
Other	5		17		11		12
Total regulatory assets	$	197	$	528	$	216	$	594
Regulatory liabilities:
Asset retirement removal costs	$	—	$	664	$	—	$	637
Asset retirement obligations	—		38		—		36
Power cost adjustment mechanism	—		14		—		10
Other	4		39		6		37
Total regulatory liabilities	$	4	$	755	$	6	$	720

Accrued expenses and other current liabilities

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



	June 30, 2012		December 31, 2011
Accrued employee compensation and benefits	$	39	$	44
Accrued interest payable	24		24
Accrued dividends payable	21		21
Other	73		68
Total accrued expenses and other current liabilities	$	157	$	157

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Credit Facilities

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


•	A $370 million syndicated credit facility, of which $10 million terminated in July 2012 and $360 million is scheduled to terminate in July 2013; and


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

Pursuant to the individual terms of the agreements, both credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both credit facilities require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreements, to 65% of total capitalization. As of June 30, 2012, PGE was in compliance with this requirement with a 50.5% debt to total capital ratio.

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

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

PGE classifies borrowings and outstanding commercial paper under the revolving credit facility as Short-term debt on the condensed consolidated balance sheets. As of June 30, 2012, PGE had no borrowings or commercial paper outstanding, $115 million of letters of credit issued, and aggregate unused credit available of $555 million under the credit facilities.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Pension and Other Postretirement Benefits

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



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



	Six Months Ended June 30,
	Defined Benefit Pension Plan						Other Postretirement Benefits				Non-Qualified Benefit Plans
	2012			2011			2012		2011		2012		2011
Service cost	$	6		$	6		$	1	$	1	$	—	$	—
Interest cost	16			14			2		2		1		1
Expected return on plan assets	(20		)	(20		)	—		—		—		—
Amortization of net actuarial loss	8			4			—		—		—		—
Net periodic benefit cost	$	10		$	4		$	3	$	3	$	1	$	1

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 June 30, 2012 and December 31, 2011, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad 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 which are unobservable for the asset or liability.

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

PGE recognizes any transfers between levels in the fair value hierarchy as of the end of the reporting period. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

between levels, except those transfers out of Level 3 to Level 2 presented in this note, as of June 30, 2012 and December 31, 2011.

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 June 30, 2012
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	4		11		—		15
Corporate credit	—		8		—		8
Non-qualified benefit plan trust: ⁽²⁾
Equity Securities:
Domestic	5		2		—		7
International	1		—		—		1
Debt securities—Domestic government	2		—		—		2
Assets from price risk management activities: ^{(1) (3)}
Electricity	—		5		—		5
Natural gas	—		2		1		3
	$	12	$	42	$	1	$	55
Liabilities from price risk management activities: ^{(1) (3)}
Electricity	$	—	$	85	$	31	$	116
Natural gas	—		139		58		197
	$	—	$	224	$	89	$	313


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


(2)	Excludes insurance policies of $24 million, which are recorded at cash surrender value.


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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)



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


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


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


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

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

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

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

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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

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

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

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

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



			Range and Weighted Average Price per Unit
	Fair Value⁽¹⁾		Low		High		Weighted Average		Unit
Liabilities from price risk management activities:⁽²⁾	(in millions)
Electricity financial swaps	$	31	$	4.71	$	55.68	$	40.80	MWh
Natural gas financial swaps	58		3.01		4.69		3.81		Dth


(1)	Assets from price risk management activities related to commodity option contracts and natural gas financial swaps are considered immaterial for this disclosure.


(2)	The Company values its Level 3 liabilities from price risk management activities using a discounted cash flow technique in which long-term quoted forward prices are unobservable inputs.

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

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

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Balance as of the beginning of the period	$	95		$	116	$	79		$	120
Net realized and unrealized (gains) losses ⁽¹⁾	(7		)	10		11			8
Purchases	—			1		—			—
Issues	—			—		(1		)	—
Settlements	—			—		—			(1		)
Transfers out of Level 3 to Level 2	—			—		(1		)	—
Balance as of the end of the period	$	88		$	127	$	88		$	127


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

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

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of long-term debt is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of June 30, 2012, the estimated aggregate fair value of PGE’s long-term debt was $2,163 million, compared to its $1,736 million carrying amount. As of December 31, 2011, the estimated aggregate fair value of PGE’s long-term debt was $2,091 million, compared to its $1,735 million carrying amount.

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NOTE 4: PRICE RISK MANAGEMENT

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

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

PGE has elected to report gross on the balance sheet the positive and negative exposures resulting from derivative instruments. As of June 30, 2012 and December 31, 2011, the Company had $29 million and $26 million, respectively, in collateral posted with counterparties under an agreement that meets the definition of a master netting arrangement. This collateral consists entirely of letters of credit.

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



	June 30, 2012			December 31, 2011
Commodity contracts:
Electricity	11		MWh	13		MWh
Natural gas	74		Decatherms	79		Decatherms
Foreign currency	$	10	Canadian	$	6	Canadian

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



	June 30, 2012			December 31, 2011
Current assets:
Commodity contracts:
Electricity	$	5		$	2
Natural gas	2			17
Total current derivative assets	7		⁽¹⁾	19		⁽¹⁾
Noncurrent assets:
Commodity contracts—Natural gas	1		⁽²⁾	—
Total derivative assets not designated as hedging instruments	$	8		$	19
Total derivative assets	$	8		$	19
Current liabilities:
Commodity contracts:
Electricity	$	71		$	66
Natural gas	122			150
Total current derivative liabilities	193			216
Noncurrent liabilities:
Commodity contracts:
Electricity	45			71
Natural gas	75			101
Total noncurrent derivative liabilities	120			172
Total derivative liabilities not designated as hedging instruments	$	313		$	388
Total derivative liabilities	$	313		$	388


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


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

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011
Commodity contracts:
Electricity	$	(10	)	$	(1	)	$	43	$	31
Natural Gas	(11		)	17			25		11

Net unrealized losses and certain net realized (gains) losses presented in the table above are offset within the consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net (gains) losses recognized in Net income for the three months ended June 30, 2012 and 2011, net gains of $37 million and net losses of $10 million, respectively, have been offset, with net losses of $44 million and $35 million offset for the six months ended June 30, 2012 and 2011, respectively.

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



	2012		2013		2014		2015		Total
Commodity contracts:
Electricity	$	24	$	55	$	22	$	10	$	111
Natural gas	80		79		28		7		194
Net unrealized loss	$	104	$	134	$	50	$	17	$	305

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 June 30, 2012 was $256 million, for which PGE has posted $94 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2012, the cash requirement to either post as collateral or settle the instruments immediately would have been $250 million.

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



	June 30, 2012		December 31, 2011
Assets from price risk management activities:
Counterparty A	12	%	—	%
Counterparty B	12		7
Counterparty C	11		19
Counterparty D	11		6
Counterparty E	7		16
Counterparty F	2		13
	55	%	61	%
Liabilities from price risk management activities:
Counterparty B	22	%	23	%
Counterparty G	11		10
	33	%	33	%

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

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NOTE 5: EARNINGS PER SHARE

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	26	$	22	$	75	$	91
Denominator (in thousands):
Weighted-average common shares outstanding—basic	75,507		75,326		75,465		75,322
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	10		75		14		47
Weighted-average common shares outstanding—diluted	75,517		75,401		75,479		75,369

Earnings per share—basic and diluted	$	0.34	$	0.29	$	0.99	$	1.21

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

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

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NOTE 6: EQUITY

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



	Portland General Electric Company Shareholders’ Equity
				Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
	Common Stock
	Shares	Amount
Balances as of December 31, 2011	75,362,956	$	836	$	(6	)	$	833		$	3
Issuance of shares pursuant to equity-based plans	164,325	—		—			—			—
Stock-based compensation	—	1		—			—			—
Dividends declared	—	—		—			(41		)	—
Net income	—	—		—			75			—
Balances as of June 30, 2012	75,527,281	$	837	$	(6	)	$	867		$	3

Balances as of December 31, 2010	75,316,419	$	831	$	(5	)	$	766		$	7
Issuance of shares pursuant to equity-based plans	24,685	—		—			—			—
Stock-based compensation	—	1		—			—			—
Dividends declared	—	—		—			(39		)	—
Noncontrolling interests’ capital distributions	—	—		—			—			(4		)
Net income	—	—		—			91			—
Balances as of June 30, 2011	75,341,104	$	832	$	(5	)	$	818		$	3

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NOTE 7: CONTINGENCIES

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

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

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

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

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

Trojan Investment Recovery

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

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

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

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

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

In 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings until the OPUC responded to the 2002 Order (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment the Company collected in prices for the period from April 1, 1995 through October 1, 2000.

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

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

Pacific Northwest Refund Proceeding

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

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

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

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

In its October 2011 Order on Remand, the FERC held the hearing procedures in abeyance pending the results of settlement discussions, which it ordered be convened before a FERC settlement judge. Pursuant to the settlement proceedings, the Company has received notice of two claims and has reached agreements to settle both of these claims for a non-material amount. The first settlement was approved by the FERC on June 26, 2012, while the second settlement remains subject to FERC approval. There is still a possibility that additional claims could be asserted against the Company in the future.

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

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

EPA Investigation of Portland Harbor

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

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

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In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a cleanup remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is expected to issue by the end of 2014.

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

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

DEQ Investigation of Downtown Reach

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

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

EPA Investigation of Harbor Oil

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

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

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

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

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and comment period, the EPA is expected to issue a final Record of Decision in December 2012.

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

Alleged Violation of Environmental Regulations at Colstrip

On July 30, 2012, PGE received a Notice of Intent to Sue for violations of the Clean Air Act at Colstrip Steam Electric Station (Notice) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other Colstrip co-owners, including PPL Montana, LLC - the operator of Colstrip. PGE has a 20% ownership interest in Units 3 and 4 of Colstrip. The Notice alleges certain violations of the Clean Air Act, including New Source Review, Title V, and opacity requirements. The Notice states that the Sierra Club and MEIC will request a United States District Court to impose injunctive relief and civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution, and seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney's fees. PGE and the other co-owners are evaluating the allegations set forth in the Notice. PGE cannot at this time predict the outcome of this matter or determine whether it is reasonably possible that the claims, if asserted, would have a material effect on the Company.

Revenue Bonds

In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow. In connection with the repurchase, PGE paid the $5.8 million repurchase price to Lehman Brothers Inc. (Lehman) as remarketing agent for the Bonds, who in turn paid off the beneficial owner of the Bonds. As a result of the payment, PGE became the beneficial owner of the Bonds and requested that Lehman safe-keep the Bonds in Lehman’s Depository Trust Company participant account until such time as the Bonds could be remarketed. After repurchase of the Bonds, PGE removed the liability for the Bonds from its financial statements.

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

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

Other Matters

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 June 30, 2012, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 9: VARIABLE INTEREST ENTITIES

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

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

Included in PGE’s condensed consolidated balance sheet are LLC assets of $1 million of Cash and cash equivalents and $5 million of Electric utility plant, net as of June 30, 2012 and December 31, 2011. 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 operations, business prospects, expected changes in future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained in records and other data available from third parties, but there can be no assurance that PGE’s expectations, beliefs or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

•

governmental policies and regulatory audits, investigations and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;


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


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


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


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


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

•

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

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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;


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


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


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


•	the failure to complete capital projects on schedule and within budget;


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


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


•	the effects of climate change, including changes in the environment 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, information technology systems, or result in the release of confidential customer and proprietary information;


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


•	general political, economic, and financial market conditions;


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


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


•	acts of war or terrorism.

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

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Overview

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

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

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

Customers and Demand — Retail energy deliveries for the first half of 2012 decreased 1% from the comparable period of 2011 largely as a result of the impact of relatively warmer weather reducing residential customer demand in 2012. The decline was partially offset by an increase of approximately 3,800 in the average number of total retail customers served.

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



	Six Months Ended June 30,
	2012		2011		% Increase /(Decrease)in Energy Deliveries
	Average Number of Customers	Retail Energy Deliveries *	Average Number of Customers	Retail Energy Deliveries *	% Increase /(Decrease)in Energy Deliveries
Residential	722,542	3,880	719,724	4,006	(3.1	)%
Commercial	103,147	3,603	102,131	3,590	0.4
Industrial	261	2,084	256	2,067	0.8
Total	825,950	9,567	822,111	9,663	(1.0	)

____________________


*	In thousands of MWh.

On a weather adjusted basis, total retail energy deliveries for the six months ended June 30, 2012 were 0.7% higher than the corresponding period of 2011 and the Company expects that the increase in weather adjusted retail energy deliveries for the full year 2012 will approximate the year to date level, after allowing for energy efficiency and conservation efforts.

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

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unavailable to provide power. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period.

During the second quarters of 2012 and 2011, such annual maintenance was performed, with more extensive, planned service maintenance completed in 2011 compared to 2012. The work performed during 2011 included planned emissions control retrofits at Boardman and the replacement of the cooling tower structure and upgrading of the gas turbine and exhaust system components at Coyote Springs. Availability of the plants PGE operates approximated 91% and 88%, for the first half of 2012 and 2011, respectively, with the availability of Colstrip, which PGE does not operate, approximating 89% and 74%, for the same periods, respectively.

During the six months ended June 30, 2012, the Company’s generating plants provided approximately 44% of its retail load requirement, compared with 38% in the six months ended June 30, 2011. The increase in the relative volume of power generated to meet the Company’s retail load requirement was primarily due to the economic displacement of a greater amount of thermal generation by lower cost purchased power during the first half of 2011.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects decreased 29% in the first half of 2012 compared with the first half of 2011. These resources provided approximately 22% of the Company’s retail load requirement for the six months ended June 30, 2012, compared with 30% for the same period last year. Energy received from these sources exceeded projections included in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 11% during the first half of 2012, compared with 18% during the first half of 2011. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year and are based, in part, on average regional hydro conditions. Any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy from hydro resources is expected to be slightly above projections included in the AUT for 2012.

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

Pursuant to the Company’s power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC for the year, to the extent such difference is outside of a pre-determined “deadband.” The PCAM provides for 90% of actual NVPC above or below the deadband to be collected from or refunded to customers, respectively, subject to a regulated earnings test. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s statements of income; any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For 2012 and 2011, the deadband range is from $15 million below to $30 million above baseline NVPC.

For the six months ended June 30, 2012, actual NVPC was approximately $10 million below baseline NVPC due to strong power supply operations and improved hydro generation, partially offset by lower than expected wind generation. Based on forecast data, NVPC for the year ending December 31, 2012 is currently estimated to be below the baseline NVPC, and slightly below the established deadband range, however, no estimated refund to customers is expected for 2012 after application of the regulated earnings test. For the six months ended June 30, 2011, actual NVPC was approximately $29 million below baseline NVPC, and $14 million below the established deadband range, with PGE recording an estimated refund to customers of approximately $12 million as of June 30, 2011.

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Capital Requirements and Financing — PGE’s capital requirements for 2012 are related primarily to ongoing expenditures for the upgrade, replacement, and expansion of transmission, distribution, and generation infrastructure, as well as technology enhancements and expenditures related to hydro licensing and construction. Capital expenditures are expected to be approximately $323 million in 2012, of which $137 million was incurred through June 30, 2012. For further information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

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

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

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


•	300 to 500 MW of base load energy resources;


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


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


•	150 MW of winter-only peaking supply.

This RFP is currently open for bids, with winning bids expected to be chosen in late 2012 or early 2013. The flexible and peaking resources are expected to be available in the 2013 to 2015 time frame and the base load energy resources expected to be available in the 2015 to 2017 time frame.

A second RFP, which PGE plans to issue in the second half of 2012, would seek approximately 100 MWa of renewable resources. The renewable resources are anticipated to be in service to help meet PGE’s 2015 requirements under Oregon’s Renewable Portfolio Standard.

PGE expects to submit benchmark proposals in each competitive bidding process for new resources.

The IRP includes a proposal for an approximately 215-mile, 500 kV transmission line referred to as the Cascade Crossing Transmission Project, or Cascade Crossing, that would help meet future electricity demand and improve regional grid reliability. The project would transmit power from new and existing energy resources in northeastern Oregon to the Company’s service territory. PGE continues to work with other stakeholders in the region in planning the project and is actively engaged in the federal, state, and tribal permitting processes. Subject to obtaining all necessary approvals, the expected in-service date would be late 2016 or early 2017.

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

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


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


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


•	An investigation of environmental matters regarding Portland Harbor.

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

The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 or affected retail customer prices, as authorized by the OPUC. In some cases, the Company deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

•

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

•

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

The Company submitted an updated forecast of 2013 power costs to the OPUC in July 2012. The latest estimate, which will be updated and finalized in November 2012, shows that power costs are expected to be lower in 2013, with a corresponding decrease in customer prices of between one and two percent becoming effective on January 1, 2013. The resulting annual revenue requirement is expected to decrease by approximately $27 million from 2012 levels.

The Company has submitted its 2011 PCAM filing to the OPUC. The filing is subject to review, and the Company expects the OPUC to issue an order later in 2012. Any impact to customer prices would be effective January 1, 2013. For further information, see Power Operations, within the Operating Activities section of this Overview, above.


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

In March 2012, PGE submitted a filing for the installation of a small solar facility, which is expected to result in a small decrease to customer prices for a one-year period beginning January 1, 2013. No RAC filing was made in 2011.

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

•

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


•	For the six months ended June 30, 2012, the Company has recorded an estimated refund of $2 million. Any estimated refund or collection for the 2012 calendar year would be provided to customers beginning June 1, 2013.


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


•	For 2010, the Company recorded an estimated collection of $8 million, as weather adjusted use per customer was less than levels included in the 2009 General Rate Case. After review, the OPUC approved collections from customers over a one-year period that began June 1, 2011.


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

The overall impact to annual revenues, as a result of the tariff changes effective January 1, 2012, is expected to be a reduction of approximately $26 million.

Critical Accounting Policies

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

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Results of Operations

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2012					2011				2012				2011
Revenues, net	$	413		100	%	$	411	100	%	$	892	100	%	$	895	100	%
Purchased power and fuel	156			38		169		41		351		39		363		41
Gross margin	257			62		242		59		541		61		532		59
Operating expenses:
Production and distribution	51			12		55		13		104		12		97		11
Administrative and other	56			14		51		13		110		12		103		12
Depreciation and amortization	63			15		55		13		125		14		111		12
Taxes other than income taxes	26			6		24		6		53		6		49		5
Total operating expenses	196			47		185		45		392		44		360		40
Income from operations	61			15		57		14		149		17		172		19
Other income (expense):
Allowance for equity funds used during construction	2			—		1		—		3		—		2		—
Miscellaneous income (expense), net	(1		)	—		1		—		2		—		3		1
Other income, net	1			—		2		—		5		—		5		1
Interest expense	27			7		28		7		55		6		55		6
Income before income taxes	35			8		31		7		99		11		122		14
Income taxes	9			2		9		2		24		3		31		4
Net income and Net income attributable to Portland General Electric Company	$	26		6	%	$	22	5	%	$	75	8	%	$	91	10	%

Net income attributable to Portland General Electric Company was $26 million, or $0.34 per diluted share, for the second quarter of 2012 compared with $22 million, or $0.29 per diluted share, for the second quarter of 2011, an increase of $4 million, or 18%. The increase in net income was predominately due to the impact of favorable power supply operations, primarily driven by lower natural gas prices for the second quarter of 2012, when compared to the same period last year, as well as extensive, planned plant maintenance expense in the second quarter of 2011.

The items above were largely offset by decreased residential energy deliveries as a result of less favorable weather conditions during the second quarter of 2012, when compared with the same period last year; lower cost hydro and wind generation decreased 10% and 12% respectively for the second quarter of 2012, when compared with the same period last year.

Net income attributable to Portland General Electric Company was $75 million, or $0.99 per diluted share, for the first half of 2012 compared with $91 million, or $1.21 per diluted share, for the first half of 2011, a decrease of $16 million, or 18%. Net income for the first half of 2012, when compared with the first half of 2011, was predominately impacted by the following: a significant reduction in hydro generation; a higher percent of thermal generation which resulted in higher production and distribution costs; decreased energy deliveries, predominately due to warmer temperatures during the heating season; and increased pension expenses resulting from lower discount rates and returns on trust assets, partially offset by favorable power supply operations primarily driven by lower natural gas prices.

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

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



	Three Months Ended June 30,
	2012					2011
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	187		45	%	$	195		48	%
Commercial	152			37		151			37
Industrial	56			14		55			13
Subtotal	395			96		401			98
Other deferred revenues, net	(1		)	—		(11		)	(3	)
Total retail revenues	394			96		390			95
Wholesale revenues	9			2		12			3
Other operating revenues	10			2		9			2
Total revenues	$	413		100	%	$	411		100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	1,621			31	%	1,715			34	%
Commercial	1,764			34		1,759			34
Industrial	1,078			21		1,043			20
Total retail energy deliveries	4,463			86		4,517			88
Wholesale energy deliveries	702			14		591			12
Total energy deliveries	5,165			100	%	5,108			100	%
Average number of retail customers:
Residential	722,886			87	%	719,834			87	%
Commercial	103,623			13		103,245			13
Industrial	253			—		253			—
Total	826,762			100	%	823,332			100	%


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


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

Total revenues increased $2 million in the second quarter of 2012 compared with the second quarter of 2011 primarily as a result of the items described below.

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

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


•	An $8 million increase related to the PCAM, as an estimated refund was recorded in 2011 while no deferral has been recorded for 2012;


•	A $4 million increase as a result of credits provided to customers during 2011 related to the ISFSI that were not applicable in 2012; and


•	A $5 million increase resulting from several items, the largest of which amounted to just over $1 million, including the recovery of costs for the solar feed-in tariff, local taxes, and the decoupling mechanism; partially offset by


•	A $9 million decrease from a lower volume of energy sold as residential demand was down in 2012 due to the higher than normal load demand caused by weather in 2011, while a large industrial customer transitioned to direct access in 2012; and


•	A $5 million decrease related to changes in the average retail price, resulting primarily from tariff changes effective January 1, 2012 as authorized by the OPUC.

Heating and cooling degree-days are an indication of the likelihood that customers will use electricity for heating and cooling, respectively, and are used to measure the effects of weather on the demand for electricity. Total heating degree-days in the second quarter of 2012, while near historical averages, were 25% less than 2011 levels. Cooling degree-days were higher in the second quarter 2012 than in the second quarter of 2011, but remain below the 15-year averages. The following table indicates the number of heating degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:



	Heating Degree-days		Cooling Degree-days
	2012	2011	2012	2011
April	356	505	5	—
May	222	331	11	—
June	131	110	24	16
Second Quarter	709	946	40	16
15-year average for the second quarter	714	698	68	69

Wholesale revenues result from sales of electricity to utilities and power marketers in conjunction with the Company’s effort to secure reasonably priced power for retail customers, manage risk, and administer long-term wholesale contracts. Such sales can vary significantly period to period. Wholesale revenues in the second quarter of 2012 declined $3 million, or 25%, compared to the second quarter of 2011, consisting of $5 million related to a 34% decrease in average sales price, partially offset by $3 million related to a 19% increase in the volume of wholesale energy sold.

Purchased power and fuel expense was $156 million for the second quarter of 2012, a decrease of $13 million, or 8%, compared with $169 million for the second quarter of 2011, primarily due to an 8% decrease in average variable power cost. A 19% decrease in the average price of purchased power was partially offset by a reduction in both hydro and wind generation of 10% and 12%, respectively. The average variable power cost decreased to $30.53 per MWh in the second quarter of 2012 compared with $33.28 per MWh in the second quarter of 2011.

Thermal generation represented 5% of PGE’s total retail load requirement for the second quarter of 2012 compared with 10% in the second quarter of 2011. A significant amount of thermal generation was economically displaced during the second quarter of 2012 by lower-cost purchased power.

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



	Three Months Ended June 30,
	2012				2011
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	208		4	%	375		8	%
Natural gas	7		—		67		1
Total thermal	215		4		442		9
Hydro	547		11		609		12
Wind	377		7		429		8
Total generation	1,139		22		1,480		29
Purchased power:
Term	2,931		58		2,159		42
Hydro	522		10		921		18
Wind	103		2		35		1
Spot	398		8		495		10
Total purchased power	3,954		78		3,610		71
Total system load	5,093		100	%	5,090		100	%
Less: wholesale sales	(702	)			(591	)
Retail load requirement	4,391				4,499

Energy from PGE-owned wind generating resources (Biglow Canyon) decreased 12% and represented 9% of the Company’s retail load requirement in the second quarter of 2012, compared with 10% in the second quarter of 2011. The decrease was due to less favorable wind conditions in the second quarter of 2012 compared with the same period last year.

Hydroelectric energy received during the second quarter of 2012, from both PGE-owned plants and from mid-Columbia projects, decreased 30% compared with the second quarter of 2011 primarily due to more favorable hydro conditions in 2011, and the expiration at the end of 2011 of an agreement to purchase a portion of the output of one mid-Columbia project. These resources provided approximately 24% of the Company’s retail load requirement for the second quarter of 2012, compared with 34% for the second quarter of 2011. Total hydro generation in the second quarter of 2012 exceeded projected levels included in the AUT for 2012 by 16%, compared with 19% for the same period last year.

The following table presents the forecast of the April-to-September 2012 runoffs (issued July 27, 2012) at particular points of major rivers relevant to PGE’s hydro resources, and actual runoffs for 2011 (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):



	Runoff as a Percent of Normal *
Location	2012 Forecast		2011 Actual
Columbia River at The Dalles, Oregon	130	%	135	%
Mid-Columbia River at Grand Coulee, Washington	136		123
Clackamas River at Estacada, Oregon	133		135
Deschutes River at Moody, Oregon	115		120

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

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For the three months ended June 30, 2012, actual NVPC was approximately $5 million below baseline NVPC and within the lower deadband of the PCAM. For the three months ended June 30, 2011, actual NVPC was approximately $9 million below baseline NVPC, with PGE recording an estimated refund to customers of approximately $8 million.

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

Gross margin was 62% in the second quarter of 2012, compared with 59% in the second quarter of 2011. Higher margins for the second quarter of 2012 resulted from favorable power supply operations primarily driven by lower natural gas prices, lowering the net variable power cost when compared with the same period last year, as well as the impact of the ISFSI tax credits refunded to customers in 2011. Gross margin was negatively impacted by decreased residential energy deliveries in the second quarter of 2012 compared with the same period in 2011.

Production and distribution expense decreased $4 million, or 7%, in the second quarter of 2012 compared with the second quarter of 2011, primarily due to decreases in maintenance expenses at the Company’s thermal generating plants resulting from shorter and less extensive maintenance outages for 2012, partially offset by higher delivery system costs related to information technology upgrades.

Administrative and other expense increased $5 million, or 10%, in the second quarter of 2012 compared with the second quarter of 2011. The increase was primarily due to increased employee pension expenses resulting from a lower discount rate and return on pension trust assets.

Depreciation and amortization expense increased $8 million, or 15%, in the second quarter of 2012 compared with the second quarter of 2011. The increase was primarily due to the amortization of ISFSI tax credits in 2011 (offset in Revenues) and increased depreciation expense related to capital additions and a shorter operating life for the Boardman plant effective July 2011, partially offset by a deferral of costs related to certain capital projects as approved in the 2011 General Rate Case.

Taxes other than income taxes increased $2 million, or 8%, in the second quarter of 2012 compared with the second quarter of 2011, primarily due to higher property taxes, resulting from both increased property values and tax rates. Also contributing to the increase were higher franchise fees.

Income taxes for the second quarter of 2012 were comparable with the second quarter of 2011, with effective tax rates of 25.7% and 29.0% in the second quarters of 2012 and 2011, respectively. The effective tax rates differ from the statutory rate primarily due to federal wind production tax credits (PTC’s). The decrease in the effective tax rate reflects the application, on a prorata basis, of the forecasted PTC’s for the year, which resulted in an increased amount of PTC’s being recorded during the second quarter of 2012.

Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011

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



	Six Months Ended June 30,
	2012					2011
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	443		49	%	$	451		51	%
Commercial	308			35		307			34
Industrial	109			12		109			12
Subtotal	860			96		867			97
Other deferred revenues, net	(4		)	—		(14		)	(2	)
Total retail revenues	856			96		853			95
Wholesale revenues	19			2		25			3
Other operating revenues	17			2		17			2
Total revenues	$	892		100	%	$	895		100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	3,880			36	%	4,006			37	%
Commercial	3,603			34		3,590			34
Industrial	2,084			20		2,067			19
Total retail energy deliveries	9,567			90		9,663			90
Wholesale energy deliveries	1,090			10		1,068			10
Total energy deliveries	10,657			100	%	10,731			100	%
Average number of retail customers:
Residential	722,542			88	%	719,724			88	%
Commercial	103,147			12		102,131			12
Industrial	261			—		256			—
Total	825,950			100	%	822,111			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 $3 million, or less than 1% for the six months ended June 30, 2012 compared with the six months ended June 30, 2011 primarily as a result of the items described below.

Retail revenues increased $3 million in the first half of 2012 compared with the first half of 2011. The comparable amounts resulted primarily from the combination and net effect of the following items:


•	A $9 million increase related to the PCAM, as an estimated refund of $12 million was recorded in the first six months of 2011 compared to a $3 million additional refund adjustment recorded in 2012 related to the 2011 PCAM. No deferral has been recorded under the 2012 PCAM;


•	A $9 million increase as a result of credits provided to customers during 2011 related to the ISFSI that were not applicable in 2012; and

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•	A $7 million increase resulting from several items, the largest of which amounted to just over $2 million for the recovery of costs under the solar feed-in tariff; partially offset by


•	A $13 million decrease from a lower volume of energy sold as residential deliveries were down due to the higher than normal load demand caused by weather in 2011, while one large industrial customer transitioned to direct access in 2012; and


•	An $8 million decrease related to changes in the average retail price, resulting primarily from tariff changes effective January 1, 2012 as authorized by the OPUC.

Total heating degree-days in the first half of 2012 were 8% below those of the first half of 2011 and 4% above historical averages. Cooling degree-days were higher in the first half of 2012 than in the first half of 2011, but remain below the 15-year averages. The following table indicates the number of heating degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:



	Heating Degree-days		Cooling Degree-days
	2012	2011	2012	2011
First Quarter	1,967	1,974	—	—
Second Quarter	709	946	40	16
Year-to-date	2,676	2,920	40	16
15-year average for the year-to-date	2,562	2,543	68	69

Wholesale revenues in the first half of 2012 declined $6 million, or 24%, compared to the first half of 2011, primarily consisting of a 22% decrease in average sales price. Lower wholesale market prices were driven by low natural gas prices.

Purchased power and fuel expense was $351 million for the first half of 2012, a decrease of $12 million, or 3%, compared with $363 million for the first half of 2011, with $6 million related to a 2% decrease in average variable power cost, and an additional $6 million, or 2% decrease in total system load. The average variable power cost decreased to $33.04 per MWh in the first half of 2012 compared with $33.63 per MWh in the first half of 2011 due primarily to a decline in the average price of purchased power.

Thermal generation represented 25% of PGE’s total retail load requirement for the first half of 2012 compared with 19% in the first half of 2011. A significant amount of thermal generation was economically displaced during the first half of 2011 by lower cost purchased power due to increased energy from above normal hydro generation.

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



	Six Months Ended June 30,
	2012				2011
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	1,285		12	%	1,509		14	%
Natural gas	1,137		11		335		3
Total thermal	2,422		23		1,844		17
Hydro	1,130		10		1,180		11
Wind	623		6		645		6
Total generation	4,175		39		3,669		34
Purchased power:
Term	4,147		39		3,720		34
Hydro	936		9		1,723		16
Wind	177		2		108		1
Spot	1,181		11		1,583		15
Total purchased power	6,441		61		7,134		66
Total system load	10,616		100	%	10,803		100	%
Less: wholesale sales	(1,090	)			(1,068	)
Retail load requirement	9,526				9,735

Energy from PGE-owned wind generating resources (Biglow Canyon) decreased 3% compared with the first half of 2011, and represented 7% of the Company’s retail load requirement in both the first half of 2012 and 2011. The decrease in these resources was due to slightly less favorable wind conditions in the first half of 2012 compared with the same period last year.

Hydroelectric energy during the first half of 2012, from both PGE-owned plants and from mid-Columbia projects, decreased 29% compared with the first half of 2011 primarily due to more favorable hydro conditions in 2011, and the expiration at the end of 2011 of an agreement to purchase a portion of the output of one mid-Columbia project. These resources provided approximately 22% of the Company’s retail load requirement for the first half of 2012, compared with 30% for the first half of 2011. Total hydro generation in the first half of 2012 exceeded projected levels included in the AUT for 2012 by 11%, compared with 18% for the same period last year.

For the six months ended June 30, 2012, actual NVPC was approximately $10 million below baseline NVPC and within the lower deadband of the PCAM. For the six months ended June 30, 2011, actual NVPC was approximately $29 million below baseline NVPC, with PGE recording an estimated refund to customers of approximately $12 million.

Gross margin was 61% in the first half of 2012, compared with 59% in the first half of 2011. Higher margins for the first half of 2012 resulted from favorable power supply operations primarily driven by lower natural gas prices lowering the net variable power cost when compared with the same period last year, as well as the impact of the ISFSI tax credits refunded to customers in 2011. Gross margin was negatively impacted by decreased residential energy deliveries in the first half of 2012 compared with the same period in 2011.

Production and distribution expense increased $7 million, or 7%, in the first half of 2012 compared with the first half of 2011, primarily due to increases in delivery system costs related to information technology upgrades and a $3 million insurance recovery related to the Selective Water Withdrawal project recorded in 2011. Partially

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offsetting the above increase was a net decrease in operating and maintenance expenses at the Company’s thermal generating plants resulting from higher planned maintenance expenses in 2011 compared to 2012.

Administrative and other expense increased $7 million, or 7% in the first half of 2012 compared with the first half of 2011. The increase was primarily due to increased employee pension expenses resulting from a lower discount rate and return on pension trust assets.

Depreciation and amortization expense increased $14 million, or 13%, in the first half of 2012 compared with the first half of 2011. The increase was primarily due to the amortization of ISFSI tax credits in 2011 (offset in Revenues) and increased depreciation expense related to capital additions and a shorter operating life for the Boardman plant effective July 2011, partially offset by a deferral of costs related to certain capital projects as approved in the 2011 General Rate Case.

Taxes other than income taxes increased $4 million, or 8%, in the first half of 2012 compared with the first half of 2011, primarily due to higher property taxes, resulting from both increased property values and tax rates. Also contributing to the increase were higher franchise fees.

Income taxes decreased $7 million in the first half of 2012 compared with the first half of 2011 primarily due to a decrease in pre-tax income and the effective tax rate. The effective tax rates are 24.2% and 25.4% in the first half of 2012 and 2011, respectively. The reduction in the effective tax rate reflects the application, on a prorata basis, of the forecasted federal wind production tax credits for the year, applied against a lower pre-tax income amount in the current period.

Liquidity and Capital Resources

Capital Requirements

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



	2012			2013		2014		2015		2016
Ongoing capital expenditures	$	260		$	269	$	239	$	242	$	336
Hydro licensing and construction	25			13		29		32		16
Boardman emissions controls ⁽¹⁾	11			11		—		—		—
Cascade Crossing	27			4		—		—		—
Total capital expenditures	$	323	⁽²⁾	$	297	$	268	$	274	$	352
Long-term debt maturities	$	100		$	100	$	—	$	70	$	67

(1)

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


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

Ongoing capital expenditures — Capital spending requirements consist primarily of upgrades to, and replacement of, transmission, distribution, and generation infrastructure, as well as new customer connections. Preliminary engineering costs, which consist of expenditures for surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects, including certain projects discussed in the Integrated Resource Plan section below, are included in Ongoing capital expenditures. As of June 30, 2012 and December 31, 2011, preliminary engineering costs of $11 million and $10 million, respectively, are included in Other noncurrent assets in PGE’s condensed consolidated balance sheets. The Company expects that it will incur approximately $3 million for preliminary engineering on major projects during 2012.

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

Emissions controls — In June 2011, the EPA approved revised rules that established new emissions limits at Boardman and provide for coal-fired operation to cease no later than December 31, 2020. The emissions limits imposed under the revised rules require the addition of certain controls. PGE’s portion of capital spending on the Boardman emissions controls through June 30, 2012 was approximately $25 million, with the amount of anticipated future expenditures reflected in the table above.

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

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

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


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

•

The construction of the Cascade Crossing transmission line at an estimated total cost of $800 million to $1.0 billion. The Company continues to work with other stakeholders in planning the project and potential project partnerships. As of June 30, 2012, the Company has recorded $33 million in costs, primarily related to environmental assessments and permitting activities, included in Construction work in progress (CWIP), in Electric utility plant, net in its condensed consolidated balance sheets.

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

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

Liquidity

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

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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):



	Six Months Ended June 30,
	2012			2011
Cash and cash equivalents, beginning of period	$	6		$	4
Net cash provided by (used in):
Operating activities	267			279
Investing activities	(128		)	(139		)
Financing activities	(71		)	(72		)
Increase in cash and cash equivalents	68			68
Cash and cash equivalents, end of period	$	74		$	72

Cash Flows from Operating Activities - Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, such as depreciation and amortization and deferred income taxes, included in net income during a given period. The $12 million decrease in cash provided by operating activities for the first half of 2012 when compared with the first half of 2011 was due to a decrease in net income, after adding back non-cash operating items. The net decrease in cash provided by operating activities driven by changes in certain working capital items was offset by the impact of a $26 million contribution to the pension plan in the second quarter 2011.

A significant portion of cash provided by operations consists of the recovery in customer prices of non-cash charges for depreciation and amortization, which PGE estimates to be approximately $249 million in 2012, with total cash provided by operations estimated to be approximately $476 million.

Cash Flows from Investing Activities - Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities. The $11 million decrease in net cash used in investing activities in the six months ended June 30, 2012 compared with the six months ended June 30, 2011 was due primarily to proceeds from the sale of a solar power facility received in the first quarter of 2012.

The Company plans approximately $323 million of capital expenditures in 2012 related to upgrades and replacement of transmission, distribution, and generation infrastructure. See Capital Requirements section above for additional information.

Cash Flows from Financing Activities - Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the six months ended June 30, 2012, cash used in such activities consisted of the repayment of commercial paper of $30 million and the payment of dividends of $41 million. During the six months ended June 30, 2011, net cash used by financing activities consisted of the payment of dividends of $39 million, the repayment of commercial paper of $19 million, the repayment of long-term debt of $10 million, and capital distributions to noncontrolling interests of $4 million.

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Dividends on Common Stock

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

Common stock dividends declared during 2012 consist of the following:



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

Debt and Equity Financings

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

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


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


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

These credit facilities supplement operating cash flow and provide a primary source of liquidity. Pursuant to the terms of the agreements, the credit facilities may be used for general corporate purposes, as backup for commercial paper borrowings, and the issuance of standby letters of credit. As of June 30, 2012, PGE had no borrowings outstanding under the credit facilities, no commercial paper outstanding, and $115 million of letters of credit issued. As of June 30, 2012, the aggregate unused credit available under the credit facilities was $555 million.

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

Capital Structure. PGE’s financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company’s financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective, while sustaining sufficient cash flow, is necessary to maintain acceptable credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were 49.5% and 48.6% as of June 30, 2012 and December 31, 2011, respectively.

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Credit Ratings and Debt Covenants

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



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

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

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by certain of its wholesale, commodity and related transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. These cash deposits are classified as Margin deposits on PGE’s condensed consolidated balance sheet, while any letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

As of June 30, 2012, PGE had posted approximately $163 million of collateral with these counterparties, consisting of $69 million in cash and $94 million in letters of credit, $29 million of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of June 30, 2012, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $105 million and decreases to approximately $45 million by December 31, 2012, and $17 million by December 31, 2013. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $277 million at June 30, 2012 and decreases to approximately $150 million by December 31, 2012, and $66 million by December 31, 2013.

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

The issuance of First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimated that on June 30, 2012, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $571 million of additional First Mortgage Bonds. Any issuance of First Mortgage Bonds would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges or other dispositions of property.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt ratio). As of June 30, 2012, the Company’s debt ratio, as calculated under the credit agreements, was 50.5%.

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Off-Balance Sheet Arrangements

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

Contractual Obligations

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

Future pension contribution obligations outlined in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 were estimated using the funding level calculated with discount rates determined by the Internal Revenue Service (IRS) and the guidelines of the Pension Protection Act. On July 6, 2012 the President signed the “Moving Ahead for Progress in the 21^st Century Act.” The effect of this legislation on the Pension Protection Act was to increase the discount rate used in determining the funded status of the pension plan, increasing the plan’s overall funded status for 2013. IRS rules are not final, but PGE expects this legislation to reduce the pension contribution obligation for 2013.



Item 3.	Quantitative and Qualitative Disclosures About Market Risk.

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



Item 4.	Controls and Procedures.

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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PART II - OTHER INFORMATION



Item 1.	Legal Proceedings.

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



Item 1A.	Risk Factors.

There have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 24, 2012.



Item 6.	Exhibits.



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

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

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SIGNATURE

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



		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)


Date:	August 6, 2012	By:	/s/ Maria M. Pope
			Maria M. Pope
			Senior Vice President, Finance, Chief Financial Officer, and Treasurer
			(duly authorized officer and principal financial officer)