10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2020

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) 

Securities registered pursuant to Section 12(b) of the Act:

(Title of class)	(Trading Symbol)	(Name of exchange on which registered)
Common Stock, no par value	POR	New York Stock Exchange
9.31% Medium-Term Notes due 2021	POR 21	New York Stock Exchange

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 every Interactive Data File required to be submitted 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 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	☒	Accelerated filer	☐
Non-accelerated filer	☐	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 July 27, 2020 is 89,508,545 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2020

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	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56
Item 4.	Controls and Procedures	56
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 6.	Exhibits	57
SIGNATURE		58

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
Colstrip	Colstrip Units 3 and 4 coal-fired generating plant
EPA	United States Environmental Protection Agency
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 hour
Nasdaq	National Association of Securities Dealers Automated Quotations
NVPC	Net Variable Power Costs
NYSE	New York Stock Exchange
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
Wheatridge	Wheatridge Renewable Energy Facility

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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Revenues:
Revenues, net	$	469	$	462	$	1,033	$	1,032
Alternative revenue programs, net of amortization	—		(2)		9		1
Total revenues	469		460		1,042		1,033
Operating expenses:
Purchased power and fuel	109		105		262		284
Generation, transmission and distribution	77		86		150		163
Administrative and other	74		78		145		149
Depreciation and amortization	104		101		212		202
Taxes other than income taxes	34		33		69		67
Total operating expenses	398		403		838		865
Income from operations	71		57		204		168
Interest expense, net	34		31		67		63
Other income:
Allowance for equity funds used during construction	4		2		7		5
Miscellaneous income (loss), net	3		—		(1)		2
Other income, net	7		2		6		7
Income before income tax expense	44		28		143		112
Income tax expense	5		3		23		14
Net income	39		25		120		98
Other comprehensive income	—		1		1		2
Comprehensive income	$	39	$	26	$	121	$	100
Weighted-average common shares outstanding (in thousands):
Basic	89,489		89,357		89,459		89,333
Diluted	89,625		89,561		89,602		89,537
Earnings per share:
Basic	$	0.44	$	0.28	$	1.34	$	1.10
Diluted	$	0.43	$	0.28	$	1.34	$	1.09
See accompanying notes to condensed consolidated financial statements.

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)

	June 30, 2020		December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	303	$	30
Accounts receivable, net	204		253
Inventories	109		96
Regulatory assets—current	12		17
Other current assets	108		104
Total current assets	736		500
Electric utility plant, net	7,301		7,161
Regulatory assets—noncurrent	526		483
Nuclear decommissioning trust	47		46
Non-qualified benefit plan trust	37		38
Other noncurrent assets	158		166
Total assets	$	8,805	$	8,394
See accompanying notes to condensed consolidated financial statements.

5

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)

	June 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	134	$	165
Liabilities from price risk management activities—current	40		23
Short-term debt	150		—
Current portion of long-term debt	140		—
Current portion of finance lease obligation	16		16
Accrued expenses and other current liabilities	289		315
Total current liabilities	769		519
Long-term debt, net of current portion	2,676		2,597
Regulatory liabilities—noncurrent	1,362		1,377
Deferred income taxes	385		378
Unfunded status of pension and postretirement plans	249		247
Liabilities from price risk management activities—noncurrent	145		108
Asset retirement obligations	265		263
Non-qualified benefit plan liabilities	101		103
Finance lease obligations, net of current portion	132		135
Other noncurrent liabilities	75		76
Total liabilities	6,159		5,803
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2020 and December 31, 2019	—		—
Common stock, no par value, 160,000,000 shares authorized; 89,506,951 and 89,387,124 shares issued and outstanding as of June 30, 2020 and December 31, 2019, respectively	1,224		1,220
Accumulated other comprehensive loss	(9)		(10)
Retained earnings	1,431		1,381
Total shareholders’ equity	2,646		2,591
Total liabilities and shareholders’ equity	$	8,805	$	8,394
See accompanying notes to condensed consolidated financial statements.

6

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Six Months Ended June 30,
	2020		2019
Cash flows from operating activities:
Net income	$	120	$	98
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	212		202
Deferred income taxes	4		6
Pension and other postretirement benefits	12		12
Allowance for equity funds used during construction	(7)		(5)
Decoupling mechanism deferrals, net of amortization	(8)		(1)
(Amortization) of net benefits due to Tax Reform	(11)		(11)
Other non-cash income and expenses, net	46		21
Changes in working capital:
Decrease in accounts receivable, net	40		63
(Increase) in inventories	(13)		(17)
(Increase)/decrease in margin deposits	(9)		11
(Decrease) in accounts payable and accrued liabilities	(27)		(65)
Other working capital items, net	18		16
Other, net	(21)		(16)
Net cash provided by operating activities	356		314
Cash flows from investing activities:
Capital expenditures	(370)		(271)
Sales of Nuclear decommissioning trust securities	4		7
Purchases of Nuclear decommissioning trust securities	(3)		(5)
Other, net	(1)		(2)
Net cash used in investing activities	(370)		(271)

7

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)

	Six Months Ended June 30,
	2020		2019
Cash flows from financing activities:
Proceeds from issuance of long-term debt	319		200
Payments on long-term debt	(98)		(300)
Borrowings on short-term debt	200		—
Repayments of short-term debt	(50)		—
Issuance of commercial paper, net	—		17
Dividends paid	(69)		(65)
Other	(15)		(3)
Net cash provided by (used in) financing activities	287		(151)
Increase (Decrease) in cash and cash equivalents	273		(108)
Cash and cash equivalents, beginning of period	30		119
Cash and cash equivalents, end of period	$	303	$	11
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	56	$	60
Cash paid for income taxes	5		20
See accompanying notes to condensed consolidated financial statements.

8

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to provide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 4,000 square mile, state-approved service area encompasses 51 incorporated cities entirely within the State of Oregon. As of June 30, 2020, PGE served 901,000 retail customers within a service area of 1.9 million residents.

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.

The financial information included herein as of and for the three and six months ended June 30, 2020 and 2019 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 2019 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2019, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 14, 2020, which should be read in conjunction with the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three and six months ended June 30, 2020 and 2019.

Use of Estimates

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

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.

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Recent Accounting Pronouncements

In August 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans. ASU 2018-14 amends Topic 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. This update will be effective for fiscal years ending after December 15, 2020. Because the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements.

Recently Adopted Accounting Pronouncements

On January 1, 2020, PGE adopted ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. ASU 2018-13 amends Topic 820 to add, remove, and clarify requirements related to fair value measurement disclosures. Because the standard relates only to disclosures, the implementation did not result in an impact to the results of operation, financial position, or cash flows.

On January 1, 2020, PGE adopted ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. ASU 2018-15 provides guidance on implementation costs incurred in a cloud computing arrangement that is a service contract and aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. PGE applied the amendments of this ASU prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows.

On January 1, 2020, PGE adopted ASU 2016-13 Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ASU 2016-13 replaces the incurred loss impairment methodology in previous GAAP with a methodology that reflects expected credit losses, and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. PGE applied this ASU using a modified-retrospective approach, and as a result, amounts recorded prior to January 1, 2020 have not been retrospectively restated. Under the new standard, PGE estimates current expected credit losses for retail sales based on an assessment of the current and forecasted probability of collection, aging of accounts receivable, bad debt write-offs experience, actual customer billings, economic conditions, and other significant events that may impact the collectability of accounts receivable and unbilled revenues. Provisions for current expected credit losses related to retail sales, and changes to the amount of expected credit losses for existing receivables, are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for credit losses. The implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows. To conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net on the condensed consolidated balance sheets as of December 31, 2019.

On April 1, 2020, PGE adopted ASU 2020-04 Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. ASU 2020-04 provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PGE applied the amendments of this ASU prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows.

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

The following table presents PGE’s revenue, disaggregated by customer type (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Retail:
Residential	$	223	$	205	$	502	$	495
Commercial	140		158		299		312
Industrial	53		50		104		94
Direct access customers	12		10		23		21
Subtotal	428		423		928		922
Alternative revenue programs, net of amortization	—		(2)		9		1
Other accrued revenues, net	1		6		6		13
Total retail revenues	429		427		943		936
Wholesale revenues*	27		16		74		53
Other operating revenues	13		17		25		44
Total revenues	$	469	$	460	$	1,042	$	1,033

* Wholesale revenues include $8 million and $2 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2020 and 2019, respectively, and $24 million and $13 million for the six months ended June 30, 2020 and 2019, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated, tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single-family housing, multiple-family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than residential customers. Commercial customers include most businesses, small industrial companies, and public street and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on energy use by this customer class.

In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and determined through general rate case proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.

Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that have not yet been billed to customers. This amount, classified as Unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.

11

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.

Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and are not reflected in Revenues, net within the condensed consolidated statements of income and comprehensive income.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power; hydro, solar and wind conditions; and daily and seasonal retail demand.

PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and other services provided to customers.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers.

12

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 3: 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 the Company’s generating plants. Periodically, the Company assesses whether inventories are recorded at the lower of average cost or net realizable value.

Accounts Receivable, Net

Accounts receivable, net includes $74 million and $86 million of unbilled revenues as of June 30, 2020 and December 31, 2019, respectively. Accounts receivable, net is net of an allowance for credit losses of $12 million as of June 30, 2020. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
Balance as of beginning of period	$	6	$	5
Increase in provision	7		9
Amounts written off	(3)		(6)
Recoveries	2		4
Balance as of end of period	$	12	$	12

In connection with the adoption of ASU 2016-13 and to conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net on the condensed consolidated balance sheets as of December 31, 2019.

Other Current Assets

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

	June 30, 2020		December 31, 2019
Prepaid expenses	$	37	$	63
Assets from price risk management activities	46		25
Margin deposits	25		16
Other current assets	$	108	$	104

Electric Utility Plant, Net

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

	June 30, 2020		December 31, 2019
Electric utility plant	$	11,163	$	10,928
Construction work-in-progress	376		328
Total cost	11,539		11,256
Less: accumulated depreciation and amortization	(4,238)		(4,095)
Electric utility plant, net	$	7,301	$	7,161

13

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 $397 million and $366 million as of June 30, 2020 and December 31, 2019, respectively. Amortization expense related to intangible assets was $31 million and $33 million for the six months ended June 30, 2020 and 2019, respectively, and $16 million and $17 million for the three months ended June 30, 2020 and 2019, respectively. 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):

	June 30, 2020					December 31, 2019
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	135	$	—		$	95
Pension and other postretirement plans	—			204		—			213
Debt issuance costs	—			27		—			26
Trojan decommissioning activities	—			94		—			94
Other	12			66		17			55
Total regulatory assets	$	12		$	526	$	17		$	483
Regulatory liabilities:
Asset retirement removal costs	$	—		$	996	$	—		$	1,021
Deferred income taxes	—			256		—			260
Asset retirement obligations	—			55		—			54
Tax Reform deferral	12			—		23			—
Other	28			55		21			42
Total regulatory liabilities	$	40	*	$	1,362	$	44	*	$	1,377

* 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):

	June 30, 2020		December 31, 2019
Accrued employee compensation and benefits	$	63	$	74
Accrued taxes payable	31		33
Accrued interest payable	27		25
Accrued dividends payable	36		36
Regulatory liabilities—current	40		44
Other	92		103
Total accrued expenses and other current liabilities	$	289	$	315

Credit Facilities

As of June 30, 2020, PGE had a $500 million revolving credit facility scheduled to expire in November 2023. The Company has the ability to expand the revolving credit facility to $600 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 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 June 30, 2020, PGE was in compliance with this covenant with a 54.4% 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. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay any commercial paper that may be outstanding at the time.

PGE typically classifies 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 June 30, 2020, PGE had no commercial paper outstanding. As a result, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. 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 $46 million were outstanding as of June 30, 2020. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate principal of $150 million. The term loan bears interest for the relevant interest period at LIBOR plus 1.25%. The interest rate is subject to adjustment pursuant to the terms of the loan. The credit agreement is classified as Short-term debt on the Company’s condensed consolidated balance sheets and expires on April 8, 2021, with any outstanding balance due and payable on such date.

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 7, 2022.

Long-term Debt

On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of PCRBs that will bear an interest rate of 2.125%, and $21 million aggregate principal of PCRBs that will bear an interest rate of 2.375%, both due in 2033.

On April 27, 2020, PGE issued $200 million of 3.15% Series First Mortgage Bonds (FMBs) due in 2030.

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(Unaudited)

Defined Benefit Retirement Plan Costs

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	4	$	4	$	8	$	8
Interest cost*	8		9		16		17
Expected return on plan assets*	(11)		(10)		(22)		(20)
Amortization of net actuarial loss*	4		2		8		5
Net periodic benefit cost	$	5	$	5	$	10	$	10

* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of June 30, 2020 and December 31, 2019. PGE then classifies these financial assets and liabilities based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:

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; and
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 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. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

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.

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(Unaudited)

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

	As of June 30, 2020
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	293	$	—	$	—	$	—	$	293
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	7		12		—		—		19
Corporate credit	—		15		—		—		15
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Price risk management activities: (1) (4)
Electricity	—		28		—		—		28
Natural gas	—		25		3		—		28
	$	308	$	80	$	3	$	13	$	404
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	19	$	154	$	—	$	173
Natural gas	—		12		—		—		12
	$	—	$	31	$	154	$	—	$	185

(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 $29 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

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(Unaudited)

	As of December 31, 2019
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	26	$	—	$	—	$	—	$	26
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	8		16		—		—		24
Corporate credit	—		9		—		—		9
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	1		—		—		—		1
Money market funds	1		—		—		—		1
Equity securities	7		—		—		—		7
Price risk management activities: (1) (4)
Electricity	—		9		7		—		16
Natural gas	—		21		1		—		22
	$	43	$	55	$	8	$	13	$	119
Liabilities:
Price risk management activities: (1) (4)
Electricity	—		14		105		—		119
Natural gas	—		12		—		—		12
	$	—	$	26	$	105	$	—	$	131

(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 $29 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of securities holdings of such funds not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. Cash equivalents 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 money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (NASDAQ) and the New York Stock Exchange (NYSE).

Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) 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.

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(Unaudited)

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 NYSE.

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 NQBP trust is invested in exchange-traded government money market funds and is 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. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.

Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates 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 5, 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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(Unaudited)

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 June 30, 2020
Electricity physical forwards	$	—	$	147	Discounted cash flow	Electricity forward price (per MWh)	$	2.69	$	38.84	$	29.51
Natural gas financial swaps	3		—		Discounted cash flow	Natural gas forward price (per Decatherm)	1.44		3.91		2.12
Electricity financial futures	—		7		Discounted cash flow	Electricity forward price (per MWh)	13.25		51.03		36.29
	$	3	$	154
As of December 31, 2019
Electricity physical forwards	$	—	$	104	Discounted cash flow	Electricity forward price (per MWh)	$	12.53	$	59.00	$	36.92
Natural gas financial swaps	1		—		Discounted cash flow	Natural gas forward price (per Decatherm)	1.39		3.73		1.90
Electricity financial futures	7		1		Discounted cash flow	Electricity forward price (per MWh)	10.57		66.32		45.11
	$	8	$	105

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 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 long-term price curves that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices.

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 under 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
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):

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(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Balance as of the beginning of the period	$	134	$	70	$	97	$	88
Net realized and unrealized losses/(gains)*	17		3		56		(16)
Transfers from Level 3 to Level 2	—		(1)		(2)		—
Balance as of the end of the period	$	151	$	72	$	151	$	72

* Both realized and unrealized losses/(gains), 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 and comprehensive income.

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.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and PCRBs is classified as a Level 2 fair value measurement.

As of June 30, 2020, the carrying amount of PGE’s long-term debt was $2,816 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,508 million. As of December 31, 2019, the carrying amount of PGE’s long-term debt was $2,597 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $3,039 million.

NOTE 5: RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace 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. Wholesale market transactions 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 to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forwards, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the 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.

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(Unaudited)

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

	June 30, 2020		December 31, 2019
Current assets:
Commodity contracts:
Electricity	$	28	$	9
Natural gas	18		16
Total current derivative assets(1)	46		25
Noncurrent assets:
Commodity contracts:
Electricity	—		7
Natural gas	10		6
Total noncurrent derivative assets(1)	10		13
Total derivative assets(2)	$	56	$	38
Current liabilities:
Commodity contracts:
Electricity	$	30	$	14
Natural gas	10		9
Total current derivative liabilities	40		23
Noncurrent liabilities:
Commodity contracts:
Electricity	143		105
Natural gas	2		3
Total noncurrent derivative liabilities	145		108
Total derivative liabilities(2)	$	185	$	131

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.

(2) As of June 30, 2020 and December 31, 2019, no derivative assets or liabilities were designated as hedging instruments.

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 at various dates through 2035, were as follows (in millions):

	June 30, 2020			December 31, 2019
Commodity contracts:
Electricity	8		MWhs	6		MWhs
Natural gas	147		Decatherms	145		Decatherms
Foreign currency	$	21	Canadian	$	23	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such 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 June 30, 2020, gross amounts included as Price risk management liabilities subject to

22

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

master netting agreements was $2 million, comprised solely of natural gas contracts for which PGE posted no collateral. As of December 31, 2019, PGE had no material master netting arrangements.

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 comprehensive income and were as follows (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Commodity contracts:
Electricity	$	15	$	6	$	47	$	(18)
Natural Gas	(13)		21		(4)		(4)
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 and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended June 30, 2020 and 2019, net gains of $1 million and net losses of $30 million, respectively, have been offset. Net losses of $41 million and net gains of $19 million have been offset for the six months ended June 30, 2020 and 2019, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 2020 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2020		2021		2022		2023		2024		Thereafter		Total
Commodity contracts:
Electricity	$	(6)	$	16	$	8	$	8	$	8	$	111	$	145
Natural gas	(1)		(13)		(2)		—		—		—		(16)
Net unrealized loss	$	(7)	$	3	$	6	$	8	$	8	$	111	$	129

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 or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE 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 June 30, 2020 was $161 million, for which PGE has posted $6 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2020, the cash requirement to either post as collateral or settle the instruments immediately would have been $151 million. As of June 30, 2020, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. 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:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

	June 30, 2020		December 31, 2019
Assets from price risk management activities:
Counterparty A	37	%	35	%
Counterparty B	11		13
Counterparty C	11		11
Counterparty D	9		11
	68	%	70	%
Liabilities from price risk management activities:
Counterparty E	79	%	79	%

See Note 4, 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 6: 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 and six months ended June 30, 2020, unvested performance-based restricted stock units and related dividend equivalent rights of 303 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 267 thousand shares excluded for the three and six months ended June 30, 2019.

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
Weighted-average common shares outstanding—basic	89,489	89,357	89,459	89,333
Dilutive effect of potential common shares	136	204	143	204
Weighted-average common shares outstanding—diluted	89,625	89,561	89,602	89,537

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(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three and six-month periods ended June 30, 2020 and 2019 was as follows (dollars in millions, except per share amounts):

	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings
	Shares	Amount						Total
Balances as of December 31, 2019	89,387,124	$	1,220	$	(10)	$	1,381	$	2,591
Issuances of shares pursuant to equity-based plans	77,397	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		81		81
Balances as of March 31, 2020	89,464,521	1,220		(9)		1,427		2,638
Issuances of shares pursuant to equity-based plans	42,430	1		—		—		1
Stock-based compensation	—	3		—		—		3
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		39		39
Balances as of June 30, 2020	89,506,951	$	1,224	$	(9)	$	1,431	$	2,646
Balances as of December 31, 2018	89,267,959	$	1,212	$	(7)	$	1,301	$	2,506
Issuances of shares pursuant to equity-based plans	88,352	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3625 per share)	—	—		—		(32)		(32)
Net income	—	—		—		73		73
Reclassification of stranded tax effects due to Tax Reform	—	—		(2)		2		—
Balances as of March 31, 2019	89,356,311	1,212		(8)		1,344		2,548
Issuances of shares pursuant to equity-based plans	15,249	1		—		—		1
Stock-based compensation	—	2		—		—		2
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		25		25
Balances as of June 30, 2019	89,371,560	$	1,215	$	(7)	$	1,334	$	2,542

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(Unaudited)

NOTE 8: 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. Costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

PGE 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, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

EPA Investigation of Portland Harbor

An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 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 as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.

A Portland Harbor site remedial investigation was completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had 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.

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(Unaudited)

The EPA finalized the feasibility study, along with the remedial investigation, and the results 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 in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of Portland Harbor, which has an undiscounted 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. Remediation construction costs were 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 EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost.

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of Portland Harbor have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs have entered into consent agreements, or are in good-faith discussion with the EPA, to perform remedial design, and if the EPA deems necessary, it has communicated it would issue Special Notice Letters to enforce action of remedial design.

PGE continues to participate 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, including the remedial design process, data with regard to property specific activities, and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up, assignment of responsibility for clean-up costs, and whether the ROD will be implemented as issued. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position.

In cases in which 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 (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe.

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 Company believes that PGE’s portion of NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

The impact of costs related to EPA and NRD liabilities on the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account mechanism (PHERA). As approved by the OPUC in 2017,

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

the PHERA allows the Company to defer and recover incurred environmental expenditures related to Portland Harbor through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million, excluding expenses related to contingent liabilities, are subject to an annual earnings test and would be ineligible for recovery to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent general rate case. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices.

Trojan Investment Recovery Class Actions

In 2003, in two separate proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers as a result of OPUC actions arising from PGE’s closure of the Trojan nuclear power plant in 1993: i) Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court (Circuit Court); and ii) Morgan v. Portland General Electric Company, Marion County Circuit Court. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In 2006, the Oregon Supreme Court (OSC) issued a ruling ordering abatement of the class action proceedings. The 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.

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

In 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement on the class action proceedings and heard oral argument on the Company’s motion for Summary Judgment. In 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. The plaintiffs subsequently appealed the Circuit Court dismissal to the Court of Appeals for the state of Oregon.

In November 2019, the Court of Appeals issued an opinion that affirmed the Circuit Court dismissal. In December 2019, the plaintiffs filed a motion for reconsideration, which the Court of Appeals denied on February 4, 2020.

On April 7, 2020 the Plaintiffs filed a petition with the OSC requesting review and reversal of the Court of Appeals opinion. On July 16, 2020, the OSC issued an order that denied the petition for review.

Deschutes River Alliance Clean Water Act Claims

In 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had 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 alleged the violations were related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface 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 alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had degraded the fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters.

In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the Confederated Tribes of Warm Springs (CTWS), which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant.

In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case.

In October 2018, DRA filed an appeal, and PGE and the CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. In December 2019, the Court of Appeals closed the case and vacated the briefing schedule, pending ongoing discussions among the parties. On March 10, 2020, the Court of Appeals reopened the case and reset the briefing schedule, which now extends into November 2020.

The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome 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.

NOTE 9: GUARANTEES

PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of June 30, 2020, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 10: INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(14.4)		(15.1)		(12.0)		(13.3)
State and local taxes, net of federal tax benefit	10.9		6.5		8.5		6.5
Flow-through depreciation and cost basis differences	(2.6)		0.4		0.3		1.4
Amortization of excess deferred income tax	(2.5)		(2.7)		(2.1)		(3.2)
Other	(1.0)		0.6		0.4		0.1
Effective tax rate	11.4	%	10.7	%	16.1	%	12.5	%

* Federal tax credits consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2024.

Carryforwards

Federal tax credit carryforwards as of June 30, 2020 and December 31, 2019 were $64 million. These credits consist of PTCs, which will expire at various dates through 2040. PGE believes that it is more likely than not that its deferred income tax assets as of June 30, 2020 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 2020, and December 31, 2019, PGE had no material unrecognized tax benefits.

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

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions, and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, 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 forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:

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

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

•changing customer expectations and choices that may reduce customer demand for its services may impact PGE’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered Electricity Service Suppliers (ESSs) or community choice aggregators;

•the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements;

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

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

•complications arising from PGE’s jointly-owned generating facilities, including changes in ownership, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs;

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•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 that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;

•changes in the availability and price of wholesale power and fuels, including natural gas and coal, 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;

•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, or industrial customer growth, or demographic patterns, in PGE’s service territory;

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

•cybersecurity attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, 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 ability to recruit and retain appropriate talent;

•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 pandemic, earthquake, flood, drought, lightning, wind, and fire;

•the impact of widespread health developments, including the recent global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities), which could materially and adversely affect, among other things, demand for electric services, customers’ ability to pay, supply chains, personnel, contract counterparties, liquidity and financial markets;

•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.

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OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. The MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, 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 in the state of Oregon. In addition, the Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, 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.

PGE has been affected by the COVID-19 pandemic, but the Company is confident in its ability to manage through the crisis. PGE remains committed to continuing to achieve steady growth and returns as the Company transforms to meet the challenges of climate change and an ever-evolving energy grid. Customers, policy makers, and other stakeholders expect PGE to reduce greenhouse gas emissions, keep the power grid reliable and secure, and ensure prices are affordable, especially for the most vulnerable customers. The Company’s strategy strives to balance these interests. PGE’s goals are to:

•Reduce greenhouse gas emissions associated with serving its retail load by more than 80 percent below 2010 levels by 2050;

•Electrify sectors of the economy, including transportation and buildings, that are also transforming to reduce greenhouse gas emissions; and

•Perform as a business, driving improvements to work efficiency, safety, and systems and equipment reliability, all while adhering to the Company’s earnings per diluted share growth guidance of 4-6% on average.

COVID-19 Impacts—The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions. In the State of Oregon, the Governor issued an executive order on March 23, 2020 directing Oregon residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact is difficult or impossible to avoid. This order was rescinded May 14, 2020 in a new executive order announcing a phased approach for reopening Oregon’s economy. The updated order contains baseline requirements that include similar provisions to the original March 23, 2020 order. The current reopening approach for Oregon includes three phases, with each phase loosening restrictions and allowing more sectors to open. Oregon’s three most populous counties, in which the majority of PGE’s customers are located, remain in the first phase with the most restrictive requirements, including, among other things, limiting local gatherings to ten individuals and requiring six feet of social distancing at restaurants and bars, with a 10 pm closure requirement. Further reopening is currently on hold as Oregon has experienced an increase in COVID-19 cases in recent weeks.

Retail loads—The economic impacts of the COVID-19 pandemic and the Governor’s initial stay-at-home order and subsequent phased reopening approach has not allowed all businesses to reopen, or has allowed reopening only at reduced capacity to meet requirements for social distancing. The slowdown in certain sectors of the economy has resulted in changes in retail load patterns. After adjusting for the effects of weather, retail energy deliveries for the three months ended June 30, 2020 decreased 3% compared to the same period of 2019. The change was driven by an increase of 7% in residential deliveries as a larger percent of the population is spending more time at home, a 16% decrease in commercial deliveries as many business have faced temporary or permanent closures, and a 3% increase in industrial energy deliveries. Based on these trends in retail load patterns the Company currently projects that retail energy deliveries will remain flat compared to 2019 weather-adjusted levels, however changes in deliveries across customer classes may impact retail revenues. See “Customers and Demand” in this Overview

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section and “Revenues” of the Results of Operations section for more information related to COVID-19 impacts on retail loads.

Bad debt expense—The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to stabilize the impacts on small businesses and low-income residential customers. PGE believes that it is reasonably possible that the combination of these actions and observed trends of increased unemployment and late customer payments will have a material impact on the results of operations. PGE’s bad debt expense is projected to be $15 million for the full-year, compared to an original $6 million forecast for 2020. See “Administrative and other” of the Results of Operations section for more information related to COVID-19 impacts on bad debt expense.

Financial condition and liquidity—Global capital markets have experienced significant volatility in response to COVID-19 and PGE continues to assess the impact of this volatility on its liquidity position and capital investment plans. The Company believes the combination of its revolver capacity, proceeds of a $150 million, 364-day term loan, issued in April 2020, and proceeds of a $200 million First Mortgage Bond (FMB) issuance, also completed in April 2020, will provide adequate liquidity for the Company’s operational needs. The Company continues to evaluate its five-year capital plan. A detailed discussion of capital market and capital investment responses is included in the “Liquidity and Capital Resources” section.

Capital market disruptions due to COVID-19 are resulting in significant changes to the inputs used to determine pension funding levels and funding requirements. In 2019, the Company contributed $62 million to its pension plan and does not anticipate any additional contributions until 2022. The Company continues to monitor the impact of COVID-19 on capital markets and the potential consequences to pension funding levels and corresponding mandatory funding.

PGE believes the COVID-19 pandemic will not have a material impact on its financial condition and cash flows for 2020 and that it has sufficient liquidity to meet the Company’s anticipated capital and operating requirements. It is reasonably possible, however, that disruption and volatility in the global capital markets may materially increase the cost of capital.

Supply chain—The global nature of the COVID-19 pandemic has resulted in supply chain disruptions and in some instances construction interruptions. While PGE has not experienced significant supply chain disruptions or construction interruptions to date, its business continuity plans have included an assessment of critical operational supply chain linkages and an assessment of potential interruptions to our capital project execution. The Company will continue to monitor supply chain issues, including possible force majeure notices, for any material impacts to its operations.

Business continuity plans—In February 2020, as more information about the potential impacts of COVID-19 became available, the Company activated its formal business continuity plans. These plans are designed to ensure the safety of the public and employees while the Company continues to provide critical service to its customers. In addition to directing employees to work from home when appropriate, the Company has implemented safeguards for employees who play critical roles to ensure operational reliability and established protocols for employees who interact directly with the public. The Company has enacted extra physical security and cybersecurity measures to safeguard systems to serve operational needs, including those of its remote workforce, and to ensure uninterrupted service to customers. The Company will continue to evolve its business continuity plans to follow guidance from the Centers for Disease Control and the Oregon Health Authority. Although PGE has plans in place to address workforce availability, including sequestration of key employees if necessary, the Company has not experienced workforce availability issues to date. Implementation of PGE’s business continuity plans may have a material impact on PGE’s results of operation.

Legislative and regulatory developments—The Company has analyzed available relief for the economic effects of COVID-19 under the following:

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•FERC Waiver—On June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative AFDC calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction. PGE has adopted the waiver and retrospectively applied its provisions as of March 2020, resulting in a $1 million increase to AFDC for the three and six months ended June 30, 2020.

•Coronavirus Aid, Relief, and Economic Security (CARES) Act—On March 27, 2020, the U.S. Government enacted the CARES Act, which provides approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 pandemic. This package included support for individuals, large corporations, small business, and health care entities, among other affected groups. The Company does not expect direct material benefits from the CARES Act.

•COVID-19 Deferral—PGE filed an application for deferral of certain incremental costs and lost revenue related to COVID-19 on March 20, 2020 with the OPUC. This application seeks to recover costs and lost revenue (including customer receivable write-offs and other incremental costs or lost revenue arising from the COVID-19 pandemic) incurred from the date of the application through at least the end of 2020. PGE will defer such costs if they are deemed probable of recovery. Until such determination is made, any incremental expenses will be recognized in the results of operations. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test.

Reduce greenhouse gas emissions—PGE partners with customers and local and state governments to advance a clean energy future. PGE continues to leverage these partnerships to pursue emission reductions using a diverse portfolio of clean and renewable energy resources, and promote economy-wide emission reductions through electrification and smart energy use to help the state meet its greenhouse gas reduction goals.

PGE’s framework for achieving a clean energy future is informed and enabled by: i) customer renewable energy programs; ii) carbon legislation and administrative actions; iii) the resource planning process; and iv) the ability to recover renewable energy costs.

Customer Renewable Energy Programs—PGE’s customers continue to express a commitment to purchasing clean energy, as over 228,000 customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation.

There has been a growing trend of business customers with goals to be served by 100 percent clean electricity. In addition, at least four municipalities in PGE’s service territory have climate action plans and resolutions with 100 percent clean or net-zero carbon electricity goals between 2030 and 2035 and 100 percent clean or net-zero carbon economy-wide energy goals by 2050. In response, the Company implemented a new customer product option, the Green Future Impact program as a tool to help customers reach their goals. The first phase allowed for up to 160 MW of PGE-provided power purchase agreements for renewable resources and up to 140 MW of customer-provided renewable resources. PGE has proposed a second phase to increase the cap from 300 MW to 500 MW to allow more customers to participate in the program. The Company is currently working through the regulatory review process for the second phase, which is expected to conclude by the end of 2020.

The program provides business and municipal customers access to bundled renewable attributes from those resources while remaining cost-of-service customers. Both the cost-of-service tariff and the price under the renewable energy option tariff apply, a structure intended to avoid stranded costs and cost shifting. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system.

Carbon Legislation and Administrative Actions—In 2016, Oregon Senate Bill (SB) 1547 set a benchmark for percentages of electricity that must come from renewable sources and requires the elimination of coal from Oregon

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utility customers’ energy supply no later than 2030 (subject to an exception that allowed extension of this date until 2035 for PGE’s output from Colstrip).

Provisions of the 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 credits (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 online before December 31, 2022; and

•An allowance for energy storage costs related to renewable energy in an electric company’s Renewable Adjustment Clause (RAC) filings.

In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE’s investment in the Colstrip facility from 2042 to 2030, which the OPUC approved. In January 2020, the owners of Colstrip Units 1 and 2 permanently retired those two units. Although PGE has no direct ownership interest in those two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2.

PGE is currently scheduled to recover the costs of its investment in Colstrip Units 3 and 4 by 2030, although some co-owners have sought approval to recover their costs sooner in their respective jurisdictions. The Company continues to evaluate its ongoing investment in Colstrip.

Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip Transmission facilities, which stretch from eastern Montana to near the western end of the state, to serve markets in the Pacific Northwest and beyond. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities. Renewable energy development in the state of Montana could benefit from any excess transmission capacity that may become available.

The Company continues with plans to cease coal-fired operation at its Boardman generating plant by the end of 2020.

During the 2019 Oregon legislative session, House Bill (HB) 2020 was introduced, which would have authorized a comprehensive cap and trade package in Oregon and would have granted the OPUC direct authority to address climate change. Although HB 2020 was not enacted in 2019, an amended version was reintroduced in the 35-day legislative session, which began in February 2020. This new proposal, SB 1530, was also a cap and trade package that included changes made to address concerns raised by various parties. Prior to the legislative session, the OPUC stated that it would continue to collaborate with the legislature and stakeholders to make progress on climate change, noting that their authority is limited to that of an economic regulator.

The short 2020 legislative session adjourned without action on SB 1530 due to a lack of quorum and, as a result, in March 2020, the Governor of Oregon issued an Executive Order directing state agencies to seek to reduce and regulate greenhouse gas (GHG) emissions. Many of the direct agency actions are on an aggressive timeline with due dates in 2020 and 2021. As the Governor is limited by current statutory authority, the Executive Order does not include a market-based mechanism as envisioned by the cap and trade legislation introduced in the 2019 and 2020 legislative sessions.

Among other things, the Executive Order:

•Modifies the statewide GHG emissions reduction goals to at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050.

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•Directs state agencies to integrate climate change and the State’s GHG reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law.

•Directs the OPUC to—

◦determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon’s reduction goals;

◦encourage electric companies to support transportation electrification infrastructure that supports GHG reductions and the SB 1044 zero emission vehicle goals; and

◦prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy.

•Directs the Oregon Department of Environmental Quality (DEQ) to adopt a program to cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas.

•More than doubles the reduction goals of the state’s Clean Fuels Program and extends the program, from the current rule that requires a 10 percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

Regional Haze—In early 2020, PGE received a letter from the DEQ indicating that, under Phase 2 of the Regional Haze rules, the Beaver generating plant, based on its allowable emissions, which are considerably higher than actual emissions and the DEQ’s screening threshold, has been identified as a potential contributor to visibility impacts to the Mt. Hood National Forest. The Company has responded to the DEQ committing to voluntarily reduce emissions to a level below the threshold in an upcoming air permit renewal application for the facility. Such approach would be sufficient to meet the Company’s Regional Haze obligations for Beaver. Taking such a reduction on allowable emissions has the potential to constrain operations, although a review of actual emissions from 2014 to 2019 showed that Beaver would not have been limited during those operating years. PGE does not expect future limitations on operations based on the anticipated reduction in allowable emissions.

The Resource Planning Process—PGE’s resource planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. This process includes consideration of customer expectations and legislative mandates to move away from fossil fuel generation and toward renewable sources of energy.

In May 2018, the Company issued a request for proposals seeking to procure approximately 100 average megawatts (MWa) of qualifying renewable resources. The prevailing bid, Wheatridge Renewable Energy Facility (Wheatridge), will be located in eastern Oregon and combine 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage.

PGE will own 100 MW of the wind resource with an investment of approximately $160 million. Subsidiaries of NextEra Energy Resources, LLC will own the balance of the 300 MW wind resource, along with the solar and battery components, and sell their portion of the output to PGE under 30-year power purchase agreements. PGE has the option to purchase the underlying assets of the power purchase agreements on the twelfth anniversary of the commercial operation date of the wind facility. As of June 30, 2020, the Company has recorded $56 million, including the allowance for funds used during construction (AFDC), in construction work-in-progress (CWIP) related to Wheatridge.

The wind component of the facility is expected to be operational and placed in-service by December 2020 and qualify for production tax credits (PTCs) at the 100 percent level. Construction of the solar and battery components is planned for 2021 and is expected to qualify for federal investment tax credits. To date, PGE has not experienced any supply chain disruptions due to the COVID-19 pandemic related to the construction of Wheatridge, and the

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project is proceeding as planned. PGE is working closely with the contractor to actively monitor for supply chain issues. See “COVID-19 Impacts” within this “Overview” section for further information on COVID-19.

In July 2019, PGE submitted its 2019 Integrated Resource Plan (2019 IRP) to the OPUC. The initial plan and modifications proposed by PGE within the docket (LC 73) set forth actions the Company proposed to undertake over the next four years to acquire the resources identified. The OPUC issued an order on May 6, 2020 that acknowledged the following Action Plan for PGE to undertake:

•Customer actions—

◦Seek to acquire all cost-effective energy efficiency; and

◦Seek to acquire all cost-effective and reasonable distributed flexibility.

•Renewable actions—Conduct a Renewables Request for Proposals (RFP) seeking up to approximately 150 MWa of new RPS-eligible resources that contribute to meeting PGE’s capacity needs by the end of 2024, with the following conditions, among others:

◦Resources must qualify for the federal Production Tax Credit (PTC) or the federal Investment Tax Credit;

◦Resources must pass the cost-containment screen; and

◦The value of RECs generated prior to 2030 must be returned to customers.

•Capacity actions—Pursue dispatchable capacity through the following concurrent processes:

◦Pursue cost-competitive, bilateral contract agreements for existing capacity in the region; and

◦Conduct an RFP for non-emitting dispatchable resources that contribute to meeting PGE’s capacity needs.

The order also requires that PGE consider resources in the Renewable and Capacity RFPs in a co-optimized manner. PGE had requested authorization to pursue up to approximately 700 MW of capacity contribution by 2025 from a combination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage. As PGE implements the Action Plan, the Company will continue to evaluate present and ongoing resource needs in light of the economic disruption related to COVID-19.

PGE expects to file an IRP Update in 2020.

PGE and Douglas County Public Utility District have signed an agreement to supply the Company additional capacity from facilities including the Wells Hydroelectric Project, located on the Columbia River in central Washington. The agreement also provides Douglas County PUD with PGE load management and wholesale market sales services.

With a start date of January 1, 2021, the five-year agreement is expected to contribute between 100 and 160 MWs toward a roughly 250 MW power capacity need that PGE identified in its 2019 IRP. The agreement is a further step toward the Company’s stated goal of providing customers with a clean energy future.

Recovery of Renewable Energy Costs—As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the RAC. This mechanism allows PGE to recover prudently incurred costs of renewable resources through filings made annually to the OPUC. In the 2019 General Rate Case (2019 GRC) Order, the OPUC also authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings, under certain conditions.

In the fourth quarter of 2019, the Company submitted a RAC filing requesting recovery of the net revenue requirement of Wheatridge. If approved as requested, the Company would begin collection in customer prices upon the project’s in-service date, which is expected to occur prior to the inclusion of the project cost in base rates.

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Regulatory review of the request continues through a public process being conducted by the OPUC with a decision anticipated in the third quarter of this year. The wind facility is expected to be in-service in the fourth quarter of this year.

Electrify other sectors of the economy—PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include:

•The use of electricity in more applications such as electric vehicles and heat pumps;

•The integration of new, geographically-diverse energy markets;

•The deployment of new technologies like energy storage, communications networks, automation and control systems for flexible loads, and distributed generation;

•The development of connected neighborhood microgrids and smart communities; and

•The use of data and analytics to better predict demand and support energy-saving customer programs.

In July 2019, PGE’s Board approved plans to construct an Integrated Operations Center (IOC) to support and enhance the reliability and resiliency of the grid and as a key step to support efforts to electrify the economy. The IOC, at an estimated total cost of $200 million, excluding AFDC, will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support functions. As of June 30, 2020, the Company has recorded $55 million, including AFDC, in CWIP related to the IOC. The project is on track for an in-service completion date in the fourth quarter of 2021. The Company continues to actively monitor any potential supply chain or labor issues as a result of the COVID-19 pandemic.

The Company is also working to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of electric vehicles. In June 2019, the Oregon Legislature enacted SB 1044 that established zero emissions goals, which include having 250,000 registered electric vehicles by 2025 and 90% of all new vehicle sales be electric by 2035. In September 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to the State’s carbon reduction goals.

Perform as a business—PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns.

Power Costs—Pursuant to the Annual Update Tariff (AUT) process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2020 AUT included a final increase in power costs for 2020, and a corresponding increase in annual revenue requirement, of $27 million from 2019 levels, which were reflected in customer prices effective January 1, 2020.

Under the power cost adjustment mechanism (PCAM) for 2019, 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 2019 during the second half of 2020 with a decision expected in the fourth quarter 2020.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—The EPA has listed PGE as one of over one hundred PRPs related to the remediation of the Portland Harbor site. As of June 30, 2020, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, and whether the final selection of a proposed remedy by the EPA will be implemented as issued. PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs and expects the next major phase of the allocation process to begin in January 2021, contemporaneously with the remedial design process that is just beginning. In a Record of Decision issued in 2017, the EPA outlined its selected

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remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. It is probable that PGE will share in a portion of the costs related to Portland Harbor, however the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation, although such costs could be material to PGE’s financial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company’s recovery mechanism allows the Company to defer and recover incurred environmental expenditures related to Portland Harbor through a combination of third-party proceeds, such as insurance recoveries, and customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

City of Portland Audit—In 2019, the city of Portland (the “City”), which is the largest city within PGE’s service territory, completed its audit of PGE’s and the City’s mutual License Fees agreement for the 2012 through 2015 periods. The preliminary claim by the City was that PGE improperly excluded certain items from the calculation of gross revenues, which resulted in underpayment of franchise taxes of $7 million, including interest and penalties. PGE believes the City’s preliminary findings are not consistent with previous audit conclusions, which found that the Company appropriately calculated gross revenues in determining franchise fees. PGE believes it has a sound basis for maintaining the historical approach to determining License Fees and has not recorded a liability for the City’s assertion. The City has not provided its Final Letter of Determination, which is an initial step in an ongoing resolution process. Discussions with the City over this matter continue.

Capital Project Deferral—In the second quarter of 2018, PGE placed into service a new customer information system at a total cost of $152 million. In accordance with agreements reached with stakeholders in the Company’s 2019 GRC, the Company’s capital cost of the asset was included in rate base and customer prices as of January 1, 2019.

Consistent with past regulatory precedent, in May 2018, the Company submitted an application to the OPUC to defer the revenue requirement associated with this new customer information system from the time the system went into service through the end of 2018. As a result, PGE began deferring its incurred expenses, primarily related to depreciation and amortization, of the new customer information system once it was placed in service.

In 2017, the OPUC opened docket UM 1909 to conduct an investigation of the scope of its authority under Oregon law to allow the deferral of costs related to capital investments for later inclusion in customer prices. In October 2018, the OPUC issued Order 18-423 (Order) concluding that the OPUC lacked authority under Oregon law to allow deferrals of any costs related to capital investments. In the Order, the OPUC acknowledged that this decision was contrary to its past limited practice of allowing deferrals related to capital investments and would require adjustments to its regulatory practices. The OPUC directed its Staff to meet with the utilities and stakeholders to address the full implications of this decision, and to propose recommendations needed to implement this decision consistent with the OPUC’s legal authority and the public interest.

During 2018, PGE deferred a total of $12 million of expenses related to the customer information system. However, the Order impacted the probability of recovery of deferred expenses and, as such, the Company recorded a reserve for the full amount of the costs related to the customer information system. The reserve was established with an offsetting charge to the results of operations in 2018.

In response to the Order, PGE and other utilities filed a motion for reconsideration and clarification, which was denied. On April 19, 2019, PGE and the other utilities filed a petition for judicial review of the Order with the Oregon Court of Appeals, although the Court has indicated that the case would be dismissed given the lack of recent action in the case.

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On April 30, 2020, the OPUC issued a final order affirming its authority to defer all cost components related to a utility’s capital projects, including both depreciation expense and the cost of financing capital projects. PGE believes that the costs incurred to date associated with the customer information system were prudently incurred and has not withdrawn its deferral application to recover the revenue requirement of this capital project. Any amounts that may ultimately be approved by the OPUC in subsequent proceedings would be recognized in earnings in the period of such approval; however, there is no assurance that such recovery would be granted by the OPUC.

Decoupling—The decoupling mechanism, authorized by the OPUC through 2022, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, 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.

The Company recorded an estimated collection of $8 million from commercial customers for the six months ended June 30, 2020, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. Estimated collections of $6 million recorded in the first quarter of 2020 from residential customers substantially reversed in the second quarter bringing the year-to-date total to nearly zero. In the near term the Company expects to see, and has seen in the second quarter, higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by COVID-19.

Collections under the decoupling mechanism are subject to an annual limitation of 2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For collections recorded in 2020, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2022. The Company has $1 million remaining under the 2020 annual cap for commercial customers and expects to reach the cap during the third quarter of 2020. No cap exists for any potential refunds under the decoupling mechanism. At December 31, 2019, PGE recorded a total collection of $14 million, which if approved, will be collected over a one-year period beginning January 1, 2021.

Corporate Activity Tax—In 2019, the State of Oregon enacted HB 3427, which imposes a new gross receipts tax on companies with annual revenues in excess of $1 million and will apply to tax years beginning on or after January 1, 2020. The tax applies to commercial activities sourced in Oregon, less a deduction for 35% of the greater of “cost inputs” or “labor costs.” The resulting amount will be taxed at 0.57%.

In January 2020, at PGE’s request, the OPUC issued an order approving a tariff and related deferral and balancing account to provide for an estimated recovery of $7 million in customer prices in 2020. The Company will revisit the expected tax consequences annually and revise the annual tariff accordingly. Pursuant to the order, PGE started collections in customer prices February 1, 2020.

Operating Activities

In combination with electricity provided by its own generation portfolio, to meet its retail load requirements and balance its energy supply with customer demand, PGE purchases and sells electricity in the wholesale market. PGE also participates in the California Independent System Operator’s Energy Imbalance Market, which allows the Company to integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market.

The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price

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changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. 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 following tables presents energy deliveries as well as the average number of customers in the various customer classes for the periods indicated.

	Three Months Ended June 30,		% Increase (Decrease) in Energy Deliveries		Six Months Ended June 30,		% Increase (Decrease) in Energy Deliveries
	2020	2019			2020	2019
Energy deliveries (MWhs in thousands):
Retail:
Residential	1,658	1,526	9	%	3,789	3,782	—	%
Commercial	1,374	1,630	(16)	%	3,000	3,261	(8)	%
Industrial	828	802	3	%	1,638	1,510	8	%
Subtotal	3,860	3,958	(2)	%	8,427	8,553	(1)	%
Direct access:
Commercial	141	177	(20)	%	311	341	(9)	%
Industrial	370	360	3	%	725	720	1	%
Subtotal	511	537	(5)	%	1,036	1,061	(2)	%
Total retail energy deliveries	4,371	4,495	(3)	%	9,463	9,614	(2)	%
Wholesale energy deliveries	1,287	785	64	%	2,980	1,459	104	%
Total energy deliveries	5,658	5,280	7	%	12,443	11,073	12	%

	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
Average number of retail customers:
Residential	789,927	88	%	777,564	88	%	788,511	88	%	776,816	88	%
Commercial	110,158	12		109,190	12		110,116	12		109,470	12
Industrial	195	—		192	—		194	—		195	—
Direct access	633	—		634	—		631	—		633	—
Total	900,913	100	%	887,580	100	%	899,452	100	%	887,114	100	%

The following table indicates the number of heating and cooling degree-days for the three and six months ended June 30, 2020 and 2019, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

	Heating Degree-days					Cooling Degree-days
	2020		2019		Avg.	2020		2019		Avg.
First Quarter	1,761		1,992		1,849	—		—		—
April	305		312		375	—		—		3
May	174		109		185	39		28		24
June	75		46		76	60		74		62
Second Quarter	554		467		636	99		102		89
Year-to-date	2,315		2,459		2,485	99		102		89
(Decrease)/increase from the 15-year average	(7)	%	(1)	%		11	%	15	%

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During the second quarter, total heating degree days, while 13% below average, were 19% greater than 2019, thus indicating a higher demand for electricity during 2020. On a year-to-date basis, total heating degree-days were 6% below prior year totals, indicating that milder temperatures in the first quarter had served to dampen demand. The impact of cooling degree-days, which have a greater impact on demand in the upcoming third quarter of the year in PGE’s service territory, was on par with 2019.

Retail energy deliveries for the six months ended June 30, 2020 decreased 2% compared with the six months ended June 30, 2019, which was attributed to an 8% decrease in commercial deliveries. Partially offsetting the decrease was a 6.0% increase in industrial deliveries, while residential deliveries were flat on the year-to-date basis.

In the second quarter, retail energy deliveries decreased 3% compared to the second quarter of 2019. Commercial deliveries decreased 16% while energy deliveries to industrial customers increased 3%. Residential deliveries, which had been down 6% in the first quarter, were up 9% in the second quarter, bringing the six months year-to-date total to nearly the same level as the first six months of 2019. The large swing from the first to the second quarter of 2020 was due largely to the impact of the COVID-19 pandemic.

The results for the first quarter largely reflected conditions prior to the COVID-19 pandemic. On March 23, 2020, the Governor of Oregon issued an order directing residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact would be difficult or impossible to avoid. The Company has seen a shift in retail demand in response, during the second quarter. In particular, residential loads have increased as a result of a larger percentage of the population spends more time at home, whether working from home, providing child-care due to school closures, or lacking employment as commercial activity slows. Conversely, commercial energy deliveries have declined as many businesses were either directed to temporarily close to maintain social distancing or have since done so as a result of the lack of business as residents follow directives from state and federal authorities. Although the industrial class as a whole experienced an increase in energy deliveries in the second quarter, this is due primarily to continued growth in the high tech and digital services sectors, which saw lesser impacts from noted closures than other sectors. It is expected that some industrial customers will be affected in the coming months as production shifts in response to evolving customer demand for goods and services.

The following table shows the percentage contribution of the Company’s 2019 commercial and industrial revenues by category, some of which have seen, or may see, larger impacts from COVID-19 than others:

Category	Percentage of Commercial and Industrial Revenues
Manufacturing - High tech	15	%
Manufacturing - Other	13
Office, Finance, Insurance, and Real Estate	12
Government and Education	11
Other Services	11
Miscellaneous Commercial	8
Other - Trade	8
Transportation, Utilities, and Warehousing	6
Restaurants and Lodging	6
Health Care	6
Food and Merchandise Stores	4

After adjusting for the effects of weather, retail energy deliveries for the six months ended June 30, 2020 increased 0.5% compared to the same period of 2019. The increase was driven by an increase of 4% in residential deliveries and 6% growth in industrial energy deliveries. Commercial energy deliveries were down 7%. Residential average

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usage per customer saw an increase, which, combined with growth of 1.5% in the average number of residential customers, contributed to increased energy deliveries. PGE now expects that, while retail energy deliveries for 2020 will continue to be impacted by COVID-19 related behavioral changes, retail energy deliveries for the full year 2020 will remain flat compared to 2019 weather-adjusted levels.

The Company’s cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from ESSs. This cap would have limited energy deliveries to these customers to an amount equal to approximately 14% of PGE’s total retail energy deliveries for the first six months of 2020. Actual energy deliveries to Direct Access customers represented 11% of PGE’s total retail energy deliveries for the first six months of 2020 and 2019.

During 2018, the OPUC created a New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. In early February 2020, PGE began offering service to customers under this program, which is capped at 119 MWa, based on an order issued by the OPUC in January 2020.

Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. The Company continuously makes economic dispatch decisions to obtain reasonably-priced power for its retail customers based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period. The following table illustrates certain operating statistics related to the performance of PGE’s own generating resources for the six month periods ended June 30:

	Plant availability (1)				Actual energy provided compared to projected levels (2)				Actual energy provided as a percentage of total retail load
	2020		2019		2020		2019		2020		2019
Generation:
Thermal:
Natural gas	91	%	92	%	77	%	79	%	39	%	36	%
Coal (3)	100		84		104		98		17		19
Wind	96		96		127		85		13		9
Hydro	90		97		77		85		8		9

(1)Plant availability represents the percentage of the period the plant was available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.

(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.

(3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip availability was 78% during the six months ended June 30, 2020, compared with 88% in 2019.

Energy received from PGE-owned and jointly-owned thermal plants decreased 1% during the six months ended June 30, 2020 compared to 2019, primarily as a result of strong performance for hydro and wind assets. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects increased 6% during the six months ended June 30, 2020 compared to 2019, due to more favorable hydro conditions in 2020. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data.

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Energy received from PGE-owned and contracted wind resources increased 45% during the six months ended June 30, 2020 compared to 2019, due to more favorable wind conditions in 2020. Energy expected to be received from wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available.

Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Subject to a regulated earnings test, customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC.

•For the six months ended June 30, 2020, actual NVPC was $38 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2020 is currently estimated to be below the baseline, but within the established deadband range. Accordingly, no estimated refund to customers is expected under the PCAM for 2020.

•For the six months ended June 30, 2019, actual NVPC was $6 million above baseline NVPC. For the year ended December 31, 2019, actual NVPC was $5 million above baseline NVPC, which was within the established deadband range. Accordingly, no estimated collection to customers was recorded pursuant to the PCAM for 2019.

Critical Accounting Policies

The Company’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, 2019, filed with the SEC on February 14, 2020.

Results of Operations

The following tables provide financial information to be considered in conjunction with management’s discussion and analysis of results of operations.

PGE defines Gross margin as Total revenues less Purchased power and fuel. Gross margin is considered a non-GAAP measure as it excludes depreciation, amortization, and other operation and maintenance expenses. The presentation of Gross margin is intended to supplement an understanding of PGE’s operating performance in relation to changes in customer prices, fuel costs, impacts of weather, customer counts and usage patterns, and impact from regulatory mechanisms such as decoupling. The Company’s definition of Gross margin may be different from similar terms used by other companies and may not be comparable to their measures.

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The results of operations are as follows for the periods presented (dollars in millions):

	Three Months Ended June 30,				% Increase (Decrease)		Six Months Ended June 30,				% Increase (Decrease)
	2020		2019				2020		2019
Total revenues	$	469	$	460	2	%	$	1,042	$	1,033	1	%
Purchased power and fuel	109		105		4	%	262		284		(8)	%
Gross margin(1)	360		355		1	%	780		749		4	%
Other operating expenses:
Generation, transmission and distribution	77		86		(10)	%	150		163		(8)	%
Administrative and other	74		78		(5)	%	145		149		(3)	%
Depreciation and amortization	104		101		3	%	212		202		5	%
Taxes other than income taxes	34		33		3	%	69		67		3	%
Total other operating expenses	289		298		(3)	%	576		581		(1)	%
Income from operations	71		57		25	%	204		168		21	%
Interest expense(2)	34		31		10	%	67		63		6	%
Other income:
Allowance for equity funds used during construction	4		2		100	%	7		5		40	%
Miscellaneous income (expense), net	3		—		—	%	(1)		2		(150)	%
Other income, net	7		2		250	%	6		7		(14)	%
Income before income tax expense	44		28		57	%	143		112		28	%
Income tax expense	5		3		67	%	23		14		64	%
Net income	$	39	$	25	56	%	$	120	$	98	22	%

(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE’s Condensed Consolidated Statements of Income and Comprehensive Income.

(2) Net of an allowance for borrowed funds used during construction of $1 million for three months ended June 30, 2020 and 2019, and $3 million and $2 million for the six months ended June 30, 2020 and 2019, respectively.

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Net income - The following items contributed to the increase (decrease) in Net income for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2019	$	25	$	98
Items increasing (decreasing) Net income:
Decrease in Purchased power and fuel expense due to lower average variable power cost per MWh	13		78
Increase in Purchased power and fuel expense due to higher total system loads	(17)		(56)
Decrease in other operating revenues primarily from the resale of excess natural gas used for fuel in 2019 that did not recur in 2020	(4)		(16)
Change in average retail price	10		12
Decline in retail deliveries	(11)		(15)
Increase in Wholesale revenues driven by increased volumes	11		21
Increase in bad debt expense	(6)		(6)
Decrease in operating expenses as a result of decreased plant maintenance expense	8		16
Other	10		(12)
June 30, 2020	$	39	$	120
Change in Net income	$	14	$	22

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Three and six months ended June 30, 2020 compared with the three and six months ended June 30, 2019

Revenues consist of the following for the periods presented (in millions):

	Three Months Ended June 30,								Six Months Ended June 30,
	2020				2019				2020				2019
Retail:
Residential	$	223	48	%	$	205	45	%	$	502	48	%	$	495	48	%
Commercial	140		30		158		34		299		29		312		30
Industrial	53		11		50		11		104		10		94		9
Direct Access	12		3		10		2		23		2		21		2
Subtotal	428		91		423		92		928		89		922		89
Alternative revenue programs, net of amortization	—		—		(2)		—		9		1		1		—
Other accrued revenues, net	1		—		6		1		6		1		13		1
Total retail revenues	429		91		427		93		943		91		936		90
Wholesale revenues	27		6		16		3		74		7		53		5
Other operating revenues	13		3		17		4		25		2		44		5
Total revenues	$	469	100	%	$	460	100	%	$	1,042	100	%	$	1,033	100	%

Total retail revenues — The following items contributed to the increase (decrease) in Total retail revenues for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2019	$	427	$	936
Increase as a result of the change in the average price of kWhs delivered	10		12
Increase attributed to alternative revenue programs related to the decoupling mechanism	2		8
Increase resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertain to the demand response pilot program	1		2
Decrease from lower retail energy deliveries driven by the impact of COVID-19 in the second quarter 2020 and milder temperatures during the winter heating season in 2020	(11)		(15)
June 30, 2020	$	429	$	943
Change in Total retail revenues	$	2	$	7

Wholesale revenues for the three months ended June 30, 2020 increased $11 million, or 69%, from the three months ended June 30, 2019, as a result of a $10 million increase related to 64% greater wholesale sales volume and a $1 million increase as a result of 4% higher average wholesale sales prices.

Wholesale revenues for the six months ended June 30, 2020 increased $21 million, or 40%, from the six months ended June 30, 2019, as sales volumes more than doubled, the effect of which was partially offset by a 32% reduction in the average wholesale sales price. The price decline was due to the relatively high wholesale prices experienced during early 2019 as a result of natural gas availability constraints combined with weaker than average regional hydro production. More normal conditions have returned during 2020 along with a relatively mild winter and strong wind generation during the first quarter.

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Other operating revenues for the three months ended June 30, 2020 decreased $4 million from the three months ended June 30, 2019, the majority of which was the result of the sales of excess natural gas that occurred during 2019 that was not repeated in 2020.

Other operating revenue for the six months ended June 30, 2020 decreased $19 million from the six months ended June 30, 2019 driven primarily by market conditions that provided less revenue from the sale of natural gas, in excess of amounts needed for the Company’s generation portfolio, back into the wholesale market. Natural gas prices were considerably higher in the first quarter of 2019 as a result of a supply pipeline disruption in the region and the milder than average winter in North America in 2020, which resulted in an oversupply of natural gas and lower prices.

Purchased power and fuel - The following items contributed to the increase (decrease) in Purchased power and fuel for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (dollars in millions, except for average variable power cost per MWh):

	Three Months Ended		Six Months Ended
June 30, 2019	$	105	$	284
Decrease related to average variable power cost per MWh	(13)		(78)
Increase related to total system load	17		56
June 30, 2020	$	109	$	262
Change in Purchased power and fuel	$	4	$	(22)
Average variable power cost per MWh:
June 30, 2019	$	21.55	$	26.92
June 30, 2020	$	20.35	$	21.98
Total system load (MWhs in thousands):
June 30, 2019	4,916		10,554
June 30, 2020	5,364		11,950

For the three months ended June 30, 2020, the $13 million decrease related to the change in average variable power cost per MWh (which includes PGE-generated power and market purchases), was driven by a 12% decline on the average cost of purchased power, combined with a 8% decline on the average cost for the Company’s own generation. The $17 million increase related to total system load was primarily due to a 33% increase in purchased power, driven by lower gas prices and surplus hydro in the region.

For the six months ended June 30, 2020, the $78 million decrease related to the change in average variable power cost per MWh, was primarily driven by a decrease in the cost for purchased power, which declined 31% on a per MWh basis. The $56 million increase related to total system load was primarily due to a 32% increase in purchased power, driven by lower gas prices and surplus hydro in the region.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	1,044	19	%	1,150	23	%	3,477	29	%	3,318	31	%
Coal	318	6		378	8		1,504	13		1,713	16
Total thermal	1,362	25		1,528	31		4,981	42		5,031	47
Hydro	317	6		460	9		686	6		837	8
Wind	608	11		608	13		1,193	10		820	8
Total generation	2,287	42		2,596	53		6,860	58		6,688	63
Purchased power:
Term	2,504	47		1,919	39		4,108	34		3,177	30
Hydro	459	9		319	6		804	7		566	6
Wind	114	2		82	2		178	1		123	1
Total purchased power	3,077	58		2,320	47		5,090	42		3,866	37
Total system load	5,364	100	%	4,916	100	%	11,950	100	%	10,554	100	%
Less: wholesale sales	(1,287)			(785)			(2,980)			(1,459)
Retail load requirement	4,077			4,131			8,970			9,095

The following table presents the forecasted April-to-September 2020 and the actual 2019 runoff at particular points of major rivers relevant to PGE’s hydro resources:

	Runoff as a Percent of Normal*
Location	2020 Forecast		2019 Actual
Columbia River at The Dalles, Oregon	106	%	94	%
Mid-Columbia River at Grand Coulee, Washington	111		87
Clackamas River at Estacada, Oregon	78		114
Deschutes River at Moody, Oregon	87		111

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

Actual NVPC - The following items contributed to the increase (decrease) in Actual NVPC for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2019	$	89	$	231
Increase (Decrease) in Purchased power and fuel expense	4		(22)
Increase in Wholesale revenues	(11)		(21)
June 30, 2020	$	82	$	188
Change in NVPC	$	(7)	$	(43)

See “Purchased power and fuel expense” and “Revenues” within this “Results of Operations” for more details.

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For the three months ended June 30, 2020 and 2019, actual NVPC was $18 million below the baseline and $6 million below the baseline NVPC, respectively. For the six months ended June 30, 2020 and 2019, actual NVPC was $38 million below and $6 million above baseline NVPC, respectively.

Based on forecast data, NVPC for the year ending December 31, 2020 is currently estimated to be below the baseline, but within the established deadband range. Accordingly, no estimated refund to customers is expected under the PCAM for 2020.

Generation, transmission and distribution - The following items contributed to the decrease in Generation, transmission and distribution for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2019	$	86	$	163
Lower operating and plant maintenance expenses at the Company’s generation facilities	(10)		(15)
Lower distribution expenses for vegetation management and storm restoration	(2)		(1)
Miscellaneous expenses	3		3
June 30, 2020	$	77	$	150
Change in Generations, transmission and distribution	$	(9)	$	(13)

Administrative and other - The following items contributed to the increase (decrease) in Administrative and other for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2019	$	78	$	149
Increase to bad debt expense	6		6
Lower employee benefits expense	(3)		(4)
Lower outside services	(3)		(3)
Miscellaneous expenses	(4)		(3)
June 30, 2020	$	74	$	145
Change in Administrative and other	$	(4)	$	(4)

COVID-19 may prospectively impact Administrative and other expenses, particularly if economic shutdowns increase bad debt expense by driving higher unemployment and impact the revenue of businesses in the Company’s service territory. PGE expects that the combination of actions benefiting customers, such as suspending disconnections and late fee penalties, and regional economic factors will likely result in significant increases to bad debt expense, which is currently projected to be $15 million for 2020.

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Depreciation and amortization - The following items contributed to the increase (decrease) in Depreciation and amortization for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):

	Three Months Ended		Six Months Ended
June 30, 2019	$	101	$	202
Increased depreciation and amortization expense from capital additions	1		3
Increased amortization related to regulatory programs (offset in revenues)	5		10
Miscellaneous expenses	(3)		(3)
June 30, 2020	$	104	$	212
Change in Depreciation and amortization	$	3	$	10

Interest expense, net increased $3 million and $4 million, in the three and six months ended June 30, 2020, respectively, primarily due to an increase in the average balance of outstanding debt and interest on additional finance leases.

Other income, net increased $5 million and decreased $1 million for the three and six months ended June 30, 2020, respectively, primarily due to market changes on the non-qualified benefit trust.

Income tax expense increased $2 million and $9 million for three and six months ended June 30, 2020, respectively, compared to the same periods in 2019, with the increases primarily due to higher pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Credit market disruptions caused by the impacts of COVID-19 have increased liquidity concerns. PGE’s capacity to respond to liquidity issues and credit market disruptions is supported by: i) a $500 million revolving credit facility; ii) $220 million in letter of credit facilities; iii) strong investment grade credit ratings with multiple agencies; iv) significant capacity to issue additional debt within existing debt covenant restrictions; and v) continued access to capital markets demonstrated by an issuance of a $150 million 364-day term loan and a $200 million FMB issuance in April 2020. The Company has the ability to expand the revolving credit facility to $600 million, if needed. PGE continues to monitor credit market conditions to identify additional actions to support anticipated capital and operating requirements. 

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, information technology systems, and 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):

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	Six Months Ended June 30,
	2020		2019
Cash and cash equivalents, beginning of period	$	30	$	119
Net cash provided by (used in):
Operating activities	356		314
Investing activities	(370)		(271)
Financing activities	287		(151)
(Decrease) increase in cash and cash equivalents	273		(108)
Cash and cash equivalents, end of period	$	303	$	11

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 benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the six months ended June 30, 2020 compared with the six months ended June 30, 2019 (in millions):

	Increase/ (Decrease)
Accounts payable and other accrued liabilities	$	38
Other non-cash income and expenses, net	25
Net income	22
Margin deposits primarily due to additional collateral requirements as the result of market conditions	(20)
Accounts receivable, net	(23)
Net change in cash flow from operations	$	42

PGE estimates that non-cash charges for depreciation and amortization in 2020 will range from $410 million to $430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $550 million to $600 million. For additional information, see “Contractual Obligations” in this Liquidity and Capital Resources section of Item 2.

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 six months ended June 30, 2020 increased $99 million when compared with the six months ended June 30, 2019, as capital expenditures increased as a result of construction underway for Wheatridge and the IOC in 2020.

Excluding AFDC, the Company plans to make capital expenditures of $740 million in 2020, which it expects to fund with cash to be generated from operations during 2020, as discussed above, and the issuance 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 six months ended June 30, 2020, net cash provided by financing activities was primarily the result of proceeds from the combination of $200 million of FMBs issued, the $150 million term loan, and $21 million from the remarketing of PCRBs previously held by the Company, partially offset by the payment of $69 million of dividends.

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Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2020 through 2024 (in millions, excluding AFDC).

	2020		2021		2022		2023		2024
Ongoing capital expenditures*	$	550	$	450	$	500	$	500	$	500
Wheatridge Renewable Energy Facility	120		15		—		—		—
Integrated Operations Center	70		100		—		—		—
Total capital expenditures	$	740	$	565	$	500	$	500	$	500
Long-term debt maturities	$	—	$	160	$	—	$	—	$	80

* Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connections. Includes preliminary engineering and removal costs.

Debt and Equity Financings

PGE’s ability to secure sufficient short- and 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, such as the significant volatility in the capital markets in response to COVID-19. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and 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.

For 2020, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $550 million to $600 million, issuances of debt securities of up to $410 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 debt payments.

Short-term Debt. PGE has approval from the Federal Energy Regulatory Commission to issue short-term debt up to a total of $900 million through February 7, 2022. The following table shows available liquidity as of June 30, 2020 (in millions):

	As of June 30, 2020
	Capacity		Outstanding		Available
Revolving credit facility (1)	$	500	$	—	$	500
Letters of credit (2)	220		46		174
Total credit	$	720	$	46	$	674
Cash and cash equivalents					303
Total liquidity					$	977

(1)Scheduled to expire November 2023.

(2)PGE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year.

The unsecured 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 to provide cash 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 credit facility.

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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. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.

On April 9, 2020, PGE obtained a 364-day, term loan in the aggregate principal of $150 million. The term loan will bear interest for the relevant interest period at the London Inter-Bank Offered Rate plus 1.25%. The interest rate is subject to adjustment pursuant to the terms of the loan. The credit agreement expires on April 8, 2021, with any outstanding balance due and payable on such date.

Long-term Debt. As of June 30, 2020, total long-term debt outstanding, net of $13 million of unamortized debt expense, was $2,816 million.

On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds, which consist of the refinancing of $98 million previously outstanding that will now bear an interest rate of 2.125%, and $21 million previously held by PGE for remarketing that will bear an interest rate of 2.375%, both due in 2033.

On April 27, 2020, PGE issued $200 million of 3.15% Series First Mortgage Bonds (FMBs) due in 2030.

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 45.6% and 48.1% as of June 30, 2020 and December 31, 2019, 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
Senior unsecured debt	A3	BBB+
Commercial paper	P-2	A-2
Outlook	Stable	Positive

Should Moody’s 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, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits, which is included in Other current assets on the Company’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets.

As of June 30, 2020, PGE had $31 million of collateral posted with these counterparties, consisting of $25 million in cash and $6 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 June 30, 2020, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade was $17 million, and decreases to $4 million by December 31, 2020 and none by December 31, 2021. The amount of additional collateral that could be requested

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upon a dual agency downgrade to below investment grade was $106 million at June 30, 2020 and decreases to $84 million by December 31, 2020 and to $71 million by December 31, 2021.

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 June 30, 2020, under the most restrictive issuance test in the Indenture, the Company could have issued up to $955 million of 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 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.

PGE’s revolving 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 June 30, 2020, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 54.4%.

Off-Balance Sheet Arrangements

PGE has no off-balance sheet arrangements, other than surety bonds and outstanding letters of credit, 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.

PGE’s surety bond and letter of credit arrangements are described in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 14, 2020, there have been no material changes outside the ordinary course of business as of June 30, 2020, with the exception of an increase of $26 million to the surety bonds PGE has provided on behalf of the operator of Colstrip for a total of $44 million.

Contractual Obligations

PGE’s contractual obligations for 2020 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, 2019, filed with the SEC on February 14, 2020. For such obligations, there have been no material changes outside the ordinary course of business as of June 30, 2020.

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, or credit risk, 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, 2019, filed with the SEC on February 14, 2020.

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

56

Chief Executive Officer and Chief Financial Officer have concluded that, as of June 30, 2020, 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.

See Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements,” for information regarding legal proceedings.

Item 1A. Risk Factors.

Other than items noted below, 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, 2019, filed with the SEC on February 14, 2020.

The spread of COVID-19 could have a material adverse effect on PGE’s business.

The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide. Measures to control the spread of COVID-19 have affected the demand for the products and services of many businesses in PGE’s service territory and disrupted supply chains around the world. Although the full scope and extent of the impacts of COVID-19 on the Company’s operations remain uncertain, PGE has experienced a reduction in load and an increase in past due accounts and late customer payments. Management believes that these trends will have an impact on its results of operations in 2020 and possibly subsequent periods. PGE continues to monitor the impacts of the COVID-19 pandemic on its workforce, liquidity, capital markets, reliability, cybersecurity, customers, and suppliers, along with overall macroeconomic conditions. Although the Company cannot predict with certainty the full extent of the COVID-19 pandemic’s impact on its business, a protracted slowdown of broad sectors of the economy, changes in demand for commodities, or significant changes in legislation or regulatory policy to address the COVID-19 pandemic could result in a significant reduction in demand for electricity in PGE’s service territory, increased late customer payments or uncollectible accounts, and the inability of the Company’s contractors, suppliers, and other business partners to fulfill their contractual obligations, any of which could have, or continue to have, a material adverse effect on the Company’s results of operations, financial condition and cash flows.

Item 6. Exhibits.

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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	Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
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. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL 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.
104	Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed July 30, 2020, formatted in iXBRL (Inline Extensible Business Reporting Language).

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:	July 30, 2020	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)

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EX-31.1

Exhibit 31.1

CERTIFICATION

I, Maria M. Pope, 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:	July 30, 2020	By:	/s/ Maria M. Pope
			Maria M. Pope
			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:	July 30, 2020	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, Maria M. Pope, 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 June 30, 2020, as filed with the Securities and Exchange Commission on July 31, 2020 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/ Maria M. Pope		/s/ James F. Lobdell
Maria M. Pope		James F. Lobdell
President and Chief Executive Officer		Senior Vice President of Finance, Chief Financial Officer and Treasurer
Date:	July 30, 2020	Date:	July 30, 2020

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Cover Page - shares	6 Months Ended
	Jun. 30, 2020	Jul. 27, 2020
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2020
Document Transition Report	false
Entity File Number	001-5532-99
Entity Registrant Name	PORTLAND GENERAL ELECTRIC COMPANY
Entity Incorporation, State or Country Code	OR
Entity Tax Identification Number	93-0256820
Entity Address, Address Line One	121 SW Salmon Street
Entity Address, City or Town	Portland
Entity Address, State or Province	OR
Entity Address, Postal Zip Code	97204
City Area Code	503
Local Phone Number	464-8000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		89,508,545
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Medium-term Notes [Member]
Title of 12(b) Security	9.31% Medium-Term Notes due 2021
Trading Symbol	POR 21
Security Exchange Name	NYSE
Title of 12(b) Security	9.31% Medium-Term Notes due 2021
Trading Symbol	POR 21
Security Exchange Name	NYSE
Common Stock [Member]
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE

XML

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Revenue, net	$ 469	$ 462	$ 1,033	$ 1,032
Alternative revenue programs, net of amortization	0	(2)	9	1
Total revenues	469	460	1,042	1,033
Operating expenses:
Purchased power and fuel	109	105	262	284
Generation, transmission and distribution	77	86	150	163
Administrative and other	74	78	145	149
Depreciation and amortization	104	101	212	202
Taxes other than income taxes	34	33	69	67
Total operating expenses	398	403	838	865
Income from operations	71	57	204	168
Interest expense, net	34	31	67	63
Other income:
Allowance for equity funds used during construction	4	2	7	5
Miscellaneous income (loss), net	3	0	(1)	2
Other income, net	7	2	6	7
Income before income tax expense	44	28	143	112
Income tax expense	5	3	23	14
Net income	39	25	120	98
Other comprehensive Income	0	1	1	2
Comprehensive Income	$ 39	$ 26	$ 121	$ 100
Weighted-average common shares outstanding (in thousands):
Basic	89,489	89,357	89,459	89,333
Diluted	89,625	89,561	89,602	89,537
Earnings per share:
Basic	$ 0.44	$ 0.28	$ 1.34	$ 1.10
Diluted	$ 0.43	$ 0.28	$ 1.34	$ 1.09

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Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 303	$ 30
Accounts receivable, net	204	253
Inventories	109	96
Regulatory assets - current	12	17
Other current assets	108	104
Total current assets	736	500
Electric utility plant, net	7,301	7,161
Regulatory assets - noncurrent	526	483
Nuclear decommissioning trust	47	46
Non-qualified benefit plan trust	37	38
Other noncurrent assets	158	166
Total assets	8,805	8,394
Current liabilities
Accounts payable	134	165
Liabilities from price risk mangement activities - current	40	23
Short-term debt	150	0
Current portion of long-term debt	140	0
Current portion of finance lease obligation	16	16
Accrued expenses and other current liabilities	289	315
Total current liabilities	769	519
Long-term debt, net of current portion	2,676	2,597
Regulatory liabilities-noncurrent	1,362	1,377
Deferred income taxes	385	378
Unfunded status of pension and psotretirement plans	249	247
Liabilities from price risk management activities-noncurrent	145	108
Asset retirement obligations	265	263
Non-qualified benefit plan liabilities	101	103
Finance lease obligations, net of current portion	132	135
Other noncurrent liabilities	75	76
Total liabilities	6,159	5,803
Commitments and contingencies (see notes)
Shareholders' Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2020 and December 31, 2019	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,506,951 and 89,387,124 shares issued and outstanding as of June 30, 2020 and December 31, 2019, respectively	1,224	1,220
Accumulated other comprehensive loss	(9)	(10)
Retained earnings	1,431	1,381
Total shareholders' equity	2,646	2,591
Total liabilities and shareholders' equity	$ 8,805	$ 8,394

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2020	Dec. 31, 2019
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	89,506,951	89,387,124
Common stock, shares outstanding	89,506,951	89,387,124

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities:
Net income	$ 120	$ 98
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	212	202
Deferred income taxes	4	6
Pension and other postretirement benefits	12	12
Allowance for equity funds used during construction	(7)	(5)
Decoupling mechanism deferrals, net of amortization	(8)	(1)
(Amortization) of net benefits due to Tax Reform	(11)	(11)
Other non-cash income and expenses, net	46	21
Changes in working capital:
Decrease in accounts receivable, net	40	63
(Increase) in inventories	(13)	(17)
(Increase)/decrease in margin deposits	(9)	11
(Decrease) in accounts payable and accrued liabilities	(27)	(65)
Other working capital items, net	18	16
Other, net	(21)	(16)
Net cash provided by operating activities	356	314
Cash flows from investing activities:
Capital expenditures	(370)	(271)
Sales of Nuclear decommissioning trust securities	4	7
Purchases of Nuclear decommissioning trust securities	(3)	(5)
Other, net	(1)	(2)
Net cash used in investing activities	(370)	(271)
Cash flows from financing activities:
Proceeds from Issuance of long-term debt	319	200
Payments on long-term debt	(98)	(300)
Borrowings on short-term debt	200	0
Repayments of short-term debt	50	0
Issuance of commercial paper, net	0	17
Dividends paid	(69)	(65)
Other	(15)	(3)
Net cash provided by (used in) financing activities	287	(151)
Increase (Decrease) in cash and cash equivalents	273	(108)
Cash and cash equivalents, beginning of period	30	119
Cash and cash equivalents, end of period	303	11
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	56	60
Cash paid for income taxes, net	$ 5	$ 20

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Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 2020

Basis of Presentation [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to provide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 4,000 square mile, state-approved service area encompasses 51 incorporated cities entirely within the State of Oregon. As of June 30, 2020, PGE served 901,000 retail customers within a service area of 1.9 million residents.

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.

The financial information included herein as of and for the three and six months ended June 30, 2020 and 2019 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 2019 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2019, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 14, 2020, which should be read in conjunction with the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three and six months ended June 30, 2020 and 2019.

Use of Estimates

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

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

In August 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans. ASU 2018-14 amends Topic 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. This update will be effective for fiscal years ending after December 15, 2020. Because the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements.

Recently Adopted Accounting Pronouncements

On January 1, 2020, PGE adopted ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. ASU 2018-13 amends Topic 820 to add, remove, and clarify requirements related to fair value measurement disclosures. Because the standard relates only to disclosures, the implementation did not result in an impact to the results of operation, financial position, or cash flows.

On January 1, 2020, PGE adopted ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. ASU 2018-15 provides guidance on implementation costs incurred in a cloud computing arrangement that is a service contract and aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. PGE applied the amendments of this ASU prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows.

On January 1, 2020, PGE adopted ASU 2016-13 Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ASU 2016-13 replaces the incurred loss impairment methodology in previous GAAP with a methodology that reflects expected credit losses, and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. PGE applied this ASU using a modified-retrospective approach, and as a result, amounts recorded prior to January 1, 2020 have not been retrospectively restated. Under the new standard, PGE estimates current expected credit losses for retail sales based on an assessment of the current and forecasted probability of collection, aging of accounts receivable, bad debt write-offs experience, actual customer billings, economic conditions, and other significant events that may impact the collectability of accounts receivable and unbilled revenues. Provisions for current expected credit losses related to retail sales, and changes to the amount of expected credit losses for existing receivables, are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for credit losses. The implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows. To conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net on the condensed consolidated balance sheets as of December 31, 2019.

On April 1, 2020, PGE adopted ASU 2020-04 Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. ASU 2020-04 provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PGE applied the amendments of this ASU prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2020

Revenue Recognition and Deferred Revenue [Abstract]

Revenue Recognition, Multiple-deliverable Arrangements [Table Text Block]

REVENUE RECOGNITION

Disaggregated Revenue

The following table presents PGE’s revenue, disaggregated by customer type (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Retail:
Residential	$	223	$	205	$	502	$	495
Commercial	140		158		299		312
Industrial	53		50		104		94
Direct access customers	12		10		23		21
Subtotal	428		423		928		922
Alternative revenue programs, net of amortization	—		(2)		9		1
Other accrued revenues, net	1		6		6		13
Total retail revenues	429		427		943		936
Wholesale revenues*	27		16		74		53
Other operating revenues	13		17		25		44
Total revenues	$	469	$	460	$	1,042	$	1,033

* Wholesale revenues include $8 million and $2 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2020 and 2019, respectively, and $24 million and $13 million for the six months ended June 30, 2020 and 2019, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated, tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single-family housing, multiple-family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than residential customers. Commercial customers include most businesses, small industrial companies, and public street and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on energy use by this customer class.

In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and determined through general rate case proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.

Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that have not yet been billed to customers. This amount, classified as Unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.

PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.

Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and are not reflected in Revenues, net within the condensed consolidated statements of income and comprehensive income.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power; hydro, solar and wind conditions; and daily and seasonal retail demand.

PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.

Other Operating Revenues

Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and other services provided to customers.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. PGE generally determines standalone selling prices based on the prices charged to customers.

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Balance Sheet Components (Notes)

3 Months Ended

Jun. 30, 2020

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 the Company’s generating plants. Periodically, the Company assesses whether inventories are recorded at the lower of average cost or net realizable value.

Accounts Receivable, Net

Accounts receivable, net includes $74 million and $86 million of unbilled revenues as of June 30, 2020 and December 31, 2019, respectively. Accounts receivable, net is net of an allowance for credit losses of $12 million as of June 30, 2020. The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
Balance as of beginning of period	$	6	$	5
Increase in provision	7		9
Amounts written off	(3)		(6)
Recoveries	2		4
Balance as of end of period	$	12	$	12

In connection with the adoption of ASU 2016-13 and to conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net on the condensed consolidated balance sheets as of December 31, 2019.

Other Current Assets

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

	June 30, 2020		December 31, 2019
Prepaid expenses	$	37	$	63
Assets from price risk management activities	46		25
Margin deposits	25		16
Other current assets	$	108	$	104

Electric Utility Plant, Net

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

	June 30, 2020		December 31, 2019
Electric utility plant	$	11,163	$	10,928
Construction work-in-progress	376		328
Total cost	11,539		11,256
Less: accumulated depreciation and amortization	(4,238)		(4,095)
Electric utility plant, net	$	7,301	$	7,161

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $397 million and $366 million as of June 30, 2020 and December 31, 2019, respectively. Amortization expense related to intangible assets was $31 million and $33 million for the six months ended June 30, 2020 and 2019, respectively, and $16 million and $17 million for the three months ended June 30, 2020 and 2019, respectively. 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):

	June 30, 2020					December 31, 2019
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	135	$	—		$	95
Pension and other postretirement plans	—			204		—			213
Debt issuance costs	—			27		—			26
Trojan decommissioning activities	—			94		—			94
Other	12			66		17			55
Total regulatory assets	$	12		$	526	$	17		$	483
Regulatory liabilities:
Asset retirement removal costs	$	—		$	996	$	—		$	1,021
Deferred income taxes	—			256		—			260
Asset retirement obligations	—			55		—			54
Tax Reform deferral	12			—		23			—
Other	28			55		21			42
Total regulatory liabilities	$	40	*	$	1,362	$	44	*	$	1,377

* 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):

	June 30, 2020		December 31, 2019
Accrued employee compensation and benefits	$	63	$	74
Accrued taxes payable	31		33
Accrued interest payable	27		25
Accrued dividends payable	36		36
Regulatory liabilities—current	40		44
Other	92		103
Total accrued expenses and other current liabilities	$	289	$	315

Credit Facilities

As of June 30, 2020, PGE had a $500 million revolving credit facility scheduled to expire in November 2023. The Company has the ability to expand the revolving credit facility to $600 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including 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 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 June 30, 2020, PGE was in compliance with this covenant with a 54.4% 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. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay any commercial paper that may be outstanding at the time.

PGE typically classifies 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 June 30, 2020, PGE had no commercial paper outstanding. As a result, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. 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 $46 million were outstanding as of June 30, 2020. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate principal of $150 million. The term loan bears interest for the relevant interest period at LIBOR plus 1.25%. The interest rate is subject to adjustment pursuant to the terms of the loan. The credit agreement is classified as Short-term debt on the Company’s condensed consolidated balance sheets and expires on April 8, 2021, with any outstanding balance due and payable on such date.

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 7, 2022.

Long-term Debt

On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of PCRBs that will bear an interest rate of 2.125%, and $21 million aggregate principal of PCRBs that will bear an interest rate of 2.375%, both due in 2033.

On April 27, 2020, PGE issued $200 million of 3.15% Series First Mortgage Bonds (FMBs) due in 2030.

Defined Benefit Retirement Plan Costs

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	4	$	4	$	8	$	8
Interest cost*	8		9		16		17
Expected return on plan assets*	(11)		(10)		(22)		(20)
Amortization of net actuarial loss*	4		2		8		5
Net periodic benefit cost	$	5	$	5	$	10	$	10

* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

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Fair Value of Financial Instruments (Notes)

6 Months Ended

Jun. 30, 2020

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 June 30, 2020 and December 31, 2019. PGE then classifies these financial assets and liabilities based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:

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; and
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 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. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

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.

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

	As of June 30, 2020
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	293	$	—	$	—	$	—	$	293
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	7		12		—		—		19
Corporate credit	—		15		—		—		15
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Price risk management activities: (1) (4)
Electricity	—		28		—		—		28
Natural gas	—		25		3		—		28
	$	308	$	80	$	3	$	13	$	404
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	19	$	154	$	—	$	173
Natural gas	—		12		—		—		12
	$	—	$	31	$	154	$	—	$	185

(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 $29 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

	As of December 31, 2019
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	26	$	—	$	—	$	—	$	26
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	8		16		—		—		24
Corporate credit	—		9		—		—		9
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	1		—		—		—		1
Money market funds	1		—		—		—		1
Equity securities	7		—		—		—		7
Price risk management activities: (1) (4)
Electricity	—		9		7		—		16
Natural gas	—		21		1		—		22
	$	43	$	55	$	8	$	13	$	119
Liabilities:
Price risk management activities: (1) (4)
Electricity	—		14		105		—		119
Natural gas	—		12		—		—		12
	$	—	$	26	$	105	$	—	$	131

(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 $29 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of securities holdings of such funds not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. Cash equivalents 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 money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (NASDAQ) and the New York Stock Exchange (NYSE).

Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) 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 NYSE.

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 NQBP trust is invested in exchange-traded government money market funds and is 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. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.

Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates 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 5, 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 June 30, 2020
Electricity physical forwards	$	—	$	147	Discounted cash flow	Electricity forward price (per MWh)	$	2.69	$	38.84	$	29.51
Natural gas financial swaps	3		—		Discounted cash flow	Natural gas forward price (per Decatherm)	1.44		3.91		2.12
Electricity financial futures	—		7		Discounted cash flow	Electricity forward price (per MWh)	13.25		51.03		36.29
	$	3	$	154
As of December 31, 2019
Electricity physical forwards	$	—	$	104	Discounted cash flow	Electricity forward price (per MWh)	$	12.53	$	59.00	$	36.92
Natural gas financial swaps	1		—		Discounted cash flow	Natural gas forward price (per Decatherm)	1.39		3.73		1.90
Electricity financial futures	7		1		Discounted cash flow	Electricity forward price (per MWh)	10.57		66.32		45.11
	$	8	$	105

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 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 long-term price curves that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices.

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 under 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
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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Balance as of the beginning of the period	$	134	$	70	$	97	$	88
Net realized and unrealized losses/(gains)*	17		3		56		(16)
Transfers from Level 3 to Level 2	—		(1)		(2)		—
Balance as of the end of the period	$	151	$	72	$	151	$	72

* Both realized and unrealized losses/(gains), 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 and comprehensive income.

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.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and PCRBs is classified as a Level 2 fair value measurement.

As of June 30, 2020, the carrying amount of PGE’s long-term debt was $2,816 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,508 million. As of December 31, 2019, the carrying amount of PGE’s long-term debt was $2,597 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $3,039 million.

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Risk Management (Notes)

6 Months Ended

Jun. 30, 2020

Price Risk Management [Abstract]

PRICE RISK MANAGEMENT

RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace 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. Wholesale market transactions 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 to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forwards, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the 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):

	June 30, 2020		December 31, 2019
Current assets:
Commodity contracts:
Electricity	$	28	$	9
Natural gas	18		16
Total current derivative assets(1)	46		25
Noncurrent assets:
Commodity contracts:
Electricity	—		7
Natural gas	10		6
Total noncurrent derivative assets(1)	10		13
Total derivative assets(2)	$	56	$	38
Current liabilities:
Commodity contracts:
Electricity	$	30	$	14
Natural gas	10		9
Total current derivative liabilities	40		23
Noncurrent liabilities:
Commodity contracts:
Electricity	143		105
Natural gas	2		3
Total noncurrent derivative liabilities	145		108
Total derivative liabilities(2)	$	185	$	131

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.

(2) As of June 30, 2020 and December 31, 2019, no derivative assets or liabilities were designated as hedging instruments.

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 at various dates through 2035, were as follows (in millions):

	June 30, 2020			December 31, 2019
Commodity contracts:
Electricity	8		MWhs	6		MWhs
Natural gas	147		Decatherms	145		Decatherms
Foreign currency	$	21	Canadian	$	23	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such 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 June 30, 2020, gross amounts included as Price risk management liabilities subject to

master netting agreements was $2 million, comprised solely of natural gas contracts for which PGE posted no collateral. As of December 31, 2019, PGE had no material master netting arrangements.

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 comprehensive income and were as follows (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Commodity contracts:
Electricity	$	15	$	6	$	47	$	(18)
Natural Gas	(13)		21		(4)		(4)
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 and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended June 30, 2020 and 2019, net gains of $1 million and net losses of $30 million, respectively, have been offset. Net losses of $41 million and net gains of $19 million have been offset for the six months ended June 30, 2020 and 2019, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 2020 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2020		2021		2022		2023		2024		Thereafter		Total
Commodity contracts:
Electricity	$	(6)	$	16	$	8	$	8	$	8	$	111	$	145
Natural gas	(1)		(13)		(2)		—		—		—		(16)
Net unrealized loss	$	(7)	$	3	$	6	$	8	$	8	$	111	$	129

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 or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE 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 June 30, 2020 was $161 million, for which PGE has posted $6 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2020, the cash requirement to either post as collateral or settle the instruments immediately would have been $151 million. As of June 30, 2020, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. 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:

	June 30, 2020		December 31, 2019
Assets from price risk management activities:
Counterparty A	37	%	35	%
Counterparty B	11		13
Counterparty C	11		11
Counterparty D	9		11
	68	%	70	%
Liabilities from price risk management activities:
Counterparty E	79	%	79	%

See Note 4, 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)

6 Months Ended

Jun. 30, 2020

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 and six months ended June 30, 2020, unvested performance-based restricted stock units and related dividend equivalent rights of 303 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 267 thousand shares excluded for the three and six months ended June 30, 2019.

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 June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
Weighted-average common shares outstanding—basic	89,489	89,357	89,459	89,333
Dilutive effect of potential common shares	136	204	143	204
Weighted-average common shares outstanding—diluted	89,625	89,561	89,602	89,537

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Equity (Notes)

6 Months Ended

Jun. 30, 2020

Equity [Abstract]

Equity

SHAREHOLDERS’ EQUITY

The activity in equity during the three and six-month periods ended June 30, 2020 and 2019 was as follows (dollars in millions, except per share amounts):

	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings
	Shares	Amount						Total
Balances as of December 31, 2019	89,387,124	$	1,220	$	(10)	$	1,381	$	2,591
Issuances of shares pursuant to equity-based plans	77,397	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		81		81
Balances as of March 31, 2020	89,464,521	1,220		(9)		1,427		2,638
Issuances of shares pursuant to equity-based plans	42,430	1		—		—		1
Stock-based compensation	—	3		—		—		3
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		39		39
Balances as of June 30, 2020	89,506,951	$	1,224	$	(9)	$	1,431	$	2,646
Balances as of December 31, 2018	89,267,959	$	1,212	$	(7)	$	1,301	$	2,506
Issuances of shares pursuant to equity-based plans	88,352	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3625 per share)	—	—		—		(32)		(32)
Net income	—	—		—		73		73
Reclassification of stranded tax effects due to Tax Reform	—	—		(2)		2		—
Balances as of March 31, 2019	89,356,311	1,212		(8)		1,344		2,548
Issuances of shares pursuant to equity-based plans	15,249	1		—		—		1
Stock-based compensation	—	2		—		—		2
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		25		25
Balances as of June 30, 2019	89,371,560	$	1,215	$	(7)	$	1,334	$	2,542

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Contingencies (Notes)

6 Months Ended

Jun. 30, 2020

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

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

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

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

PGE 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, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

EPA Investigation of Portland Harbor

An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 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 as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.

A Portland Harbor site remedial investigation was completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had 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 finalized the feasibility study, along with the remedial investigation, and the results 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 in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of Portland Harbor, which has an undiscounted 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. Remediation construction costs were 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 EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost.

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of Portland Harbor have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs have entered into consent agreements, or are in good-faith discussion with the EPA, to perform remedial design, and if the EPA deems necessary, it has communicated it would issue Special Notice Letters to enforce action of remedial design.

PGE continues to participate 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, including the remedial design process, data with regard to property specific activities, and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up, assignment of responsibility for clean-up costs, and whether the ROD will be implemented as issued. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position.

In cases in which 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 (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe.

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 Company believes that PGE’s portion of NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

The impact of costs related to EPA and NRD liabilities on the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account mechanism (PHERA). As approved by the OPUC in 2017,

the PHERA allows the Company to defer and recover incurred environmental expenditures related to Portland Harbor through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million, excluding expenses related to contingent liabilities, are subject to an annual earnings test and would be ineligible for recovery to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent general rate case. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices.

Trojan Investment Recovery Class Actions

In 2003, in two separate proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers as a result of OPUC actions arising from PGE’s closure of the Trojan nuclear power plant in 1993: i) Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court (Circuit Court); and ii) Morgan v. Portland General Electric Company, Marion County Circuit Court. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In 2006, the Oregon Supreme Court (OSC) issued a ruling ordering abatement of the class action proceedings. The 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.

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

In 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement on the class action proceedings and heard oral argument on the Company’s motion for Summary Judgment. In 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. The plaintiffs subsequently appealed the Circuit Court dismissal to the Court of Appeals for the state of Oregon.

In November 2019, the Court of Appeals issued an opinion that affirmed the Circuit Court dismissal. In December 2019, the plaintiffs filed a motion for reconsideration, which the Court of Appeals denied on February 4, 2020.

On April 7, 2020 the Plaintiffs filed a petition with the OSC requesting review and reversal of the Court of Appeals opinion. On July 16, 2020, the OSC issued an order that denied the petition for review.

Deschutes River Alliance Clean Water Act Claims

In 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had 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 alleged the violations were related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.

The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface 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 alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had degraded the fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters.

In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and the Confederated Tribes of Warm Springs (CTWS), which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant.

In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case.

In October 2018, DRA filed an appeal, and PGE and the CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. In December 2019, the Court of Appeals closed the case and vacated the briefing schedule, pending ongoing discussions among the parties. On March 10, 2020, the Court of Appeals reopened the case and reset the briefing schedule, which now extends into November 2020.

The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome 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)	6 Months Ended
	Jun. 30, 2020
Guarantees [Abstract]
GUARANTEES	GUARANTEESPGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of June 30, 2020, 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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Income tax Income tax (Notes)

6 Months Ended

Jun. 30, 2020

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(14.4)		(15.1)		(12.0)		(13.3)
State and local taxes, net of federal tax benefit	10.9		6.5		8.5		6.5
Flow-through depreciation and cost basis differences	(2.6)		0.4		0.3		1.4
Amortization of excess deferred income tax	(2.5)		(2.7)		(2.1)		(3.2)
Other	(1.0)		0.6		0.4		0.1
Effective tax rate	11.4	%	10.7	%	16.1	%	12.5	%

* Federal tax credits consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2024.

Carryforwards

Federal tax credit carryforwards as of June 30, 2020 and December 31, 2019 were $64 million. These credits consist of PTCs, which will expire at various dates through 2040. PGE believes that it is more likely than not that its deferred income tax assets as of June 30, 2020 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 2020, and December 31, 2019, PGE had no material unrecognized tax benefits.

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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2020

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 the Company’s generating plants. Periodically, the Company assesses whether inventories are recorded at the lower of average cost or net realizable value.

Debt, Policy [Policy Text Block]

PGE typically classifies 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 value of the Company’s FMBs and PCRBs is classified as a Level 2 fair value measurement.

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

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 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. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.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]

Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) 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 NYSE.

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 NQBP trust is invested in exchange-traded government money market funds and is 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. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.

Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates 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 5, 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.

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.

Derivatives, Policy [Policy Text Block]

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forwards, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the 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. Costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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

PGE 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, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be 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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Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 2020

Revenue Recognition and Deferred Revenue [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table presents PGE’s revenue, disaggregated by customer type (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Retail:
Residential	$	223	$	205	$	502	$	495
Commercial	140		158		299		312
Industrial	53		50		104		94
Direct access customers	12		10		23		21
Subtotal	428		423		928		922
Alternative revenue programs, net of amortization	—		(2)		9		1
Other accrued revenues, net	1		6		6		13
Total retail revenues	429		427		943		936
Wholesale revenues*	27		16		74		53
Other operating revenues	13		17		25		44
Total revenues	$	469	$	460	$	1,042	$	1,033

* Wholesale revenues include $8 million and $2 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2020 and 2019, respectively, and $24 million and $13 million for the six months ended June 30, 2020 and 2019, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

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Balance Sheet Components (Tables)

6 Months Ended

Jun. 30, 2020

Balance Sheet Components [Abstract]

Allowance for Credit Losses [Text Block]

The following summarizes activity in the allowance for credit losses (in millions):

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
Balance as of beginning of period	$	6	$	5
Increase in provision	7		9
Amounts written off	(3)		(6)
Recoveries	2		4
Balance as of end of period	$	12	$	12

Schedule of Other Current Assets [Table Text Block]

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

	June 30, 2020		December 31, 2019
Prepaid expenses	$	37	$	63
Assets from price risk management activities	46		25
Margin deposits	25		16
Other current assets	$	108	$	104

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

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

	June 30, 2020		December 31, 2019
Electric utility plant	$	11,163	$	10,928
Construction work-in-progress	376		328
Total cost	11,539		11,256
Less: accumulated depreciation and amortization	(4,238)		(4,095)
Electric utility plant, net	$	7,301	$	7,161

Schedule of Regulatory Assets and Liabilities [Text Block]

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

	June 30, 2020					December 31, 2019
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	135	$	—		$	95
Pension and other postretirement plans	—			204		—			213
Debt issuance costs	—			27		—			26
Trojan decommissioning activities	—			94		—			94
Other	12			66		17			55
Total regulatory assets	$	12		$	526	$	17		$	483
Regulatory liabilities:
Asset retirement removal costs	$	—		$	996	$	—		$	1,021
Deferred income taxes	—			256		—			260
Asset retirement obligations	—			55		—			54
Tax Reform deferral	12			—		23			—
Other	28			55		21			42
Total regulatory liabilities	$	40	*	$	1,362	$	44	*	$	1,377

* 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):

	June 30, 2020		December 31, 2019
Accrued employee compensation and benefits	$	63	$	74
Accrued taxes payable	31		33
Accrued interest payable	27		25
Accrued dividends payable	36		36
Regulatory liabilities—current	40		44
Other	92		103
Total accrued expenses and other current liabilities	$	289	$	315

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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Service cost	$	4	$	4	$	8	$	8
Interest cost*	8		9		16		17
Expected return on plan assets*	(11)		(10)		(22)		(20)
Amortization of net actuarial loss*	4		2		8		5
Net periodic benefit cost	$	5	$	5	$	10	$	10

* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2020

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 June 30, 2020
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	293	$	—	$	—	$	—	$	293
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	7		12		—		—		19
Corporate credit	—		15		—		—		15
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Price risk management activities: (1) (4)
Electricity	—		28		—		—		28
Natural gas	—		25		3		—		28
	$	308	$	80	$	3	$	13	$	404
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	19	$	154	$	—	$	173
Natural gas	—		12		—		—		12
	$	—	$	31	$	154	$	—	$	185

(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 $29 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

	As of December 31, 2019
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	26	$	—	$	—	$	—	$	26
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	8		16		—		—		24
Corporate credit	—		9		—		—		9
Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	1		—		—		—		1
Money market funds	1		—		—		—		1
Equity securities	7		—		—		—		7
Price risk management activities: (1) (4)
Electricity	—		9		7		—		16
Natural gas	—		21		1		—		22
	$	43	$	55	$	8	$	13	$	119
Liabilities:
Price risk management activities: (1) (4)
Electricity	—		14		105		—		119
Natural gas	—		12		—		—		12
	$	—	$	26	$	105	$	—	$	131

(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 $29 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

Fair Value Option, 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 June 30, 2020
Electricity physical forwards	$	—	$	147	Discounted cash flow	Electricity forward price (per MWh)	$	2.69	$	38.84	$	29.51
Natural gas financial swaps	3		—		Discounted cash flow	Natural gas forward price (per Decatherm)	1.44		3.91		2.12
Electricity financial futures	—		7		Discounted cash flow	Electricity forward price (per MWh)	13.25		51.03		36.29
	$	3	$	154
As of December 31, 2019
Electricity physical forwards	$	—	$	104	Discounted cash flow	Electricity forward price (per MWh)	$	12.53	$	59.00	$	36.92
Natural gas financial swaps	1		—		Discounted cash flow	Natural gas forward price (per Decatherm)	1.39		3.73		1.90
Electricity financial futures	7		1		Discounted cash flow	Electricity forward price (per MWh)	10.57		66.32		45.11
	$	8	$	105

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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Balance as of the beginning of the period	$	134	$	70	$	97	$	88
Net realized and unrealized losses/(gains)*	17		3		56		(16)
Transfers from Level 3 to Level 2	—		(1)		(2)		—
Balance as of the end of the period	$	151	$	72	$	151	$	72

* Both realized and unrealized losses/(gains), 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 and comprehensive income.

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Price Risk Management (Tables)

6 Months Ended

Jun. 30, 2020

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):

	June 30, 2020		December 31, 2019
Current assets:
Commodity contracts:
Electricity	$	28	$	9
Natural gas	18		16
Total current derivative assets(1)	46		25
Noncurrent assets:
Commodity contracts:
Electricity	—		7
Natural gas	10		6
Total noncurrent derivative assets(1)	10		13
Total derivative assets(2)	$	56	$	38
Current liabilities:
Commodity contracts:
Electricity	$	30	$	14
Natural gas	10		9
Total current derivative liabilities	40		23
Noncurrent liabilities:
Commodity contracts:
Electricity	143		105
Natural gas	2		3
Total noncurrent derivative liabilities	145		108
Total derivative liabilities(2)	$	185	$	131

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.

(2) As of June 30, 2020 and December 31, 2019, no derivative assets or liabilities were designated as hedging instruments.

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 at various dates through 2035, were as follows (in millions):

	June 30, 2020			December 31, 2019
Commodity contracts:
Electricity	8		MWhs	6		MWhs
Natural gas	147		Decatherms	145		Decatherms
Foreign currency	$	21	Canadian	$	23	Canadian

Derivatives Not Designated as Hedging Instruments [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 comprehensive income and were as follows (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Commodity contracts:
Electricity	$	15	$	6	$	47	$	(18)
Natural Gas	(13)		21		(4)		(4)
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 and comprehensive 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/(gain) recorded as of June 30, 2020 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

	2020		2021		2022		2023		2024		Thereafter		Total
Commodity contracts:
Electricity	$	(6)	$	16	$	8	$	8	$	8	$	111	$	145
Natural gas	(1)		(13)		(2)		—		—		—		(16)
Net unrealized loss	$	(7)	$	3	$	6	$	8	$	8	$	111	$	129

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:

	June 30, 2020		December 31, 2019
Assets from price risk management activities:
Counterparty A	37	%	35	%
Counterparty B	11		13
Counterparty C	11		11
Counterparty D	9		11
	68	%	70	%
Liabilities from price risk management activities:
Counterparty E	79	%	79	%

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2020

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

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

The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

	Three Months Ended June 30,		Six Months Ended June 30,
	2020	2019	2020	2019
Weighted-average common shares outstanding—basic	89,489	89,357	89,459	89,333
Dilutive effect of potential common shares	136	204	143	204
Weighted-average common shares outstanding—diluted	89,625	89,561	89,602	89,537

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Equity (Tables)

6 Months Ended

Jun. 30, 2020

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three and six-month periods ended June 30, 2020 and 2019 was as follows (dollars in millions, except per share amounts):

	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings
	Shares	Amount						Total
Balances as of December 31, 2019	89,387,124	$	1,220	$	(10)	$	1,381	$	2,591
Issuances of shares pursuant to equity-based plans	77,397	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		81		81
Balances as of March 31, 2020	89,464,521	1,220		(9)		1,427		2,638
Issuances of shares pursuant to equity-based plans	42,430	1		—		—		1
Stock-based compensation	—	3		—		—		3
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		39		39
Balances as of June 30, 2020	89,506,951	$	1,224	$	(9)	$	1,431	$	2,646
Balances as of December 31, 2018	89,267,959	$	1,212	$	(7)	$	1,301	$	2,506
Issuances of shares pursuant to equity-based plans	88,352	—		—		—		—
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3625 per share)	—	—		—		(32)		(32)
Net income	—	—		—		73		73
Reclassification of stranded tax effects due to Tax Reform	—	—		(2)		2		—
Balances as of March 31, 2019	89,356,311	1,212		(8)		1,344		2,548
Issuances of shares pursuant to equity-based plans	15,249	1		—		—		1
Stock-based compensation	—	2		—		—		2
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	—		—		(35)		(35)
Net income	—	—		—		25		25
Balances as of June 30, 2019	89,371,560	$	1,215	$	(7)	$	1,334	$	2,542

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Income tax Income tax (Tables)

6 Months Ended

Jun. 30, 2020

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	(14.4)		(15.1)		(12.0)		(13.3)
State and local taxes, net of federal tax benefit	10.9		6.5		8.5		6.5
Flow-through depreciation and cost basis differences	(2.6)		0.4		0.3		1.4
Amortization of excess deferred income tax	(2.5)		(2.7)		(2.1)		(3.2)
Other	(1.0)		0.6		0.4		0.1
Effective tax rate	11.4	%	10.7	%	16.1	%	12.5	%

* Federal tax credits consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2024.

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Basis of Presentation (Details) retail_customers in Thousands, mi² in Thousands	Jun. 30, 2020 mi² retail_customers
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4
Incorporated Cities	51
Number of Retail Customers | retail_customers	901

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Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Revenue [Line Items]
Subtotal	$ 428	$ 423	$ 928	$ 922
Alternative revenue programs, net of amortization	0	(2)	9	1
Other accrued (deferred) revenues, net	1	6	6	13
Total retail revenues	429	427	943	936
Wholesale revenues	27	16	74	53
Other operating revenue	13	17	25	44
Total revenues	469	460	1,042	1,033
Gain on Derivative Instruments, Pretax	8	2	24	13
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	223	205	502	495
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	140	158	299	312
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	53	50	104	94
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 12	$ 10	$ 23	$ 21

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Balance Sheet Components Allowance for Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss	$ 6	$ 5
Accounts Receivable, Allowance for Credit Loss, Period Increase (Decrease)	7	9
Accounts Receivable, Allowance for Credit Loss, Writeoff	(3)	(6)
Accounts Receivable, Allowance for Credit Loss, Recovery	2	4
Accounts Receivable, Allowance for Credit Loss	$ 12	$ 12

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Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Other Current Assets [Line Items]
Prepaid expenses	$ 37	$ 63
Assets from price risk management activities	46	25
Margin deposits	25	16
Other current assets	$ 108	$ 104

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Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Electric utility plant	$ 11,163	$ 10,928
Construction work-in-progress	376	328
Total cost	11,539	11,256
Less: accumulated depreciation and amortization	(4,238)	(4,095)
Electric utility plant, net	$ 7,301	$ 7,161

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Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 12	$ 17
Regulatory assets - noncurrent	526	483
Regulatory Liability, Current	40	44
Regulatory liabilities-noncurrent	1,362	1,377
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory liabilities-noncurrent	996	1,021
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory liabilities-noncurrent	256	260
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory liabilities-noncurrent	55	54
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	12	23
Regulatory liabilities-noncurrent	0	0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	28	21
Regulatory liabilities-noncurrent	55	42
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	135	95
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	204	213
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	27	26
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	94	94
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	12	17
Regulatory assets - noncurrent	$ 66	$ 55

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Accrued employee compensation and benefits	$ 63	$ 74
Accrued taxes payable	31	33
Accrued interest payable	27	25
Accrued dividends payable	36	36
Regulatory liabilities—current	40	44
Other	92	103
Total accrued expenses and other current liabilities	$ 289	$ 315

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4	$ 4	$ 8	$ 8
Interest cost	8	9	16	17
Expected return on plan assets	(11)	(10)	(22)	(20)
Amortization of net actuarial loss	4	2	8	5
Net periodic benefit cost	$ 5	$ 5	$ 10	$ 10

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Balance Sheet Components (Details) $ in Millions		3 Months Ended		6 Months Ended
	Apr. 27, 2020 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)	Apr. 09, 2020 USD ($)	Mar. 31, 2020 USD ($)	Mar. 11, 2020 USD ($)	Dec. 31, 2019 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Accounts Receivable, Allowance for Credit Loss		$ 12		$ 12			$ 6		$ 5
Unbilled Receivables, Current		74		74					86
Finite-Lived Intangible Assets, Accumulated Amortization		397		397					366
Amortization of Intangible Assets		16	$ 17	31	$ 33
Line of Credit Facility, Maximum Borrowing Capacity		$ 600		$ 600
Debt Instrument, Covenant Description				65.00%
Ratio of Indebtedness to Net Capital		0.544		0.544
Short-term debt		$ 150		$ 150		$ 150			0
Line of Credit Facility, Remaining Borrowing Capacity		500		500
Line of Credit Facility, Current Borrowing Capacity		220	$ 500	220	500
Letters of credit issued		46		46
Authorized Short-Term Debt		900		900
Long-term Debt, Current Maturities		140		140					$ 0
Proceeds from Issuance of Long-term Debt				319	$ 200
Long-term Pollution Control Bond								$ 119
Proceeds from Issuance of Debt	$ 200
Letter of Credit [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Short-term debt		$ 0		$ 0
Member one [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Long-term Pollution Control Bond								98
Member 2 [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Long-term Pollution Control Bond								$ 21

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Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Assets:
Cash equivalents	$ 293	$ 26
Debt securities:
Domestic government	19	24
Corporate credit	15	9
Money market funds measured at NAV (2)	13	13
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	6	7
Debt securities—domestic government	1	1
Assets from price risk management activities: (1) (3)
Electricity	28	16
Natural gas	28	22
Total	13	13
Assets, Fair Value Disclosure	404	119
Liabilities from price risk management activities: (1) (3)
Electricity	173	119
Natural gas	12	12
Total	185	131
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	293	26
Debt securities:
Domestic government	7	8
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	6	7
Debt securities—domestic government	1	1
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	308	43
Liabilities from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Assets:
Cash equivalents	0	0
Debt securities:
Domestic government	12	16
Corporate credit	15	9
Non-qualified benefit plan trust: (2)
Money market funds	0	0
Equity securities - domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	28	9
Natural gas	25	21
Total	80	55
Liabilities from price risk management activities: (1) (3)
Electricity	19	14
Natural gas	12	12
Total	31	26
Fair Value, Inputs, Level 3 [Member]
Assets:
Cash equivalents	0	0
Debt securities:
Domestic government	0	0
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	0	0
Equity securities - domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	0	7
Natural gas	3	1
Total	3	8
Liabilities from price risk management activities: (1) (3)
Electricity	154	105
Natural gas	0	0
Total	$ 154	$ 105

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Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Jun. 30, 2020	Dec. 31, 2019
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 2.69	$ 12.53
Natural gas financial swaps	1.44	1.39
Financial swaps - electricity	13.25	10.57
High [Member]
Commodity Contracts
Electricity physical forwards	38.84	59.00
Natural gas financial swaps	3.91	3.73
Financial swaps - electricity	51.03	66.32
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	29.51	36.92
Natural gas financial swaps	2.12	1.90
Financial swaps - electricity	36.29	45.11
Assets [Member]
Commodity Contracts
Electricity physical forwards	0	0
Natural gas financial swaps	3,000,000	1,000,000
Financial swaps - electricity	0	7,000,000
Total commodity contracts	3,000,000	8,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	147,000,000	104,000,000
Natural gas financial swaps	0	0
Financial swaps - electricity	7,000,000	1,000,000
Total commodity contracts	$ 154,000,000	$ 105,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 134	$ 70	$ 97	$ 88
Net realized and unrealized (gains)/losses	17	3	56	(16)
Transfers out of Level 3 to Level 2		(1)	(2)	0
Balance as of the end of the period	151	$ 72	$ 151	$ 72
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	$ 0

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Surrender Value, Fair Value Disclosure	$ 29	$ 29
Long-term Debt	2,816	2,597
Unamortized Debt Issuance Expense	13	11
Long-term Debt, Fair Value	$ 3,508	$ 3,039

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Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2020	Dec. 31, 2019
Current Assets, Commodity Contracts:
Electricity	$ 28	$ 9
Natural gas	18	16
Total current derivative assets	46	25
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	0	7
Commodity Contract Asset, Noncurrent, Natural Gas	10	6
Derivative Asset, Noncurrent	10	13
Total derivative assets	56	38
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	30	14
Natural gas	10	9
Total current derivative liabilities	40	23
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	143	105
Natural gas	2	3
Total noncurrent derivative liabilities	145	108
Total derivative liabilities	$ 185	$ 131

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Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Jun. 30, 2020 CAD ($) MMBTU MWh	Dec. 31, 2019 CAD ($) MMBTU MWh
Commodity contracts:
Electricity | MWh	8	6
Natural gas | MMBTU	147	145
Foreign currency | $	$ 21	$ 23

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Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Commodity contracts:
Electricity	$ 15	$ 6	$ 47	$ (18)
Natural Gas	(13)	21	(4)	(4)
Foreign currency exchange	$ 0	$ 0	$ 1	$ 0

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Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Jun. 30, 2020 USD ($)
Electricity [Member]
Commodity contracts:
2020	$ (6)
2021	(16)
2022	(8)
2023	8
2024	8
Thereafter	111
Total	(145)
Natural Gas [Member]
Commodity contracts:
2020	(1)
2021	(13)
2022	(2)
2023	0
2024	0
Thereafter	0
Total	(16)
Net Unrealized Loss [Member]
Commodity contracts:
2020	(7)
2021	(3)
2022	(6)
2023	8
2024	8
Thereafter	111
Total	$ (129)

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Risk Management Counterparties Representing 10% or More of Assets and Liabilities from price risk management activities (Details)	Jun. 30, 2020	Dec. 31, 2019
Assets from price risk management activities:
Counterparty A	37.00%	35.00%
Counterparty B	11.00%	13.00%
Counterparty C	11.00%	11.00%
Counterparty D	9.00%	11.00%
Concentration of Risk, Derivative Instruments, Assets	68.00%	70.00%
Liabilities from price risk management activities:
Counterparty C	79.00%	79.00%

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Risk Management (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ 1	$ 30	$ (41)	$ (19)
Derivative, Net Liability Position, Aggregate Fair Value	161		161
Collateral Already Posted, Aggregate Fair Value	6		6
Collateral cash requirement	151		151
Deposit Assets	0		0
Liabilities, Total [Member]
Derivative Instruments and Hedges, Liabilities	$ 2		$ 2

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Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	89,489	89,357	89,459	89,333
Dilutive effect of potential common shares	136	204	143	204
Weighted Average Number of Shares Outstanding, Diluted	89,625	89,561	89,602	89,537

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Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	303	267	303	267

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Schedule of Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019
Common Stock, Shares, Outstanding beginning of period		89,387,124			89,387,124
Issuance of shares pursuant to equity-based plans	$ 1	$ 0	$ 1	$ 0
Stockholders' Equity	2,638	2,591	2,548	2,506	$ 2,591	$ 2,506
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent		1	1	1
Dividends declared	(35)	(35)	(35)	(32)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 39	81	25	73	$ 120	98
Reclassification of stranded tax effects due to Tax Reform				0
Common Stock, Shares, Outstanding end of period	89,506,951				89,506,951
Stockholders' Equity	$ 2,646	$ 2,638	2,542	$ 2,548	$ 2,646	$ 2,542
Common Stock, Dividends, Per Share, Declared	$ 0.3850			$ 0.3625
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	$ 3		$ 2
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	89,464,521	89,387,124	89,356,311	89,267,959	89,387,124	89,267,959
Issuances of shares pursuant to equity-based plans	42,430	77,397	15,249	88,352
Common Stock, Shares, Outstanding end of period	89,506,951	89,464,521	89,371,560	89,356,311	89,506,951	89,371,560
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 1	$ 0	$ 1	$ 0
Stockholders' Equity	1,220	1,220	1,212	1,212	$ 1,220	$ 1,212
Dividends declared	0	0	0	0
Stockholders' Equity	1,224	1,220	1,215	1,212	1,224	1,215
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	3		2
AOCI Attributable to Parent [Member]
Stockholders' Equity	(9)	(10)	(8)	(7)	(10)	(7)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent		1	1	1
Dividends declared	0	0	0	0
Reclassification of stranded tax effects due to Tax Reform				(2)
Stockholders' Equity	(9)	(9)	(7)	(8)	(9)	(7)
Retained Earnings [Member]
Stockholders' Equity	1,427	1,381	1,344	1,301	1,381	1,301
Dividends declared	35	35	35	32
Reclassification of stranded tax effects due to Tax Reform				(2)
Stockholders' Equity	$ 1,431	$ 1,427	$ 1,334	$ 1,344	$ 1,431	$ 1,334

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Contingencies (Details) $ in Millions	6 Months Ended
	Jun. 30, 2020 USD ($) party
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties | party	100
Litigation Settlement, Expense	$ 115
Loss Contingency, Estimate of Possible Loss	1,700
Loss Contingency, Damages Sought, Value	1,200
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500
Environmental Remediation Expense	6
Class action damages sought	$ 260

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Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21.00%	21.00%	21.00%	21.00%
Federal tax credits	(14.40%)	(15.10%)	(12.00%)	(13.30%)
State and local taxes, net of federal tax benefit	10.90%	6.50%	8.50%	6.50%
Flow through depreciation and cost basis differences	(2.60%)	0.40%	0.30%	1.40%
Excess deferred tax amortization	(2.50%)	(2.70%)	(2.10%)	(3.20%)
Other	(1.00%)	0.60%	0.40%	0.10%
Effective tax rate	11.40%	10.70%	16.10%	12.50%

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Income tax Income tax (Details) - USD ($)	Jun. 30, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$ 64,000,000	$ 64,000,000
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0