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 March 31, 2017

or

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

For the transition period from ____________________ to ____________________

Commission File Number: 001-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and registrant’s telephone number, including area code) 

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

[x] Yes x [ ] No

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

Large accelerated filer [x]	Accelerated filer [ ]
Non-accelerated filer [ ]	(Do not check if a smaller reporting company)
	Smaller reporting company [ ]
	Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standard provided pursuant to Section 13(a) of the Exchange Act. [ ]

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

Number of shares of common stock outstanding as of April 20, 2017 is 89,068,043shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED March 31, 2017

TABLE OF CONTENTS

Definitions		3
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	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	51
Item 4.	Controls and Procedures	51
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	52
Item 5.	Other Information	52
Item 6.	Exhibits	53
SIGNATURE		53

2

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
Boardman	Boardman coal-fired generating plant
Carty	Carty natural gas-fired generating plant
Colstrip	Colstrip Units 3 and 4 coal-fired generating plant
CWIP	Construction work-in-progress
EPA	United States Environmental Protection Agency
ESS	Electricity Service Supplier
FERC	Federal Energy Regulatory Commission
FMBs	First Mortgage Bonds
GAAP	Accounting principles generally accepted in the United States of America
GRC	General Rate Case
IRP	Integrated Resource Plan
Moody’s	Moody’s Investors Service
MW	Megawatts
MWa	Average megawatts
MWh	Megawatt hours
NVPC	Net Variable Power Costs
OCEP	Oregon Clean Electricity and Coal Transition Plan
OPUC	Public Utility Commission of Oregon
PCAM	Power Cost Adjustment Mechanism
RPS	Renewable Portfolio Standard
S&P	S&P Global Ratings
SEC	United States Securities and Exchange Commission
Trojan	Trojan nuclear power plant

3

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)

	Three Months Ended March 31,
	2017			2016
Revenues, net	$	530		$	487
Operating expenses:
Purchased power and fuel	141			149
Generation, transmission and distribution	81			66
Administrative and other	68			61
Depreciation and amortization	84			82
Taxes other than income taxes	33			30
Total operating expenses	407			388
Income from operations	123			99
Interest expense, net	30			27
Other income:
Allowance for equity funds used during construction	2			7
Miscellaneous income (expense), net	1			(1		)
Other income, net	3			6
Income before income tax expense	96			78
Income tax expense	23			17
Net income	$	73		$	61
Other comprehensive loss	(1		)	—
Comprehensive income	$	72		$	61
Weighted-average shares outstanding—basic and diluted (in thousands)	89,003			88,833
Earnings per share—basic and diluted	$	0.82		$	0.68
Dividends declared per common share	$	0.32		$	0.30
See accompanying notes to condensed consolidated financial statements.

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)

	March 31, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	31	$	6
Accounts receivable, net	162		155
Unbilled revenues	71		107
Inventories	77		82
Regulatory assets—current	57		36
Other current assets	87		77
Total current assets	485		463
Electric utility plant, net	6,466		6,434
Regulatory assets—noncurrent	532		498
Nuclear decommissioning trust	41		41
Non-qualified benefit plan trust	34		34
Other noncurrent assets	54		57
Total assets	$	7,612	$	7,527
See accompanying notes to condensed consolidated financial statements.

5

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)

	March 31, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	92		$	129
Liabilities from price risk management activities—current	59			44
Current portion of long-term debt	150			150
Accrued expenses and other current liabilities	247			254
Total current liabilities	548			577
Long-term debt, net of current portion	2,200			2,200
Regulatory liabilities—noncurrent	973			958
Deferred income taxes	682			669
Unfunded status of pension and postretirement plans	283			281
Liabilities from price risk management activities—noncurrent	156			125
Asset retirement obligations	164			161
Non-qualified benefit plan liabilities	106			105
Other noncurrent liabilities	113			107
Total liabilities	5,225			5,183
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2017 and December 31, 2016	—			—
Common stock, no par value, 160,000,000 shares authorized; 89,067,858 and 88,946,704 shares issued and outstanding as of March 31, 2017 and December 31, 2016, respectively	1,200			1,201
Accumulated other comprehensive loss	(8		)	(7		)
Retained earnings	1,195			1,150
Total equity	2,387			2,344
Total liabilities and equity	$	7,612		$	7,527
See accompanying notes to condensed consolidated financial statements.

6

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)                 

	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities:
Net income	$	73		$	61
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	84			82
Deferred income taxes	17			14
Pension and other postretirement benefits	6			7
Allowance for equity funds used during construction	(2		)	(7		)
Decoupling mechanism deferrals, net of amortization	(9		)	(4		)
Other non-cash income and expenses, net	7			8
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	29			46
Decrease in inventories	5			1
(Increase) in margin deposits, net	(12		)	(7		)
(Decrease) in accounts payable and accrued liabilities	(10		)	(11		)
Other working capital items, net	(13		)	(16		)
Other, net	(5		)	(13		)
Net cash provided by operating activities	170			161
Cash flows from investing activities:
Capital expenditures	(114		)	(131		)
Sales of Nuclear decommissioning trust securities	7			6
Purchases of Nuclear decommissioning trust securities	(5		)	(6		)
Other, net	(1		)	(2		)
Net cash used in investing activities	(113		)	(133		)
See accompanying notes to condensed consolidated financial statements.

7

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)

	Three Months Ended March 31,
	2017			2016
Cash flows from financing activities:
Proceeds from issuance of long-term debt	—			140
Payments on long-term debt	—			(133		)
Change in short-term debt	—			(6		)
Dividends paid	(28		)	(27		)
Other	(4		)	(2		)
Net cash used in financing activities	(32		)	(28		)
Increase in cash and cash equivalents	25			—
Cash and cash equivalents, beginning of period	6			4
Cash and cash equivalents, end of period	$	31		$	4
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	13		$	10
Cash paid for income taxes	—			—
See accompanying notes to condensed consolidated financial statements.

8

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, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area allocation, located entirely within the State of Oregon, encompasses 51 incorporated cities, of which Portland and Salem are the largest. As of March 31, 2017, PGE served approximately 865,000 retail customers with a service area population of approximately 1.9 million, comprising approximately 46% of the state’s population.

Condensed Consolidated Financial Statements

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

To conform with the 2017 presentation, PGE has reclassified Decoupling mechanism deferrals, net of amortization from Other non-cash income and expenses, net of $4 million within the operating activities section and reclassified both Payments on capital leases of $1 million and Debt issuance costs of $1 million to Other within the financing activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2016.

The financial information included herein for the three months ended March 31, 2017 and 2016 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 income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 2016 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2016, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 17, 2017, which should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income

PGE recorded a net $1 million loss in other comprehensive income for the three months ended March 31, 2017 due to the combination of changes in compensation retirement benefit liability and amortization, net of taxes of an immaterial amount, and other miscellaneous adjustments. No material change occurred in the three months ended March 31, 2016.

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 could differ materially from those estimates.

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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.

Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively (full retrospective method) or as a cumulative-effect adjustment as of the effective date (modified retrospective method), which is January 1, 2018 for calendar year-end public entities. The Company is evaluating which transition method it will elect. The Company does not anticipate any material changes to its revenue policy for tariff-based revenues, which comprises a majority of PGE’s retail revenues, as performance obligations are expected to be satisfied in a similar recognition pattern. PGE continues to evaluate the impacts the new guidance may have on its consolidated financial position, consolidated results of operations, and consolidated cash flows, particularly related to recognizing revenue for certain contracts where collectibility may be in question, certain matters of presentation of alternative revenue programs (such as decoupling), wholesale, and other operating revenue contracts.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting principles. Lessees will be required to classify leases as either finance leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019 and must be applied on a modified retrospective basis as of the beginning of the earliest comparative period presented. The new standard also provides reporting entities the option to elect a package of practical expedients for existing leases that commenced before the effective date. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-02.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15), with the intention to reduce diversity in practice, as well as simplify elements of classification within the statement of cash flows for certain transactions. The new ASU prescribes specific clarification guidance for the following eight classes of transactions: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance (COLI) policies, distributions received from equity method investments, beneficial interest in

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

securitization transactions, and separately identifiable cash flows and application of the predominance principal. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018 and requires application using a retrospective transition method. Early adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact to its presentation of consolidated cash flows.

In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). Pursuant to this ASU, only the service cost component of net periodic pension and postretirement benefit costs will be eligible for capitalization and should be applied on a prospective basis upon implementation. Also, the non-service components are required to be presented in the income statement separately from the service cost component and outside the subtotal of income from operations and should be applied on a retrospective basis upon implementation. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018. The Company does not plan to early adopt. The Company is in the process of evaluating the impact the guidance may have on its consolidated financial position and consolidated results of operations.

NOTE 2: BALANCE SHEET COMPONENTS

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil, for use in its generating plants. Periodically, the Company assesses inventory for purposes of determining that inventory is recorded at the lower of average cost or net realizable value.

Other Current Assets

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

	March 31, 2017		December 31, 2016
Prepaid expenses	$	58	$	48
Margin deposits	20		8
Assets from price risk management activities	9		18
Other	—		3
Other current assets	$	87	$	77

Electric Utility Plant, Net

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

	March 31, 2017			December 31, 2016
Electric utility plant	$	9,605		$	9,534
Construction work-in-progress	242			213
Total cost	9,847			9,747
Less: accumulated depreciation and amortization	(3,381		)	(3,313		)
Electric utility plant, net	$	6,466		$	6,434

11

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 $265 million and $257 million as of March 31, 2017 and December 31, 2016, respectively. Amortization expense related to intangible assets was $11 million for the three months ended March 31, 2017 and 2016. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Regulatory Assets and Liabilities

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

	March 31, 2017					December 31, 2016
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	50		$	154	$	26		$	120
Pension and other postretirement plans	—			232		—			235
Deferred income taxes	—			83		—			86
Debt issuance costs	—			21		—			22
Other	7			42		10			35
Total regulatory assets	$	57		$	532	$	36		$	498
Regulatory liabilities:
Asset retirement removal costs	$	—		$	898	$	—		$	887
Trojan decommissioning activities	12			—		18			—
Asset retirement obligations	—			50		—			49
Other	30			25		33			22
Total regulatory liabilities	$	42	*	$	973	$	51	*	$	958

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Accrued Expenses and Other Current Liabilities

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

	March 31, 2017		December 31, 2016
Regulatory liabilities—current	$	42	$	51
Accrued employee compensation and benefits	41		52
Accrued interest payable	40		25
Accrued dividends payable	30		30
Accrued taxes payable	34		25
Other	60		71
Total accrued expenses and other current liabilities	$	247	$	254

Credit Facilities

As of March 31, 2017, PGE had a $500 million revolving credit facility scheduled to expire in November 2020.

12

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to 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. The revolving credit facility contains a provision that allows for two, one-year extensions, subject to approval by the banks. During the first quarter of 2017, PGE exercised one of the two extensions available under the terms of the credit facility. Such action resulted in an updated expiration date for the agreement of November 2020. The facility also contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2017, PGE was in compliance with this covenant with a 50.6% 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 revolving credit facility.

PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.

Under the revolving credit facility, as of March 31, 2017, since PGE had no borrowings outstanding, and no commercial paper or letters of credit issued, the aggregate unused available credit capacity under the facility was $500 million.

In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide a total capacity of $160 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $56 million were outstanding as of March 31, 2017. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2018.

Long-term Debt

During the three months ended March 31, 2017, PGE did not enter into any new First Mortgage Bond (FMB) long-term debt transactions.

In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in an aggregate principal amount of up to $200 million by October 31, 2016. Under the agreement, PGE obtained the following term loans:

• $50 million on May 4, 2016;

• $75 million on June 15, 2016; and

• $25 million on October 31, 2016.

The term loan interest rates are set at the beginning of the interest period for periods of 1-month, 3-months, or 6-months, as selected by PGE, and are based on the London Interbank Offered Rate (LIBOR) plus 63 basis points, and was 1.6% as of March 31, 2017, with no other fees.

13

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults, and other customary defaults for financings of this type.

Defined Benefit Pension Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

	Three Months Ended March 31,
	2017			2016
Service cost	$	4		$	4
Interest cost	8			8
Expected return on plan assets	(10		)	(10		)
Amortization of net actuarial loss	3			4
Net periodic benefit cost	$	5		$	6

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 2017 and December 31, 2016, and then classifies these financial assets and liabilities based on a fair value hierarchy that is used to prioritize the inputs to the valuation techniques used to measure fair value. The three levels and application to the Company are discussed below.

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy, instead these assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels during the three month periods ended March 31, 2017 and 2016, except those presented in this note.

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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

	As of March 31, 2017
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	$	2	$	9	$	—	$	—	$	11
Corporate credit	—		8		—		—		8
Money market funds measured at NAV (2)	—		—		—		22		22
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Collective trust—domestic equity measured at NAV (2)	—		—		—		—		—
Assets from price risk management activities: (1) (4)
Electricity	—		3		2		—		5
Natural gas	—		6		—		—		6
	$	10	$	26	$	2	$	22	$	60
Liabilities from price risk management activities: (1) (4)
Electricity	$	—	$	16	$	133	$	—	$	149
Natural gas	—		53		13		—		66
	$	—	$	69	$	146	$	—	$	215

(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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3) Excludes insurance policies of $26 million, which are recorded at cash surrender value.

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

15

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

	As of December 31, 2016
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	$	2	$	10	$	—	$	—	$	12
Corporate credit	—		8		—		—		8
Money market funds measured at NAV (2)	—		—		—		21		21
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV(2)	—		—		—		—		—
Collective trust—domestic equity measured at NAV (2)	—		—		—		2		2
Assets from price risk management activities: (1) (4)
Electricity	—		6		1		—		7
Natural gas	—		15		1		—		16
	$	8	$	39	$	2	$	23	$	72
Liabilities from price risk management activities: (1) (4)
Electricity	$	—	$	6	$	112	$	—	$	118
Natural gas	—		42		9		—		51
	$	—	$	48	$	121	$	—	$	169

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

(2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3) Excludes insurance policies of $26 million, which are recorded at cash surrender value.

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

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan (NQ Plan) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:

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

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. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

The Nuclear decommissioning trust money market funds were valued at NAV as a practical expedient and not included in the fair value hierarchy. The NQ Plan money market funds are exchange traded government money market funds and are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE.

Common and collective trust funds—PGE invests in common and collective trust funds that invest in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) 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 forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures, and swaps.

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2017:
Electricity physical forwards	$	—	$	132	Discounted cash flow	Electricity forward price (per MWh)	$	5.45	$	44.76	$	31.58
Natural gas financial swaps	—		13		Discounted cash flow	Natural gas forward price (per Decatherm)	1.57		3.43		2.14
Electricity financial futures	2		1		Discounted cash flow	Electricity forward price (per MWh)	8.20		29.86		20.42
	$	2	$	146
As of December 31, 2016:
Electricity physical forwards	$	—	$	112	Discounted cash flow	Electricity forward price (per MWh)	$	14.25	$	54.73	$	38.18
Natural gas financial swaps	1		9		Discounted cash flow	Natural gas forward price (per Decatherm)	1.85		4.92		2.64
Electricity financial futures	1		—		Discounted cash flow	Electricity forward price (per MWh)	8.57		33.60		25.10
	$	2	$	121

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. For shorter term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

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

	Three Months Ended March 31,
	2017			2016
Balance as of the beginning of the period	$	119		119
Net realized and unrealized losses *	26			12
Transfers out of Level 3 to Level 2	(1		)	—
Balance as of the end of the period	$	144		$	131

* Both realized and unrealized losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the three month periods ended March 31, 2017 and 2016, 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 derivative instruments.

Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Revenue Bonds 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. The fair value of PGE’s unsecured term bank loans was classified as a Level 3 fair value measurement and was estimated based on the terms of the loans and PGE’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

As of March 31, 2017, the carrying amount of PGE’s long-term debt was $2,350 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,718 million, consisting of $2,568 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2016, the carrying amount of PGE’s long-term debt was $2,350 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.

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 purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from

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(Unaudited)

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 exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments may include forward, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the Public Utility Commission of Oregon (OPUC), the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes.

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

	March 31, 2017			December 31, 2016
Current assets:
Commodity contracts:
Electricity	$	3		$	6
Natural gas	6			12
Total current derivative assets	9		(1)	18		(1)
Noncurrent assets:
Commodity contracts:
Electricity	2			1
Natural gas	—			4
Total noncurrent derivative assets	2		(2)	5		(2)
Total derivative assets not designated as hedging instruments	$	11		$	23
Total derivative assets	$	11		$	23
Current liabilities:
Commodity contracts:
Electricity	$	24		$	12
Natural gas	35			32
Total current derivative liabilities	59			44
Noncurrent liabilities:
Commodity contracts:
Electricity	125			106
Natural gas	31			19
Total noncurrent derivative liabilities	156			125
Total derivative liabilities not designated as hedging instruments	$	215		$	169
Total derivative liabilities	$	215		$	169

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

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

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(Unaudited)

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 2035, were as follows (in millions):

	March 31, 2017			December 31, 2016
Commodity contracts:
Electricity	8		MWh	8		MWh
Natural gas	101		Decatherms	107		Decatherms
Foreign currency	$	32	Canadian	$	22	Canadian

PGE has elected to report gross on the condensed consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of March 31, 2017 and December 31, 2016, gross amounts included as Price risk management liabilities subject to master netting agreements were $136 million and $115 million, respectively, for which PGE posted collateral of $11 million as of March 31, 2017 and December 31, 2016, which consisted entirely of letters of credit. As of March 31, 2017, of the gross amounts recognized, $132 million was for electricity and $4 million was for natural gas compared to $112 million for electricity and $3 million for natural gas recognized as of December 31, 2016.

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

	Three Months Ended March 31,
	2017		2016
Commodity contracts:
Electricity	$	33	$	25
Natural Gas	34		17
Foreign currency exchange	—		(1		)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income by the effects of regulatory accounting. Of the net losses (gains) recognized in Net income for the three month periods ended March 31, 2017 and 2016, net losses of $61 million and $34 million have been offset, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2017 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2017		2018		2019		2020		2021		Thereafter		Total
Commodity contracts:
Electricity	$	19	$	7	$	8	$	8	$	8	$	94	$	144
Natural gas	28		19		10		3		—		—		60
Net unrealized loss	$	47	$	26	$	18	$	11	$	8	$	94	$	204

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(Unaudited)

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (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 derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2017 was $201 million, for which PGE has posted $16 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2017, the cash requirement to either post as collateral or settle the instruments immediately would have been $195 million. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheet.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:

	March 31, 2017		December 31, 2016
Assets from price risk management activities:
Counterparty A	43	%	22	%
Counterparty B	14		17
Counterparty C	7		12
	64	%	51	%
Liabilities from price risk management activities:
Counterparty D	61	%	66	%
	61	%	66	%

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

NOTE 5: EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three month period ended March 31, 2017, unvested performance-based restricted stock units and related dividend equivalent rights of approximately 274,000 were excluded from the dilutive calculation because the performance goals had not been met, with 304,000 excluded for the three month period ended March 31, 2016.

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(Unaudited)

Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended March 31,
	2017	2016
Weighted-average common shares outstanding—basic and diluted	89,003	88,833

NOTE 6: EQUITY

The activity in equity during the three months ended March 31, 2017 and 2016 is as follows (dollars in millions):

	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Shares	Amount									Total
Balances as of December 31, 2016	88,946,704	$	1,201		$	(7	)	$	1,150		$	2,344
Issuances of shares pursuant to equity-based plans	121,154	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(28		)	(28		)
Other comprehensive (loss)	—	—			(1		)	—			(1		)
Net income	—	—			—			73			73
Balances as of March 31, 2017	89,067,858	$	1,200		$	(8	)	$	1,195		$	2,387
Balances as of December 31, 2015	88,792,751	$	1,196		$	(8	)	$	1,070		$	2,258
Issuances of shares pursuant to equity-based plans	106,608	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(27		)	(27		)
Net income	—	—			—			61			61
Balances as of March 31, 2016	88,899,359	$	1,195		$	(8	)	$	1,104		$	2,291

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 condensed consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be

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(Unaudited)

determined, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons.

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

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

Carty

Background—The Company is involved in several litigation proceedings that involve claims concerning the Company’s termination of the construction agreement relating to the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon, and the payment obligations of two sureties who provided a performance bond in connection with such agreement. The Company is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the contractor and claims against the sureties pursuant to the performance bond. There are currently several lawsuits pending in U.S. District Court, as well as an arbitration proceeding before the International Chamber of Commerce (ICC). The Company is seeking to have all claims relating to this matter tried in U.S. District Court for the District of Oregon, but several procedural motions concerning jurisdiction remain pending as of the filing date of this report.

Arbitration Proceeding—In 2013, the Company entered into an agreement (Construction Agreement) with its engineering, procurement and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of Carty. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

On December 18, 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015.

On January 28, 2016, the Company received notice from the International Chamber of Commerce (ICC) International Court of Arbitration that Abengoa S.A. had submitted a request for arbitration. In the request, Abengoa S.A. alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to any liability of Abengoa S.A. under the terms of a guaranty in favor of PGE and pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the request for arbitration and on February 29, 2016

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(Unaudited)

filed a complaint and motion for preliminary injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration. In addition, the Contractor has been joined as a party to the arbitration and is seeking damages of approximately $117 million based on a claim that PGE wrongfully terminated the Construction Agreement. The Contractor is also seeking estimated damages of $44 million based on a claim that PGE failed to disclose to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals, certain information regarding union labor productivity rates in eastern Oregon, and that this failure caused the Contractor to submit a bid with a contract price that was lower than the contract price that would have been submitted had Contractor known such information. PGE disagrees with both of these claims.

Bankruptcy Proceedings - On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries, including the four entities that collectively comprise the Contractor, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the Company’s District Court action against Abengoa S.A. was stayed. In early October 2016, the bankruptcy court in the Chapter 11 proceeding granted the Company’s motion for relief from stay with respect to the four entities that collectively comprise the Contractor, which allows the Company to bring claims against such entities in the U.S. District Court.

U.S. District Court Proceedings against Sureties - On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties make the following assertions in support of their determination:

1. that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and

2. that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

The Company disagrees with the foregoing assertions and, on March 23, 2016, filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty.

On April 15, 2016, the Sureties filed a motion to stay this U.S. District Court proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE opposed the motion and filed a motion to enjoin the Sureties from pursuing, in the ICC arbitration proceeding, claims relating to the Performance Bond. On July 27, 2016, the court denied the Sureties’ motion to stay and granted PGE’s motion for a preliminary injunction. The Sureties appealed the rulings to the Ninth Circuit Court of Appeals. On December 13, 2016, the Ninth Circuit issued an order staying the district court proceeding, pending a decision on the Sureties’ appeal.Oral argument on the Sureties’ appeal is scheduled for May 8, 2017.

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(Unaudited)

U.S. District Court Proceedings against Contractor - On October 21, 2016, PGE filed a complaint in the U.S. District Court for the District of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from Abeinsa in excess of $200 million for: i) costs incurred to complete construction of Carty, settle claims with unpaid contractors and vendors and remove liens; and ii) damages in excess of the construction costs, including a project management fee, liquidated damages under the Construction Agreement, legal fees and costs, damages due to delay of the project, warranty costs, and interest. On March 21, 2017, the U.S. District Court for the District of Oregon entered an order staying the case for 120 days.

Recovery of Capital Costs in Excess of $514 million—Following termination of the Construction Agreement, PGE brought on new contractors and resumed construction. Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, based on the approved cost of $514 million. Actual costs for Carty have exceeded the $514 millionapproved for inclusion in customer prices by the OPUC. As of March 31, 2017, PGE has capitalized $636 million for Carty classified as Electric utility plant. The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials. Costs also increased as a result of PGE’s discovery through the construction process of latent defects in work performed by the former Contractor and the corresponding labor and materials required to correct the work. Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage resulting from poor storage and maintenance on the part of the former Contractor.

PGE estimates the total cost of Carty will be approximately $640 million. This cost estimate does not reflect any offsetting amounts that may be received from the Sureties pursuant to the Performance Bond. This estimate also excludes approximately $14 million of lien claims filed against PGE for goods and services provided under contracts with the former Contractor. The Company believes these liens are invalid and is contesting the claims in the courts.

In the event the total project costs incurred by PGE, net of offsetting amounts that may be received from the Sureties, Abengoa S.A., or the Contractor, ultimately exceed the $514 million amount approved by the OPUC for inclusion in customer prices, the Company intends to seek approval to recover the excess amounts in customer prices in a subsequent rate proceeding after exhausting all remedies against the aforementioned parties. However, there is no assurance that such recovery would be allowed by the OPUC. In accordance with GAAP and the Company’s accounting policies, any such excess costs would be charged to expense at the time disallowance of recovery becomes probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood that a portion of the cost of Carty will be disallowed for recovery in customer prices is less than probable. Accordingly, no loss has been recorded to date related to the project.

As actual project costs for Carty exceed $514 million, the Company is incurring a higher cost than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation and interest expense. On July 29, 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent General Rate Case (GRC) proceeding. The Company has requested that the OPUC delay its review of this deferral request until the Company’s claims against the Sureties have been resolved. Until such time, the effects of this higher cost are recognized in the Company’s results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. Any amounts approved by the OPUC for recovery under the deferral filing will be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC. The

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Company believes that costs incurred to date and capitalized in Electric utility plant, net in the consolidated balance sheet were prudently incurred. There has been no settlement discussions with regulators related to such costs.

EPA Investigation of Portland Harbor

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

The Portland Harbor site remedial investigation (RI) has been completed 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. The LWG has funded the RI and feasibility study (FS) and has stated that it has incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

The EPA has finalized the FS, along with the RI, and these documents provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued on January 6, 2017. The ROD outlines the EPA’s selected remediation alternative to clean-up for Portland Harbor which has an estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.05 billion. As stated within the ROD, such cost ranges were estimated with an accuracy between -30% and +50% of actual costs. Remediation construction costs are estimated to be incurred over a 13 year period, with long-term operation and maintenance costs estimated to be incurred over a 30 year period from the start of construction. The Company anticipates that prior to the commencement of remediation activities, a phase of resampling of the river will be necessary to better refine the remedial design and may impact estimated costs.

PGE is participating in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including a final allocation methodology and data with regard to property specific activities and history of ownership of sites within Portland Harbor. Based on the above facts and remaining uncertainties, PGE cannot reasonably estimate its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor.

Where injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor Natural Resource Damages assessment (NRDA) process. The EPA does not manage NRDA activities, but provides claims information and coordination support to the Natural Resource Damages (NRD) trustees. Damage assessment activities are typically conducted by a Trustee Council made up of the trustee entities for the site. The Portland Harbor NRD trustees are the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, and certain tribal entities.

The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

the trustees for costs incurred in assessing the damages. The NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. PGE believes that the Company’s portion of NRDA liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

As discussed above, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of the Portland Harbor site, although such costs could be material. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

In July 2016, the Company filed a deferral application with the OPUC seeking the deferral of the future environmental remediation costs, as well as, seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, which the OPUC approved in the first quarter of 2017. The mechanism will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test.

Trojan Investment Recovery Class Actions

In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.

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

In August 2006, the OSC issued a ruling ordering the abatement of the class action proceedings. The Oregon Supreme Court (OSC) concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.

The OSC further stated that if the OPUC determined that it could provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The OSC added that, if the OPUC determined that it could not provide a remedy, the court system may have a role to play. The OSC also ruled that the plaintiffs retained the right to return to the Circuit Court for disposition of whatever issues remained unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds of $33 million, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in February 2013 and by the OSC in October 2014.

In June 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. Following oral argument on PGE’s motion for Summary Judgment, the plaintiffs moved to amend the complaints. On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the complaint and on March 16, 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon.

PGE believes that the October 2, 2014 OSC decision and the recent Circuit Court decisions have reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain subject to a decision in the appeal, management believes that it is reasonably possible that a loss in excess of amounts previously recorded could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.

Deschutes River Alliance Clean Water Act Claims

On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company in the U.S. District Court of the District of Oregon. DRA’s claims seek injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleges the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project. The SWW, located above Round Butte Dam, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010 as part of the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat below the Project and harmed the economic and personal interests of DRA’s members and supporters.

On September 30, 2016, PGE filed a motion to dismiss, which asserted that the CWA does not allow citizen suits of this nature, and that FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 6, 2017, PGE filed a motion for certification to file an interlocutory appeal with the U.S. Ninth Circuit Court of Appeals and for a stay of the District Court proceeding. A court decision on that motion has not yet been issued. On April 7, 2017, the court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes) to appear in the case as Amicus Curiae (friend of the court). The Tribes share ownership of the Project with PGE, but have not been named as a defendant.

The Company cannot predict the outcome of this matter, but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because i) this matter involves novel issues of law and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time, determine the likelihood of whether the outcome of this matter will result in a material loss.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Other Matters

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

NOTE 8: GUARANTEES

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of March 31, 2017, 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.

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

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future results of operations, business prospects, future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs, and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or 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 the 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 the Condensed Consolidated Financial Statements;

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

• operational factors affecting PGE’s power generating facilities, including forced outages, hydro, and wind conditions, and disruptions of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;

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

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

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

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

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

• changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;

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• 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;

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

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

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

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

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

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

• political and economic conditions;

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

• changes in 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 or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. This 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, 2016, and other periodic and current reports filed with the SEC.

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 in order to meet the needs of its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

The Company submitted its 2016 Integrated Resource Plan (IRP), which addresses anticipated resource needs over the next 20 years. The areas of focus for the plan, filed with the OPUC in the fourth quarter of 2016, include, among other topics, additional resources needed to meet Oregon’s Renewable Portfolio Standard (RPS) requirements and to replace energy from Boardman, the Company’s coal-fired generating plant located in Eastern Oregon, that will cease coal-fired operations at the end of 2020. Recent updates to the IRP request have reduced the future capacity

31

need to approximately 565 MW. For further information regarding the IRP, see “Integrated Resource Plan” in this Overview section of Item 2.

In February 2017, PGE filed a general rate case for a 2018 test year. Regulatory review is expected to occur throughout 2017, with new customer prices effective January 1, 2018. For further information, see “General Rate Case” in this Overview section of Item 2.

PGE continues to pursue a number of regulatory and legal matters that resulted from the construction of Carty, which was placed into service in July 2016. As the Company incurred costs to complete the project beyond what the OPUC authorized for recovery, PGE has claims pending with the construction contractor and with companies that provided performance bonds, as well as regulatory requests pending to recover the excess costs. For further information regarding Carty, see “Power Operations” within the Operating Activities portion of this Overview section of Item 2.

The discussion that follows in this MD&A provides additional information related to the Company’s operating activities, legal, regulatory, and environmental matters, results of operations, and liquidity and financing activities.

Capital Requirements and Financing—In total, the Company’s 2017 capital expenditures are expected to approximate $585 million, excluding AFDC. For additional information regarding estimated capital expenditures, see “Capital Requirements” in the Liquidity and Capital Resources section of this Item 2.

PGE plans to fund the 2017 capital requirements and current maturities of long-term debt of $150 million with cash from operations during 2017, which is expected to range from $425 million to $475 million, and the issuance of debt securities of approximately $450 million. For additional information, see “Liquidity” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 2.

General Rate Case—On February 28, 2017, the Company filed with the OPUC a general rate case based on a 2018 test year (2018 GRC). The filing includes investments to ensure system safety and reliability and to better meet customers’ changing needs and service expectations. The 2018 GRC requests a $100 million increase in the annual revenue requirement related primarily to an increase in base business costs for upgrades to PGE's transmission and distribution system, investments in strengthening and safeguarding the grid, and support for key initiatives such as participation in the western Energy Imbalance Market.

The requested net increase in annual revenue requirement, representing an approximate 5.6% overall increase in customer prices, is based upon:

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

• A return on equity of 9.75%; and

• A rate base of $4.6 billion.

Regulatory review of the 2018 GRC will continue throughout 2017, with a final order targeted to be issued by the OPUC by December 2017 and new customer prices expected to become effective January 1, 2018.

The 2018 GRC filing (OPUC Docket UE 319), as well as copies of direct testimony and exhibits, are available on the OPUC Internet website at www.oregon.gov/puc.

Operating Activities—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 typically experiences its

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highest average MWh deliveries and retail energy sales during the winter heating season, although deliveries also increase during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

Customers and Demand—The 6.2% increase in retail energy deliveries for the three months ended March 31,2017 compared with the three months ended March 31,2016 resulted predominantly from an increase in residential energy deliveries, although energy deliveries to industrial customers also increased.

Energy deliveries to residential customers increased 13.3%, due in large part to the effects of cooler temperatures as well as residential customer growth of 1.2%. Energy deliveries to industrial customers increased 2.8%, largely due to continued strength in the high tech sector. Weather adjusted deliveries were down 3.9% from the first quarter 2016 reflecting the impact of an extra day in 2016 due to leap year, a continued long-term decline in residential use per customer, and lower commercial deliveries resulting in part from the impact to commercial activity due to the snow events in the first quarter of 2017. Energy efficiency and conservation efforts by retail customers also influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See “Legal, Regulatory and Environmental” in this Overview section of Item 2 for further information on the decoupling mechanism.

During the first quarter of 2017, heating degree-days, an indication of the extent to which customers are likely to have used electricity for heating, were 16% above average and 37% above the first quarter of 2016. Residential energy deliveries, which are most weather sensitive, were higher in the first quarter 2017 than the first quarter of 2016, as a combined result of the historically warm weather in early 2016 and cold weather in the first quarter of 2017. See “Revenues” in the Results of Operations section of this Item 2 for further information on heating degree days.

The following table, which includes deliveries to the Company’s direct access customers who purchase their energy from Electricity Service Suppliers (ESSs), presents the average number of retail customers by customer type, and the corresponding energy deliveries, for the periods indicated:

	Three Months Ended March 31,
	2017		2016		% Increase (Decrease)in Energy Deliveries
	Average Number of Customers	Retail Energy Deliveries*	Average Number of Customers	Retail Energy Deliveries*
Residential	758,087	2,383	749,287	2,103	13.3	%
Commercial (PGE sales only)	105,566	1,687	104,872	1,702	(0.9	)%
Direct access	415	143	319	129	10.9	%
Total Commercial	105,981	1,830	105,191	1,831	(0.1	)%
Industrial (PGE sales only)	198	686	187	697	(1.6	)%
Direct access	65	321	63	283	13.4	%
Total Industrial	263	1,007	250	980	2.8	%
Total (PGE sales only)	863,851	4,756	854,346	4,502	5.6	%
Total Direct access	480	464	382	412	12.6	%
Total	864,331	5,220	854,728	4,914	6.2	%

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 * In thousands of MWh.

Power Operations—To meet the energy needs of its retail customers, the Company utilizes a combination of its own generating resources and power purchases in the wholesale market. In an effort to obtain reasonably-priced power for its retail customers, PGE makes economic dispatch decisions based on numerous factors including plant availability, customer demand, river flows, wind conditions, and current wholesale prices.

PGE’s generating plants require varying levels of annual maintenance, during which the respective plants are unavailable to provide power. As a result, the amount of power generated to meet the Company’s retail load requirement can vary from period to period. Plant availability, which is affected by both planned and unplanned outages, approximated 95% and 93% during the three months ended March 31,2017 and 2016, respectively, for those plants PGE operates. Plant availability of Colstrip Units 3 and 4, of which the Company has a 20% ownership interest, approximated 89% and 96% during the three months ended March 31,2017 and 2016, respectively.

During the three months ended March 31,2017, the Company’s generating plants provided approximately 60% of its retail load requirement compared with 56% in the three months ended March 31,2016. The increase in the proportion of power generated to meet the Company’s retail load requirement was largely the result of increased production from the Company’s thermal generation facilities, including the addition of Carty, during 2017 relative to 2016.

Energy expected to be received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects is projected annually in the Annual Power Cost Update Tariff (AUT). Any excess in such hydro generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the three months ended March 31, 2017, energy received from these hydro resources increased by 3% compared to the three months ended March 31, 2016. Energy received from these hydro resources exceeded projected levels included in PGE’s AUT by 16% and 11% for the three months ended March 31,2017 and 2016, respectively, and provided 20% and 21% of the Company’s retail load requirement for the three months ended March 31,2017 and 2016, respectively. Energy from hydro resources is expected to exceed levels projected in the AUT for the full year 2017.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT. Any excess in wind generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the three months ended March 31, 2017, energy received from these wind generating resources decreased 17% compared to the three months ended March 31, 2016, resulting in the Company incurring higher replacement costs, as well as generating fewer PTCs than what was estimated in customer prices. Energy received from these wind generating resources fell short of that projected in PGE’s AUT by 30% for the three months ended March 31,2017 and 21% for the three months ended March 31,2016, and provided approximately 6% and 8% of the Company’s retail load requirement during the three months ended March 31,2017 and 2016, respectively. Energy from wind resources is expected to be below projected levels included in the AUT for 2017.

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. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s condensed consolidated statements of income) and is net of wholesale revenues, which are classified as Revenues, net in the condensed consolidated statements of income. Effective January 1, 2017, and pursuant to the Oregon Clean Electricity and Coal Transition Plan (OCEP), PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year with

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actual variances subject to the PCAM. To the extent actual annual NVPC, subject to certain adjustments, is above or below the deadband, which is a defined range from $30 million above to $15 million below baseline NVPC, the PCAM provides for 90% of the variance beyond 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, net in the Company’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense.

For the three months ended March 31,2017, actual NVPC was $2 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2017 is currently estimated to be below the baseline NVPC, but within the deadband range. Accordingly, no estimated collection from, or refund to, customers is expected under the PCAM for 2017.

For the three months ended March 31,2016, actual NVPC was $1 million above baseline NVPC. For the year ended December 31, 2016, actual NVPC was $10 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded pursuant to the PCAM for 2016.

PGE has contractual access to natural gas storage in Mist, Oregon from which it can draw in the event that natural gas supplies are interrupted or if economic factors require its use. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PGE’s Port Westward Unit 1 and Beaver natural gas-fired generating plants and the Port Westward Unit 2 natural gas-fired flexible capacity generating plant. PGE has entered into a long-term agreement with this gas company to expand the current storage facilities, including the construction of a new 13-mile pipeline, that will be designed to provide no-notice storage services to these PGE generating plants. NW Natural estimates construction will be completed during the winter of 2018-2019, at a cost of approximately $128 million. Due to the level of PGE’s involvement during the construction period, the Company is deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE has recorded $29 million to CWIP and a corresponding liability for the same amount to Other noncurrent liabilities in the condensed consolidated balance sheets as of March 31, 2017. Upon completion of the facility, PGE will assess whether the assets and liabilities qualify as a successful sale-leaseback transaction in which the asset and liability are removed and accounted for as either a capital or operating lease.

Carty—Pursuant to the final order issued by the OPUC on November 3, 2015 in connection with the Company’s 2016 GRC, the Company was authorized to include in customer prices the capital costs for Carty of up to $514 million, as well as Carty’s operating costs, effective August 1, 2016, following the placement of the plant into service on July 29, 2016. As actual project costs for Carty have exceeded $514 million (as of March 31, 2017, PGE had $636 million in plant in service related to Carty) the Company will incur a higher cost of service than what is reflected in the current authorized revenue requirement amount. This higher cost of service is primarily due to depreciation and amortization on the incremental capital cost, interest expense, and legal expense, all of which totaled $4 million for the three months ended March 31, 2017 and is estimated to be approximately $13 million for the full year 2017. The Company estimates that the total capital expenditures for Carty will be approximately $640 million.

On July 29, 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent GRC proceeding. The Company has requested the OPUC delay its review of this deferral request until the Company’s claims against the Sureties have been resolved. Until such time, the effects of this higher cost of service will be recognized in the Company’s results of operations. Any amounts approved by the OPUC for recovery under the deferral filing will be recognized in earnings in the period of such approval.

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For additional details regarding various legal and regulatory proceedings related to Carty, see Note 7, Contingencies, in the Notes to the Condensed Consolidated Financial Statements.

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

• An investigation of environmental matters regarding Portland Harbor;

• Claims pertaining to the termination of the Construction Agreement for Carty and recovery of incremental costs.

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

Oregon Clean Electricity and Coal Transition Plan—The State of Oregon passed Senate Bill 1547, effective in March 2016, a law referred to as the Oregon Clean Electricity and Coal Transition Plan (OCEP). The legislation has impacted PGE in a several ways, including preventing the Company from including the costs and benefits associated with coal-fired generation in Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for the Company’s output from the Colstrip facility). As a result, in October 2016, the Company filed a tariff request, and the OPUC approved the request, to incorporate in customer prices on January 1, 2017 the approximate $6 million annual effect of accelerating recovery of the Colstrip facility from 2042 to 2030, as required under the legislation. In addition, projected production tax credits (PTCs) were included in prices through the AUT filing for 2017.

Future effects under the new law include:

• an increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;

• a limitation on the life of renewable energy certificates (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects on line before December 31, 2022; and

• an allowance for energy storage costs in its renewable adjustment clause mechanism (RAC) filings.

The Company has evaluated the potential impacts and has incorporated the effects of the legislation into its 2016 IRP, which was filed with the OPUC in the fourth quarter of 2016.

Clean Power Plan—In August 2015, the U.S. Environmental Protection Agency (EPA) released a final rule, which it calls the “Clean Power Plan” (CPP). Under the final rule, each state would have to reduce the carbon intensity of its power sector on a state-wide basis by an amount specified by the EPA. The rule establishes state-specific goals in terms of pounds of carbon dioxide emitted per MWh of energy produced. The rule is intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 32% below 2005 levels by 2030.

The target amount was determined based on the EPA’s view of the options for each state, including: i) making efficiency upgrades at fossil fuel-fired power plants; ii) shifting generation from coal-fired plants to natural gas-fired plants; and iii) expanding use of zero- and low-carbon emitting generation (such as renewable energy and nuclear energy). The final goal would need to be met by 2030 and interim goals for each state would need to be met from 2022 to 2029. Under the rule, states have flexibility in designing programs to meet their emission reduction

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targets, including the three approaches noted above and any other measures the states choose to adopt (such as carbon tax and cap-and-trade) that would result in verified emission reductions.

PGE cannot predict how the states in which the Company’s thermal generation facilities are located (Oregon and Montana) will implement the rule or how the rule may impact the Company’s operations. The Company continues to monitor the developments around the implementation of the rule and efforts by state regulators to develop state plans. On February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the CPP pending the resolution of legal challenges to the rule. 

On March 28, 2017, the President of the United States issued an Executive Order that directed various agencies to review existing regulations that “potentially burden” the development of the nation’s energy resources. Among other items, the Executive Order specifically directs the EPA to take several actions relating to the CPP. The EPA is instructed to review the final CPP and the final new source performance standard rules for new and modified power plants (NSPS) under the Clean Air Act and suspend, revise, or rescind the rules, if appropriate. Additionally, the Executive Order directs the EPA to notify the U.S. Attorney General of actions pursuant to this order so that courts that are judicially reviewing the above rules and associated litigation may stay or otherwise delay further the litigation while the EPA reviews them. In response to the Executive Order, the Department of Justice filed requests asking the U.S. Court of Appeals for the D.C. Circuit to suspend and hold in abeyance the current litigation over the CPP and the NSPS.

The Company cannot predict the impact of the stay, the ultimate outcome of the legal challenges, or whether Oregon and Montana will continue to develop implementation plans in light of the Supreme Court stay, the Executive Order, and consequential EPA actions.

The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the first quarter of 2017 compared to the first quarter of 2016, or have affected retail customer prices, as authorized by the OPUC. In some cases, the Company has deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

Power Costs—Pursuant to the AUT process, PGE files annually an estimate of power costs for the following year. Effective January 1, 2017, customer prices were decreased $56 million from 2016 levels to reflect an expected reduction in power costs under the AUT. As part of its 2018 GRC, PGE included a projected $29 million reduction in power costs that was included in the overall request submitted to the OPUC and expected to be reflected in customer prices effective January 1, 2018. Pursuant to the schedule established in the proceeding, updates of the forecast will occur through mid-November that could change this estimate.

Under the PCAM for 2016, NVPC was within the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the results of the PCAM for 2016 during the latter half of 2017 with a decision expected in the fourth quarter 2017.

As a result of the recently passed OCEP legislation described above, PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year. Prior to this legislative change, PGE included forecasts of PTCs only in General Rate Case proceedings. The inclusion of PTCs in the AUT provides for annual forecast updates for these estimated tax credits, thus reducing the risk of regulatory lag in terms of adjusting customer prices, as well as providing the Company an opportunity to potentially collect or refund variances from projected PTC’s pursuant to the PCAM.

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

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part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in customer prices until the January 1st effective date.

In March 2016, PGE submitted to the OPUC a RAC filing that requested no significant additions or deferrals for 2016. No RAC filing is expected to be submitted in 2017 as the Company does not expect new renewables to be placed into service during 2017.

Decoupling—The decoupling mechanism, which the OPUC has authorized through 2019, 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 collection from (or refund to) customers if weather adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

Accordingly, refund of the $5 million recorded during 2014 occurred over a one year period, which began January 1, 2016. The $9 million refund recorded in 2015 that resulted from variances between actual weather adjusted use per customer and that projected in the 2015 GRC, is expected to occur over a one year period, which began January 1, 2017. The Company recorded an estimated collection of $3 million during the year ended December 31, 2016, which resulted from variances between actual weather adjusted use per customer and that projected in the 2016 GRC. Any collection is expected to occur over a one-year period, which would begin January 1, 2018.

The Company recorded an estimated collection of $6 million during the three months ended March 31, 2017, which resulted from variances between actual weather adjusted use per customer and that projected in the 2016 GRC. Any collection from (or refund to) customers for the 2017 year is expected to occur over a one-year period, which would begin January 1, 2019.

Storm Restoration Costs—Beginning in 2011, the OPUC authorized the Company to collect $2 million annually from retail customers to establish a reserve balance to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. During 2015 and 2016, PGE fully utilized the existing reserve balance as a result of restoration costs associated with storm damage occurring during those years. In the first quarter of 2017, the Company incurred $5 million of incremental expenses as a result of a series of storm events and, as a result, the $2 million storm collection for 2017 was fully utilized. Consequently, PGE is exposed to the estimated incremental costs to-date, less the $2 million to be collected in 2017, as well as any additional major storm damage costs experienced during the remainder of 2017. A significant wind storm in early April 2017 resulted in additional incremental restoration expenses of approximately $6million.

As a result of the additional costs incurred, during the first quarter of 2017, PGE filed an application with the OPUC requesting authorization to defer incremental storm restoration costs from the date of the application through the end of 2017, net of the $2 million being collected annually under the existing methodology for 2017. Since the application will not likely be reviewed until 2017 is complete and all applicable costs are identified, and Company is unable to predict how the OPUC will ultimately rule on this application, the Company is unable to state with any certainty at this time whether these incremental costs are probable of recovery. Accordingly, no deferral has been recorded to-date. In the event it becomes probable that some or all of these costs are recoverable, the Company will record a deferral for such amounts at such time.

As part of PGE’s 2018 GRC filing, the Company has requested that the storm damage cost recovery mechanism be changed to a balancing account concept, beginning in 2018. At this time, the Company is unable to predict whether or not the OPUC will approve this proposed change in methodology.

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Integrated Resource Plan—PGE’s IRP outlines how the Company proposes to meet future customer demand and describes PGE’s future energy supply strategy. PGE’s IRP filing acknowledged by the OPUC in December 2014, and updated in December 2015, included an “Action Plan” that covered PGE’s proposed actions before the end of 2017. In conjunction with the Action Plan, in September 2015, the Company announced plans to explore participation in the western energy imbalance market (EIM), which was launched in 2014 by the California Independent System Operator. The western EIM is a real-time energy wholesale market that automatically dispatches the lowest-cost electricity resources available to meet utility customer needs, while optimizing use of renewable energy over a large geographic area. PGE has signed an agreement, which was approved by the FERC in January 2016, to join the western EIM. The agreement outlines a schedule of activities and milestones in anticipation of the Company’s participation in the EIM, targeted to begin in the fall of 2017.

PGE filed a subsequent IRP (2016 IRP) with the OPUC in mid- November 2016. The 2016 IRP addresses acquisition of additional resources to meet RPS requirements and replace energy and capacity from Boardman, which will cease coal-fired operations at the end of 2020. Further actions identified through 2021 are expected to offset expiring power purchase agreements and integrate variable energy resources, such as wind or solar generation facilities. The 2016 IRP also considers the OCEP, which, among other things, increased the RPS requirements for 2025 and future years. For further information on the OCEP, see the “Legal, Regulatory and Environmental” section in this Overview section of Item 2.

All portfolios analyzed in the 2016 IRP pursue: i) compliance with the RPS through 2050; ii) inclusion of cost-effective customer-side options, including energy efficiency, demand response, conservation voltage reduction, and dispatchable standby generation; and iii) retention of all existing power plants until 2050, with the exception of Boardman and Colstrip Units 3 & 4.

The 2016 IRP is available on PGE’s website. The recommended Action Plan in the 2016 IRP encompasses both demand-side and supply-side actions as well as integration through flexible technologies. Specific initial recommendations included: i) the deployment of a minimum of 135 MWa of cost-effective energy efficiency; ii) the pursuit of up to 77 MW of additional demand response; and iii) the addition of approximately 175 MWa in RPS compliant renewable resources, which could include unbundled RECs. The initial submission also identified the need for PGE to acquire up to 850 MW of capacity, which included 375-550 MW of long-term dispatchable resources and up to 400 MW of annual capacity resources. As a result of recent actions that were not incorporated in the initial IRP submission, as described in the following paragraphs, PGE has subsequently reduced the capacity need in the IRP for 2021 to approximately 565 MW.

On March 29, 2017, PGE executed a 10-year Power Purchase Agreement (PPA), beginning September 1, 2018, with Douglas County Public Utility District for output from the Wells Hydroelectric Project (Wells), located in the state of Washington. The existing contract with Wells for 150 MW, set to expire in 2018, was identified as a portion of PGE’s future resource needs in the initial 2016 IRP filing. Under the new PPA, PGE will continue to receive a portion of the capacity and energy produced at Wells, which is expected to reduce PGE’s capacity need by 135 MW.

PGE has also incorporated its December 2016 load forecast update, which reduced its capacity need by 71 MW. In addition, contracts for approximately 143 MW of nameplate capacity were executed between June 1, 2016 and December 31, 2016, reducing PGE’s capacity shortfall by 52 MW, with projects that include solar, biomass, and geothermal resources as required under the Public Utility Regulatory Policies Act of 1978 that defines such qualifying facilities.

The renewal of existing hydro contracts and execution of the new contracts does not change the IRP Action Plan.

Acknowledgment of the 2016 IRP is now expected in late summer 2017. Following acknowledgment, PGE will request approval from the OPUC to issue one or more request for proposals (RFPs) for remaining capacity and renewable resources. PGE is open to a variety of options and will seek the best combination of resources, consistent

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with the acknowledged IRP Action Plan, to meet its customers’ future energy needs. Resource options could include hydro, wind, solar, geothermal, biomass, efficient natural gas-fired facilities, and energy storage. The RFP process will include oversight by an independent evaluator and review by the OPUC.

In preparation for the RFP process, PGE has identified a potential benchmark wind resource with nameplate capacity of up to approximately 500 MW, which would qualify for the production tax credit. The submission of this resource into the RFP process as a benchmark bid is subject to additional due diligence by PGE and the negotiation and execution of definitive agreements. If agreements are reached, the potential benchmark resource would be considered in the RFP process along with other renewable resource offerings. Such resource would help PGE meet its RPS requirements, as well as provide a portion of PGE’s identified capacity needs.

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, 2016, filed with the SEC on February 17, 2017.

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Results of Operations

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

	Three Months Ended March 31,
	2017				2016
Revenues, net	$	530	100	%	$	487		100	%
Purchased power and fuel	141		27		149			31
Gross margin	389		73		338			69
Other operating expenses:
Generation, transmission and distribution	81		15		66			14
Administrative and other	68		13		61			12
Depreciation and amortization	84		16		82			17
Taxes other than income taxes	33		6		30			6
Total other operating expenses	266		50		239			49
Income from operations	123		23		99			20
Interest expense*	30		6		27			5
Other income:
Allowance for equity funds used during construction	2		—		7			1
Miscellaneous income (expense), net	1		—		(1		)	—
Other income, net	3		1		6			1
Income before income tax expense	96		18		78			16
Income tax expense	23		4		17			3
Net income	$	73	14	%	$	61		13	%
* Net of an allowance for borrowed funds used during construction of $1 million and $4 million for the three months ended March 31, 2017 and 2016, respectively.

Net income attributable to PGE was $73 million, or $0.82 per diluted share, for the three months ended March 31, 2017 compared with $61 million, or $0.68 per diluted share, for the three months ended March 31, 2016. The increase in Net income reflects the influence that considerably cooler temperatures had on customer demand in the first three months of 2017. These temperature variances contributed to a 6.2% increase in energy deliveries over the first three months of 2016. The increase in operating expenses was primarily due to increased generation, transmission, and distribution costs, which increased by $7 million due to higher storm restoration costs and $5 million for Carty operations, the latter of which was anticipated and offset with higher revenues. Legal costs related to Carty construction contributed to a $2 million increase in Administrative expenses. Actual NVPC was $2 million below the baseline for the first three months of 2017, while actual NVPC was $1 million above baseline NVPC for the first three months of 2016. Allowance for equity funds during construction decreased in 2017 by $5 million due to lower average CWIP balances primarily as a result of placing Carty into service in late July 2016, although such decline was offset with the resulting increase in revenues being collected from customers effective August 1, 2016.

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Three Months EndedMarch 31, 2017 Compared with the Three Months EndedMarch 31, 2016

Revenues, energy deliveries (presented in MWh), and the average number of retail customers consist of the following for the periods presented:

	Three Months Ended March 31,
	2017				2016
Revenues * (dollars in millions):
Retail:
Residential	$	288	54	%	$	254	52	%
Commercial	161		31		160		33
Industrial	49		9		49		10
Subtotal	498		94		463		95
Other retail revenues, net	8		2		3		1
Total retail revenues	506		96		466		96
Wholesale revenues	13		2		12		2
Other operating revenues	11		2		9		2
Total revenues	$	530	100	%	$	487	100	%
Energy deliveries (MWh in thousands):
Retail:
Residential	2,383		42	%	2,103		39	%
Commercial	1,687		30		1,702		32
Industrial	686		12		697		13
Subtotal	4,756		84		4,502		84
Direct access:
Commercial	143		2		129		2
Industrial	321		6		283		5
Subtotal	464		8		412		7
Total retail energy deliveries	5,220		92		4,914		91
Wholesale energy deliveries	439		8		488		9
Total energy deliveries	5,659		100	%	5,402		100	%
Average number of retail customers:
Residential	758,087		88	%	749,287		88	%
Commercial	105,566		12		104,872		12
Industrial	198		—		187		—
Direct access	480		—		382		—
Total	864,331		100	%	854,728		100	%

* Includes revenues from customers who purchase their energy from the Company as well as $9million and $7 million in the first three months of 2017 and 2016, respectively, from Direct access customers for transmission and delivery charges only.

Total revenues for the three months ended March 31, 2017 increased $43 million compared to the three months ended March 31, 2016, comprised primarily of a $40 million increase in Retail revenues.

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The change in Retail revenues resulted from the following:

• A $29 million increase from a 6.2% increase in retail energy deliveries due largely to considerably cooler temperatures than experienced in the first quarter of 2016;

• A $10 million net increase from an average price increase of 2.0% over 2016 levels. Price changes, as authorized by the OPUC, include Carty going into service in mid-2016 and reflect a reduction as a result of lower net variable power costs as filed in the 2017 AUT. Higher delivery volumes also pushed average prices higher as the increased volumes are, at times, subject to higher tariff prices; and

• A $4 million increase resulted from other tariffs including a $3 million increase in estimated collections under the decoupling mechanism; partially offset by

• A $5 million decrease from supplemental tariffs, due to the timing of the Trojan spent fuel refund to customers, as the refund, offset in Depreciation and amortization, temporarily suspended in early 2016, has resumed.

Total heating degree-days for the three months ended March 31, 2017 were 37% above the three months ended March 31, 2016 and 16% above average.

The following table indicates the number of heating degree-days for the three months ended March 31, 2017 and 2016, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

	Heating Degree-days
	2017	2016	Avg.
January	969	688	734
February	672	448	599
March	530	449	533
Totals for the quarter	2,171	1,585	1,866

Wholesale revenues for the three months ended March 31, 2017 increased $1 million, or 8%, from the three months ended March 31, 2016 with the change consisting of a $2 million increase related to a 24% increase in average wholesale price partially offset by a $1 million decrease related to a 10% decrease in wholesale sales volume.

Purchased power and fuel expense decreased $8 million, or 5%, for the three months ended March 31, 2017 compared with the three months ended March 31, 2016, and consisted of $20 million related to a 10% decrease in the average variable power cost per MWh, partially offset by $12 million related to a 6% increase in total system load.

The decrease in the average variable power cost to $25.20 per MWh in the three months ended March 31, 2017 from $28.13 per MWh in the three months ended March 31, 2016 was driven by a $14 million decrease in purchased power due to a 16% decrease in the average variable power cost per MWh, combined with an $8 million, or 16% decrease in the average variable cost per MWh of energy generated from the Company’s natural gas-fired resources. Lower natural gas prices in the region also contributed to the decrease in price, partially offset by higher replacement costs due to a 17% reduction in energy received from the Company’s wind resources. The decrease related to price was partially offset by an increase in total system load comprised of a $12 million, or 30% increase in energy generated from the Company’s natural gas-fired generation resources and a $3 million, or 20% increase in energy generated from the Company’s coal-fired resources. The increase in generation from natural gas-fired plants in 2017 in comparison to 2016 is due largely to the Carty facility being placed in service in July 2016.

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

	Three Months Ended March 31,
	2017				2016
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	911		16	%	757		14	%
Natural gas	1,303		24		1,002		19
Total thermal	2,214		40		1,759		33
Hydro	548		10		568		11
Wind	299		5		361		7
Total generation	3,061		55		2,688		51
Purchased power:
Term	1,982		35		2,088		39
Hydro	497		9		445		9
Wind	39		1		59		1
Total purchased power	2,518		45		2,592		49
Total system load	5,579		100	%	5,280		100	%
Less: wholesale sales	(439	)			(488	)
Retail load requirement	5,140				4,792

Energy received from PGE-owned wind generating resources decreased 17% in the three months ended March 31, 2017 compared with the same period of 2016 as a result of less favorable wind conditions. Energy received from these wind generating resources represented 6% and 8% of the Company’s retail load requirements for the three months ended March 31, 2017 and 2016, respectively. Due to slightly more favorable hydroelectric conditions, energy received from hydro resources during the three months ended March 31, 2017, from both PGE-owned generating plants and purchased from mid-Columbia projects, increased 3% compared with the same period of 2016, and represented 20% and 21% of the Company’s retail load requirement for the three months ended March 31, 2017 and 2016, respectively.

The following table presents the forecast April-to-September 2017 runoff (issued April 23, 2017), along with actual 2016, at particular points of major rivers relevant to PGE’s hydro resources (as a percentage of normal, as measured over the 30-year period from 1981 through 2010):

	Runoff as a Percent of Normal*
Location	2017 Forecast		2016 Actual
Columbia River at The Dalles, Oregon	126	%	89	%
Mid-Columbia River at Grand Coulee, Washington	120		91
Clackamas River at Estacada, Oregon	116		71
Deschutes River at Moody, Oregon	105		91

* Volumetric water supply forecasts and historical 30-year averages 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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Actual NVPC for the three months ended March 31, 2017 decreased $9 million when compared with the three months ended March 31, 2016. The decrease was driven by a 10% decline in the average variable power cost per MWh, partially offset by a 6% increase in total system load. The increase in wholesale revenues was driven primarily by a 24% increase in the average wholesale sales price, offset slightly with a 10% decrease in wholesale sales volume. For the three months ended March 31, 2017, actual NVPC was $2 million below the baseline, while the three months ended March 31, 2016 actual NVPC was $1 million above baseline NVPC.

Generation, transmission and distribution expense increased $15 million, or 23%, in the three months ended March 31, 2017 compared with the three months ended March 31, 2016 driven primarily by $7 million of storm restoration costs and $5 million of operating expense for Carty, which was placed in service in July 2016.

Administrative and other expense increased $7 million, or 11%, in the three months ended March 31, 2017 compared with the three months ended March 31, 2016. The increase was primarily due to a $2 million increase in legal costs related to Carty litigation and a $2 million increase in employee benefit expense.

Depreciation and amortization expense increased $2 million in the three months ended March 31, 2017 compared with the three months ended March 31, 2016. The increase was primarily driven by higher depreciation expense as a result of the Carty plant going into service in July 2016, partially offset by an amortization credit in the first quarter of 2017 related to the Trojan spent fuel refund to customers, which is also reflected in reduced revenues.

Taxes other than income taxes increased $3 million, or 10%, in the three months ended March 31, 2017 compared to the three months ended March 31, 2016 due to $2 million higher property taxes.

Interest expense increased $3 million, or 10%, in the three months ended March 31, 2017 compared with the three months ended March 31, 2016, due to $3 million lower allowance for borrowed funds used during construction credits, primarily as a result of Carty going into service in July 2016.

Other income, net decreased $3 million for the three months ended March 31, 2017 compared with the three months ended March 31, 2016. This was due to a decrease in the allowance for equity funds used during construction, primarily related to the Carty project, offset by gains on the non-qualified benefit trust.

Income tax expense was $23 million in the three months ended March 31, 2017 compared with $17 million in the three months ended March 31, 2016, with effective tax rates of 24.0%and21.8%, respectively. The increase in income tax expense and effective tax rate was primarily due to higher pre-tax income, partially offset by production tax credits.

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Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2017through2021 (in millions, excluding AFDC):

	2017			2018		2019		2020		2021
Ongoing capital expenditures (1)	$	535		$	434	$	294	$	300	$	290
Customer information system (2)	$	50		$	12	$	—	$	—	$	—
Total capital expenditures	$	585	(3)	$	446	$	294	$	300	$	290
Long-term debt maturities	$	150		$	—	$	300	$	—	$	160

(1) Consists primarily of upgrades to, and replacement of, generation, transmission and distribution infrastructure, as well as new customer connections. For 2017, $134 million is included for transmission, distribution, and generation resiliency projects.

(2) As of December 31, 2016, total capital expenditures for the Customer information system was $65 million, excluding AFDC.

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

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

Liquidity

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

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

	Three Months Ended March 31,
	2017			2016
Cash and cash equivalents, beginning of period	$	6		$	4
Net cash provided by (used in):
Operating activities	170			161
Investing activities	(113		)	(133		)
Financing activities	(32		)	(28		)
Increase in cash and cash equivalents	25			—
Cash and cash equivalents, end of period	$	31		$	4

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, with adjustments for certain non-cash items, such as depreciation and amortization, deferred income taxes, and pension and other postretirement

46

benefit costs included in net income during a given period. Net cash flows from operating activities for the three months ended March 31,2017 increased $9 million when compared with the three months ended March 31,2016. Such change resulted from a number of relatively small, somewhat offsetting factors, including:

• A $16 million increase from the combination of higher Net income, increases in non-cash expenses for Depreciation and amortization and Deferred income taxes, and a decrease in the non-cash credit to income for the Allowance for equity funds used during construction as Carty was placed in service in July 2016, net of the overall decrease in Other non-cash income and expenses; and

• A $14 million net increase from a combination of smaller net increases in Other working capital items, net and Other, net adjustments to net income along with a reduction in inventory as fuel stocks were drawn down; partially offset by

• A $17 million reduction in the comparative quarter over quarter decrease in Accounts receivable and unbilled revenues as balances remained higher in 2017, due in part to higher deliveries that resulted from cooler weather and increases in customer prices; and

• A $4 million increase in margin deposits.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that such charges in 2017 will range from $340 million to $350 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $425 million to $475 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 generation facilities and transmission and distribution systems. Net cash used in investing activities for the three months ended March 31,2017 decreased$20 million when compared with the three months ended March 31,2016, largely due to the lower level of capital expenditures resulting from the completion of Carty during 2016.

The Company plans to make capital expenditures of approximately $585 million, excluding AFDC, in 2017, which it expects to fund with cash to be generated from operations during 2017, as discussed above, as well as with proceeds received from the issuances of debt securities. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the three months ended March 31,2017, net cash used in financing activities consisted primarily of the payment of dividends of $28 million. During the three months ended March 31,2016, net cash used in financing activities consisted of the repayment of long-term debt of $133 million and the payment of dividends of $27 million, partially offset by proceeds received from the issuance of FMBs of $140 million.

Dividends on Common Stock

While PGE 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.

47

Common stock dividends declared during 2017 consist of the following:

			Dividends
			Declared Per
Declaration Date	Record Date	Payment Date	Common Share
February 15, 2017	March 27, 2017	April 17, 2017	$	0.32
April 26, 2017	June 26, 2017	July 17, 2017	0.34

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, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors. Management believes that the availability of its revolving credit facility, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions.

For 2017, PGE expects to fund estimated capital expenditures and maturities of long-term debt with cash from operations (which is expected to range from $425 million to $475 million), issuances of debt securities of up to $450 million, and the issuance of commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures and maturities of long-term debt.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $900 million through February 6, 2018.

As of March 31, 2017, PGE had a $500 million revolving credit facility scheduled to expire in November 2020. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and for general corporate purposes. 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.

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 revolving credit facility.

Under the revolving credit facility, as of March 31, 2017, PGE had no borrowings outstanding, and no commercial paper or letters of credit issued. As a result, as of March 31, 2017, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for a total capacity of $160 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $56 million were outstanding as of March 31, 2017.

Long-term Debt. During the three months ended March 31,2017, PGE had no long-term debt transactions.

48

As of March 31, 2017, total long-term debt outstanding, net of $11 million of unamortized debt expense, was $2,350 million, with $150 million scheduled maturities classified as current.

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including any current debt maturities) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and facilitates access to long-term capital at favorable interest rates. The Company’s common equity ratio was 49.8% and 49.4% as of March 31, 2017 and December 31, 2016, respectively.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P), with current credit ratings and outlook as follows:

	Moody’s	S&P
First Mortgage Bonds	A1	A-
Issuer rating	A3	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and 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. Cash deposits provided as collateral are classified as Margin deposits, which is included in Other current assets on PGE’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

As of March 31, 2017, PGE had posted approximately $41 million of collateral with these counterparties, consisting of $20 million in cash and $21 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2017, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade was approximately $78 million, and decreases to approximately $25 million by December 31, 2017 and to $9 million by December 31, 2018. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade was approximately $168 million at March 31, 2017, and decreases to approximately $108 million by December 31, 2017 and to $82 million by December 31, 2018.

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 and issuing letters of credit under the credit facility would increase.

The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on March 31, 2017, under the most restrictive issuance test in the Indenture, the Company could have issued up to approximately $1,249 millionof additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

49

PGE’s credit facility contains 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-to-total capital ratio). As of March 31, 2017, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 50.6%.

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 2017 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, 2016, filed with the SEC on February 17, 2017. For such obligations, there have been no material changes outside the ordinary course of business, as of March 31, 2017.

50

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, 2016, filed with the SEC on February 17, 2017.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2017, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in PGE’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

For further information regarding PGE’s legal proceedings, see “Legal Proceedings” set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 17, 2017.

Portland General Electric Company v. Liberty Mutual Insurance Company and Zurich American Insurance Company, U.S. District Court of the District of Oregon.

On July 27, 2016, the judge denied the Sureties’ motion to stay the case in favor of a pending ICC Arbitration and granted PGE’s motion for an injunction prohibiting the Sureties from pursuing any Performance Bond claims in the ICC Arbitration. The Sureties appealed the rulings to the Ninth Circuit Court of Appeals and asked the district court to stay the district court proceedings pending resolution of the appeal. In October 2016, the district court denied the request to stay the proceedings. Briefing on the merits of the appeal to the Ninth Circuit has been completed, but no oral argument dates have been set. On October 24, 2016, the Sureties filed a motion with the Ninth Circuit for a stay of PGE’s district court proceedings against the Sureties pending the Sureties’ appeal to the Ninth Circuit. Oral argument is set for May 8, 2017.  For additional information on this matter, see Note 7, Contingencies, in the Notes to the Condensed Consolidated Financial Statements.

Portland General Electric Company v. Abeinsa EPC LLC, Abener Construction Services, LLC (formerly known as Abener Engineering and Construction Services, LLC), Teyma Construction USA LLC, and Abeinsa Abener Teyma General Partnership, U.S. District Court of the District of Oregon.

On October 21, 2016, PGE filed a complaint in the U.S. District Court of the District of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from Abeinsa in excess of $200 million for: i) costs incurred to complete construction of Carty, settle claims with unpaid contractors and vendors and remove liens; and ii) damages in excess of the construction costs, including a project management fee, liquidated damages under the Construction Agreement, legal fees and costs, damages due to delay of the project, warranty costs, and interest. On March 21, 2017, the judge entered an order staying the case for 120 days.

Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon.

On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company in the U.S. District Court of the District of Oregon. DRA’s claims seek injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. For additional information on this matter, see Note 7, Contingencies, in the Notes to the Condensed Consolidated Financial Statements.

51

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, 2016, filed with the SEC on February 17, 2017.

Item 5. Other Information.

Portland General Electric Company held its 2017 annual meeting of shareholders on April 26, 2017 in Portland, Oregon. The following proposals were voted on at the meeting by the Company’s shareholders:

1. The election of directors;

2. The ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2017;

3. An advisory, non-binding vote to approve the compensation of the Company’s named executive officers; and

4. An advisory, non-binding vote on the frequency of future shareholder votes to approve the compensation of the Company’s named executive officers.

There were 89,059,366 shares of common stock issued and outstanding as of February 28, 2017, the record date for the meeting, with 83,870,238shares represented at the annual meeting.

Each of the director nominees listed below was elected and the voting results were as follows:

Nominee	For	Against	Abstain	Broker Non-votes
John W. Ballantine	63,224,690	15,221,286	61,892	5,362,370
Rodney L. Brown, Jr.	78,011,439	436,331	60,098	5,362,370
Jack E. Davis	78,011,596	437,253	59,019	5,362,370
David A. Dietzler	77,763,736	684,954	59,178	5,362,370
Kirby A. Dyess	78,001,951	449,769	56,148	5,362,370
Mark B. Ganz	77,788,777	660,427	58,664	5,362,370
Kathryn J. Jackson	78,033,935	423,790	50,143	5,362,370
Neil J. Nelson	78,016,674	432,018	59,176	5,362,370
M. Lee Pelton	77,757,687	690,508	59,673	5,362,370
James J. Piro	77,935,874	510,150	61,844	5,362,370
Charles W. Shivery	78,024,415	426,387	57,066	5,362,370

Our shareholders ratified the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2017. There were 83,394,480 votes cast for the proposal, 407,494 votes cast against the proposal, and 68,264 abstentions.

Our shareholders approved the compensation of the Company’s named executive officers. There were 77,847,959 votes cast for the proposal, 478,622 votes cast against the proposal, 181,287 abstentions, and 5,362,370 broker non-votes.

Our shareholders recommended a frequency of “one year” for future shareholder votes to approve the compensation of the Company’s named executive officers. There were 71,342,181 votes cast for a frequency of one year, 88,415

52

votes cast for a frequency of two years, 6,986,717 votes cast for a frequency of three years, 90,555 abstentions, and 5,362,370 broker non-votes.

Item 6. Exhibits.

Exhibit Number	Description
3.1	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2	Tenth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed May 9, 2014).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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

SIGNATURE

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

		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)
Date:	April 27, 2017	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)

53

EX-31.1

Exhibit 31.1

CERTIFICATION

I, James J. Piro, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Portland General Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	April 27, 2017	By:	/s/ James J. Piro
			James J. Piro
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James F. Lobdell, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Portland General Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	April 27, 2017	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

We, James J. Piro, President and Chief Executive Officer, and James F. Lobdell, Senior Vice President of Finance, Chief Financial Officer and Treasurer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017, as filed with the Securities and Exchange Commission on April 28, 2017 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”), fully complies with the requirements of that section.

We further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ James J. Piro		/s/ James F. Lobdell
James J. Piro		James F. Lobdell
President and Chief Executive Officer		Senior Vice President of Finance, Chief Financial Officer and Treasurer
Date:	April 27, 2017	Date:	April 27, 2017

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 20, 2017
Entity Information [Line Items]
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	0000784977
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		89,068,043
Trading Symbol	POR

XML

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues, net	$ 530	$ 487
Operating expenses:
Purchased power and fuel	141	149
Generation, transmission and distribution	81	66
Administrative and other	68	61
Depreciation and amortization	84	82
Taxes other than income taxes	33	30
Total operating expenses	407	388
Income from operations	123	99
Interest expense, net	30	27
Other income:
Allowance for equity funds used during construction	2	7
Miscellaneous income (expense), net	1	(1)
Other income, net	3	6
Income before income tax expense	96	78
Income tax expense	23	17
Net income and Comprehensive income	73	61
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	(1)	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 72	$ 61
Weighted-average shares outstanding (in thousands):
Weighted Average Number of Shares Outstanding, Basic and Diluted	89,003	88,833
Earnings per share:
Earnings Per Share, Basic and Diluted	$ 0.82	$ 0.68
Dividends declared per common share	$ 0.32	$ 0.30

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 31	$ 6
Accounts receivable, net	162	155
Unbilled revenues	71	107
Inventories	77	82
Regulatory assets - current	57	36
Other current assets	87	77
Total current assets	485	463
Electric utility plant, net	6,466	6,434
Regulatory assets - noncurrent	532	498
Nuclear decommissioning trust	41	41
Non-qualified benefit plan trust	34	34
Other noncurrent assets	54	57
Total assets	7,612	7,527
Current liabilities
Accounts payable	92	129
Liabilities from price risk mangement activities - current	59	44
Current portion of long-term debt	150	150
Accrued expenses and other current liabilities	247	254
Total current liabilities	548	577
Long-term debt, net of current portion	2,200	2,200
Regulatory liabilities - noncurrent	973	958
Deferred income taxes	682	669
Unfunded status of pension and postretirement plans	283	281
Liabilities from price risk mangement activities - noncurrent	156	125
Asset retirement obligations	164	161
Non-qualified benefit plan liabilities	106	105
Other noncurrent liabilities	113	107
Total liabilities	5,225	5,183
Commitments and contingencies (see notes)
Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2017 and December 31, 2016	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,067,858 and 88,946,704 shares issued and outstanding as of March 31, 2017 and December 31, 2016, respectively	1,200	1,201
Accumulated other comprehensive loss	(8)	(7)
Retained earnings	1,195	1,150
Total equity	2,387	2,344
Total liabilities and equity	$ 7,612	$ 7,527

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	160,000,000	160,000,000
Common stock, shares issued	89,067,858	88,946,704
Common stock, shares outstanding	89,067,858	88,946,704

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income	$ 73	$ 61
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	84	82
Deferred income taxes	17	14
Pension and other postretirement benefits	6	7
Allowance for equity funds used during construction	(2)	(7)
Decoupling Mechanism Deferrals, net of amortization	(9)	(4)
Other non-cash income and expenses, net	7	8
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	29	46
Decrease in inventories	5	1
(Increase) in margin deposits, net	(12)	(7)
(Decrease) in accounts payable and accrued liabilities	(10)	(11)
Other working capital items, net	(13)	(16)
Other, net	(5)	(13)
Net cash provided by operating activities	170	161
Cash flows from investing activities:
Capital expenditures	(114)	(131)
Sales of Nuclear decommissioning trust securities	7	6
Purchases of Nuclear decommissioning trust securities	(5)	(6)
Other, net	(1)	(2)
Net cash used in investing activities	(113)	(133)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	0	140
Payments on long-term debt	0	(133)
Change in short-term debt	0	(6)
Dividends paid	(28)	(27)
Other	(4)	(2)
Net cash used in financing activities	(32)	(28)
Increase in cash and cash equivalents	25	0
Cash and cash equivalents, beginning of period	6	4
Cash and cash equivalents, end of period	31	4
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	13	10
Cash paid for income taxes	$ 0	$ 0

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Basis of Presentation (Notes)

3 Months Ended

Mar. 31, 2017

Basis of Presentation [Abstract]

BASIS OF PRESENTATION

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, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area allocation, located entirely within the State of Oregon, encompasses 51 incorporated cities, of which Portland and Salem are the largest. As of March 31, 2017, PGE served approximately 865,000 retail customers with a service area population of approximately 1.9 million, comprising approximately 46% of the state’s population.

Condensed Consolidated Financial Statements

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

To conform with the 2017 presentation, PGE has reclassified Decoupling mechanism deferrals, net of amortization from Other non-cash income and expenses, net of $4 million within the operating activities section and reclassified both Payments on capital leases of $1 million and Debt issuance costs of $1 million to Other within the financing activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2016.

The financial information included herein for the three months ended March 31, 2017 and 2016 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 income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 2016 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2016, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 17, 2017, which should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income

PGE recorded a net $1 million loss in other comprehensive income for the three months ended March 31, 2017 due to the combination of changes in compensation retirement benefit liability and amortization, net of taxes of an immaterial amount, and other miscellaneous adjustments. No material change occurred in the three months ended March 31, 2016.

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 could differ materially from those estimates.

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.

Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively (full retrospective method) or as a cumulative-effect adjustment as of the effective date (modified retrospective method), which is January 1, 2018 for calendar year-end public entities. The Company is evaluating which transition method it will elect. The Company does not anticipate any material changes to its revenue policy for tariff-based revenues, which comprises a majority of PGE’s retail revenues, as performance obligations are expected to be satisfied in a similar recognition pattern. PGE continues to evaluate the impacts the new guidance may have on its consolidated financial position, consolidated results of operations, and consolidated cash flows, particularly related to recognizing revenue for certain contracts where collectibility may be in question, certain matters of presentation of alternative revenue programs (such as decoupling), wholesale, and other operating revenue contracts.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting principles. Lessees will be required to classify leases as either finance leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019 and must be applied on a modified retrospective basis as of the beginning of the earliest comparative period presented. The new standard also provides reporting entities the option to elect a package of practical expedients for existing leases that commenced before the effective date. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-02.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15), with the intention to reduce diversity in practice, as well as simplify elements of classification within the statement of cash flows for certain transactions. The new ASU prescribes specific clarification guidance for the following eight classes of transactions: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance (COLI) policies, distributions received from equity method investments, beneficial interest in securitization transactions, and separately identifiable cash flows and application of the predominance principal. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018 and requires application using a retrospective transition method. Early adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact to its presentation of consolidated cash flows.

In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). Pursuant to this ASU, only the service cost component of net periodic pension and postretirement benefit costs will be eligible for capitalization and should be applied on a prospective basis upon implementation. Also, the non-service components are required to be presented in the income statement separately from the service cost component and outside the subtotal of income from operations and should be applied on a retrospective basis upon implementation. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018. The Company does not plan to early adopt. The Company is in the process of evaluating the impact the guidance may have on its consolidated financial position and consolidated results of operations.

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Balance Sheet Components (Notes)

3 Months Ended

Mar. 31, 2017

Balance Sheet Components [Abstract]

BALANCE SHEET COMPONENTS

BALANCE SHEET COMPONENTS

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil, for use in its generating plants. Periodically, the Company assesses inventory for purposes of determining that inventory is recorded at the lower of average cost or net realizable value.

Other Current Assets

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

	March 31, 2017		December 31, 2016
Prepaid expenses	$	58	$	48
Margin deposits	20		8
Assets from price risk management activities	9		18
Other	—		3
Other current assets	$	87	$	77

Electric Utility Plant, Net

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

	March 31, 2017			December 31, 2016
Electric utility plant	$	9,605		$	9,534
Construction work-in-progress	242			213
Total cost	9,847			9,747
Less: accumulated depreciation and amortization	(3,381		)	(3,313		)
Electric utility plant, net	$	6,466		$	6,434

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $265 million and $257 million as of March 31, 2017 and December 31, 2016, respectively. Amortization expense related to intangible assets was $11 million for the three months ended March 31, 2017 and 2016. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Regulatory Assets and Liabilities

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

	March 31, 2017					December 31, 2016
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	50		$	154	$	26		$	120
Pension and other postretirement plans	—			232		—			235
Deferred income taxes	—			83		—			86
Debt issuance costs	—			21		—			22
Other	7			42		10			35
Total regulatory assets	$	57		$	532	$	36		$	498
Regulatory liabilities:
Asset retirement removal costs	$	—		$	898	$	—		$	887
Trojan decommissioning activities	12			—		18			—
Asset retirement obligations	—			50		—			49
Other	30			25		33			22
Total regulatory liabilities	$	42	*	$	973	$	51	*	$	958

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Accrued Expenses and Other Current Liabilities

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

	March 31, 2017		December 31, 2016
Regulatory liabilities—current	$	42	$	51
Accrued employee compensation and benefits	41		52
Accrued interest payable	40		25
Accrued dividends payable	30		30
Accrued taxes payable	34		25
Other	60		71
Total accrued expenses and other current liabilities	$	247	$	254

Credit Facilities

As of March 31, 2017, PGE had a $500 million revolving credit facility scheduled to expire in November 2020.

Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to 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. The revolving credit facility contains a provision that allows for two, one-year extensions, subject to approval by the banks. During the first quarter of 2017, PGE exercised one of the two extensions available under the terms of the credit facility. Such action resulted in an updated expiration date for the agreement of November 2020. The facility also contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2017, PGE was in compliance with this covenant with a 50.6% 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 revolving credit facility.

PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.

Under the revolving credit facility, as of March 31, 2017, since PGE had no borrowings outstanding, and no commercial paper or letters of credit issued, the aggregate unused available credit capacity under the facility was $500 million.

In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide a total capacity of $160 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $56 million were outstanding as of March 31, 2017. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2018.

Long-term Debt

During the three months ended March 31, 2017, PGE did not enter into any new First Mortgage Bond (FMB) long-term debt transactions.

In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in an aggregate principal amount of up to $200 million by October 31, 2016. Under the agreement, PGE obtained the following term loans:

• $50 million on May 4, 2016;

• $75 million on June 15, 2016; and

• $25 million on October 31, 2016.

The term loan interest rates are set at the beginning of the interest period for periods of 1-month, 3-months, or 6-months, as selected by PGE, and are based on the London Interbank Offered Rate (LIBOR) plus 63 basis points, and was 1.6% as of March 31, 2017, with no other fees.

The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable. Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults, and other customary defaults for financings of this type.

Defined Benefit Pension Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

	Three Months Ended March 31,
	2017			2016
Service cost	$	4		$	4
Interest cost	8			8
Expected return on plan assets	(10		)	(10		)
Amortization of net actuarial loss	3			4
Net periodic benefit cost	$	5		$	6

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Fair Value of Financial Instruments (Notes)

3 Months Ended

Mar. 31, 2017

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 2017 and December 31, 2016, and then classifies these financial assets and liabilities based on a fair value hierarchy that is used to prioritize the inputs to the valuation techniques used to measure fair value. The three levels and application to the Company are discussed below.

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy, instead these assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels during the three month periods ended March 31, 2017 and 2016, except those presented in this note.

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 March 31, 2017
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	$	2	$	9	$	—	$	—	$	11
Corporate credit	—		8		—		—		8
Money market funds measured at NAV (2)	—		—		—		22		22
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Collective trust—domestic equity measured at NAV (2)	—		—		—		—		—
Assets from price risk management activities: (1) (4)
Electricity	—		3		2		—		5
Natural gas	—		6		—		—		6
	$	10	$	26	$	2	$	22	$	60
Liabilities from price risk management activities: (1) (4)
Electricity	$	—	$	16	$	133	$	—	$	149
Natural gas	—		53		13		—		66
	$	—	$	69	$	146	$	—	$	215

(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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3) Excludes insurance policies of $26 million, which are recorded at cash surrender value.

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

	As of December 31, 2016
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	$	2	$	10	$	—	$	—	$	12
Corporate credit	—		8		—		—		8
Money market funds measured at NAV (2)	—		—		—		21		21
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV(2)	—		—		—		—		—
Collective trust—domestic equity measured at NAV (2)	—		—		—		2		2
Assets from price risk management activities: (1) (4)
Electricity	—		6		1		—		7
Natural gas	—		15		1		—		16
	$	8	$	39	$	2	$	23	$	72
Liabilities from price risk management activities: (1) (4)
Electricity	$	—	$	6	$	112	$	—	$	118
Natural gas	—		42		9		—		51
	$	—	$	48	$	121	$	—	$	169

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

(2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3) Excludes insurance policies of $26 million, which are recorded at cash surrender value.

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

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan (NQ Plan) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:

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 measurement 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 yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

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

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. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

The Nuclear decommissioning trust money market funds were valued at NAV as a practical expedient and not included in the fair value hierarchy. The NQ Plan money market funds are exchange traded government money market funds and are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE.

Common and collective trust funds—PGE invests in common and collective trust funds that invest in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) 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 forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term commodity forwards, futures, and swaps.

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2017:
Electricity physical forwards	$	—	$	132	Discounted cash flow	Electricity forward price (per MWh)	$	5.45	$	44.76	$	31.58
Natural gas financial swaps	—		13		Discounted cash flow	Natural gas forward price (per Decatherm)	1.57		3.43		2.14
Electricity financial futures	2		1		Discounted cash flow	Electricity forward price (per MWh)	8.20		29.86		20.42
	$	2	$	146
As of December 31, 2016:
Electricity physical forwards	$	—	$	112	Discounted cash flow	Electricity forward price (per MWh)	$	14.25	$	54.73	$	38.18
Natural gas financial swaps	1		9		Discounted cash flow	Natural gas forward price (per Decatherm)	1.85		4.92		2.64
Electricity financial futures	1		—		Discounted cash flow	Electricity forward price (per MWh)	8.57		33.60		25.10
	$	2	$	121

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. For shorter term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)

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

	Three Months Ended March 31,
	2017			2016
Balance as of the beginning of the period	$	119		119
Net realized and unrealized losses *	26			12
Transfers out of Level 3 to Level 2	(1		)	—
Balance as of the end of the period	$	144		$	131

* Both realized and unrealized losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the three month periods ended March 31, 2017 and 2016, 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 derivative instruments.

Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Revenue Bonds 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. The fair value of PGE’s unsecured term bank loans was classified as a Level 3 fair value measurement and was estimated based on the terms of the loans and PGE’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

As of March 31, 2017, the carrying amount of PGE’s long-term debt was $2,350 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,718 million, consisting of $2,568 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2016, the carrying amount of PGE’s long-term debt was $2,350 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.

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Price Risk Management (Notes)

3 Months Ended

Mar. 31, 2017

Price Risk Management [Abstract]

PRICE RISK MANAGEMENT

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 purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this ongoing business activity, 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 exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments may include forward, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the Public Utility Commission of Oregon (OPUC), the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes.

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

	March 31, 2017			December 31, 2016
Current assets:
Commodity contracts:
Electricity	$	3		$	6
Natural gas	6			12
Total current derivative assets	9		(1)	18		(1)
Noncurrent assets:
Commodity contracts:
Electricity	2			1
Natural gas	—			4
Total noncurrent derivative assets	2		(2)	5		(2)
Total derivative assets not designated as hedging instruments	$	11		$	23
Total derivative assets	$	11		$	23
Current liabilities:
Commodity contracts:
Electricity	$	24		$	12
Natural gas	35			32
Total current derivative liabilities	59			44
Noncurrent liabilities:
Commodity contracts:
Electricity	125			106
Natural gas	31			19
Total noncurrent derivative liabilities	156			125
Total derivative liabilities not designated as hedging instruments	$	215		$	169
Total derivative liabilities	$	215		$	169

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

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

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle through 2035, were as follows (in millions):

	March 31, 2017			December 31, 2016
Commodity contracts:
Electricity	8		MWh	8		MWh
Natural gas	101		Decatherms	107		Decatherms
Foreign currency	$	32	Canadian	$	22	Canadian

PGE has elected to report gross on the condensed consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of March 31, 2017 and December 31, 2016, gross amounts included as Price risk management liabilities subject to master netting agreements were $136 million and $115 million, respectively, for which PGE posted collateral of $11 million as of March 31, 2017 and December 31, 2016, which consisted entirely of letters of credit. As of March 31, 2017, of the gross amounts recognized, $132 million was for electricity and $4 million was for natural gas compared to $112 million for electricity and $3 million for natural gas recognized as of December 31, 2016.

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

	Three Months Ended March 31,
	2017		2016
Commodity contracts:
Electricity	$	33	$	25
Natural Gas	34		17
Foreign currency exchange	—		(1		)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income by the effects of regulatory accounting. Of the net losses (gains) recognized in Net income for the three month periods ended March 31, 2017 and 2016, net losses of $61 million and $34 million have been offset, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2017 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2017		2018		2019		2020		2021		Thereafter		Total
Commodity contracts:
Electricity	$	19	$	7	$	8	$	8	$	8	$	94	$	144
Natural gas	28		19		10		3		—		—		60
Net unrealized loss	$	47	$	26	$	18	$	11	$	8	$	94	$	204

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (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 derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2017 was $201 million, for which PGE has posted $16 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2017, the cash requirement to either post as collateral or settle the instruments immediately would have been $195 million. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheet.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:

	March 31, 2017		December 31, 2016
Assets from price risk management activities:
Counterparty A	43	%	22	%
Counterparty B	14		17
Counterparty C	7		12
	64	%	51	%
Liabilities from price risk management activities:
Counterparty D	61	%	66	%
	61	%	66	%

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

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Earnings Per Share (Notes)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three month period ended March 31, 2017, unvested performance-based restricted stock units and related dividend equivalent rights of approximately 274,000 were excluded from the dilutive calculation because the performance goals had not been met, with 304,000 excluded for the three month period ended March 31, 2016.

Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended March 31,
	2017	2016
Weighted-average common shares outstanding—basic and diluted	89,003	88,833

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Equity (Notes)

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

Equity

EQUITY

The activity in equity during the three months ended March 31, 2017 and 2016 is as follows (dollars in millions):

	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Shares	Amount									Total
Balances as of December 31, 2016	88,946,704	$	1,201		$	(7	)	$	1,150		$	2,344
Issuances of shares pursuant to equity-based plans	121,154	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(28		)	(28		)
Other comprehensive (loss)	—	—			(1		)	—			(1		)
Net income	—	—			—			73			73
Balances as of March 31, 2017	89,067,858	$	1,200		$	(8	)	$	1,195		$	2,387
Balances as of December 31, 2015	88,792,751	$	1,196		$	(8	)	$	1,070		$	2,258
Issuances of shares pursuant to equity-based plans	106,608	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(27		)	(27		)
Net income	—	—			—			61			61
Balances as of March 31, 2016	88,899,359	$	1,195		$	(8	)	$	1,104		$	2,291

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Contingencies (Notes)

3 Months Ended

Mar. 31, 2017

Contingencies [Abstract]

CONTINGENCIES

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 condensed consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

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

Carty

Background—The Company is involved in several litigation proceedings that involve claims concerning the Company’s termination of the construction agreement relating to the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon, and the payment obligations of two sureties who provided a performance bond in connection with such agreement. The Company is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the contractor and claims against the sureties pursuant to the performance bond. There are currently several lawsuits pending in U.S. District Court, as well as an arbitration proceeding before the International Chamber of Commerce (ICC). The Company is seeking to have all claims relating to this matter tried in U.S. District Court for the District of Oregon, but several procedural motions concerning jurisdiction remain pending as of the filing date of this report.

Arbitration Proceeding—In 2013, the Company entered into an agreement (Construction Agreement) with its engineering, procurement and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of Carty. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

On December 18, 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015.

On January 28, 2016, the Company received notice from the International Chamber of Commerce (ICC) International Court of Arbitration that Abengoa S.A. had submitted a request for arbitration. In the request, Abengoa S.A. alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to any liability of Abengoa S.A. under the terms of a guaranty in favor of PGE and pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the request for arbitration and on February 29, 2016 filed a complaint and motion for preliminary injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration. In addition, the Contractor has been joined as a party to the arbitration and is seeking damages of approximately $117 million based on a claim that PGE wrongfully terminated the Construction Agreement. The Contractor is also seeking estimated damages of $44 million based on a claim that PGE failed to disclose to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals, certain information regarding union labor productivity rates in eastern Oregon, and that this failure caused the Contractor to submit a bid with a contract price that was lower than the contract price that would have been submitted had Contractor known such information. PGE disagrees with both of these claims.

Bankruptcy Proceedings - On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries, including the four entities that collectively comprise the Contractor, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the Company’s District Court action against Abengoa S.A. was stayed. In early October 2016, the bankruptcy court in the Chapter 11 proceeding granted the Company’s motion for relief from stay with respect to the four entities that collectively comprise the Contractor, which allows the Company to bring claims against such entities in the U.S. District Court.

U.S. District Court Proceedings against Sureties - On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties make the following assertions in support of their determination:

1. that, because Abengoa S.A. has alleged that PGE wrongfully terminated the Construction Agreement, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and

2. that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

The Company disagrees with the foregoing assertions and, on March 23, 2016, filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty.

On April 15, 2016, the Sureties filed a motion to stay this U.S. District Court proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE opposed the motion and filed a motion to enjoin the Sureties from pursuing, in the ICC arbitration proceeding, claims relating to the Performance Bond. On July 27, 2016, the court denied the Sureties’ motion to stay and granted PGE’s motion for a preliminary injunction. The Sureties appealed the rulings to the Ninth Circuit Court of Appeals. On December 13, 2016, the Ninth Circuit issued an order staying the district court proceeding, pending a decision on the Sureties’ appeal.Oral argument on the Sureties’ appeal is scheduled for May 8, 2017.

U.S. District Court Proceedings against Contractor - On October 21, 2016, PGE filed a complaint in the U.S. District Court for the District of Oregon against Abeinsa for failure to satisfy its obligations under the Construction Agreement. PGE is seeking damages from Abeinsa in excess of $200 million for: i) costs incurred to complete construction of Carty, settle claims with unpaid contractors and vendors and remove liens; and ii) damages in excess of the construction costs, including a project management fee, liquidated damages under the Construction Agreement, legal fees and costs, damages due to delay of the project, warranty costs, and interest. On March 21, 2017, the U.S. District Court for the District of Oregon entered an order staying the case for 120 days.

Recovery of Capital Costs in Excess of $514 million—Following termination of the Construction Agreement, PGE brought on new contractors and resumed construction. Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, based on the approved cost of $514 million. Actual costs for Carty have exceeded the $514 millionapproved for inclusion in customer prices by the OPUC. As of March 31, 2017, PGE has capitalized $636 million for Carty classified as Electric utility plant. The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials. Costs also increased as a result of PGE’s discovery through the construction process of latent defects in work performed by the former Contractor and the corresponding labor and materials required to correct the work. Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage resulting from poor storage and maintenance on the part of the former Contractor.

PGE estimates the total cost of Carty will be approximately $640 million. This cost estimate does not reflect any offsetting amounts that may be received from the Sureties pursuant to the Performance Bond. This estimate also excludes approximately $14 million of lien claims filed against PGE for goods and services provided under contracts with the former Contractor. The Company believes these liens are invalid and is contesting the claims in the courts.

In the event the total project costs incurred by PGE, net of offsetting amounts that may be received from the Sureties, Abengoa S.A., or the Contractor, ultimately exceed the $514 million amount approved by the OPUC for inclusion in customer prices, the Company intends to seek approval to recover the excess amounts in customer prices in a subsequent rate proceeding after exhausting all remedies against the aforementioned parties. However, there is no assurance that such recovery would be allowed by the OPUC. In accordance with GAAP and the Company’s accounting policies, any such excess costs would be charged to expense at the time disallowance of recovery becomes probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood that a portion of the cost of Carty will be disallowed for recovery in customer prices is less than probable. Accordingly, no loss has been recorded to date related to the project.

As actual project costs for Carty exceed $514 million, the Company is incurring a higher cost than what is reflected in the current authorized revenue requirement amount, primarily due to higher depreciation and interest expense. On July 29, 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent General Rate Case (GRC) proceeding. The Company has requested that the OPUC delay its review of this deferral request until the Company’s claims against the Sureties have been resolved. Until such time, the effects of this higher cost are recognized in the Company’s results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP. Any amounts approved by the OPUC for recovery under the deferral filing will be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC. The Company believes that costs incurred to date and capitalized in Electric utility plant, net in the consolidated balance sheet were prudently incurred. There has been no settlement discussions with regulators related to such costs.

EPA Investigation of Portland Harbor

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

The Portland Harbor site remedial investigation (RI) has been completed 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. The LWG has funded the RI and feasibility study (FS) and has stated that it has incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

The EPA has finalized the FS, along with the RI, and these documents provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued on January 6, 2017. The ROD outlines the EPA’s selected remediation alternative to clean-up for Portland Harbor which has an estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.05 billion. As stated within the ROD, such cost ranges were estimated with an accuracy between -30% and +50% of actual costs. Remediation construction costs are estimated to be incurred over a 13 year period, with long-term operation and maintenance costs estimated to be incurred over a 30 year period from the start of construction. The Company anticipates that prior to the commencement of remediation activities, a phase of resampling of the river will be necessary to better refine the remedial design and may impact estimated costs.

PGE is participating in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including a final allocation methodology and data with regard to property specific activities and history of ownership of sites within Portland Harbor. Based on the above facts and remaining uncertainties, PGE cannot reasonably estimate its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor.

Where injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor Natural Resource Damages assessment (NRDA) process. The EPA does not manage NRDA activities, but provides claims information and coordination support to the Natural Resource Damages (NRD) trustees. Damage assessment activities are typically conducted by a Trustee Council made up of the trustee entities for the site. The Portland Harbor NRD trustees are the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, and certain tribal entities.

The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. The NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. PGE believes that the Company’s portion of NRDA liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

As discussed above, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of the Portland Harbor site, although such costs could be material. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

In July 2016, the Company filed a deferral application with the OPUC seeking the deferral of the future environmental remediation costs, as well as, seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, which the OPUC approved in the first quarter of 2017. The mechanism will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test.

Trojan Investment Recovery Class Actions

In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.

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

In August 2006, the OSC issued a ruling ordering the abatement of the class action proceedings. The Oregon Supreme Court (OSC) concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.

The OSC further stated that if the OPUC determined that it could provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The OSC added that, if the OPUC determined that it could not provide a remedy, the court system may have a role to play. The OSC also ruled that the plaintiffs retained the right to return to the Circuit Court for disposition of whatever issues remained unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC.

In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds of $33 million, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in February 2013 and by the OSC in October 2014.

In June 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. Following oral argument on PGE’s motion for Summary Judgment, the plaintiffs moved to amend the complaints. On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the complaint and on March 16, 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon.

PGE believes that the October 2, 2014 OSC decision and the recent Circuit Court decisions have reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain subject to a decision in the appeal, management believes that it is reasonably possible that a loss in excess of amounts previously recorded could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.

Deschutes River Alliance Clean Water Act Claims

On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company in the U.S. District Court of the District of Oregon. DRA’s claims seek injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleges the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project. The SWW, located above Round Butte Dam, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010 as part of the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat below the Project and harmed the economic and personal interests of DRA’s members and supporters.

On September 30, 2016, PGE filed a motion to dismiss, which asserted that the CWA does not allow citizen suits of this nature, and that FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 6, 2017, PGE filed a motion for certification to file an interlocutory appeal with the U.S. Ninth Circuit Court of Appeals and for a stay of the District Court proceeding. A court decision on that motion has not yet been issued. On April 7, 2017, the court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes) to appear in the case as Amicus Curiae (friend of the court). The Tribes share ownership of the Project with PGE, but have not been named as a defendant.

The Company cannot predict the outcome of this matter, but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because i) this matter involves novel issues of law and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time, determine the likelihood of whether the outcome of this matter will result in a material loss.

Other Matters

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

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Guarantees (Notes)

3 Months Ended

Mar. 31, 2017

Guarantees [Abstract]

GUARANTEES

GUARANTEES

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of March 31, 2017, 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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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2017

Basis of Presentation [Abstract]

Consolidation, Policy [Policy Text Block]

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations

Inventory, Policy [Policy Text Block]

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil, for use in its generating plants. Periodically, the Company assesses inventory for purposes of determining that inventory is recorded at the lower of average cost or net realizable value.

Debt, Policy [Policy Text Block]

PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Revenue Bonds 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. The fair value of PGE’s unsecured term bank loans was classified as a Level 3 fair value measurement and was estimated based on the terms of the loans and PGE’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

Fair Value of Financial Instruments, Policy [Policy Text Block]

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 2017 and December 31, 2016, and then classifies these financial assets and liabilities based on a fair value hierarchy that is used to prioritize the inputs to the valuation techniques used to measure fair value. The three levels and application to the Company are discussed below.

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy, instead these assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.

Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan (NQ Plan) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:

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 measurement 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 yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

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

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. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

The Nuclear decommissioning trust money market funds were valued at NAV as a practical expedient and not included in the fair value hierarchy. The NQ Plan money market funds are exchange traded government money market funds and are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE.

Common and collective trust funds—PGE invests in common and collective trust funds that invest in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) 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 forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument.

Fair Value Transfer, Policy [Policy Text Block]

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 derivative 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.

Derivatives, Policy [Policy Text Block]

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments may include forward, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the Public Utility Commission of Oregon (OPUC), the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes.

Commitments and Contingencies, Policy [Policy Text Block]

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 condensed consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

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

Guarantees, Indemnifications and Warranties Policies [Policy Text Block]

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.

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Balance Sheet Components (Tables)

3 Months Ended

Mar. 31, 2017

Balance Sheet Components [Abstract]

Schedule of Other Current Assets [Table Text Block]

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

	March 31, 2017		December 31, 2016
Prepaid expenses	$	58	$	48
Margin deposits	20		8
Assets from price risk management activities	9		18
Other	—		3
Other current assets	$	87	$	77

Schedule of Public Utility Property, Plant, and Equipment [Table Text Block]

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

	March 31, 2017			December 31, 2016
Electric utility plant	$	9,605		$	9,534
Construction work-in-progress	242			213
Total cost	9,847			9,747
Less: accumulated depreciation and amortization	(3,381		)	(3,313		)
Electric utility plant, net	$	6,466		$	6,434

Schedule of Regulatory Assets and Liabilities [Text Block]

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

	March 31, 2017					December 31, 2016
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	50		$	154	$	26		$	120
Pension and other postretirement plans	—			232		—			235
Deferred income taxes	—			83		—			86
Debt issuance costs	—			21		—			22
Other	7			42		10			35
Total regulatory assets	$	57		$	532	$	36		$	498
Regulatory liabilities:
Asset retirement removal costs	$	—		$	898	$	—		$	887
Trojan decommissioning activities	12			—		18			—
Asset retirement obligations	—			50		—			49
Other	30			25		33			22
Total regulatory liabilities	$	42	*	$	973	$	51	*	$	958

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Other Liabilities Disclosure [Text Block]

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

	March 31, 2017		December 31, 2016
Regulatory liabilities—current	$	42	$	51
Accrued employee compensation and benefits	41		52
Accrued interest payable	40		25
Accrued dividends payable	30		30
Accrued taxes payable	34		25
Other	60		71
Total accrued expenses and other current liabilities	$	247	$	254

Pension and Other Postretirement Benefits Disclosure [Text Block]

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):

	Three Months Ended March 31,
	2017			2016
Service cost	$	4		$	4
Interest cost	8			8
Expected return on plan assets	(10		)	(10		)
Amortization of net actuarial loss	3			4
Net periodic benefit cost	$	5		$	6

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value of Financial Instruments [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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 March 31, 2017
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	$	2	$	9	$	—	$	—	$	11
Corporate credit	—		8		—		—		8
Money market funds measured at NAV (2)	—		—		—		22		22
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Collective trust—domestic equity measured at NAV (2)	—		—		—		—		—
Assets from price risk management activities: (1) (4)
Electricity	—		3		2		—		5
Natural gas	—		6		—		—		6
	$	10	$	26	$	2	$	22	$	60
Liabilities from price risk management activities: (1) (4)
Electricity	$	—	$	16	$	133	$	—	$	149
Natural gas	—		53		13		—		66
	$	—	$	69	$	146	$	—	$	215

(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) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3) Excludes insurance policies of $26 million, which are recorded at cash surrender value.

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

	As of December 31, 2016
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	$	2	$	10	$	—	$	—	$	12
Corporate credit	—		8		—		—		8
Money market funds measured at NAV (2)	—		—		—		21		21
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV(2)	—		—		—		—		—
Collective trust—domestic equity measured at NAV (2)	—		—		—		2		2
Assets from price risk management activities: (1) (4)
Electricity	—		6		1		—		7
Natural gas	—		15		1		—		16
	$	8	$	39	$	2	$	23	$	72
Liabilities from price risk management activities: (1) (4)
Electricity	$	—	$	6	$	112	$	—	$	118
Natural gas	—		42		9		—		51
	$	—	$	48	$	121	$	—	$	169

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

(2) Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3) Excludes insurance policies of $26 million, which are recorded at cash surrender value.

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

Fair Value, Option, Quantitative Disclosures [Table Text Block]

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2017:
Electricity physical forwards	$	—	$	132	Discounted cash flow	Electricity forward price (per MWh)	$	5.45	$	44.76	$	31.58
Natural gas financial swaps	—		13		Discounted cash flow	Natural gas forward price (per Decatherm)	1.57		3.43		2.14
Electricity financial futures	2		1		Discounted cash flow	Electricity forward price (per MWh)	8.20		29.86		20.42
	$	2	$	146
As of December 31, 2016:
Electricity physical forwards	$	—	$	112	Discounted cash flow	Electricity forward price (per MWh)	$	14.25	$	54.73	$	38.18
Natural gas financial swaps	1		9		Discounted cash flow	Natural gas forward price (per Decatherm)	1.85		4.92		2.64
Electricity financial futures	1		—		Discounted cash flow	Electricity forward price (per MWh)	8.57		33.60		25.10
	$	2	$	121

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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

	Three Months Ended March 31,
	2017			2016
Balance as of the beginning of the period	$	119		119
Net realized and unrealized losses *	26			12
Transfers out of Level 3 to Level 2	(1		)	—
Balance as of the end of the period	$	144		$	131

* Both realized and unrealized losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income.

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Price Risk Management (Tables)

3 Months Ended

Mar. 31, 2017

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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

	March 31, 2017			December 31, 2016
Current assets:
Commodity contracts:
Electricity	$	3		$	6
Natural gas	6			12
Total current derivative assets	9		(1)	18		(1)
Noncurrent assets:
Commodity contracts:
Electricity	2			1
Natural gas	—			4
Total noncurrent derivative assets	2		(2)	5		(2)
Total derivative assets not designated as hedging instruments	$	11		$	23
Total derivative assets	$	11		$	23
Current liabilities:
Commodity contracts:
Electricity	$	24		$	12
Natural gas	35			32
Total current derivative liabilities	59			44
Noncurrent liabilities:
Commodity contracts:
Electricity	125			106
Natural gas	31			19
Total noncurrent derivative liabilities	156			125
Total derivative liabilities not designated as hedging instruments	$	215		$	169
Total derivative liabilities	$	215		$	169

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

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

Schedule of Derivative Instruments [Table Text Block]

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 2035, were as follows (in millions):

	March 31, 2017			December 31, 2016
Commodity contracts:
Electricity	8		MWh	8		MWh
Natural gas	101		Decatherms	107		Decatherms
Foreign currency	$	32	Canadian	$	22	Canadian

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

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

	Three Months Ended March 31,
	2017		2016
Commodity contracts:
Electricity	$	33	$	25
Natural Gas	34		17
Foreign currency exchange	—		(1		)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income by the effects of regulatory accounting.

Schedule of Price Risk Derivatives [Table Text Block]

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2017 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2017		2018		2019		2020		2021		Thereafter		Total
Commodity contracts:
Electricity	$	19	$	7	$	8	$	8	$	8	$	94	$	144
Natural gas	28		19		10		3		—		—		60
Net unrealized loss	$	47	$	26	$	18	$	11	$	8	$	94	$	204

Schedule of Concentration of Risk, by Counterparty [Table Text Block]

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:

	March 31, 2017		December 31, 2016
Assets from price risk management activities:
Counterparty A	43	%	22	%
Counterparty B	14		17
Counterparty C	7		12
	64	%	51	%
Liabilities from price risk management activities:
Counterparty D	61	%	66	%
	61	%	66	%

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended March 31,
	2017	2016
Weighted-average common shares outstanding—basic and diluted	89,003	88,833

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Equity (Tables)

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three months ended March 31, 2017 and 2016 is as follows (dollars in millions):

	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Shares	Amount									Total
Balances as of December 31, 2016	88,946,704	$	1,201		$	(7	)	$	1,150		$	2,344
Issuances of shares pursuant to equity-based plans	121,154	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(28		)	(28		)
Other comprehensive (loss)	—	—			(1		)	—			(1		)
Net income	—	—			—			73			73
Balances as of March 31, 2017	89,067,858	$	1,200		$	(8	)	$	1,195		$	2,387
Balances as of December 31, 2015	88,792,751	$	1,196		$	(8	)	$	1,070		$	2,258
Issuances of shares pursuant to equity-based plans	106,608	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(27		)	(27		)
Net income	—	—			—			61			61
Balances as of March 31, 2016	88,899,359	$	1,195		$	(8	)	$	1,104		$	2,291

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Basis of Presentation (Details) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) mi² retail_customers shares	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)
Basis of Presentation [Abstract]
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 72	$ 61
Service Area Sq Miles | mi²	4,000
Incorporated Cities	51
Number of Retail Customers | retail_customers	865,000
Service Area Population | shares	1.9
Percent of State's Population	46.00%
Decoupling Mechanism Deferrals, Net	$ 9	4
Repayments of Long-term Capital Lease Obligations		1
Other Comprehensive Income	1
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	(1)	0
Unamortized Debt Issuance Expense	$ 11	$ 1	$ 11

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Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Other Current Assets [Line Items]
Prepaid expenses	$ 58	$ 48
Margin deposits	20	8
Assets from price risk management activities	9	18
Other	0	3
Other current assets	$ 87	$ 77

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Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Amortization of Intangible Assets	$ 11
Electric utility plant		$ 9,605	$ 9,534
Construction work-in-progress		242	213
Total cost		9,847	9,747
Less: accumulated depreciation and amortization		(3,381)	(3,313)
Electric utility plant, net		$ 6,466	$ 6,434

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Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Price risk management	$ 50	$ 26
Pension and other postretirement plans	0	0
Deferred income taxes	0	0
Debt issuance costs	0	0
Other	7	10
Total regulatory assets	57	36
Noncurrent Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Price risk management	154	120
Pension and other postretirement plans	232	235
Deferred income taxes	83	86
Debt issuance costs	21	22
Other	42	35
Total regulatory assets	532	498
Current Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Asset retirement removal costs	0	0
Trojan decommissioning activities	12	18
Asset retirement obligations	0	0
Other	30	33
Total regulatory liabilities	42	51
Noncurrent Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Asset retirement removal costs	898	887
Trojan decommissioning activities	0	0
Asset retirement obligations	50	49
Other	25	22
Total regulatory liabilities	$ 973	$ 958

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Regulatory liabilities—current	$ 42	$ 51
Accrued employee compensation and benefits	41	52
Accrued interest payable	40	25
Accrued dividends payable	30	30
Accrued taxes payable	34	25
Other	60	71
Total accrued expenses and other current liabilities	$ 247	$ 254

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4	$ 4
Interest cost	8	8
Expected return on plan assets	(10)	(10)
Amortization of net actuarial loss	3	4
Net periodic benefit cost	$ 5	$ 6

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Balance Sheet Components (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Jun. 30, 2016	May 04, 2016
Valuation and Qualifying Accounts Disclosure [Line Items]
Finite-Lived Intangible Assets, Accumulated Amortization	$ 265,000,000		$ 257,000,000
Amortization of Intangible Assets		$ 11,000,000
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes	514,000,000
Syndicated credit facility scheduled to expire in 2019	$ 500,000,000
Debt Instrument, Covenant Description	0.65
Ratio of Indebtedness to Net Capital	0.506
Short-term debt	$ 0
Line of Credit Facility, Remaining Borrowing Capacity	500,000,000
Line of Credit Facility, Current Borrowing Capacity	160,000,000
Letters of credit issued	56,000,000
Authorized Short-Term Debt	$ 900,000,000
Debt Instrument, Redemption, Description	200
Proceeds from Issuance of Long-term Debt			$ 25,000,000	$ 75,000,000	$ 50,000,000
Unsecured term bank loan rate - minimum	1.60%
Extinguishment of Debt, Amount	$ 0	$ 133,000,000

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Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt securities:
Domestic government	$ 11	$ 12
Corporate credit	8	8
Money market funds	22	21
Non-qualified benefit plan trust: (2)
Fair Value - Money market funds	1	1
Domestic	6	4
Debt securities—domestic government	1	1
Investments, Fair Value Disclosure	0	2
Alternative Investments, Fair Value Disclosure		0
Assets from price risk management activities: (1) (3)
Electricity	5	7
Natural gas	6	16
Total	22	23
Assets, Fair Value Disclosure	60	72
Liabilities from price risk management activities: (1) (3)
Electricity	149	118
Natural gas	66	51
Total	215	169
Fair Value, Inputs, Level 1 [Member]
Debt securities:
Domestic government	2	2
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Fair Value - Money market funds	1	1
Domestic	6	4
Debt securities—domestic government	1	1
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	10	8
Liabilities from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Debt securities:
Domestic government	9	10
Corporate credit	8	8
Non-qualified benefit plan trust: (2)
Fair Value - Money market funds		0
Domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	3	6
Natural gas	6	15
Total	26	39
Liabilities from price risk management activities: (1) (3)
Electricity	16	6
Natural gas	53	42
Total	69	48
Fair Value, Inputs, Level 3 [Member]
Debt securities:
Domestic government	0	0
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Fair Value - Money market funds		0
Domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	2	1
Natural gas	0	1
Total	2	2
Liabilities from price risk management activities: (1) (3)
Electricity	133	112
Natural gas	13	9
Total	$ 146	$ 121

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Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Low [Member]
Commodity Contracts
Electricity physical forward	$ 5.45	$ 14.25
Natural gas financial swaps	1.57	1.85
Fnancial swaps - electricity	8.20	8.57
High [Member]
Commodity Contracts
Electricity physical forward	44.76	54.73
Natural gas financial swaps	3.43	4.92
Fnancial swaps - electricity	29.86	33.60
Weighted Average [Member]
Commodity Contracts
Electricity physical forward	31.58	38.18
Natural gas financial swaps	2.14	2.64
Fnancial swaps - electricity	20.42	25.10
Assets [Member]
Commodity Contracts
Electricity physical forward	0	0
Natural gas financial swaps	0	1,000,000
Fnancial swaps - electricity	2,000,000	1,000,000
Total commodity contracts	2,000,000	2,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forward	132,000,000	112,000,000
Natural gas financial swaps	13,000,000	9,000,000
Fnancial swaps - electricity	1,000,000	0
Total commodity contracts	$ 146,000,000	$ 121,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 119	$ 119
Net realized and unrealized losses (gains)	26	12
Transfers out of Level 3 to Level 2	(1)	0
Balance as of the end of the period	$ 144	$ 131

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0	$ 0
Cash Surrender Value, Fair Value Disclosure	26,000,000		$ 26,000,000
Long-term Debt	2,350,000,000		2,350,000,000
Unamortized Debt Issuance Expense	11,000,000	1,000,000	11,000,000
Long-term Debt, Fair Value	2,718,000,000		2,693,000,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3		$ 0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	2,568,000,000		2,543,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	$ 150,000,000		$ 150,000,000

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Price Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets, Commodity Contracts:
Electricity	$ 3	$ 6
Natural gas	6	12
Total current derivative assets	9	18
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Natural Gas	0	4
Commodity Contract Asset, Noncurrent, Electricity	2	1
Total noncurrent derivative assets	2	5
Total derivative assets not designated as hedging instruments	11	23
Total derivative assets	11	23
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	24	12
Natural gas	35	32
Total current derivative liabilities	59	44
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	125	106
Natural gas	31	19
Total noncurrent derivative liabilities	156	125
Total derivative liabilities not designated as hedging instruments	215	169
Total derivative liabilities	$ 215	$ 169

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Price Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, CAD in Millions	Mar. 31, 2017 CAD MMBTU MWh	Dec. 31, 2016 CAD MMBTU MWh
Commodity contracts:
Electricity | MWh	8	8
Natural gas | MMBTU	101	107
Foreign currency | CAD	CAD 32	CAD 22

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Price Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Commodity contracts:
Electricity	$ 33	$ 25
Natural Gas	34	17
Derivative, Forward Exchange Rate	$ 0	$ (1)

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Price Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Mar. 31, 2017 USD ($)
Electricity [Member]
Commodity contracts:
2016	$ 19
2017	7
2018	8
2019	8
2020	8
Thereafter	94
Total	144
Natural Gas [Member]
Commodity contracts:
2016	28
2017	19
2018	10
2019	3
2020	0
Thereafter	0
Total	60
Net Unrealized Loss [Member]
Commodity contracts:
2016	47
2017	26
2018	18
2019	11
2020	8
Thereafter	94
Total	$ 204

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Price Risk Management Counterparties Representing 10% or More of Assets and Liabilities from price risk management activities (Details)	Mar. 31, 2017	Dec. 31, 2016
Assets from price risk management activities:
Counterparty A	43.00%	22.00%
Counterparty B	14.00%	17.00%
Counterparty C	7.00%	12.00%
Total	64.00%	51.00%
Liabilities from price risk management activities:
Counterparty D	61.00%	66.00%
Total	61.00%	66.00%

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Price Risk Management Price Risk Management (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	$ 11
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	61	$ 34
Derivative, Net Liability Position, Aggregate Fair Value	201
Collateral Posted, Aggregate Fair Value	16		$ 11
Collateral cash requirement	195
Natural Gas [Member]
Derivative Instruments and Hedges, Liabilities	4		3
4911 Electric Services [Member]
Derivative Instruments and Hedges, Liabilities	132		112
Liabilities, Total [Member]
Derivative Instruments and Hedges, Liabilities	$ 136		$ 115

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Earnings Per Share Components of Earnings Per Share (Details) - shares	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	274,000	304,000
Weighted Average Number of Shares Outstanding, Basic and Diluted	89,003,000	88,833,000

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Schedule of Stockholders Equity (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	$ (1)	$ 0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	$ (1)
Common Stock, Shares, Outstanding beginning of period	88,946,704
Issuance of shares pursuant to equity-based plans	$ 0	0
Adjustments Related to Tax Withholding for Share-based Compensation	(1)	(1)
Stockholders' Equity	2,344	2,258
Dividends declared	(28)	(27)
Net Income	$ 73	61
Common Stock, Shares, Outstanding end of period	89,067,858
Stockholders' Equity	$ 2,387	$ 2,291
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	88,946,704	88,792,751
Issuances of shares pursuant to equity-based plans	121,154	106,608
Common Stock, Shares, Outstanding end of period	89,067,858	88,899,359
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 0	$ 0
Adjustments Related to Tax Withholding for Share-based Compensation	1	1
Stockholders' Equity	1,201	1,196
Dividends declared	0	0
Stockholders' Equity	1,200	1,195
AOCI Attributable to Parent [Member]
Stockholders' Equity	(7)	(8)
Stock-based compensation	0	0
Dividends declared	0	0
Stockholders' Equity	(8)	(8)
Retained Earnings [Member]
Stockholders' Equity	1,150	1,070
Stock-based compensation	0	0
Dividends declared	(28)	(27)
Net Income	73	61
Stockholders' Equity	$ 1,195	$ 1,104

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Contingencies (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 1997	Dec. 31, 2016	Sep. 30, 2008	Dec. 31, 1993
Loss Contingencies [Line Items]
Investment in Trojan					87.00%
Refund to customers for Trojan Investment including interest				$ 33.0
Class action damages sought	$ 260.0
Site Contingency, Names of Other Potentially Responsible Parties	100	69
Litigation Settlement, Expense	$ 115.0
Loss Contingency, Estimate of Possible Loss	1,700.0
Malpractice Loss Contingency, Letters of Credit and Surety Bonds	145.6
Gain Contingency, Unrecorded Amount	200.0
Loss Contingency, Damages Sought, Value	1,200.0
Loss Contingency, Range of Possible Loss, Portion Not Accrued			$ 500.0
Public Utilities, Property, Plant and Equipment, Amount of Construction Work in Process Included in Rate Base	514.0
Construction in Progress, Gross	636.0
Liability for Title Claims and Claims Adjustment Expense	14.0
Construction work-in-progress	242.0		$ 213.0
Minimum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	1,100.0
Loss Contingency, Damages Sought, Value	44.0
Construction work-in-progress	640.0
Maximum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 117.0