UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, ~~2017~~2020



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

[x] Yes x [ ] No

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


Large accelerated filer			☒	Accelerated filer	☐
Non-accelerated filer			☐	Smaller reporting company	☐

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

~~Table of Contents~~

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 October ~~17, 2017~~26, 2020 is ~~89,092,325~~89,510,606shares.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, ~~2017~~2020

TABLE OF CONTENTS

Table of Contents

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


~~Abbreviation or Acronym~~		~~Definition~~
~~AFDC~~Colstrip		~~Allowance for funds used during construction~~
~~AUT~~	~~Annual Power Cost Update Tariff~~
~~Boardman~~	~~Boardman coal-fired generating plant~~
~~Carty~~	~~Carty natural gas-fired generating plant~~
~~Colstrip~~	Colstrip Units 3 and 4 coal-fired generating plant
~~CWIP~~		~~Construction work-in-progress~~
EPA		United States Environmental Protection Agency
~~FERC~~
FERC		Federal Energy Regulatory Commission
FMBs		First Mortgage Bonds
GAAP		Accounting principles generally accepted in the United States of America
GRC		General Rate Case
IRP		Integrated Resource Plan
Moody’s		Moody’s Investors Service
MW		Megawatts
MWa		Average megawatts
MWh		Megawatt ~~hours~~hour
~~NVPC~~Nasdaq		National Association of Securities Dealers Automated Quotations
NVPC		Net Variable Power Costs
~~OCEP~~NYSE		~~Oregon Clean Electricity and Coal Transition Plan~~New York Stock Exchange
~~OPUC~~
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
~~RPS~~

RPS		Renewable Portfolio Standard
S&P		S&P Global Ratings
SEC		United States Securities and Exchange Commission
~~Trojan~~

Trojan		Trojan nuclear power plant
Wheatridge		Wheatridge Renewable Energy Facility

Table of Contents

PART I — FINANCIAL INFORMATION



Item 1.			Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues:
Revenues, net	$	556	$	538	$	1,589	$	1,570
Alternative revenue programs, net of amortization	(9)		4		0		5
Total revenues	547		542		1,589		1,575
Operating expenses:
Purchased power and fuel	292		165		554		449
Generation, transmission and distribution	65		78		215		241
Administrative and other	63		74		208		223
Depreciation and amortization	108		103		320		305
Taxes other than income taxes	35		34		104		101
Total operating expenses	563		454		1,401		1,319
Income (loss) from operations	(16)		88		188		256
Interest expense, net	35		32		102		95
Other income:
Allowance for equity funds used during construction	4		2		11		7
Miscellaneous income, net	3		3		2		5
Other income, net	7		5		13		12
Income (loss) before income tax expense	(44)		61		99		173
Income tax expense (benefit)	(27)		6		(4)		20
Net income (loss)	(17)		55		103		153
Other comprehensive income (loss)	0		0		1		2
Comprehensive income (loss)	$	(17)	$	55	$	104	$	155

Weighted-average common shares outstanding (in thousands):
Basic	89,509		89,372		89,476		89,346
Diluted	89,509		89,594		89,629		89,555

Earnings per share:
Basic	$	(0.19)	$	0.61	$	1.16	$	1.71
Diluted	$	(0.19)	$	0.61	$	1.15	$	1.70

See accompanying notes to condensed consolidated financial statements.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Revenues, net $ 515
$ 484
$ 1,494
$ 1,399
Operating expenses:
Purchased power and fuel 184
180
443
455
Generation, transmission and distribution 73
69
235
199
Administrative and other 64
63
197
185
Depreciation and amortization 87
79
257
244
Taxes other than income taxes 30
29
94
89
Total operating expenses 438
420
1,226
1,172
Income from operations 77
64
268
227
Interest expense, net 30
28
90
82
Other income:
Allowance for equity funds used during construction 4
4
9
19
Miscellaneous income, net 2
—
4
—
Other income, net 6
4
13
19
Income before income tax expense 53
40
191
164
Income tax expense 13
6
46
32
Net income and Comprehensive income $ 40
$ 34
$ 145
$ 132

Weighted-average shares outstanding—basic and diluted (in thousands) 89,065
88,921
89,044
88,885

Earnings per share—basic and diluted $ 0.44
$ 0.38
$ 1.62
$ 1.49

Dividends declared per common share $ 0.34
$ 0.32
$ 1.00
$ 0.94

See accompanying notes to condensed consolidated financial statements.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)


	September 30, 2020		December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	253	$	30
Accounts receivable, net	250		253

Inventories	86		96

Regulatory assets—current	8		17
Other current assets	123		104
Total current assets	720		500
Electric utility plant, net	7,371		7,161
Regulatory assets—noncurrent	527		483
Nuclear decommissioning trust	47		46
Non-qualified benefit plan trust	39		38
Other noncurrent assets	165		166
Total assets	$	8,869	$	8,394

See accompanying notes to condensed consolidated financial statements.

September 30,
2017 December 31,
2016
ASSETS
Current assets:
Cash and cash equivalents $ 89
$ 6
Accounts receivable, net 151
155
Unbilled revenues 71
107
Inventories 70
82
Regulatory assets—current 42
36
Other current assets 43
77
Total current assets 466
463
Electric utility plant, net 6,638
6,434
Regulatory assets—noncurrent 526
498
Nuclear decommissioning trust 41
41
Non-qualified benefit plan trust 37
34
Other noncurrent assets 51
57
Total assets $ 7,759
$ 7,527

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)


	September 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	139	$	165
Liabilities from price risk management activities—current	16		23
Short-term debt	225		0
Current portion of long-term debt	160		0

Current portion of finance lease obligation	16		16
Accrued expenses and other current liabilities	368		315
Total current liabilities	924		519
Long-term debt, net of current portion	2,657		2,597
Regulatory liabilities—noncurrent	1,375		1,377
Deferred income taxes	378		378
Unfunded status of pension and postretirement plans	250		247
Liabilities from price risk management activities—noncurrent	138		108
Asset retirement obligations	251		263
Non-qualified benefit plan liabilities	99		103
Finance lease obligations, net of current portion	131		135
Other noncurrent liabilities	71		76
Total liabilities	6,274		5,803
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, 0 par value, 30,000,000 shares authorized; NaN issued and outstanding as of September 30, 2020 and December 31, 2019	0		0
Common stock, 0 par value, 160,000,000 shares authorized; 89,509,783 and 89,387,124 shares issued and outstanding as of September 30, 2020 and December 31, 2019, respectively	1,226		1,220
Accumulated other comprehensive loss	(9)		(10)
Retained earnings	1,378		1,381


Total shareholders’ equity	2,595		2,591
Total liabilities and shareholders’ equity	$	8,869	$	8,394

See accompanying notes to condensed consolidated financial statements.

September 30,
2017 December 31,
2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 100
$ 129
Liabilities from price risk management activities—current 43
44
Current portion of long-term debt 100
150
Accrued expenses and other current liabilities 248
254
Total current liabilities 491
577
Long-term debt, net of current portion 2,277
2,200
Regulatory liabilities—noncurrent 1,002
958
Deferred income taxes 701
669
Unfunded status of pension and postretirement plans 288
281
Liabilities from price risk management activities—noncurrent 150
125
Asset retirement obligations 166
161
Non-qualified benefit plan liabilities 105
105
Other noncurrent liabilities 177
107
Total liabilities 5,357
5,183
Commitments and contingencies (see notes)

Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2017 and December 31, 2016 —
—
Common stock, no par value, 160,000,000 shares authorized; 89,091,955 and 88,946,704 shares issued and outstanding as of
September 30, 2017 and December 31, 2016, respectively
1,204
1,201
Accumulated other comprehensive loss (7 ) (7 )
Retained earnings 1,205
1,150
Total equity 2,402
2,344
Total liabilities and equity $ 7,759
$ 7,527

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Nine Months Ended September 30,							Nine Months Ended September 30,
	2017			2016				2020		2019
Cash flows from operating activities:							Cash flows from operating activities:
Net income	$	145		$	132		Net income	$	103	$	153
Adjustments to reconcile net income to net cash provided by operating activities:							Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	257			244			Depreciation and amortization	320		305

Deferred income taxes	35			18			Deferred income taxes	(14)		3
Pension and other postretirement benefits	19			21			Pension and other postretirement benefits	17		16
Allowance for equity funds used during construction	(9		)	(19		)	Allowance for equity funds used during construction	(11)		(7)

Decoupling mechanism deferrals, net of amortization	(15		)	(4		)	Decoupling mechanism deferrals, net of amortization	0		(6)

Amortization of net benefits due to Tax Reform							Amortization of net benefits due to Tax Reform	(17)		(16)
Other non-cash income and expenses, net	18			12			Other non-cash income and expenses, net	38		38
Changes in working capital:							Changes in working capital:
Decrease in accounts receivable and unbilled revenues	40			53
Decrease in inventories	12			1
Decrease in margin deposits, net	4			25
Increase in accounts payable and accrued liabilities	14			31
(Increase)/decrease in accounts receivable, net							(Increase)/decrease in accounts receivable, net	(3)		50
Decrease/(increase) in inventories							Decrease/(increase) in inventories	10		(7)
(Increase)/decrease in margin deposits							(Increase)/decrease in margin deposits	(6)		4
Increase/(decrease) in accounts payable and accrued liabilities							Increase/(decrease) in accounts payable and accrued liabilities	24		(25)
Other working capital items, net	20			12			Other working capital items, net	27		25

Other, net	(21		)	(29		)	Other, net	(46)		(31)
Net cash provided by operating activities	519			497			Net cash provided by operating activities	442		502

Cash flows from investing activities:							Cash flows from investing activities:
Capital expenditures	(369		)	(454		)	Capital expenditures	(549)		(407)

Sales of Nuclear decommissioning trust securities	14			17			Sales of Nuclear decommissioning trust securities	6		11
Purchases of Nuclear decommissioning trust securities	(12		)	(16		)	Purchases of Nuclear decommissioning trust securities	(5)		(8)

Other, net	(2		)	(1		)	Other, net	(3)		(2)
Net cash used in investing activities	(369		)	(454		)	Net cash used in investing activities	(551)		(406)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)


	Nine Months Ended September 30,
	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	275		0
Repayments of short-term debt	(50)		0

Dividends paid	(103)		(99)


Other	(11)		(5)
Net cash provided by (used in) financing activities	332		(204)
Increase (Decrease) in cash and cash equivalents	223		(108)
Cash and cash equivalents, beginning of period	30		119
Cash and cash equivalents, end of period	$	253	$	11

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	70	$	73
Cash paid for income taxes	9		21






See accompanying notes to condensed consolidated financial statements.

Nine Months Ended September 30,
2017 2016
Cash flows from financing activities:
Proceeds from issuance of long-term debt 75
265
Payments on long-term debt (50 ) (133 )
Change in short-term debt —
(6 )
Dividends paid (87 ) (82 )
Other (5 ) (3 )
Net cash (used in) provided by financing activities (67 ) 41
Increase in cash and cash equivalents 83
84
Cash and cash equivalents, beginning of period 6
4
Cash and cash equivalents, end of period $ 89
$ 88

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized $ 68
$ 61
Cash paid for income taxes 16
12
Non-cash investing and financing activities:
Assets obtained under capital lease 73
57

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a ~~single, vertically integrated~~vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company ~~also~~ participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to ~~obtain~~provide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities ~~maintained~~recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its ~~approximately~~ 4,000 square mile, state-approved service area ~~allocation, located~~encompasses 51 incorporated cities entirely within the State of ~~Oregon, encompasses 51 incorporated cities, of which Portland and Salem are the largest.~~Oregon. As of September 30, ~~2017,~~2020, PGE served ~~approximately 873,000~~904,000 retail customers ~~with~~within a service area ~~population~~ of ~~approximately~~ 1.9 million ~~comprising approximately 46% of the state’s population.~~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.

~~To conform to the 2017 presentation,~~PGE has reclassified Decoupling mechanism deferrals, net of amortization of $(4) million from Other non-cash income and expenses, net within the operating activities section of the condensed consolidated statement of cash flows for the nine months ended September 30, 2016.

The financial information included herein as of and for the three and nine months ended September 30, ~~2017~~2020 and ~~2016~~2019 is unaudited; however, in the opinion of management, such information reflects all adjustments ~~consisting of normal recurring adjustments, that are, in the opinion of management,~~ necessary ~~for a fair presentation of~~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, ~~2016~~2019 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, ~~2016,~~2019, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February ~~17, 2017,~~14, 2020, which should be read in conjunction with ~~such condensed consolidated financial statements.~~the interim unaudited Financial Statements.

Comprehensive Income

~~PGE had an immaterial amount of~~

No material change occurred in Other comprehensive income ~~during~~in the three and nine ~~month periods~~months ended September 30, ~~2017~~2020 and ~~2016.~~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.

~~Table of Contents~~

~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year.

~~Recent Accounting Pronouncements~~

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

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

~~In March 2017, the FASB issued ASU 2017-07,~~ ~~Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~ (ASU 2017-07). Pursuant to this ASU, only the service cost component of net periodic pension and postretirement benefit costs will be eligible for capitalization and should be applied on a prospective basis upon implementation. Also, the non-service components are required to be presented in the income statement separately from the service cost component and outside the subtotal of income from operations and should be applied on a retrospective basis upon implementation. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018. The Company does not plan to early adopt. For ratemaking purposes, the Company will continue to be allowed to recover this portion of the non-service costs as a component of rate base, however such amounts will be recorded as

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

~~Regulatory assets~~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. As 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. As 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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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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Retail:
Residential	$	245	$	218	$	747	$	713
Commercial	164		167		463		479
Industrial	58		50		162		144
Direct access customers	12		13		35		34
Subtotal	479		448		1,407		1,370
Alternative revenue programs, net of amortization	(9)		4		0		5
Other accrued revenues, net	7		4		13		17
Total retail revenues	477		456		1,420		1,392
Wholesale revenues*	56		72		130		125
Other operating revenues	14		14		39		58
Total revenues	$	547	$	542	$	1,589	$	1,575

* Wholesale revenues include $31 million and $25 million related to electricity commodity contract derivative settlements for the three months ended September 30, 2020 and 2019, respectively, and $55 million and $38 million for the nine months ended September 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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, ~~instead~~is calculated based on actual net retail system load each month, the number of ~~Utility plant,~~days from the last meter read date through the last day of the month, and ~~amortized~~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 ~~a systematic and rational manner and reflected as expense in a line item outside the subtotal of income from operations on~~Revenues, net within the condensed consolidated statements of income and ~~other~~ comprehensive income.

Wholesale Revenues

PGE ~~estimates~~participates in the ~~portion~~wholesale electricity marketplace in order to balance its supply of power to meet the ~~non-service components~~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 ~~periodic pension~~certain purchase and ~~postretirement benefit costs that is eligible for capitalization for ratemaking purposes,~~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 ~~$2 million for the twelve month period ending December 31, 2018,~~physically settled and ~~is deemed to have an immaterial impact~~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 ~~consolidated financial position~~generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and ~~consolidated results~~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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 2:3: 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 ~~inventory for purposes of determining that inventory is~~whether inventories are recorded at the lower of average cost or net realizable value.

Accounts Receivable, Net

Accounts receivable, net includes $79 million and $86 million of unbilled revenues as of September 30, 2020 and December 31, 2019, respectively. Accounts receivable, net is net of an allowance for credit losses of $14 million as of September 30, 2020. The following summarizes activity in the allowance for credit losses (in millions):


	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020

Balance as of beginning of period	$	12	$	5
Increase in provision	4		13
Amounts written off	(3)		(9)
Recoveries	1		5
Balance as of end of period	$	14	$	14

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):


	September 30, 2020		December 31, 2019
Prepaid expenses	$	44	$	63

Assets from price risk management activities	57		25
Margin deposits	22		16


Other current assets	$	123	$	104

September 30, 2017 December 31, 2016
Prepaid expenses $ 27
$ 48
Assets from price risk management activities 4
18
Margin deposits 4
8
Other 8
3
Other current assets $ 43
$ 77

Electric Utility Plant, Net

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


	September 30, 2020		December 31, 2019
Electric utility plant	$	11,202	$	10,928
Construction work-in-progress	473		328
Total cost	11,675		11,256
Less: accumulated depreciation and amortization	(4,304)		(4,095)
Electric utility plant, net	$	7,371	$	7,161

September 30, 2017 December 31,
2016
Electric utility plant $ 9,766
$ 9,534
Construction work-in-progress 386
213
Total cost 10,152
9,747
Less: accumulated depreciation and amortization (3,514 ) (3,313 )
Electric utility plant, net $ 6,638
$ 6,434

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of ~~$288~~$403 million and ~~$257~~$366 million as of September 30, ~~2017~~2020 and December 31, ~~2016,~~2019, respectively. Amortization expense related to intangible assets was ~~$11~~$47 million and $49 million for the nine months ended September 30, 2020 and 2019, respectively, and $16 million and $16 million for the three months ended September 30, ~~2017~~2020 and ~~2016, and $34 million and $33 million for the nine months ended September 30, 2017 and 2016,~~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):


	September 30, 2020					December 31, 2019
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management (1)	$	0		$	114	$	0		$	95
Pension and other postretirement plans	0			200		0			213

Debt issuance costs	0			26		0			26
Trojan decommissioning activities	0			95		0			94
Other	8			92		17			55
Total regulatory assets	$	8		$	527	$	17		$	483
Regulatory liabilities:
Asset retirement removal costs	$	0		$	1,005	$	0		$	1,021
Deferred income taxes	0			246		0			260

Asset retirement obligations	0			55		0			54
Tax Reform deferral	6			0		23			0
Price risk management (1)	39			0		2			0
Other	20			69		19			42
Total regulatory liabilities	$	65	(2)	$	1,375	$	44	(2)	$	1,377

(1)For the nine months ended September 30, 2020, PGE’s actual net variable power costs (NVPC) were $70 million above the prescribed “deadband” limit of $30 million pursuant to the Company’s power cost adjustment mechanism (PCAM). PGE will not be pursuing regulatory recovery for amounts related to trading positions that resulted in realized losses of $127 million during the third quarter of 2020. The Company no longer has net market exposure from these energy trading positions. As of September 30, 2020, all other outstanding positions and related regulatory accounting deferrals have been recorded in accordance with accounting for rate-regulated enterprises.

(2)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):


	September 30, 2020		December 31, 2019
Accrued employee compensation and benefits	$	63	$	74
Accrued taxes payable	57		33
Accrued interest payable	43		25
Accrued dividends payable	37		36
Regulatory liabilities—current	65		44
Other	103		103
Total accrued expenses and other current liabilities	$	368	$	315

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

~~Regulatory Assets and Liabilities~~

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

September 30, 2017 December 31, 2016
Current Noncurrent Current Noncurrent
Regulatory assets:
Price risk management $ 39
$ 150
$ 26
$ 120
Pension and other postretirement plans —
225
—
235
Deferred income taxes —
83
—
86
Debt issuance costs —
20
—
22
Other 3
48
10
35
Total regulatory assets $ 42
$ 526
$ 36
$ 498
Regulatory liabilities:
Asset retirement removal costs $ —
$ 921
$ —
$ 887
Trojan decommissioning activities 4
—
18
—
Asset retirement obligations —
52
—
49
Other 16
29
33
22
Total regulatory liabilities $ 20
^*
$ 1,002
$ 51
^*
$ 958

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

~~Accrued Expenses and Other Current Liabilities~~

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

September 30, 2017 December 31, 2016
Accrued employee compensation and benefits $ 51
$ 52
Accrued taxes payable 46
25
Accrued interest payable 40
25
Accrued dividends payable 31
30
Regulatory liabilities—current 20
51
Other 60
71
Total accrued expenses and other current liabilities $ 248
$ 254

Credit Facilities

As of September 30, ~~2017,~~2020, PGE had a $500 million revolving credit facility scheduled to expire inNovember ~~2020~~.

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. ~~During the first quarter of 2017, PGE exercised one of the two one-year extensions available under the terms of the~~The revolving credit ~~facility. Such action resulted in an updated expiration date of November 2020. The~~ facility ~~also~~ contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

requirement that limits consolidated indebtedness, as defined in the agreement, to65% of total capitalization. As of September 30, ~~2017,~~2020, PGE was in compliance with this covenant with a ~~51.3%~~55.5% debt-to-total capital ratio. The aggregate unused available credit capacity under the revolving credit facility was $500 million.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 ~~days, limited~~days. The Company has elected to ~~the unused amount of credit~~limit its borrowings under the revolving credit ~~facility.~~facility to cover any potential need to repay any commercial paper that may be outstanding at the time. As of September 30, 2020, PGE had$75 million of commercial paper outstanding.

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

Under the revolving credit facility, as of September 30, 2017, since PGE had no borrowings outstanding, and no commercial paper or letters of credit issued, 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. ~~These facilities provide a total capacity of $220 million.~~ The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of$5455 million were outstanding as of September 30, ~~2017.~~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~~$900 million through February ~~6, 2018~~.7, 2022.

Long-term Debt

On ~~August 2, 2017,~~March 11, 2020, PGE ~~entered into a bond purchase agreement to issue First Mortgage Bonds (FMBs) in~~completed the ~~amount~~remarketing of $225 million at an interest rate of 3.98%. The first tranche of $75 million, with a maturity in 2048, was issued on August 2, 2017. The second tranche of $150 million, with a maturity in 2047, is expected to be issued and funded on or about November 21, 2017.

~~In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in~~ an aggregate principal amount of ~~up to~~$119 million of Pollution Control Revenue Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of PCRBs that bear an interest rate of 2.125%, and $21 million aggregate principal of PCRBs that bear an interest rate of 2.375%, both due in 2033.

On April 27, 2020, PGE issued $200 million ~~by October 31, 2016. Under the agreement, PGE obtained three separate loans totaling $150 million. On August 21, 2017, the Company repaid one~~ of ~~the loans~~3.15% Series First Mortgage Bonds (FMBs) due in ~~the amount of $50 million. The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable.~~

The term loan interest rates on the remaining loans are set at the beginning of the interest period for periods of one, three, or six months, as selected by PGE, and are based on the London Interbank Offered Rate plus 63 basis points, and was 1.9% as of September 30, 2017, with no other fees.

Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults, and other customary defaults for financings of this type.

2030.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Defined Benefit ~~Pension~~Retirement Plan Costs

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Service cost	$	4	$	4	$	12	$	12
Interest cost*	8		8		24		25
Expected return on plan assets*	(11)		(10)		(33)		(30)
Amortization of net actuarial loss*	4		3		12		8
Net periodic benefit cost	$	5	$	5	$	15	$	15

* 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.

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Service cost $ 4
$ 4
$ 12
$ 12
Interest cost 8
9
25
25
Expected return on plan assets (10 ) (10 ) (30 ) (30 )
Amortization of net actuarial loss 3
3
9
11
Net periodic benefit cost $ 5
$ 6
$ 16
$ 18

NOTE 3:4: 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 September 30, ~~2017~~2020 and December 31, ~~2016, and~~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 discussed below.~~are:


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

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

	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 ~~fair value~~ assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value ~~hierarchy; instead these~~hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

~~PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments.~~ Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. ~~There were no significant transfers between levels during the three and nine month periods ended September 30, 2017 and 2016, except those presented in this note.~~

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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


	As of September 30, 2017											As of September 30, 2020
	Level 1		Level 2		Level 3		Other⁽²⁾		Total			Level 1		Level 2		Level 3		Other(2)		Total
Assets:											Assets:
Cash equivalents											Cash equivalents	$	228	$	0	$	0	$	—	$	228
Nuclear decommissioning trust: ⁽¹⁾											Nuclear decommissioning trust: (1)
Debt securities:											Debt securities:
Domestic government	$	3	$	8	$	—	$	—	$	11	Domestic government	8		12		0		—		20
Corporate credit	—		7		—		—		7		Corporate credit	0		14		0		—		14
Money market funds measured at NAV ⁽²⁾	—		—		—		23		23		Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: ⁽³⁾											Non-qualified benefit plan trust: (3)
Money market funds	2		—		—		—		2		Money market funds	1		0		0		—		1
Equity securities—domestic	6		—		—		—		6
Equity securities											Equity securities	7		0		0		—		7

Debt securities—domestic government	1		—		—		—		1		Debt securities—domestic government	1		0		0		—		1
Collective trust—domestic equity measured at NAV ⁽²⁾	—		—		—		—		—
Assets from price risk management activities: ^{(1) (4)}

Price risk management activities: (1) (4)											Price risk management activities: (1) (4)
Electricity	—		3		—		—		3		Electricity	0		9		2		—		11
Natural gas	—		1		—		—		1		Natural gas	0		60		10		—		70
	$	12	$	19	$	—	$	23	$	54		$	245	$	95	$	12	$	13	$	365
Liabilities from price risk management activities: ^{(1) (4)}
Liabilities:											Liabilities:

Price risk management activities: (1) (4)											Price risk management activities: (1) (4)
Electricity	$	—	$	3	$	140	$	—	$	143	Electricity	$	0	$	3	$	146	$	—	$	149
Natural gas	—		37		13		—		50		Natural gas	0		5		0		—		5
	$	—	$	40	$	153	$	—	$	193		$	0	$	8	$	146	$	—	$	154


~~(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 $28 million, which are recorded at cash surrender value.~~


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

(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 $30 million, which are recorded at cash surrender value.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)


	As of December 31, 2016											As of December 31, 2019
	Level 1		Level 2		Level 3		Other ⁽²⁾		Total			Level 1		Level 2		Level 3		Other (2)		Total
Assets:											Assets:
Cash equivalents											Cash equivalents	$	26	$	0	$	0	$	—	$	26
Nuclear decommissioning trust: ⁽¹⁾											Nuclear decommissioning trust: (1)

Debt securities:											Debt securities:
Domestic government	$	2	$	10	$	—	$	—	$	12	Domestic government	8		16		0		—		24
Corporate credit	—		8		—		—		8		Corporate credit	0		9		0		—		9
Money market funds measured at NAV ⁽²⁾	—		—		—		21		21		Money market funds measured at NAV (2)	—		—		—		13		13
Non-qualified benefit plan trust: ⁽³⁾											Non-qualified benefit plan trust: (3)
Debt securities—domestic government											Debt securities—domestic government	1		0		0		—		1
Money market funds	1		—		—		—		1		Money market funds	1		0		0		—		1
Equity securities—domestic	4		—		—		—		4
Debt securities—domestic government	1		—		—		—		1
Collective trust—domestic equity measured at NAV ⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Equity securities											Equity securities	7		0		0		—		7

Price risk management activities: (1) (4)											Price risk management activities: (1) (4)
Electricity	—		6		1		—		7		Electricity	0		9		7		—		16
Natural gas	—		15		1		—		16		Natural gas	0		21		1		—		22
	$	8	$	39	$	2	$	23	$	72		$	43	$	55	$	8	$	13	$	119
Liabilities from price risk management activities: ^{(1) (4)}
Liabilities:											Liabilities:

Price risk management activities: (1) (4)											Price risk management activities: (1) (4)
Electricity	$	—	$	6	$	112	$	—	$	118	Electricity	0		14		105		—		119
Natural gas	—		42		9		—		51		Natural gas	0		12		0		—		12
	$	—	$	48	$	121	$	—	$	169		$	0	$	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 $26 million, which are recorded at cash surrender value.~~


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

(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.

~~Trust~~(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 arehighly 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 ~~(NQ 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~~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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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(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.

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

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

~~Common~~The NQBP trust is invested in exchange-traded government money market funds and ~~collective trust funds—PGE invests in common and collective trust funds that invest in equity securities. The Company believes the redemption value of these funds~~ is ~~likely to be the fair value, which is represented by the net asset value~~classified as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance to be paid after the annual fund audit is complete. Common and collective trusts are not classifiedLevel 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as ~~they are~~NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical ~~expedient.~~expedient and is not included in the fair value hierarchy.

Assets and liabilities from price risk management activities, ~~are~~ recorded at fair value in PGE’s condensed consolidated balance sheets, ~~and~~ consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price ~~risk~~ and foreign currency exchange ~~rate risk,~~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 ~~4, Price~~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~~longer-term commodity forwards, futures, and swaps.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities 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 September 30, 2020
Electricity physical forwards	$	0	$	144	Discounted cash flow	Electricity forward price (per MWh)	$	12.66	$	43.21	$	29.49
Natural gas financial swaps	10		0		Discounted cash flow	Natural gas forward price (per Decatherm)	1.64		4.77		2.39
Electricity financial futures	2		2		Discounted cash flow	Electricity forward price (per MWh)	16.50		56.00		38.63
	$	12	$	146
As of December 31, 2019
Electricity physical forwards	$	0	$	104	Discounted cash flow	Electricity forward price (per MWh)	$	12.53	$	59.00	$	36.92
Natural gas financial swaps	1		0		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 Valuation Technique Significant Unobservable Input Price per Unit
Commodity Contracts Assets Liabilities Low High Weighted Average
(in millions)
As of September 30, 2017:
Electricity physical forwards $ —
$ 140
Discounted cash flow Electricity forward price (per MWh) $ 8.20
$ 37.15
$ 28.36
Natural gas financial swaps —
13
Discounted cash flow Natural gas forward price (per Decatherm) 1.59
3.22
2.07
Electricity financial futures —
—
Discounted cash flow Electricity forward price (per MWh) 8.20
29.50
23.05
$ —
$ 153

As of December 31, 2016:
Electricity physical forwards $ —
$ 112
Discounted cash flow Electricity forward price (per MWh) $ 14.25
$ 54.73
$ 38.18
Natural gas financial swaps 1
9
Discounted cash flow Natural gas forward price (per Decatherm) 1.85
4.92
2.64
Electricity financial futures 1
—
Discounted cash flow Electricity forward price (per MWh) 8.57
33.60
25.10
$ 2
$ 121

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

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller under thecontract. 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)

~~Significant Unobservable Input~~

~~Position~~

~~Change to Input~~

~~Impact on Fair Value Measurement~~

~~Market price~~

~~Buy~~

~~Increase (decrease)~~

~~Gain (loss)~~

~~Market price~~

~~Sell~~

~~Increase (decrease)~~

~~Loss (gain)~~

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017
2016 2017 2016
Balance as of the beginning of the period 153
158
$ 119
$ 119
Net realized and unrealized (gains)/losses^*
(1 ) —
34
40
Transfers out of Level 3 to Level 2 1
2
—
1
Balance as of the end of the period $ 153
$ 160
$ 153
$ 160

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Balance as of the beginning of the period	$	151	$	72	$	97	$	88
Net realized and unrealized losses/(gains)*	(17)		30		39		14



Transfers from Level 3 to Level 2	0		(1)		(2)		(1)
Balance as of the end of the period	$	134	$	101	$	134	$	101

* Both realized and unrealized losses/(gains)~~/losses,~~, of which ~~the~~ unrealized portion ~~is fully~~are 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 into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the three and nine months ended September 30, 2017 and 2016, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. ~~PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments.~~

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

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The ~~fair~~ value of the Company’s FMBs and ~~Pollution Control Revenue Bonds~~PCRBs is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans was classified as a Level 3 fair value measurement and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.measurement.

As of September 30, ~~2017~~,2020, the carrying amount of PGE’s long-term debt was ~~$2,377~~$2,817 million, net of $9$12 million of unamortized debt expense, and its estimated aggregate fair value was ~~$2,763 million, consisting of$2,663 million and$100 millionclassified as Level 2 and Level 3, respectively, in the fair value hierarchy.~~

$3,531 million. As of December 31, ~~2016,~~2019, the carrying amount of PGE’s long-term debt was ~~$2,350~~$2,597 million, net of $11 millionof unamortized debt expense, and its estimated aggregate fair value was ~~$2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.~~$3,039 million.

NOTE ~~4: PRICE~~5: RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace ~~in order~~ to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. ~~Such activities~~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

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.

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

For the nine months ended September 30, 2020, PGE’s actual net variable power costs (NVPC) were $70 millionabove the prescribed “deadband” limit of $30 million pursuant to the Company’s power cost adjustment mechanism (PCAM). PGE will not be pursuing regulatory recovery for amounts related to trading positions that resulted in realized losses of $127 million during the third quarter of 2020. These losses were the result of a convergence of increased wholesale electricity prices at various market hubs due to extreme weather conditions, constraints to

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

regional transmission facilities and changes in power supply in the West that occurred in August 2020. The Company no longer has net market exposure from these trading positions. As of September 30, 2020, all other outstanding positions and related regulatory accounting deferrals have been recorded in accordance with accounting for rate-regulated enterprises.

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


	September 30, 2020		December 31, 2019
Current assets:
Commodity contracts:
Electricity	$	9	$	9
Natural gas	48		16
Total current derivative assets(1)	57		25
Noncurrent assets:
Commodity contracts:
Electricity	2		7
Natural gas	22		6
Total noncurrent derivative assets(1)	24		13

Total derivative assets(2)	$	81	$	38
Current liabilities:
Commodity contracts:
Electricity	$	11	$	14
Natural gas	5		9
Total current derivative liabilities	16		23
Noncurrent liabilities:
Commodity contracts:
Electricity	138		105
Natural gas	0		3
Total noncurrent derivative liabilities	138		108

Total derivative liabilities(2)	$	154	$	131

September 30, 2017 December 31,
2016
Current assets:
Commodity contracts:
Electricity $ 3
$ 6

Natural gas 1
12

Total current derivative assets 4
⁽¹⁾
18
⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity —
1

Natural gas —
4

Total noncurrent derivative assets —
5
⁽²⁾
Total derivative assets not designated as hedging instruments $ 4
$ 23

Total derivative assets $ 4
$ 23

Current liabilities:
Commodity contracts:
Electricity $ 11
$ 12

Natural gas 32
32

Total current derivative liabilities 43
44

Noncurrent liabilities:
Commodity contracts:
Electricity 132
106

Natural gas 18
19

Total noncurrent derivative liabilities 150
125

Total derivative liabilities not designated as hedging instruments $ 193
$ 169

Total derivative liabilities $ 193
$ 169

(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.


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


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

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

PGE’s net ~~purchase~~ 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):

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~


	September 30, 2017			December 31, 2016				September 30, 2020			December 31, 2019
Commodity contracts:							Commodity contracts:
Electricity	6		MWh	8		MWh	Electricity	8		MWhs	6		MWhs
Natural gas	114		Decatherms	107		Decatherms	Natural gas	133		Decatherms	145		Decatherms

Foreign currency	$	21	Canadian	$	22	Canadian	Foreign currency	$	21	Canadian	$	23	Canadian

PGE has elected to report ~~gross on the condensed consolidated balance sheets the~~ positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting ~~arrangement.~~arrangement gross on the condensed consolidated balance

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

sheets. In the case of default on, or termination of, any contract under the master netting arrangements, ~~these~~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 September 30, ~~2017, and December 31, 2016,~~2020, gross amounts included as Price risk management liabilities subject to master netting agreements ~~were $143~~was $2 million, ~~and $115 million, respectively,~~comprised solely of natural gas contracts for which PGE posted ~~collateral of $11 million, which consisted entirely of letters of credit.~~no collateral. As of September 30, 2017, of the gross amounts recognized, $140 million was for electricity and $3 million was for natural gas compared to $112 million for electricity and $3 million for natural gas recognized as of December 31, ~~2016.~~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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Commodity contracts:
Electricity	$	113	$	36	$	160	$	18
Natural Gas	(47)		(9)		(51)		(13)
Foreign currency exchange	(1)		0		0		0

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Commodity contracts:
Electricity $ 1
$ 8
$ 50
$ 60
Natural Gas 7
10
48
(14 )
Foreign currency exchange —
—
(1 ) (1 )

Net unrealized and certain net realized ~~losses~~ 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. ~~None of~~Of the net ~~losses~~amounts recognized in Net income for the ~~three month period~~three-month periods ended September 30, ~~2017 was offset, while~~2020 and 2019, net gains of $63 million and net losses of ~~$20~~$24 million, ~~were offset for the three month period ended September 30, 2016.~~respectively, have been offset. Net gains of $22 million and net losses of ~~$65 million and $36~~$5 million have been offset for the nine ~~month periods~~months ended September 30, ~~2017~~2020 and ~~2016,~~2019, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized ~~loss~~loss/(gain) recorded as of September 30, ~~2017~~2020 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):


	2017		2018		2019		2020		2021		Thereafter		Total			2020		2021		2022		2023		2024		Thereafter		Total
Commodity contracts:															Commodity contracts:
Electricity	$	—	$	9	$	8	$	8	$	8	$	107	$	140	Electricity	$	(4)	$	6	$	7	$	8	$	8	$	113	$	138
Natural gas	14		22		9		4		—		—		49		Natural gas	(14)		(40)		(10)		(1)		0		0		(65)
Net unrealized loss	$	14	$	31	$	17	$	12	$	8	$	107	$	189
Net unrealized loss/(gain)															Net unrealized loss/(gain)	$	(18)	$	(34)	$	(3)	$	7	$	8	$	113	$	73

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s ~~and/~~or S&P reduce their rating on ~~PGE’s~~the Company’s unsecured debt to below

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

investment grade, ~~the Company~~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 September 30, ~~2017~~2020 was ~~$191~~$150 million, for which PGE has posted ~~$18~~$10 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, ~~2017,~~2020, the cash requirement to either post as collateral or settle the instruments immediately would have been ~~$190~~$145 million. As of September 30, 2020, PGE had 0 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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


	September 30, 2017		December 31, 2016			September 30, 2020		December 31, 2019
Assets from price risk management activities:					Assets from price risk management activities:
Counterparty A	53	%	22	%	Counterparty A	11	%	35	%
Counterparty B	3		17		Counterparty B	16		13
Counterparty C	1		12		Counterparty C	21		11
Counterparty D	15		—	%	Counterparty D	17		11
						65	%	70	%
Liabilities from price risk management activities:					Liabilities from price risk management activities:
Counterparty E	10		—	%	Counterparty E	94	%	79	%
	82	%	51	%
Liabilities from price risk management activities:
Counterparty F	72	%	66	%
	72	%	66	%

See Note 3,4, 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 5:6: 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. Anti-dilutive stock awards are excluded from the calculation of diluted earnings per common share. For the three months ended September 30, 2020, 173 thousand shares have been excluded from the diluted weighted-average common shares outstanding because they are anti-dilutive.

For the three and nine ~~month periods~~months ended September 30, ~~2017,~~2020, unvested performance-based restricted stock units and related dividend equivalent rights ~~in the total amount~~ of ~~267~~302 thousandshares were excluded from the dilutive calculation because the performance goals had not been met, with ~~306~~265 thousand shares excluded for the three and nine ~~month periods~~months ended September 30, ~~2016.~~2019.

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~~PORTLAND GENERAL ELECTRIC COMPANY~~

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

~~(Unaudited)~~

Net income (loss) 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 September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
Weighted-average common shares outstanding—basic	89,509	89,372	89,476	89,346
Dilutive effect of potential common shares	0	222	153	209
Weighted-average common shares outstanding—diluted	89,509	89,594	89,629	89,555

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Weighted-average common shares outstanding—basic and diluted 89,065
88,921
89,044
88,885

NOTE 6:7: SHAREHOLDERS’ EQUITY

The activity in equity during the ~~nine months~~three and nine-month periods ended September 30, ~~2017~~2020 and ~~2016~~ is2019 was as follows (dollars in ~~millions)~~millions, except per share amounts):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Common Stock
Accumulated
Other
Comprehensive
Loss

Retained
Earnings

Shares Amount Total
Balances as of December 31, 2016 88,946,704
$ 1,201
$ (7 ) $ 1,150
$ 2,344
Issuances of shares pursuant to equity-based plans 145,251
1
—
—
1
Stock-based compensation —
2
—
—
2
Dividends declared —
—
—
(90 ) (90 )
Net income —
—
—
145
145
Balances as of September 30, 2017 89,091,955
$ 1,204
$ (7 ) $ 1,205
$ 2,402

Balances as of December 31, 2015 88,792,751
$ 1,196
$ (8 ) $ 1,070
$ 2,258
Issuances of shares pursuant to equity-based plans 133,875
1
—
—
1
Stock-based compensation —
2
—
—
2
Dividends declared —
—
—
(84 ) (84 )
Other comprehensive income —
1
—
1
Net income —
—
—
132
132
Balances as of September 30, 2016 88,926,626
$ 1,199
$ (7 ) $ 1,118
$ 2,310


	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	0		—		—		0
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3850 per share)	—	0		0		(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)	—	0		0		(35)		(35)
Net income	—	—		—		39		39
Balances as of June 30, 2020	89,506,951	1,224		(9)		1,431		2,646
Issuances of shares pursuant to equity-based plans	2,832	0		—		—		0
Stock-based compensation	—	2		—		—		2
Dividends declared ($0.4075 per share)	—	0		0		(36)		(36)
Net income (loss)	—	—		—		(17)		(17)
Balances as of September 30, 2020	89,509,783	$	1,226	$	(9)	$	1,378	$	2,595

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)


	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings

	Shares	Amount						Total
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	0		—		—		0
Other comprehensive income	—	—		1		—		1
Dividends declared ($0.3625 per share)	—	0		0		(32)		(32)
Net income	—	—		—		73		73
Reclassification of stranded tax effects due to Tax Reform	—	—		(2)		2		0
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)	—	0		0		(35)		(35)
Net income	—	—		—		25		25
Balances as of June 30, 2019	89,371,560	1,215		(7)		1,334		2,542
Issuances of shares pursuant to equity-based plans	414	0		—		—		0
Stock-based compensation	—	2		0		—		2
Dividends declared ($0.3850 per share)	—	0		0		(35)		(35)
Net income	—	—		—		55		55
Balances as of September 30, 2019	89,371,974	$	1,217	$	(7)	$	1,354	$	2,564

NOTE 7:8: 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. ~~Legal costs~~Costs incurred in connection with loss

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

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

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

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

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

~~Carty~~

In 2013, PGE entered into an agreement (Construction Agreement) with an engineering, procurement, and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (collectively, the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

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

Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, 2016, as authorized by the OPUC, based on the approved cost of $514 million. Actual costs for the construction of Carty exceeded the approved amount and, as of September 30, 2017, PGE has capitalized $637 million to Electric utility plant.

As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. These incremental expenses are

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~~recognized in the Company’s current results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP.~~

Actual costs do not reflect any offsetting amounts that may be received from the Sureties, pursuant to the Performance Bond. The amounts recorded also exclude $8 million of liens and claims filed for goods and services provided under contracts with the former Contractor that remain in dispute. The Company believes these liens are invalid and is contesting the claims in the courts.

The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, correcting latent defects in work performed by the former Contractor, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials.

Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage that resulted from poor storage and maintenance on the part of the former Contractor.

The Company is involved in several litigation proceedings concerning the termination of the construction agreement and the payment obligations of the Sureties. PGE is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the contractor and claims against the Sureties pursuant to the performance bond. The Sureties have denied liability in whole under the Performance Bond.

Various actions relating to this matter have been filed in the U.S. District Court for the District of Oregon (U.S. District Court), in the Ninth Circuit Court of Appeals (Ninth Circuit), and in an arbitration proceeding before the International Chamber of Commerce International Court of Arbitration (ICC arbitration), involving the following:

A breach of contract claim brought by PGE against the Sureties in U.S. District Court asserting that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Contractor’s breach of contract;

~~A claim brought by PGE in U.S. District Court against the Contractor for failure to satisfy its obligations under the Construction Agreement;~~

A claim by Abengoa S.A. in the ICC arbitration proceeding alleging that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and did not give rise to any liability of Abengoa S.A.; and

A claim by the Contractor against PGE in the ICC arbitration proceeding seeking damages of $117 million based on a claim that PGE wrongfully terminated the Construction Agreement and $44 million based on a claim that PGE failed to disclose certain information to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals.

Following various procedural arguments in the ICC arbitration and the U.S. District Court, in July 2017, the Ninth Circuit held that the ICC arbitration had jurisdiction to determine what parties and what claims could be presented in the ICC arbitration. Oral argument before the ICC arbitration is expected to take place in the spring of 2018. The decision of the ICC arbitration is expected to determine the forum in which the above referenced claims will be heard. Further detail on the various proceedings is presented in ~~Item1. Legal Proceedings~~ ~~in Part II - Other Information, of this Quarterly Report on Form 10-Q.~~

In July 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that

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such amounts are approved in a subsequent regulatory proceeding. The Company has requested that the OPUC delay its review of this deferral request until all legal actions with respect to this matter, including PGE’s actions against the Sureties, have been resolved.

Any amounts approved by the OPUC for recovery under the deferral filing 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. The Company believes that costs incurred to date and capitalized in Electric utility plant, net, in the condensed consolidated balance sheet, were prudently incurred. There have been no settlement discussions with regulators related to such costs.

After exhausting all remedies against the aforementioned parties, the Company intends to seek approval to recover any remaining excess amounts in customer prices in a subsequent regulatory proceeding. However, there is no assurance that such recovery would be allowed by the OPUC.

In accordance with GAAP and the Company’s accounting policies, any such excess costs may be charged to expense at the time recovery becomes less than probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood is less than probable that a portion of the cost of Carty will be disallowed for recovery in customer prices. Accordingly, no loss has been recorded to date related to the project.

EPA Investigation of Portland Harbor

~~A 1997~~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 and listed 69~~site. PGE has been included among more than 100 Potentially Responsible Parties (PRPs)~~. PGE was included among the PRPs~~ as it ~~has~~ historically owned or operated property near the river. In 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over 100.

~~The~~A Portland Harbor site remedial investigation ~~(RI) has been~~was completed pursuant to an ~~Administrative Order on Consent~~agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which ~~does~~did not include PGE. The LWG ~~has~~ funded the RIremedial investigation and feasibility study ~~(FS)~~ and ~~has~~ 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 ~~has~~ finalized the ~~FS,~~feasibility study, along with the ~~RI,~~remedial investigation, and ~~these documents~~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 ~~on January 6,~~in 2017. The ROD ~~outlines~~outlined the EPA’s selected remediation ~~alternative to~~plan for clean-up ~~for~~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, for a combined discounted present value of $1.05 billion. As stated within the ROD, such cost ranges were estimated with accuracy between -30% and +50% of actual~~ costs. Remediation construction costs ~~are~~were estimated to be incurred over a ~~13 year~~13-year period, with long-term operation and maintenance costs estimated to be incurred over a ~~30 year~~30-year period from the start of construction. The EPA ~~acknowledges~~acknowledged the estimated costs ~~are~~were based on data that ~~is now~~was outdated and that ~~a period of~~ pre-remedial design sampling iswas 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 ~~has prepared a Draft Sampling Plan~~indicated that while it would use the data to ~~encourage PRPs~~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 ~~enter into an Administrative Order on Consent with~~be used to design the ~~agency and begin the sampling process before the end of 2017.~~

expected remedial actions. Certain

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PRPs have entered into consent agreements, or are in good-faith discussion or on-going negotiation with the EPA, to perform remedial design. The EPA has indicated that it may perform remedial design of some areas on its own.

PGE ~~is participating~~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, ~~percentage,~~ including ~~a final allocation methodology and~~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. ~~Based~~However, based on the above facts and remaining uncertainties, PGE ~~cannot~~does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that ~~represents~~would represent PGE’s portion of the liability to clean-up Portland ~~Harbor.~~Harbor, although such costs could be material to PGE’s financial position.

~~Where damage~~In cases in which injuries to natural resources ~~has~~have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as ~~natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor~~ Natural Resource Damages ~~assessment (NRDA) process.~~(NRD). The EPA does not manage ~~NRDA~~NRD assessment activities but ~~provides~~does provide claims information and coordination support to the ~~Natural Resource Damages (NRD)~~NRD trustees. ~~Damage~~NRD assessment activities are typically conducted by a ~~Trustee~~ Council made up of the trustee entities for the site. The Portland Harbor NRD trustees ~~are~~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 ~~certain tribal entities.~~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 ~~damaged~~injured resources and may also compensate the trustees for costs incurred in assessing the damages. The ~~NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. PGE~~Company believes that ~~the Company’s~~PGE’s portion of ~~NRDA~~NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

~~As discussed above, significant uncertainties still remain concerning~~The impact of costs related to EPA and NRD liabilities on the ~~precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA,~~Company’s results of ~~resampling efforts, and the method of allocation of costs amongst PRPs. It~~operations is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation ofmitigated by the Portland Harbor ~~site, although~~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 ~~costs could~~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 ~~material.~~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 ~~the~~EPA’s determination of liability for Portland Harbor ~~proceeding~~ through ~~claims under insurance policies and regulatory recovery in~~application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices.

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

~~Trojan Investment Recovery Class Actions~~

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

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several

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~~appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.~~

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

In August 2006, the Oregon Supreme Court (OSC) issued a ruling ordering the 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. The OSC also ruled that the plaintiffs retained the right to return to the Circuit Court for disposition of whatever issues remained unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC.

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

In June 2015, at PGE’s request, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. Briefing on the appeal is now complete, with a Court of Appeals decision pending.

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

Deschutes River Alliance Clean Water Act Claims

In ~~August~~ 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company ~~in the~~(Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of ~~Oregon. DRA’s claims seek~~Oregon) thatsought injunctive and declaratory relief ~~against PGE~~ under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA ~~claims~~claimed PGE ~~has~~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

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acidity or alkalinity of the water. DRA ~~alleges~~alleged the violations ~~are~~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 ~~of the reservoir~~ with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements, for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA ~~has~~ alleged that PGE’s operation of the SWW ~~has~~had caused the above-referenced violations of the CWA, which in turn ~~have~~had degraded the ~~Deschutes River’s~~ 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 December 2020.

The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome will result in a material loss.

Shareholder Lawsuits

During September and October, 2020, three putative class action complaints were filed in U.S. District Court for the District of Oregon against PGE and certain of its officers, captioned Hessel v. Portland General Electric Co., No. 20-cv-01523, Cannataro v. Portland General Electric Co., No. 3:20-cv-01583, and Public Employees’ Retirement System of Mississippi v. Portland General Electric Co., No. 20-cv-01786. Two of these actions were filed on behalf of purported purchasers of PGE stock between April 24, 2020, and August 24, 2020; a third action was filed on behalf of purported purchasers of PGE stock between February 13, 2020, and August 24, 2020.

All three complaints assert causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 for alleged misstatements and omissions regarding, among other things, PGE’s alleged lack of sufficient internal controls and risks associated with PGE's trading activity in wholesale electric markets. Each complaint demands a jury trial and seeks compensatory damages of an unspecified amount and reimbursement of plaintiffs’ costs and attorneys’ and expert fees. The Company intends to vigorously defend against the lawsuits.Since these lawsuits are in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible losses.

Other Matters

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In September 2016, PGE filed a motion to dismiss, which asserted that the CWA does not allow citizen suits of this nature, and that FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 6, 2017, PGE filed a motion with the District Court for certification to file an interlocutory appeal with the Ninth Circuit and for a stay of the District Court proceeding. On April 7, 2017, the court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes) to appear in the case as a friend of the court. The Tribes share ownership of the Project with PGE, but have not been named as a defendant. The District Court granted PGE’s request on May 19, 2017, but the Ninth Circuit denied the appeal on August 14, 2017. The parties are engaged in settlement discussions and filed a joint motion, which was granted September 11, 2017, to extend the stay of the District Court proceedings until either party finds the settlement negotiations unproductive.

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

~~Other Matters~~

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

NOTE 8:9: GUARANTEES

PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas ~~purchase and sale agreements~~ that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of September 30, ~~2017,~~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.

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 pre-tax book loss for the quarter is the primary driver for the change in interim effective tax rate results. 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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits*	14.8		(14.8)		(23.6)		(13.8)

State and local taxes, net of federal tax benefit	4.2		6.5		10.4		6.5
Flow-through depreciation and cost basis differences	17.5		1.0		(7.2)		1.2
Amortization of excess deferred income tax	(0.4)		(3.9)		(2.8)		(3.5)
Other	4.3		0		(1.8)		0.2
Effective tax rate	61.4	%	9.8	%	(4.0)	%	11.6	%

* Federal tax credits primarily 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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Carryforwards

Federal tax credit carryforwards as of September 30, 2020 and December 31, 2019 were$82 million and $64 million, respectively. 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 September 30, 2020 will be realized; accordingly, 0 valuation allowance has been recorded. As of September 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, ~~future~~ loads, ~~the~~ outcome of litigation and regulatory proceedings, ~~future~~ capital expenditures, market conditions, ~~future~~ events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s ~~forward-looking statements~~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

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parties, but there can be no assurance that ~~the~~PGE’s expectations, beliefs, or projections ~~contained in such forward-looking statements~~ will be achieved or accomplished.

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

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

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

•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 7,8, 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 ~~that could affect~~affecting PGE’s power generating facilities, including forced outages, ~~adverse~~ hydro and wind conditions, and disruption of fuel supply, ~~disruptions,~~ 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;

~~the~~

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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 ~~which~~that could require PGE to post additional collateral or issue additional letters of credit ~~or post additional cash as collateral with counterparties~~ pursuant to power and natural gas purchase agreements;

•changes in the availability and price of wholesale power and fuels, including natural gas 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, ~~and~~or industrial customer growth, ~~and in~~or demographic patterns, in PGE’s service territory;

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

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

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

•employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and ~~employee retirements;~~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 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.~~terrorism; and

•the outcome of the review being conducted by the Special Committee relating to energy trading losses, including the impact of the recommendations of the Special Committee on the Company and its operations, the time and expense incurred in implementing the recommendations of the Special Committee, and any reputational damage to the Company relating to the matters underlying the Special Committee’s review.

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Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

~~Overview~~OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. ~~This~~The MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, ~~as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended~~ ~~December 31, 2016~~, and other periodic and current reports filed with the SEC.

PGE is a ~~vertically integrated~~vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity ~~as well as~~in the state of Oregon. In addition, the Company participates in wholesale ~~purchase~~markets by purchasing and ~~sale of~~selling electricity and natural gas in ~~order~~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.

~~In the fourth quarter of 2016,~~ Energy Trading

PGE ~~submitted~~is exposed to ~~the OPUC~~commodity price risk as its ~~2016 Integrated Resource Plan (IRP), which addresses the Company’s proposal~~primary business is to meet future customer demand and describes PGE’s future energy supply strategy and anticipated resource needs over the next 20 years. The areas of focus for the plan, include, among other topics, additional resources neededprovide electricity to meet Oregon’s Renewable Portfolio Standard (RPS) requirements and to replace energy from Boardman, the Company’s coal-fired generating plant located in Eastern Oregon that will cease coal-fired operations at the end of 2020. For further information regarding the IRP, see ~~“Integrated Resource Plan”~~ ~~in this Overview section of Item 2.~~

~~In February 2017, PGE filed a general rate case for a 2018 test year. Stipulations filed on September 18, 2017 and October 9, 2017 reflect settlement of all issues.~~ its retail customers. The Company expects ~~the OPUC~~ to ~~authorize new customer prices effective January 1, 2018. For further information, see~~ ~~“General Rate Case”~~ manage commodity price volatility within net variable power costs by engaging in ~~this Overview section~~energy trading activities. The Company does not intend to engage in trading activities for non-retail purposes.

PGE personnel entered into a number of ~~Item 2.~~

~~On October 1, 2017, the Company began active participation~~energy trades during 2020, with increasing volume accumulating late in the ~~Western Energy Imbalance Market (EIM). As~~second quarter and into the third quarter, resulting in significant exposure to the Company. In August 2020, a portion of energy trading positions in PGE’s energy portfolio experienced significant losses as wholesale electricity prices increased substantially at various market ~~participant, PGE’s generating plants now receive automated dispatch signals from~~hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. During this time period, the California Independent System Operator ~~that allows for load balancing with other EIM participants in five-minute intervals, which~~(CAISO) declared a Stage 3 Electrical Emergency and ordered the ~~Company expects will help integrate more renewable energy into the grid by better matching the variable~~

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~~output of renewable resources. Additionally, this gives PGE access to the least-cost energy available~~first rolling blackouts in the ~~region to meet changes in real-time energy demand and short-term variations in customer demand.~~state of California since 2001.

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

~~Capital Requirements and Financing—The Company expects 2017 capital expenditures to total $533 million, excluding AFDC. For additional information regarding estimated capital expenditures, see “Capital Requirements” in the Liquidity and Capital Resources section of this Item 2.~~

PGE plans to fund capital requirements and maturities of long-term debt during the year of $150 million with cash from operations during 2017, which is expected to range from $515 million to $565 million, and the issuance of debt securities of $225 million. For additional information, see ~~“Liquidity”~~ ~~and~~ ~~“Debt and Equity Financings”~~ ~~in the Liquidity and Capital Resources section of this Item 2.~~

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

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

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

~~A rate base of $4.6 billion.~~

~~PGE, OPUC staff, and certain customer groups have reached agreements that resolve all issues in the case, provide for an expected $20 million net increase in annual revenue requirements, and reflect:~~

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

~~A return on equity of 9.5%; and~~

~~A rate base of $4.5 billion.~~

~~The net increase in annual revenue requirement as proposed in the Company’s initial filing and as revised consists of the following (in millions):~~

As Filed February 28, 2017 $ 100
Load and Power Cost Updates (28 )
Depreciation Study Updates (8 )
Base Business Revenue Requirement Updates:
     Lower return on equity $ (10 )
     Lower labor costs (9 )
     Adjustment to depreciation expense (8 )
     Lower level of plant in service (5 )
     Other reductions to rate base (4 )
     Other various modifications (8 )

          Subtotal (44 )
As Stipulated
$ 20

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Regulatory review of the 2018 GRC will continue until the final order is issued, which is expected in December 2017, with new customer prices expected to become effective January 1, 2018. Final revenue requirement amounts subject to revision include power costs (to be finalized November 2017) and actual cost of debt, including any additional debt issuances. Any subsequent reductions in PGE's overall cost of long-term debt through June 30, 2018 will be reflected either in the final 2018 GRC update or through a supplemental tariff filing. All stipulations remain subject to OPUC approval.

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

~~Operating Activities—~~The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues and income from operations to fluctuate from period to period. PGE typically experiences its highest average MWh deliveries and retail energy sales during the winter heating season, although deliveries also increase during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

~~Customers and Demand—~~The 5.9% increase in retail energy deliveries for the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 resulted from increases in all retail categories with the greatest percentage increase in residential deliveries, which are most sensitive to fluctuations in weather.

Energy deliveries to residential customers increased 10.4% due in large part to the effects of cooler temperatures during the heating season and warmer temperatures during the cooling season, as well as customer growth of 1.3%. Energy deliveries to industrial customers increased 5.1%, largely due to continued strength in the high tech sector. Weather adjusted deliveries increased 0.3% from the first nine months of 2016 reflecting strength in the industrial sector. One additional day in 2016 due to leap year resulted in a comparative decrease of 0.4% in retail energy deliveries. Energy efficiency and conservation efforts by retail customers also influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See ~~“Legal, Regulatory and Environmental”~~ ~~in this Overview section of Item 2 for further information on the decoupling mechanism.~~

During the third quarter of 2017, cooling degree-days, an indication of the extent to which customers are likely to have used electricity for cooling, were 45% above the third quarter of 2016. Residential energy deliveries, which are most weather sensitive, were 12.3% higher in the third quarter of 2017 than the third quarter of 2016. Unseasonably warm weather in first quarter of 2016, which decreased energy deliveries in that quarter, and temperatures that resulted in more heating and cooling degree days in the second quarter of 2017 also contributed to the increased deliveries on a year-to-date basis. See ~~“Revenues”~~ ~~in the Results of Operations section of this Item 2 for further information on heating degree days.~~

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

Nine Months Ended September 30,
2017 2016
% Increase (Decrease) in Energy
Deliveries

Average
Number of
Customers

Retail Energy
Deliveries*

Average
Number of
Customers

Retail Energy
Deliveries*

Residential 761,028
5,826
751,198
5,278
10.4 %

Commercial (PGE sales only) 107,296
5,193
106,458
5,148
0.9 %
     Direct Access 479
472
314
403
17.1 %
Total Commercial 107,775
5,665
106,772
5,551
2.1 %

Industrial (PGE sales only) 198
2,187
193
2,168
0.9 %
     Direct Access 68
1,046
63
907
15.3 %
Total Industrial 266
3,233
256
3,075
5.1 %

Total (PGE sales only) 868,522
13,206
857,849
12,594
4.9 %
     Total Direct Access 547
1,518
377
1,310
15.9 %
Total 869,069
14,724
858,226
13,904
5.9 %


*	~~In thousands of MWh.~~

The Company’s Retail Customer Choice Program caps participation by Direct Access customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy supplied to Direct Access customers. This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE’s total retail energy deliveries for the first nine months of 2017. Energy deliveries to Direct Access customers represented 9% of the Company’s total retail energy deliveries for the full year 2016, compared with 10% in the first nine months of 2017.

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

~~PGE’s generating plants require varying levels of annual maintenance, during which the respective plants are unavailable to provide power.~~ As a result of the ~~amount~~convergence of ~~power generated to meet~~these conditions, the Company’s ~~retail load requirement can vary from period to period. Plant availability, which is affected by both planned and unplanned outages, approximated 90% and 94% during the nine months ended~~energy portfolio experienced realized losses of $127 million on these positions as of September 30, ~~2017~~2020. PGE determined the energy trading positions that led to the losses were outside the Company’s acceptable risk tolerances, and ~~2016, respectively, for those plants PGE operates. Plant availability of Colstrip Units 3 and 4, of which~~ the Company ~~has a 20% ownership interest, approximated 85% during the nine months ended September 30, 2017 and 2016, respectively.~~

~~During the nine months ended September 30, 2017, the Company’s generating plants provided 65% of its retail load requirement compared with~~ ~~69%~~ ~~in the nine months ended September 30, 2016. The decrease in the proportion of power generated to meet the Company’s retail load requirement was largely due to the combination of decreased~~

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production from the Company’s wind facilities due to unfavorable weather conditions and a reduction in energy provided from the Company’s thermal generation facilities due to outages and economic displacement. The decrease was partially offset by favorable hydro generation, during the first nine months of 2017. Favorable hydro conditions within the region had the effect of reducing energy prices in the wholesale power market which allowed the Company to economically displace a greater portion of its thermal generation to meet its retail load requirement.

Energy expected to be received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects is projected annually in the Annual Power Cost Update Tariff (AUT). Any excess in such hydro generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the nine months ended September 30, 2017, energy received from these hydro resources increased by 13% compared to the nine months ended September 30, 2016. Energy received from these hydro resources exceeded projected levels included in PGE’s AUT by 10% and fell below projected levels by 2% for the nine months ended September 30, 2017 and 2016, respectively, and provided 19% and 18%will not pursue regulatory recovery of the ~~Company’s retail load requirement for the nine months ended September 30, 2017 and 2016, respectively. Energy from hydro resources is expected to exceed levels projected~~associated losses. The increase in ~~the AUT for 2017.~~

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT. Any excess in wind generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the nine months ended September 30, 2017, energy received from these wind generating resources decreased 18% compared to the nine months ended September 30, 2016, resulting in the Company incurring higher replacement costs, as well as generating fewer Production Tax Credits (PTCs) than what was estimated in customer prices. Energy received from these wind generating resources fell short of that projected in PGE’s AUT by20% for the nine months ended September 30, 2017 and 6% for the nine months ended September 30, 2016, and provided 9% and 12% of the Company’s retail load requirement during the nine months ended September 30, 2017 and 2016, respectively. Energy from wind resources is expected to be below projected levels included in the AUT for 2017.

~~Pursuant to the Company’s power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted~~ net variable power costs ~~(NVPC) included~~due to this trading activity has been recognized in ~~customer prices (baseline NVPC)~~PGE’s results of operations. PGE no longer has net market exposure from the energy trading positions that led to these losses.

PGE has engaged and ~~actual NVPC for the year. NVPC consists~~is working with an external consultant to perform a full operational review of the ~~cost~~Company’s energy supply risk management policies, procedures and personnel. In addition, PGE has placed two individuals on administrative leave, pending review, and enhanced oversight including implementing immediate supervisory and reporting changes in advance of ~~power purchased~~the conclusion of a broader evaluation. The Company’s review and ~~fuel used~~evaluation are ongoing.

In addition, the PGE Board of Directors formed a Special Committee comprising five independent Board members to ~~generate electricity~~review the energy trading that led to ~~meet PGE’s retail load requirements, as well as~~ the ~~cost of settled electric~~losses and ~~natural gas financial contracts (all classified as Purchased power and fuel expense in~~ the Company’s ~~condensed consolidated statements of income)~~procedures and is net of wholesale revenues, which are classified as Revenues, net in the condensed consolidated statements of income. Effective January 1, 2017, PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year with actual variances subjectcontrols related to the ~~PCAM. To~~trading, and to make recommendations to the ~~extent actual annual NVPC, subject to certain adjustments, is above or below~~Board for appropriate action. The Special Committee retained independent legal advisors. The review being undertaken by the ~~deadband, which is a defined range from $30 million above to $15 million below baseline NVPC, the PCAM provides for 90%~~Special Committee of the ~~variance beyond the deadband to be collected from, or refunded to, customers, respectively, subject to a regulated earnings test.~~Board of Directors is ongoing.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in the Company’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense.

For the nine months ended September 30, 2017, actual NVPC was $14 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2017 is currently estimated to be above the baseline NVPC, but within the deadband range. Accordingly, no estimated collection from, or refund to, customers is expected under the PCAM for 2017.

~~For the nine months ended September 30,~~ ~~2016, actual NVPC was~~ ~~$3 million~~ below baseline NVPC. For the year ended December 31, 2016, actual NVPC was $10 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded pursuant to PCAM for 2016.

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PGE has contractual access to natural gas storage in Mist, Oregon from which it can draw in the event that natural gas supplies are interrupted or if economic factors require its use. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PGE’s Port Westward Unit 1 and Beaver natural gas-fired generating plants and the Port Westward Unit 2 natural gas-fired flexible capacity generating plant. PGE has entered into a long-term agreementFor further information regarding legal proceedings associated with this gas company to expand the current storage facilities, including the construction of a new reservoir, compressor station, and 13-miles of pipeline, which will collectively be designed to provide no-notice storage services to these PGE generating plants. NW Natural estimates construction will be completed during the winter of 2018-2019, at a cost of approximately $128 million. Due to the level of PGE’s involvement during the construction period, the Company is deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE has recorded $94 million to construction work-in-progress (CWIP) and a corresponding liability for the same amount to Other noncurrent liabilitiesmatter, see “Shareholder Lawsuits” in the condensed consolidated balance sheets as of September 30, 2017. Upon completion of the facility, PGE will assess whether the assets and liabilities qualify as a successful sale-leaseback transaction in which the asset and liability are removed and accounted for as either a capital or operating lease.

~~Carty~~—Pursuant to the final order issued by the OPUC on November 3, 2015 in connection with the Company’s 2016 GRC, the Company was authorized to include in customer prices the capital costs for Carty of up to $514 million, as well as Carty’s operating costs, effective August 1, 2016, following the placement of the plant into service on July 29, 2016. As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. This higher cost of service is primarily due to depreciation and amortization on the incremental capital cost, interest expense, and legal expense, all of which totaled $12 million for the nine months ended September 30, 2017 and is estimated to be approximately $14 million for the full year 2017.

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

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

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

~~An investigation of environmental matters regarding Portland Harbor;~~

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

~~For additional information regarding the above and other matters, see Note 7,~~8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

~~Oregon Clean Electricity~~COVID-19 Impacts

The COVID-19 pandemic has adversely impacted economic activity and ~~Coal Transition Plan—The~~conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions. In the State of Oregon, ~~passed~~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.

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 September 30, 2020 increased 4% compared to the same period of 2019. The change was driven by an 11% increase in residential deliveries as a larger percent of the population is spending more time at home, a 5% decrease in commercial deliveries as many business have faced temporary or permanent closures, and a 9% increase in industrial energy deliveries. Based on these trends in retail load patterns the Company currently projects that retail energy deliveries will increase approximately 1% for the full-year 2020 compared to 2019 weather-adjusted levels, however changes in deliveries across customer classes may impact retail revenues. See “Customers and Demand” and “Decoupling” in this Overview section and “Revenues” of the Results of Operations section for more information related to COVID-19 impacts on retail loads and Revenues, net.

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 soften the impacts on small businesses and low-income residential customers. PGE’s bad debt expense is projected to be $15 million for the full-year, compared to an original $6 million forecast for 2020, subject to deferral. 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

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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, although PGE has not experienced significant supply chain disruptions or construction interruptions to date. The Company’s business continuity plans have included an assessment of critical operational supply chain linkages and an assessment of potential interruptions to its 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 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 have not had 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:

•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 adopted the waiver in Q2 2020 and retrospectively applied its provisions as of March 2020, resulting in a $1 million increase to AFDC.

•Coronavirus Aid, Relief, and Economic Security (CARES) Act—On March 27, 2020, the U.S. Government enacted the CARES Act, which provides economic relief and stimulus to support the national economy during the COVID-19 pandemic and includes 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. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities which may qualify for deferral under Docket UM2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet). The Term Sheet dictates costs in scope for deferral but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020, however the final stipulations for the Term Sheet has not yet been approved by the Commission. As of September 30, 2020, PGE has deferred $6 million related to bad debt expense, and $2 million for other incremental costs associated with COVID-19 under the Term Sheet. All other incremental expenses will be recognized in the results of operations, until a determination is made that

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cost recovery is probable. 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.

Company Strategy

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.

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 229,000 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 ~~effective in March 2016,~~set a ~~law referred to as~~benchmark for percentages of electricity that must come from renewable sources and requires the elimination of coal from Oregon Clean Electricity and Coal Transition Plan (OCEP). The legislation has impacted PGE in several ways, including preventing the Company from including the costs and benefits associated with coal-fired generation in Oregon retail rates afterutility customers’ energy supply no later than 2030 (subject to an exception that ~~extends~~allowed extension of this date until 2035 for ~~the Company’s~~PGE’s output from ~~the Colstrip facility)~~Colstrip). ~~As a result, in October 2016, the Company filed a tariff request, and the OPUC approved the request, to incorporate in customer prices, on January 1, 2017, the approximate~~

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~~$6 million annual effect of accelerating recovery~~Provisions of the ~~Colstrip facility from 2042 to 2030, as required under the legislation.~~

~~Future effects under the new~~ law include:

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

a•A limitation on the life of renewable energy ~~certificates~~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 ~~on line~~online before December 31, 2022; and

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

~~The~~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 ~~evaluated~~no direct ownership interest in those two units, the ~~potential impacts~~Company does have a 20% ownership share in Colstrip Units 3 and ~~has incorporated~~4, which utilize certain common facilities with Units 1 and 2.

PGE is currently scheduled to recover the ~~effects of the legislation into its 2016 IRP.~~

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

The target amount was determined based on the EPA’s view of the options for each state, including: i) making efficiency upgrades at fossil fuel-fired power plants; ii) shifting generation from coal-fired plants to natural gas-fired plants;Colstrip Units 3 and ~~iii) expanding use of zero- and low-carbon emitting generation (such as renewable energy and nuclear energy). The final goal would need to be met~~4 by 2030, ~~and interim goals for each state would need~~although some co-owners have sought approval to ~~be met from 2022 to 2029. Under the rule, states have flexibility~~recover their costs sooner in ~~designing programs to meet~~ their emission reduction targets, including the three approaches noted above and any other measures the states choose to adopt (such as carbon tax and cap-and-trade) that would result in verified emission reductions.

~~PGE cannot predict how the states in which the Company’s thermal generation facilities are located (Oregon and Montana) will implement the rule or how the rule may impact the Company’s operations.~~respective jurisdictions. The Company continues to ~~monitor~~evaluate its ongoing investment and ownership in Colstrip, including the ~~developments around~~possibility of earlier closure of these facilities.

Any reduction in generation from Colstrip has the ~~implementation~~potential to provide capacity on the Colstrip Transmission facilities, which stretch from eastern Montana to near the western end of the ~~rule~~state, to serve markets in the Pacific Northwest and ~~efforts~~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 ceased coal-fired operation at its Boardman generating plant on October 15, 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 state regulators to develop state plans. On February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the CPP pending the resolution of legal challengesvarious parties. Prior to the ~~rule.~~ 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.

OnThe short 2020 legislative session adjourned without action on SB 1530 due to a lack of quorum and, as a result, in March ~~28, 2017,~~2020, the ~~President~~Governor of ~~the United States~~Oregon issued an Executive Order ~~that directed various~~directing state agencies to ~~review existing regulations that “potentially burden” the development~~seek to reduce and regulate greenhouse gas (GHG) emissions. Many of the ~~nation’s energy resources. Among other items,~~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 ~~specifically directs~~does not include a market-based mechanism as envisioned by the ~~EPA~~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 ~~take several actions relating~~at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050.

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

•Directs the OPUC to—

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◦determine whether utility portfolios and customer programs reduce risks and costs to ~~review the final CPP~~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 ~~final new source performance standard rules for new~~SB 1044 zero emission vehicle goals; and ~~modified power plants (NSPS) under~~

◦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 ~~Air Act~~Fuels Program and ~~suspend, revise, or rescind~~extends the ~~rules, if appropriate. On October 16, 2017,~~program, from the ~~EPA published a proposed~~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 responded to the DEQ committing to voluntarily reduce emissions to a level below the threshold in an upcoming air permit renewal for the facility. In August 2020, the DEQ provided a letter stating that they agreed with PGE’s approach and, given the total emissions will be below the screening threshold, that the facility does not need to undergo further analysis. DEQ has committed to issue the permit renewal by the end of Q2 2021 to meet its Regional Haze program obligations. 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 September 30, 2020, the Company has recorded $57 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 ~~now open~~expected to be operational and placed in-service by December 2020 and qualify for ~~comment,~~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 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.

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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 ~~which it outlined~~ the ~~rationale~~region; and

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

The ~~Company cannot predict~~order also requires that PGE consider resources in the ~~impact~~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 ~~stay,~~Action Plan, the ~~ultimate outcome of the legal challenges, or whether Oregon and Montana~~Company will continue to ~~develop implementation plans~~evaluate present and ongoing resource needs in light of the ~~Supreme Court stay,~~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 ~~Executive Order,~~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 ~~consequential EPA actions.~~wholesale market sales services.

~~SB 978—The State~~With a start date of ~~Oregon legislature passed~~January 1, 2021, the five-year agreement is expected to contribute between 100 and 160 MWs toward a ~~bill~~roughly 250 MW power capacity need that PGE identified in its ~~2017 session referred to as SB 978, which directs~~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 ~~investigate and provide a report~~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 ~~legislature by~~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. On September ~~15, 2018~~29, 2020, the OPUC issued an order in response to PGE’s RAC filing that stated PGE’s decision to proceed with Wheatridge was prudent and has authorized cost recovery of, and return on, ~~how developing industry trends, technology, and policy drivers~~the facility in customer prices once service to PGE's customers begins, in the ~~electricity sector might impact the existing regulatory system and~~fourth quarter 2020.

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~~incentives.~~ 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 September 30, 2020, the Company has recorded $79 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 ~~on this initiative, both internally~~to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and ~~in conjunction~~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 ~~provide guidance~~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 ~~support development~~maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns.

Wildfire—In 2020, Oregon experienced one of the ~~report.~~

~~Recovery~~most destructive wildfire seasons on record, with over one million acres of ~~Utility License Fees~~—land burned. PGE’s wildfire mitigation planning includes regular risk assessment. On September 7, 2020 PGE proactively initiated a public safety power shutoff (PSPS) in a zone near Mt. Hood that was identified as the region at highest risk of wildfire. In ~~May 2011,~~addition to the ~~city~~PSPS region, PGE cut power to eight different high-risk fire areas. These actions were coordinated with emergency responders and helped clear the path for them to fight wildfires. During this time, PGE also established a community resource center within the PSPS zone to help support the residents affected. The Oregon Department of ~~Gresham, Oregon (Gresham), which is within PGE’s service territory, adopted a resolution to increase utility license fees from 5% to 7%, effective July 1, 2011.~~Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company ~~believed that these utility license fees met the definition~~has received a subpoena and is fully cooperating. The Company is not aware of ~~privilege taxes within the Oregon statutes~~any wildfires caused by PGE equipment. PGE will incur costs to replace and ~~that Gresham’s increase violated the statutory 5% limitation on such taxes.~~rebuild PGE ~~began collecting the incremental 2% tax from customers~~facilities, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in Gresham, but filed suit against Gresham in Multnomah County Circuit Court, claiming that such an increase in privilege taxes violated Oregon law. In January, 2012, the Multnomah County Circuit Court ruled in favorand outside of ~~PGE,~~PGE’s property and the Company ceased collecting from Gresham customers the incremental 2% tax. Gresham appealed the Multnomah County Circuit Court decision to the Oregon Court of Appeals, which subsequently ruled in Gresham’s favor.

PGE appealed the Court of Appeals’ ruling to the Oregon Supreme Court and on August 4, 2016, the Oregon Supreme Court issued its appellate judgment in favor of Gresham. As a result of this ruling, the Company was required to pay Gresham $0.8 million, which represented the amount it had already collected from customers, plus $7 million for the remaining accrued, but uncollected, amount of incremental taxes that were not paid to Gresham when due, covering the period from July 1, 2011 through September 1, 2016. PGE recorded a corresponding regulatory asset for the $7 million.right-of-way. On ~~February 24, 2017, the Company made a filing requesting that~~October 20, 2020, the OPUC ~~allow~~formally approved PGE’s request for deferral of such costs. As of September 30, 2020, PGE deferred $10 million in costs related to wildfire response. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of ~~the $7 million from customers in Gresham over a five-year period.~~prudently incurred restoration costs.

On May 26, 2017, the OPUC Staff recommended against such recovery, stating that the OPUC has no legal authority to allow PGE to retroactively recover, from customers in Gresham, costs arising from the City’s privilege tax increase. PGE disputes the Staff’s position and believes that such amounts are legally eligible for recovery through customer prices. However, the Company cannot predict the outcome of this matter. The OPUC has indicated that it will render a decision by February 1, 2018.

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

Power Costs—Pursuant to the ~~AUT~~Annual Update Tariff (AUT) process, PGE annually files ~~annually~~ an estimate of power costs for the following year. ~~Effective January 1, 2017, customer prices were decreased $56 million annually from 2016 levels to reflect an expected reduction~~As approved by the OPUC, the 2020 AUT included a final increase in power costs ~~under the AUT. As part~~for 2020, and a corresponding increase in annual revenue requirement, of ~~its 2018 GRC, PGE included a projected reduction in power costs of $29~~$27 million ~~that was included in the overall request submitted to the OPUC and expected to be~~from 2019 levels, which were reflected in customer prices effective January 1, ~~2018. As submitted in the September 29, 2017 GRC update, PGE further reduced the projected power costs that resulted in a total reduction~~2020.

Table of ~~$36 million. Pursuant to the schedule established in the proceeding, updates of the forecast will occur through mid-November that could change this estimate.~~Contents

Under the ~~PCAM~~power cost adjustment mechanism (PCAM) for ~~2016,~~2019, NVPC waswithin the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the results of the PCAM for ~~2016~~2019 during the ~~latter~~second half of ~~2017~~2020 with a decision expected in the fourth quarter ~~2017.~~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 September 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 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 ~~recently passed OCEP legislation described above, PGE’s~~new customer information system once it was placed in service.

In 2017, ~~AUT filing included projected PTCs~~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 ~~2017 calendar year. Prior~~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 ~~legislative change, PGE included forecasts~~decision was contrary to its past limited practice of ~~PTCs only in General Rate Case proceedings.~~allowing deferrals related to capital investments and would require adjustments to its regulatory practices. The ~~inclusion~~OPUC directed its Staff to meet with the utilities and stakeholders to address the full implications of ~~PTCs in~~this decision, and to propose recommendations needed to implement this decision consistent with the ~~AUT provides for annual forecast updates for these estimated tax credits, thus reducing~~OPUC’s legal authority and the ~~risk of regulatory lag in terms of adjusting customer prices, as well as providing the Company an opportunity to potentially collect or refund variances from projected PTC’s pursuant to the PCAM.~~

public interest.

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~~Renewable Resource Costs—Pursuant~~During 2018, PGE deferred a total of $12 million of expenses related to the ~~RAC,~~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 ~~can recover~~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.

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 ~~prices~~information system were prudently incurred ~~costs~~and has not withdrawn its deferral application to recover the revenue requirement of ~~renewable resources~~this capital project. Any amounts that ~~are expected to~~may ultimately be ~~placed~~approved by the OPUC in ~~service~~subsequent proceedings would be recognized in earnings in the ~~current year. The Company may submit a filing to~~period of such approval; however, there is no assurance that such recovery would be granted by the OPUC by April 1st each year, with prices expected to become effective January 1st of the following year. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in customer prices until the January 1st effective date.OPUC.

~~In March 2016, PGE submitted to the OPUC a RAC filing that requested no significant additions or deferrals for 2016. No RAC filing has been submitted in 2017.~~

Decoupling—The decoupling mechanism, ~~which~~authorized by the OPUC ~~has authorized~~ through ~~2019, provides~~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~~weather-adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

~~Accordingly, a~~The Company recorded an estimated refund of ~~the $5 million recorded during 2014 occurred over a one-year period, which began January 1, 2016. The~~ $9 million ~~refund recorded in 2015 that~~and a collection of $9 million from residential and commercial customers, respectively for the nine months ended September 30, 2020, which resulted from variances between actual ~~weather adjusted~~weather-adjusted use per customer and that projected in the ~~2015 GRC, is expected to occur over a one-year period, which began January 1, 2017.~~2019 GRC. The Company ~~recorded an estimated collection of $3 million during the year ended December 31, 2016, as a result of variances~~continues to expect to see higher weather-adjusted use per customer from ~~amounts established in the 2016 GRC. Any collection for the year ended December 31, 2016 is expected to occur over a one-year period, which would begin January 1, 2018.~~residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by COVID-19.

~~The Company recorded an estimated collection of $9 million during the nine months ended September 30, 2017, which resulted from projections established in the 2016 GRC.~~ Collections under the decoupling mechanism are subject to an annual limitation ~~which~~of 2% of revenues for ~~2017 would currently stand~~each eligible customer class, based on the net prices in effect for the applicable tariff schedule at ~~$18 million. Any~~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 reached its 2020 annual cap for collection from ~~(or refund to)~~commercial customers during the third quarter of 2020. No cap exists for any potential refunds under the ~~2017 year is expected to occur~~decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic has resulted in larger estimated refunds under the decoupling mechanism, which have largely offset the revenue increases that have resulted from higher residential demand. At December 31, 2019, PGE recorded a total collection of $14 million, which if approved, will be collected over a one-year period ~~which would begin~~beginning January 1, ~~2019.~~2021.

~~Storm Restoration Costs~~Corporate Activity Tax—~~Beginning~~In 2019, the State of Oregon enacted HB 3427, which imposes a new gross receipts tax on companies with annual revenues in ~~2011,~~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 ~~authorized~~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.

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Non-utility Asset Retirement Obligation (ARO)—PGE is planning to perform a decommissioning study for work related to its properties leased to third parties that may result in material revision of the non-utility ARO in the fourth quarter of 2020. Additions in non-utility AROs are charged directly to the consolidated statement of income in the period in which the revisions are probable and reasonably estimable.

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 ~~collect $2.0 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized~~integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the ~~current year. If approved, stipulations filed~~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 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 September 30,	% Increase (Decrease) in Energy Deliveries			Nine Months Ended September 30,		% Increase (Decrease) in Energy Deliveries
	2020		2019			2020		2019














Energy deliveries (MWhs in thousands):
Retail:
Residential	1,832	1,646	11	%		5,621		5,428	4	%
Commercial	1,672	1,738	(4)	%		4,672		4,999	(7)	%
Industrial	914	822	11	%		2,552		2,332	9	%
Subtotal	4,418	4,206	5	%		12,845		12,759	1	%
Direct access:
Commercial	167	195	(14)	%		478		536	(11)	%
Industrial	389	373	4	%		1,114		1,093	2	%
Subtotal	556	568	(2)	%		1,592		1,629	(2)	%
Total retail energy deliveries	4,974	4,774	4	%		14,437		14,388	—	%
Wholesale energy deliveries	1,613	2,015	(20)	%		4,593		3,474	32	%
Total energy deliveries	6,587	6,789	(3)	%		19,030		17,862	7	%

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019




























Average number of retail customers:
Residential	792,155	88	%	781,223	88	%	789,726	88	%	778,285	88	%
Commercial	110,323	12		109,589	12		110,185	12		109,509	12
Industrial	194	—		193	—		194	—		194	—
Direct access	641	—		632	—		634	—		633	—
Total	903,313	100	%	891,637	100	%	900,739	100	%	888,621	100	%

Retail energy deliveries for the nine months ended September 30, 2020 increased 0.3% compared with the ~~OPUC~~nine months ended September 30, 2019, as increases in residential and industrial deliveries more than offset the decline in commercial deliveries.

In the third quarter, retail energy deliveries increased 4% compared to the third quarter of 2019, as deliveries to both residential, up 11%, and industrial, up 9%, showed considerable growth over the prior year, while commercial deliveries, down 5%, continued to lag.

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 ~~2018 GRC~~first quarter driven by mild temperatures, were up 9% in the second quarter of 2020 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 ~~increase~~be difficult or impossible to avoid. The Company saw a shift in retail demand in response, during the ~~annual collection amount~~second quarter. In particular, residential loads increased as a larger percentage of the population spent more time at home, whether working from home, providing child-care due to ~~$2.6 million, annually beginning~~school closures, or lacking employment as commercial activity slowed. Conversely, commercial energy deliveries declined as many businesses were disrupted in ~~2018.~~

~~During 2015 and 2016, PGE fully utilized the existing reserve balance~~an attempt to maintain social distancing or have closed as a result of ~~restoration costs associated~~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 was due primarily to continued growth in the high tech and digital services sectors, which saw lesser impacts from noted closures than other sectors.

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:

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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

The following table indicates the number of heating and cooling degree-days for the three and nine months ended September 30, 2020 and 2019, along with ~~storm damage occurring~~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	—		—		—



Second Quarter	554		467		636	99		102		89
July	11		3		7	180		176		182
August	1		—		6	197		216		195
September	35		80		65	115		70		71
Third Quarter	47		83		78	492		462		448
Year-to-date	2,362		2,542		2,563	591		564		537
(Decrease)/increase from the 15-year average	(8)	%	(1)	%		10	%	5	%

Cooling degree-days, which have a greater impact on demand in the third quarter of the year in PGE’s service territory, were up 6% for the quarter compared with 2019 and 10% above average, indicating larger load demand for cooling during ~~those years.~~the summer months of 2020. Total heating degree days, while 40% below average for the third quarter 2020 and 43% below 2019, bear more on customer demand during the first and second quarters when there is a greater need for heating. On a year-to-date basis, total heating degree-days in 2020 were 7% below prior year totals and 8% below average, reflecting that mild temperatures in the first quarter had served to dampen demand.

After adjusting for the effects of weather, retail energy deliveries for the nine months ended September 30, 2020 increased 1.6% compared to the same period of 2019. The increase was driven by an increase of 6% in residential deliveries and 7% growth in industrial energy deliveries partially offset by a decrease in commercial energy deliveries of 6%. Residential average 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. Retail energy deliveries for 2020 will continue to be impacted by COVID-19 related behavioral changes. Based on these trends in retail load patterns the Company currently projects that retail energy deliveries will increase approximately 1% for the full-year 2020 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

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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 nine months of 2020. Actual energy deliveries to Direct Access customers represented 11% of PGE’s total retail energy deliveries for the first nine 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 ~~a series of storm events~~power generated and purchased in the ~~first half of 2017,~~wholesale market to meet the ~~Company exhausted the $2 million storm collection authorized for 2017. Consequently, PGE is exposed~~Company’s retail load requirement can vary from period to period. The following table illustrates certain operating statistics related to the ~~incremental costs to-date related~~performance of PGE’s own generating resources for the nine months ended September 30, 2020 and 2019:


	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	93	%	94	%		73	%	84	%		42	%	46	%
Coal (3)	99		90			93		96			20		23
Wind	95		96			113		94			13		10
Hydro	88		93			76		85			7		8

(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 79% during the nine months ended September 30, 2020, compared with 88% in 2019.

Energy received from PGE-owned and jointly-owned thermal plants decreased9% during the nine months ended September 30, 2020 compared to ~~such major storms events, which total $10 million, less the amount~~2019, primarily as a result of strong performance for hydro and wind assets. Energy expected to be ~~collected~~received from thermal resources is projected annually in ~~2017, as well as any additional major storm damage costs experienced~~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 ~~remainder of 2017.~~

~~As a result~~second quarter of the ~~additional costs incurred,~~year.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects increased 11% during the ~~first quarter~~nine months ended September 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 ~~2017, PGE filed an application with~~historical stream flow data.

Energy received from PGE-owned and contracted wind resources increased 20% during the ~~OPUC requesting authorization~~nine months ended September 30, 2020 compared to ~~defer incremental storm restoration costs~~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 ~~date~~AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of ~~the application through the end of 2017, net of the $2 million being collected annually under the existing methodology. Since the application will~~historical wind levels or forecast studies when historical data is not likely be reviewed until 2017 is complete, and all applicable costs are identified, the Company is unable to predict how the OPUC will ultimately rule on this application. The Company is unable to state with any certainty at this time whether these incremental costs are probable of recovery and, accordingly, no deferral has been recorded to-date. In the event it becomes probable that some or all of these costs are recoverable, the Company will record a deferral for such amounts at such time.available.

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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.

~~Integrated Resource Plan—In November 2016, PGE filed an IRP (2016 IRP) with~~

•For the ~~OPUC. The 2016 IRP addresses acquisition of additional resources to meet RPS requirements and replace energy and capacity from Boardman, which will cease coal-fired operations at~~nine months ended September 30, 2020, actual NVPC, excluding certain trading losses, was $27 million below baseline NVPC. Based on forecast data, NVPC for the end of 2020. Further actions identified through 2021 are expected to offset expiring power purchase agreements and integrate variable energy resources, such as wind or solar generation facilities. The 2016 IRP also considers the OCEP, which, among other things, increased the RPS requirements for 2025 and future years. For further information on the OCEP, see the ~~“Legal, Regulatory and Environmental”~~ ~~section in this Overview section of Item 2.~~

~~All portfolios analyzed in the 2016 IRP pursue:~~

~~compliance with the RPS through 2050;~~

~~inclusion of cost-effective customer-side options, including energy efficiency, demand response, conservation voltage reduction, and dispatchable standby generation; and~~

~~retention of all existing power plants until 2050, with the exception of Boardman and Colstrip Units 3 & 4.~~

~~In August 2017, the OPUC acknowledged PGE’s 2016 IRP and the following primary action plan items:~~

~~Acknowledge capacity needs of 561 MW, of which 240 MW must be dispatchable, in 2021;~~

~~Acquire a total of 135 MWa of cost-effective energy efficiency;~~

~~Acquire at least 77 MW (winter) and 69 MW (summer) demand response through~~year ending December 31, 2020 ~~and 16 MW of dispatchable standby generation from customers to help manage peak load conditions and other supply contingencies;~~

~~Deploy 1 MWa of conservation voltage reduction through 2020;~~

~~Submit one or more energy storage proposals in accordance with House Bill 2193, by January 1, 2018, with an initial proposal expected~~is currently estimated to be ~~filed with~~below the ~~OPUC by mid-November 2017; and~~

~~Perform various research and studies~~baseline, but within the established deadband range. Accordingly, no estimated refund to customers is expected under the PCAM for 2020. For the nine months ended September 30, 2020, actual NVPC, including certain trading losses, was $100 million above the baseline NVPC. However, PGE will not be pursuing regulatory recovery for amounts related to ~~flexible capacity~~these trading losses, and ~~curtailment metrics, customer insights, decarbonization, risks associated with Direct Access, treatment of market capacity, accessing resources~~will be excluded from ~~Montana, and load forecasting improvements.~~NVPC for 2020.

~~PGE is engaged in bilateral negotiations with owners of existing regional resources~~•For the nine months ended September 30, 2019, actual NVPC was $5 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 ~~fill its capacity need. In August 2017,~~customers was recorded pursuant to the ~~Company filed with the OPUC a request~~PCAM for a waiver of the OPUC’s competitive bidding guidelines. In that filing, PGE requests a waiver to procure 350 - 450 MW of capacity to partially satisfy PGE’s 561 MW capacity deficit. PGE expects additional capacity contributions from contracts with Qualifying Facilities as defined by the Public Utility Regulatory Policies Act of 1978, acquisition of energy storage in compliance with House Bill 2193, and an assumed capacity contribution from incremental renewables procured through a request for proposal (RFP). The OPUC is scheduled to make a decision on the waiver request by December 5, 2017 and the Company currently anticipates negotiations to be complete by the end of the first quarter of 2018. Following the outcome of the bilateral negotiations and waiver process, PGE may request approval from the OPUC to issue RFPs for any remaining capacity need.2019.

The OPUC did not acknowledge PGE’s proposed actions for acquiring renewable resources and asked the Company to work with OPUC staff and parties to prepare and submit a revised proposal, which PGE presented at a public meeting on October 10, 2017. In the revised proposal, the Company identified the potential of revising the procurement target for the addition of RPS compliant renewable resources to 100 MWa, which could include unbundled RECs. PGE expects to submit an IRP addendum by the end of 2017 that would seek acknowledgement of a revised renewable action plan, including the issuance of RFPs for renewable resources.

Since issuing the IRP, PGE has identified a potential benchmark wind resource that could have a nameplate capacity of up to approximately 300 MW, that would meet the need for the renewable resources, and which would qualify for the production tax credit. The Company continues to explore this option. The submission of this resource into an

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RFP for renewable resources as a benchmark bid is subject to additional due diligence and negotiation along with execution of definitive agreements. If agreements are reached, the potential benchmark resource would be considered in the RFP along with other renewable resource offerings.

~~The RFP process will include oversight by an independent evaluator and review by the OPUC.~~

Critical Accounting Policies

~~PGE’s~~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, ~~2016~~,2019, filed with the SEC on February ~~17, 2017~~.14, 2020.

Results of Operations

The following ~~table contains condensed consolidated statements~~tables provide financial information to be considered in conjunction with management’s discussion and analysis of ~~income information~~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 September 30,			% Increase (Decrease)					Nine Months Ended September 30,			% Increase (Decrease)
	2020		2019						2020	2019
Total revenues	$	547			$	542	1	%		$	1,589		$	1,575	1	%
Purchased power and fuel	292				165		77	%		554			449		23	%
Gross margin(1)	255				377		(32)	%		1,035			1,126		(8)	%
Other operating expenses:
Generation, transmission and distribution	65				78		(17)	%		215			241		(11)	%
Administrative and other	63				74		(15)	%		208			223		(7)	%
Depreciation and amortization	108				103		5	%		320			305		5	%
Taxes other than income taxes	35				34		3	%		104			101		3	%
Total other operating expenses	271				289		(6)	%		847			870		(3)	%
Income (loss) from operations	(16)				88		(118)	%		188			256		(27)	%
Interest expense(2)	35				32		9	%		102			95		7	%
Other income:
Allowance for equity funds used during construction	4				2		100	%		11			7		57	%
Miscellaneous income, net	3				3		—	%		2			5		(60)	%
Other income, net	7				5		40	%		13			12		8	%
Income (loss) before income tax expense	(44)				61		(172)	%		99			173		(43)	%
Income tax expense (benefit)	(27)				6		(550)	%		(4)			20		(120)	%
Net income (loss)	$	(17)			$	55	(131)	%		$	103		$	153	(33)	%

(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 $2 million and $1 million for three months ended September 30, 2020 and 2019, respectively, and $6 million and $4 million for the nine months ended September 30, 2020 and 2019, respectively.

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Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Revenues, net $ 515
100 % $ 484
100 % $ 1,494
100 % $ 1,399
100 %
Purchased power and fuel 184
36
180
37
443
30
455
33
Gross margin 331
64
304
63
1,051
70
944
67
Other operating expenses:
Generation, transmission and distribution 73
14
69
14
235
16
199
14
Administrative and other 64
12
63
13
197
13
185
13
Depreciation and amortization 87
17
79
17
257
17
244
18
Taxes other than income taxes 30
6
29
6
94
6
89
6
Total other operating expenses 254
49
240
50
783
52
717
51
Income from operations 77
15
64
13
268
18
227
16
Interest expense* 30
6
28
6
90
6
82
6
Other income:
Allowance for equity funds used during construction 4
1
4
1
9
1
19
1
Miscellaneous income, net 2
1
—
—
4
—
—
—
Other income, net 6
2
4
1
13
1
19
1
Income before income tax expense 53
11
40
8
191
13
164
11
Income tax expense 13
3
6
1
46
3
32
2
Net income $ 40
8 % $ 34
7 % $ 145
10 % $ 132
9 %

* Net of an allowance for borrowed funds used during construction of $1 million for the three months ended September 30, 2017 and 2016, and $4 million and $10 million for the nine months ended September 30, 2017 and 2016.
Three and nine months ended September 30, 2020 compared with the three and nine months ended September 30, 2019

Net income ~~was $40 million, or $0.44 per diluted share,~~ (loss) - The following items contributed to the change in Net income for the three and nine months ended September 30, 2020 compared to the same periods in 2019 as follows (in millions):


	Three Months Ended		Nine Months Ended
September 30, 2019	$	55	$	153
Items increasing (decreasing) Net income:
Increase in Purchased power and fuel expense related to certain trading losses	(127)		(127)
Change in Purchased power and fuel expense, excluding certain trading losses	—		22
Decrease in other operating revenues primarily from the resale of excess natural gas used for fuel in 2019 that did not recur in 2020	—		(17)
Change in average retail price	8		19
Increase in retail deliveries	19		5

(Decrease) increase in wholesale revenues	(16)		5


Decrease (increase) in bad debt expense	3		(3)
Decrease in plant maintenance expense	7		21
Income taxes	33		24
Other	1		1
September 30, 2020	$	(17)	$	103
Change in Net income (loss)	$	(72)	$	(50)

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


	Three Months Ended September 30,								Nine Months Ended September 30,
	2020				2019				2020				2019

Retail:
Residential	$	245	45	%	$	218	40	%	$	747	47	%	$	713	45	%
Commercial	164		30		167		31		463		29		479		31
Industrial	58		11		50		9		162		10		144		9
Direct Access	12		2		13		2		35		2		34		2
Subtotal	479		88		448		83		1,407		88		1,370		87
Alternative revenue programs, net of amortization	(9)		(2)		4		1		—		—		5		—
Other accrued revenues, net	7		1		4		1		13		1		17		1
Total retail revenues	477		87		456		84		1,420		89		1,392		88
Wholesale revenues	56		10		72		13		130		8		125		8
Other operating revenues	14		3		14		3		39		3		58		4
Total revenues	$	547	100	%	$	542	100	%	$	1,589	100	%	$	1,575	100	%

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


	Three Months Ended		Nine Months Ended
September 30, 2019	$	456	$	1,392
Increase from higher retail energy deliveries driven by the impact of COVID-19 in the third quarter 2020, which were partially offset by milder temperatures during the winter heating season in 2020 for the nine months	19		5
Increase as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19	8		19
Increase resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertain to the demand response pilot program	7		9
Decrease attributed to alternative revenue programs related to the decoupling mechanism due to increased residential use per customer resulting from COVID-19	(13)		(5)

September 30, 2020	$	477	$	1,420
Change in Total retail revenues	$	21	$	28

Wholesale revenues for the three months ended September 30, ~~2017 compared with $34~~2020 decreased $16 million, or $0.38 per diluted share, for the three months ended September 30, 2016. The increase in Net income reflects higher usage per customer across all customer classes, along with the effect of warmer weather in 2017 compared to the same period of 2016. Depreciation and amortization expense increased due to capital additions including Carty, a portion of which is offset in higher revenues.

~~Net income~~ was $145 million, or $1.62 per diluted share, for the nine months ended September 30, 2017, compared with $132 million, or $1.49 per diluted share, for the nine months ended September 30, 2016. Temperature contrasts contributed to higher energy demand in the first three quarters of 2017 than 2016 and helped improve Gross margin. While total deliveries and customer growth remains favorable, weather-adjusted usage per residential customer continues a pattern of long-term decline. As a result, the Company recorded a $6 million increase in the estimated collection under the Decoupling mechanism in the first three quarters of 2017 compared with the first three quarters

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of 2016. Net income was aided by reduced NVPC as the average variable power cost per MWh declined 5%. NVPC was $14 million above baseline NVPC for the first three quarters of 2017, compared with $3 million below the baseline for the first three quarters of 2016. Allowance for equity funds used during construction decreased by $10 million in the first three quarters of 2017 in comparison with the first three quarters of 2016 due to lower average CWIP balances. Higher operating expenses, including additional depreciation expense, contributed to partially offset the higher net income. Lower AFDC in 2017 resulted from the completion of Carty in July 2016, and, although recovery in customer prices began in August 2016, some earnings drag continues as costs exceeded those authorized by the OPUC. Expenses related to Carty (primarily incremental depreciation, interest, and legal costs) continue to reduce earnings.

~~Three Months Ended September 30, 2017 Compared with the Three Months Ended September 30, 2016~~

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

Three Months Ended September 30,
2017 2016
Revenues^* (dollars in millions):

Retail:
Residential $ 224
43 % $ 203
42 %
Commercial 178
35
170
35
Industrial 55
11
54
11
Subtotal 457
89
427
88
Other retail revenues, net (2 ) (1 ) 1
—
Total retail revenues 455
88
428
88
Wholesale revenues 50
10
48
10
Other operating revenues 10
2
8
2
Total revenues $ 515
100 % $ 484
100 %
Energy deliveries (MWh in thousands):

Retail:

Residential 1,817
29 % 1,618
27 %
Commercial 1,851
30
1,751
30
Industrial 752
12
754
13
Subtotal 4,420
71
4,123
70
Direct access:

Commercial 169
3
141
2
Industrial 366
6
301
5
Subtotal 535
9
442
7
Total retail energy deliveries 4,955
80
4,565
77
Wholesale energy deliveries 1,224
20
1,360
23
Total energy deliveries 6,179
100 % 5,925
100 %
Average number of retail customers:

Residential 763,553
88 % 753,345
87 %
Commercial 108,705
12
107,844
13
Industrial 200
—
204
—
Direct access 588
—
373
—
Total 873,046
100 % 861,766
100 %

* Includes revenues from customers who purchase their energy from the Company as well as $10 million and $7 million in revenues for 2017 and for 2016, respectively, from Direct Access customers for transmission and delivery charges only.

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Total revenues for the three months ended September 30, 2017 increased $31 million compared to the three months ended September 30, 2016, as Total retail revenues increased $27 million while Wholesale and Other revenues were a total of $4 million higher.

~~The change in Retail revenues resulted largely from the following:~~

A $37 million increase resulting from 8.5% greater retail energy deliveries due to favorable weather conditions and increased average usage per customer across all classes. Energy deliveries to residential customers increased 12.3% in the third quarter of 2017 due in part to the effects of weather, as temperatures in 2017 were abnormally warm during the summer cooling season, and customer growth continued. Energy deliveries to commercial customers showed an increase of 6.8% while deliveries to industrial customers increased 6.0%, largely due to strength in the high tech sector; and

~~A $3 million increase in various Supplemental tariffs, the largest of which was a $1 million increase due to the accelerated cost recovery of Colstrip; partially offset by~~

~~A $7 million decrease that resulted from customer price changes; and~~

~~A $4 million decrease that resulted from other tariffs, which included $3 million greater estimated refunds under the decoupling mechanism, combined with a variety of smaller items.~~

Total cooling degree-days for the three months ended September 30, 2017, were up 45% from the level for the three months ended September 30, 2016, 43% above the quarterly average. Total heating degree-days for the three months ended September 30, 2017 were on par with the three months ended September 30, 2016 and the historical average.

The following table indicates the number of heating and cooling degree-days for the three months ended September 30, 2017 and 2016, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

Heating Degree-days Cooling Degree-days
2017 2016 Avg. 2017 2016 Avg.
July 1
3
9
164
140
163
August 1
3
8
275
224
168
September 76
72
61
132
30
68
Totals for the quarter 78
78
78
571
394
399

~~Wholesale revenues~~ ~~for the three months ended September 30, 2017 increased $2 million, or 4%~~22%, from the three months ended September 30, ~~2016, and consisted~~2019, as a result of a$7 $14 million ~~increase~~decrease related to 20% lower wholesale sales volume and a ~~16% increase~~$2 million decrease as a result of a 3% decline in average wholesale ~~price~~sales prices.

Wholesale revenues for the nine months ended September 30, 2020 increased $5 million, or 4%, from the nine months ended September 30, 2019, as sales volumes increased 32%, the effect of which was partially offset by a ~~$5 million decrease related to a 10% decrease~~21% reduction in the average wholesale sales ~~volume.~~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

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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.

~~Purchased power and fuel~~ ~~expense increased$4 million, or 2%,~~

Other operating revenues for the three months ended September 30, ~~2017 compared with~~2020 was unchanged from the three months ended September 30, ~~2016. This change consisted of $3 million related to~~2019. The Company recorded an increase in ~~total system load combined with $1~~revenue from its participation in the western Energy Imbalance Market although that was more than offset by the temporary pause on late fees that resulted from the COVID-19 pandemic.

Other operating revenue for the nine months ended September 30, 2020 decreased $19 million ~~related~~from the nine months ended September 30, 2019 predominately resulting from market conditions that provided less revenue from the resale 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. Milder than average winter temperatures in North America in 2020 resulted in an oversupply of natural gas and lower prices.

Purchased power and fuel - The following items contributed to ~~an overall~~the increase (decrease) in Purchased power and fuel for the three and nine months ended September 30, 2020 compared to the same periods in 2019 as follows (dollars in millions, except for average variable power cost per MWh. The increase in expense due to changes in system load was driven primarily by a 7% increase in retail energy sales to meet summer load requirements. Average variable power cost increased to $30.99 per MWh inMWh):


	Three Months Ended		Nine Months Ended
September 30, 2019	$	165	$	449
Increase related to average variable power cost per MWh	108		32
Increase related to total system load	19		73
September 30, 2020	$	292	$	554
Change in Purchased power and fuel	$	127	$	105

Average variable power cost per MWh:
September 30, 2019	$	25.16	$	26.25
September 30, 2020	$	46.62	$	30.44

Total system load (MWhs in thousands):
September 30, 2019	6,531		17,085
September 30, 2020	6,251		18,201

For the three months ended September 30, ~~2017 from $30.82 per MWh~~2020, the $108 million increase related to the change in ~~the three months ended September 30, 2016.~~

While the Company generated 78% of its total system load in the three months ended September 30, 2017, compared with 77% in the three months ended September 30, 2016, the average variable cost per MWh of energy generated declined 10%. Included in this percentage was a 21% decrease in the average variable cost per MWh of energy generated from the Company’s natural gas-fired resources due to lower fuel costs, less hedging activity

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~~losses, and a 4% increase in the volume of energy obtained from the Company’s hydro resources due to more favorable hydroelectric conditions.~~

~~Although the Company purchased 22% of its total system load in 2017 compared with 23% in 2016, the~~ average variable power cost per MWh (which includes PGE-generated power and market purchases), was driven by a 105% increase on the average cost of purchased power, ~~increased~~offset with an 8% decrease on the average cost for the Company’s own generation. The increase in the cost of purchased power was driven by ~~18%~~realized losses of $127 million related to a portion of energy trading positions in PGE’s energy portfolio. See the “Overview” section of this Item 2. for more details on trading losses. The $19 million increase related to total system load was primarily due to a 46% increase in purchased power (which was purchased at higher ~~market prices reflecting the increased summer peak demands. A 16%~~average prices), offset by a 17% decrease in ~~energy received from~~ the Company’s ~~wind generating resources necessitated~~own generation, driven by lower gas prices and surplus hydro in the ~~purchase~~region.

For the nine months ended September 30, 2020, the $32 million increase related to the change in average variable power cost per MWh, was primarily driven by a 14% increase in the cost for purchased power, offset with an 8% decrease on the average cost for the Company’s own generation. The $73 million increase related to total system load was primarily due to a 35% increase in purchased power, driven by lower gas prices and surplus hydro in the region.

Table of ~~replacement power as a result.~~Contents

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	2,290	37	%	2,881	44	%	5,767	32	%	6,199	36	%
Coal	1,248	20		1,450	22		2,752	15		3,163	19
Total thermal	3,538	57		4,331	66		8,519	47		9,362	55
Hydro	233	4		261	4		919	5		1,098	7
Wind	527	8		598	10		1,720	9		1,418	8
Total generation	4,298	68		5,190	79		11,158	61		11,878	70
Purchased power:
Term	1,477	24		1,000	15		5,585	31		4,177	24
Hydro	398	6		241	4		1,202	7		807	5
Wind	78	1		100	2		256	1		223	1

Total purchased power	1,953	32		1,341	21		7,043	39		5,207	30
Total system load	6,251	100	%	6,531	100	%	18,201	100	%	17,085	100	%
Less: wholesale sales	(1,613)			(2,015)			(4,593)			(3,474)
Retail load requirement	4,638			4,516			13,608			13,611

Three Months Ended September 30,

2017
2016
Sources of energy (MWh in thousands):

Generation:

Thermal:

Coal 1,404

24 %
1,418

24 %
Natural gas 2,442

41

2,243

39
Total thermal 3,846

65

3,661

63
Hydro 277

5

267

4
Wind 480

8

570

10
Total generation 4,603

78

4,498

77
Purchased power:

Term 908

15

913

16
Hydro 332

6

322

6
Wind 83

1

91

1
Total purchased power 1,323

22

1,326

23
Total system load 5,926

100 %
5,824

100 %
Less: wholesale sales (1,224 )

(1,360 )

Retail load requirement 4,702

4,464

Energy received from PGE-owned wind generating resources decreased 16% in the three months ended September 30, 2017 compared with the same period of 2016 as a result of less favorable wind conditions. Energy received from these wind generating resources represented 10% and 13% of the Company’s retail load requirements for the three months ended September 30, 2017 and 2016, respectively. Due to more favorable hydroelectric conditions, energy received from hydro resources during the three months ended September 30, 2017, from both PGE-owned generating plants and purchased from mid-Columbia projects, increased~~3% compared with the same period of 2016, and represented 13% of the Company’s retail load requirement for the three months ended September 30, 2017 and 2016, respectively.~~

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The following table presents the actual April-to-September ~~2017~~2020 and ~~2016~~2019 runoff at particular points of major rivers relevant to PGE’s hydro resources:


	Actual Runoff as a Percent of Normal*					Runoff as a Percent of Normal*
Location	2017		2016		Location	2020 Actual		2019 Actual
Columbia River at The Dalles, Oregon	98	%	89	%	Columbia River at The Dalles, Oregon	104	%	94	%
Mid-Columbia River at Grand Coulee, Washington	98		91		Mid-Columbia River at Grand Coulee, Washington	109		87
Clackamas River at Estacada, Oregon	97		71		Clackamas River at Estacada, Oregon	75		114
Deschutes River at Moody, Oregon	98		91		Deschutes River at Moody, Oregon	86		111

* Volumetric water supply forecasts and historical ~~30-year~~ averages ~~(as measured over the period from 1981 through 2010)~~ for the Pacific Northwest region are prepared by the Northwest River Forecast Center, ~~in conjunction~~ with the Natural Resources Conservation Service and other cooperating agencies.

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


	Three Months Ended		Nine Months Ended
September 30, 2019	$	93	$	324
Increase in Purchased power and fuel expense	127		105
Decrease (Increase) in Wholesale revenues	16		(5)
September 30, 2020	$	236	$	424
Change in NVPC	$	143	$	100

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 September 30, 2020 and 2019, actual NVPC, excluding certain trading losses, was $11 million above the baseline and $2 million below the baseline NVPC, respectively. For the nine months ended September 30, 2020 and 2019, actual NVPC, excluding certain trading losses, was$27 million below and $5 million above baseline NVPC, respectively. If NVPC for 2020 included certain trading losses, it would have been $138 million and $100 million above the baseline for the three and nine months ended September 30, 2020, respectively.

Based on forecast data, NVPC, excluding certain trading losses, 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 nine months ended September 30, 2020 compared to the same periods in 2019 (in millions):


	Three Months Ended		Nine Months Ended
September 30, 2019	$	78	$	241
Decrease primarily due to lower maintenance expense as the result of reduced run hours and lower long-term service agreement costs at some of the Company’s generation facilities	(7)		(22)
Decrease due to lower utilization of contract labor and higher capitalization rates	(9)		(8)
Miscellaneous expenses	3		4
September 30, 2020	$	65	$	215
Change in Generations, transmission and distribution	$	(13)	$	(26)

In the third quarter 2020, PGE deferred $10 million of incremental costs related to wildfires in PGE’s service territory. See the “Overview” section of this Item 2. for more information.

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


	Three Months Ended		Nine Months Ended
September 30, 2019	$	74	$	223
Lower employee benefits expense	(6)		(11)
Increase (decrease) to bad debt expense	(3)		3
Lower outside services	(2)		(4)
Miscellaneous expenses	—		(3)
September 30, 2020	$	63	$	208
Change in Administrative and other	$	(11)	$	(15)

In the third quarter 2020, PGE deferred $6 million of bad debt related to incremental expense incurred related to COVID-19 as part of the OPUC’s Energy Term Sheet. See the “Overview” section of this Item 2. for more information.

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


	Three Months Ended		Nine Months Ended
September 30, 2019	$	103	$	305
Increased depreciation and amortization expense from capital additions	3		8
Increased amortization related to regulatory programs (offset in revenues)	2		11
Miscellaneous expenses	—		(4)
September 30, 2020	$	108	$	320
Change in Depreciation and amortization	$	5	$	15

Interest expense, netincreased$3 million and $7 million, in the threeandnine months ended September 30, 2020, respectively. The increase for the three months ended September 30, ~~2017 increased $2 million when compared with~~2020 was primarily due to an increase in the ~~three~~average balance of outstanding debt. The increase for the nine months ended September 30, ~~2016. The increase~~2020 was ~~driven by a 1% increase in~~primarily attributable to the higher average ~~variable power cost per MWh,~~balance of outstanding debt as well as interest on additional finance leases.

Other income, net increased $2 million and a 2% increase in total system load. The increase in wholesale revenues was driven primarily by a 16% increase in the average wholesale sales price, offset slightly by a 10% decrease in wholesale sales volume. For$1 million for the three and nine months ended September 30, 2017, actual NVPC was $22 million above the baseline as the Company met higher customer load, driven by historically hot weather, with energy purchased at super peak prices in the open market in addition to the cost of foregoing the use of Company resources in order to maintain mandated reliability reserves. For the three months ended September 30, 2016, actual NVPC was $3 million above baseline NVPC.

~~Generation, transmission and distribution~~ expense increased $4 million, or 6%, in the three months ended September 30, 2017 compared with the three months ended September 30, 2016, driven primarily by $2 million of operating expense for Carty (placed in service July 29, 2016).

~~Administrative and other~~ ~~expense increased$1 million, or 2%, in the three months ended September 30, 2017 compared with the three months ended September 30, 2016.~~2020, respectively. The increase ~~was primarily due to a $2 million increase in employee incentives, offset by decreases in other miscellaneous expenses.~~

~~Depreciation and amortization~~ expense increased $8 million in the three months ended September 30, 2017 compared with the three months ended September 30, 2016. The increase was driven by higher depreciation expense of $6 million resulting from capital additions, $2 million of which was due to Carty going into service in July 2016, and a $1million decrease in the amortization credit related to the Trojan spent fuel refund to customers, which is also reflected in revenues as increases or decreases in expense resulting from amortization of regulatory assets or liabilities are directly offset in revenues.

~~Interest expense, net~~ increased $2 million, or 7%, in the three months ended September 30, 2017 compared with the three months ended September 30, 2016, primarily due to a lower Allowance for borrowed funds used during construction, as a result of Carty going into service in July 2016.

~~Other income, net~~ ~~increased $2 million~~ for the three months ended September 30, ~~2017 compared with~~2020 was primarily due to market changes on the ~~three months ended September 30, 2016, due largely to interest income on various regulatory assets and unrealized gains on~~non-qualified benefit trust ~~assets.~~

~~Income tax expense~~ ~~was $13 million in the three months ended September 30, 2017 compared with $6 million in the three months ended September 30, 2016, with effective tax rates of 24.5%and15.0%, respectively.~~. The increase ~~in income tax expense and effective tax rate was primarily driven by higher pre-tax income and lower PTCs.~~

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~~Nine Months Ended September 30, 2017 Compared with the Nine Months Ended September 30, 2016~~

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

Nine Months Ended September 30,
2017 2016
Revenues ^* (dollars in millions):

Retail:
Residential $ 715
48 % $ 648
47 %
Commercial 501
34
492
35
Industrial 158
11
153
11
Subtotal 1,374
93
1,293
93
Other retail revenues, net 7
—
5
—
Total retail revenues 1,381
93
1,298
93
Wholesale revenues 79
5
74
5
Other operating revenues 34
2
27
2
Total revenues $ 1,494
100 % $ 1,399
100 %
Energy deliveries (MWh in thousands):
Retail:
Residential 5,826
34 % 5,278
32 %
Commercial 5,193
30
5,148
31
Industrial 2,187
13
2,168
13
Subtotal 13,206
77
12,594
76
Direct access:
Commercial 472
3
403
2
Industrial 1,046
6
907
6
Subtotal 1,518
9
1,310
8
Total retail energy deliveries 14,724
86
13,904
84
Wholesale energy deliveries 2,336
14
2,621
16
Total energy deliveries 17,060
100 % 16,525
100 %
Average number of retail customers:
Residential 761,028
88 % 751,198
88 %
Commercial 107,296
12
106,458
12
Industrial 198
—
193
—
Direct access 547
—
377
—
Total 869,069
100 % 858,226
100 %

* Includes revenues from customers who purchase their energy from the Company as well as $28 million in revenues for 2017 and $22 million for 2016 from Direct Access customers for transmission and delivery charges only.

~~Total revenues for the~~ nine months ended September 30, ~~2017 increased $95~~2020 was primarily due to higher AFDC equity income, partially offset by market changes on the non-qualified benefit trust.

Income tax expense decreased $33 million ~~or 7%, compared to the~~and $24 million for three and nine months ended September 30, ~~2016, consisting primarily of an $83 million increase in Total retail revenues.~~

~~The change in Retail revenues consisted of the following contributing factors:~~

~~A $76 million increase due to a 5.9% increase in retail energy deliveries due largely~~2020, respectively, compared to the ~~effects of weather on electricity demand. Considerably cooler temperatures~~same periods in the first half of the year than experienced in 2016 combined with warmer temperatures in the summer cooling season, when air conditioning loads influence customer demand, both drove deliveries higher in 2017 than in 2016;

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A $7 million net increase from an average price increase of 0.5% over 2016 levels. Price changes, as authorized by the OPUC, include Carty going into service in mid-2016 and reflect a reduction as a result of lower NVPC as filed in the 2017 AUT; and

~~A $3 million increase resulted from other tariffs, which included a $4 million increase in estimated collections under the decoupling mechanism; partially offset by~~

A $3 million decrease from supplemental tariffs, due in part to the $9 million timing difference related to the Trojan spent fuel refund to customers, as the refund, offset in Depreciation and amortization, temporarily suspended during the first seven months of 2016, has resumed, partially offset by a $4 million increase related to the accelerated cost recovery of Colstrip, and various smaller items.

Total heating degree-days for the nine months ended September 30, 2017 were up 42% from those for the nine months ended September 30, 2016 and 11% above average. Total cooling degree-days for the nine months ended September 30, 2017 were 28% above those for the nine months ended September 30, 2016, and 49% above average.

The following table indicates the number of heating and cooling degree-days for the nine months ended September 30, 2017 and 2016, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

Heating Degree-days Cooling Degree-days
2017 2016 Avg. 2017 2016 Avg.
First quarter 2,171
1,585
1,867
—
—
—
Second quarter 686
403
689
129
154
70
Third quarter 78
78
78
571
394
399
Year-to-date 2,935
2,066
2,634
700
548
469

~~Wholesale revenues~~ for the nine months ended September 30, 2017 increased $5 million, or 7%, from the nine months ended September 30, 2016, and consisted of $13 million related to a 19% increase in wholesale sales volume partially offset by $8 million related to an 11% decrease in wholesale prices.

~~Other operating revenues~~ ~~increased $7 million as the sale of gas not needed to fuel the Company’s generating facilities accounted for the majority of the increase.~~

~~Purchased power and fuel~~ ~~expense decreased$12 million, or 3%, for the nine months ended September 30, 2017 compared~~2019, with the ~~nine months ended September 30, 2016, and consisted of $22 million related to a5% decrease in the average variable power cost per MWh, partially offset by$10 million related to a 2% increase in total system load.~~

~~The decrease in the average variable power cost to $26.93 per MWh in the nine months ended September 30, 2017 from $28.28 per MWh in the nine months ended September 30, 2016, was driven~~decreases primarily ~~by a 10% reduction in the average variable power cost per MWh for purchased power~~ due to lower pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Credit market ~~prices. This was partially offset~~disruptions caused by the ~~purchase~~impacts of ~~replacement power due~~COVID-19 have increased liquidity concerns. PGE’s capacity to ~~18% less energy received from the Company’s wind generating resources.~~

~~The $10~~respond to liquidity issues and credit market disruptions is supported by: i) a $500 million increase related to total system load in the nine months ended September 30, 2017 in comparison to the nine months ended September 30, 2016 was driven primarily by a 7% increase in energy obtained from purchased power in response to higher weather-driven loads, as well as the purchase of replacement energy due to an 18% reduction in energy deliveries from the Company’s wind generating resources due to unfavorable weather conditions. This was partially offset by a 12% increase in energy obtained from the Company’s hydro resources due to more favorable hydroelectric conditions.

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

Nine Months Ended September 30,
2017 2016
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal 2,571
16 % 2,535
16 %
Natural gas 3,982
24
4,017
25
Total thermal 6,553
40
6,552
41
Hydro 1,353
8
1,214
7
Wind 1,283
8
1,559
10
Total generation 9,189
56
9,325
58
Purchased power:

Term 5,705
35
5,355
33
Hydro 1,332
8
1,160
7
Wind 207
1
241
2
Total purchased power 7,244
44
6,756
42
Total system load 16,433
100 % 16,081
100 %
Less: wholesale sales (2,336 ) (2,621 )
Retail load requirement 14,097
13,460

Energy received from PGE-owned wind generating resources decreased 18% in the nine months ended September 30, 2017 compared with the same period of 2016 as a result of less favorable wind conditions. Energy received from these wind generating resources represented 9% and 12% of the Company’s retail load requirements for the nine months ended September 30, 2017 and 2016, respectively. Due to more favorable hydroelectric conditions, energy received from hydro resources during the nine months ended September 30, 2017, from both PGE-owned generating plants and purchased from mid-Columbia projects, increased 13% compared with the same period of 2016, and represented 19% and 18% of the Company’s retail load requirement for the nine months ended September 30, 2017 and 2016, respectively.

~~Actual NVPC~~ ~~for the nine months ended September 30, 2017 decreased~~$17 million when compared with the nine months ended September 30, 2016. The decrease in purchased power and fuel was driven by a 5% decrease in the average variable power cost per MWh, partially offset by a 2% increase in total system load. The overall decrease in Actual NVPC was also driven by a 7% increase in wholesale revenues. The change in wholesale revenues was due mostly to a~~19% increase in wholesale sales price, partially offset by an11% decrease in sales volume. For the nine months ended September 30, 2017 and 2016, actual NVPC was$14 million above and $3 million below baseline NVPC, respectively.~~

~~Generation, transmission and distribution~~ ~~expense increased~~$36 million, or 18%, in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 primarily related to $13 million higher operating expense for Carty (placed in service July 29, 2016), $12 million higher overall storm restoration costs, and $5 million higher maintenance and overhaul expense.

~~Administrative and other~~ expense increased $12 million, or 6%, in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016. The increase was primarily due to $6 million higher employee incentives and $3 million higher legal costs for Carty.

~~Depreciation and amortization~~ ~~expense increased $13~~revolving credit facility; ii) $220 million in ~~the nine months ended September 30, 2017 compared~~letter of credit facilities; iii) strong investment grade credit ratings with ~~the nine months ended September 30, 2016. The increase was primarily due~~multiple agencies; iv) significant capacity to ~~higher depreciation expense~~issue additional debt within existing debt covenant restrictions; and v) continued access to capital markets demonstrated by an issuance of $8a $150 million driven by the Carty plant going into service in July 2016, $13 million higher depreciation expense due to other capital additions, partially offset by a $9 million amortization credit in 2017 related to the Trojan spent fuel refund to customers, which is also reflected in reduced revenues.

~~Taxes other than income taxes~~ increased $5 million, or 6%, in the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, driven by $3 million higher property taxes, due largely to the addition of Carty,364-day term loan and a $2$200 million ~~increase~~FMB issuance in ~~FICA taxes due to~~April 2020. The Company has the combination of increased headcount, higher FICA limits and rates, annual pay increases, and incremental labor required as a result of the numerous storms and resulting restoration activities during 2017.

~~Interest expense, net~~ ~~increased~~$8 million, or 10%, in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016, primarily due to a lower allowance for borrowed funds used during construction, as a result of Carty going into service in July 2016.

~~Other income, net~~ ~~was~~$13 million in the nine months ended September 30, 2017 compared with $19 million in the nine months ended September 30, 2016. The change was due to a $10 million decrease in the allowance for equity funds used during construction, primarily related to the Carty project, partially offset by higher gains on the non-qualified benefit trust assets.

~~Income tax expense~~ ~~was $46 million in the nine months ended September 30, 2017 compared with $32 million in the nine months ended September 30, 2016, with effective tax rates of 24.1%and~~19.5%, respectively. The increase in income tax expense and the effective tax rate was driven by higher pre-tax income, the tax effect of lower AFDC equity, and a decrease in PTCs, partially offset by an increase in the domestic production activity deduction.

~~Liquidity and Capital Resources~~

~~Capital Requirements~~

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

2017 2018 2019 2020 2021
Ongoing capital expenditures ⁽¹⁾
$ 486
$ 535
$ 443
$ 451
$ 440
Customer information system ⁽²⁾
47
16
—
—
—
Total capital expenditures $ 533
⁽³⁾
$ 551
$ 443
$ 451
$ 440
Long-term debt maturities $ 150
$ —
$ 300
$ —
$ 160


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


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


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

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

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~~Liquidity~~

PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, ~~as well as~~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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	Nine Months Ended September 30,							Nine Months Ended September 30,
	2017			2016				2020		2019
Cash and cash equivalents, beginning of period	$	6		$	4		Cash and cash equivalents, beginning of period	$	30	$	119
Net cash provided by (used in):							Net cash provided by (used in):
Operating activities	519			497			Operating activities	442		502
Investing activities	(369		)	(454		)	Investing activities	(551)		(406)
Financing activities	(67		)	41			Financing activities	332		(204)
Increase in cash and cash equivalents	83			84
Increase (decrease) in cash and cash equivalents							Increase (decrease) in cash and cash equivalents	223		(108)
Cash and cash equivalents, end of period	$	89		$	88		Cash and cash equivalents, end of period	$	253	$	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. ~~Net~~The following items contributed to the net change in cash flows from ~~operating activities~~operations for the nine months ended September 30, ~~2017 increased $22 million when~~2020 compared with the nine months ended September 30, ~~2016. Included in the change were a number of relatively small, somewhat offsetting, factors such as:~~2019 (in millions):


	Increase/ (Decrease)
Net income	$	(50)
Deferred income tax	(17)
Accounts receivable, net	(53)
Accounts payable and accrued liabilities	49
Depreciation and amortization	15
Other	(4)
Net change in cash flow from operations	$	(60)

A $48 million increase from the combination of higher Net income, increases in non-cash expenses for Depreciation and amortization and Deferred taxes, increases from Other non-cash income and expenses, and a

The decrease in ~~the non-cash credit~~cash provided from Accounts receivable, net is primarily driven by a higher Accounts receivable, net balance in Q3 2020 due to ~~income for the Allowance for equity funds used during construction as Carty was placed in service in July 2016, net of the overall decrease resulting from Decoupling deferrals; and~~moratoriums related to COVID-19,

~~A $14 million net increase from a combination of changes in Other working capital items, net and Other, net adjustments to net income; partially offset by~~

~~A $21 million smaller decrease in Margin deposits; and~~

~~A $17 million reduction in the comparative quarter over quarter increase in Accounts payable and accrued liabilities.~~

~~Cash provided by operations includes the recovery in customer prices of~~PGE estimates that non-cash charges for depreciation and ~~amortization. PGE estimates that such charges~~amortization in ~~2017~~2020 will range from ~~$340~~$410 millionto ~~$350~~$430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from ~~$515~~$450 million to ~~$565~~$500 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 nine months ended September 30, ~~2017 decreased $85~~2020 increased $145 million when compared with the nine months ended September 30, ~~2016, largely due to the lower level of~~2019, as capital expenditures ~~resulting from~~increased as a result of construction underway for Wheatridge and the ~~completion of Carty during 2016.~~IOC in 2020.

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~~The~~Excluding AFDC, the Company plans to make capital expenditures of ~~$533~~$750 million ~~excluding AFDC,~~ in ~~2017,~~2020, which it expects to fund with cash to be generated from operations during ~~2017,~~2020, as discussed above, ~~as well as with proceeds received from~~and the ~~issuances~~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 nine months ended September 30, ~~2017, a net use of cash resulted from financing activities primarily for the payment of dividends of $87 million and, as further described in~~ ~~“Debt and Equity Financings”~~ ~~in this Liquidity section of Item 2, the repayment of $50 million of term loans, net of the issuance of $75 million of FMBs. During the nine months ended September 30, 2016,~~2020, net cash provided by financing activities~~consisted~~ was primarily the result of ~~$265 million received~~proceeds from the ~~issuances~~combination of $200 million of FMBs

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issued, the $150 million term loan, $75 million of commercial paper and ~~borrowing under an unsecured credit agreement,~~$21 million from the remarketing of PCRBs previously held by the Company, partially offset by ~~repayment~~the payment of $103 million of dividends.

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2020through2024 (in millions, excluding AFDC).


	2020		2021		2022		2023		2024
Ongoing capital expenditures*	$	560	$	540	$	500	$	500	$	500
Wheatridge Renewable Energy Facility	120		15		—		—		—
Integrated Operations Center	70		100		—		—		—
Total capital expenditures	$	750	$	655	$	500	$	500	$	500
Long-term debt maturities	$	—	$	160	$	—	$	—	$	80

* Consists primarily of ~~$133 million~~upgrades to, and ~~the payment~~replacement of, ~~dividends of $82 million.~~generation, transmission, and distribution infrastructure, as well as new customer connections. Includes preliminary engineering and removal costs.

~~Dividends on Common Stock~~

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

~~Common stock dividends declared during 2017 consist of the following:~~



			~~Dividends~~
			~~Declared Per~~
~~Declaration Date~~	~~Record Date~~	~~Payment Date~~	~~Common Share~~
~~February 15, 2017~~	~~March 27, 2017~~	~~April 17, 2017~~	~~$0.32~~
~~April 26, 2017~~	~~June 26, 2017~~	~~July 17, 2017~~	~~0.34~~
~~July 26, 2017~~	~~September 25, 2017~~	~~October 16, 2017~~	~~0.34~~
~~October 25, 2017~~	~~December 26, 2017~~	~~January 16, 2018~~	~~0.34~~

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.~~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. ~~However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions.~~

For ~~2017,~~2020, PGE expects to fund estimated capital ~~expenditures and maturities of long-term debt~~requirements with cash from operations, ~~(which~~which is expected to range from$~~515~~450 million to~~$565 million),~~ $500 million, issuances of debt securities of up to ~~$225~~$450 million, and the issuance of commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures and ~~maturities of long-term debt.~~debt payments.

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

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As7, 2022. The following table shows available liquidity as of September 30, ~~2017, PGE had a $500 million revolving credit facility scheduled~~2020 (in millions):


	As of September 30, 2020
	Capacity		Outstanding		Available
Revolving credit facility (1)	$	500	$	—	$	500
Letters of credit (2)	220		55		165
Total credit	$	720	$	55	$	665
Cash and cash equivalents					253
Total liquidity					$	918

(1)Scheduled to expire in November ~~2020~~. 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.

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PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the ~~applicable~~ credit facility.

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

~~Under the revolving credit facility, as~~As of September 30, ~~2017, since~~2020, PGE had ~~no borrowings outstanding, and no~~$75 million commercial paper ~~or letters of credit issued, the~~outstanding. The aggregate unused available credit capacity under the revolving credit facility was $500 million. 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.

~~In addition,~~On April 9, 2020, PGE ~~has four letter~~obtained a 364-day, term loan in the aggregate principal of ~~credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for a total capacity of $220~~$150 million. The ~~issuance of such letters of credit~~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 ~~approval~~terms of the ~~issuing institution. Under these facilities, letters of~~loan. The credit ~~for a total of$54 million were~~agreement expires on April 8, 2021, with any outstanding ~~as of September 30, 2017.~~balance due and payable on such date.

Long-term Debt. As of September 30, ~~2017,~~2020, total long-term debt outstanding, net of $9$12 million of unamortized debt expense, was ~~$2,377 million, with $100 million scheduled maturities classified as current.~~$2,817 million.

On ~~August 2, 2017,~~March 11, 2020, PGE ~~entered into a bond purchase agreement to issue First Mortgage Bonds (FMBs) in~~completed the ~~amount~~remarketing of ~~$225 million at an interest rate of 3.98%. Under this agreement, PGE drew $75 million in August, with a maturity in 2048, and plans to draw $150 million in November 2017, with a maturity in 2047.~~

~~In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in~~ an aggregate principal amount of ~~up to~~$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 ~~by October 31, 2016. Under the agreement, PGE obtained three separate loans totaling $150 million. On August 21, 2017, the Company repaid one~~ of ~~the loans~~3.15% Series First Mortgage Bonds (FMBs) due in ~~the amount of $50 million. The remaining $100 million is due and payable on or before the November 30, 2017 credit agreement expiration date.~~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 ~~50.3%~~44.5% and ~~49.4%~~48.1% as of September 30, ~~2017~~2020 and December 31, ~~2016~~,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-A
~~Issuer rating~~Senior unsecured debt	A3	~~BBB~~BBB+
Commercial paper	P-2	A-2
Outlook	Stable	~~Positive~~Negative

Should Moody’s ~~and/~~or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits ~~provided~~that PGE provides as collateral are classified as Margin deposits, which is included in Other current

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assets on ~~PGE’s~~the Company’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the ~~Company’s~~ condensed consolidated balance sheets.

As of September 30, ~~2017,~~2020, PGE had ~~posted $22~~$32 million of collateral posted with these counterparties, consisting of$422 million in cash and$1810 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy

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market prices, and the level of collateral outstanding as of September 30, ~~2017,~~2020, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade was ~~$70~~$35 million, and decreases to$311 million by December 31, ~~2017~~2020 and to~~$10 million~~none by December 31, ~~2018.~~2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade was ~~$150~~$117 million at September 30, ~~2017,~~2020 and decreases to$~~106~~76 million by December 31, ~~2017~~2020 and to$7367 million by December 31, ~~2018.~~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 September 30, ~~2017,~~2020, under the most restrictive issuance test in the Indenture, the Company could have issued up to ~~$1,020~~$688 millionof additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE ~~also~~ has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

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 September 30, ~~2017,~~2020, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was ~~51.3%~~55.5%.

Off-Balance Sheet Arrangements

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

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 September 30, 2020, with the exception of an increase of $26 million in surety bonds to a total of $44 million, of which $30 million PGE has provided on behalf of the operator of Colstrip.

Contractual Obligations

PGE’s contractual obligations for ~~2017~~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, ~~2016~~,2019, filed with the SEC on February ~~17, 2017~~.14, 2020. For such obligations, there have been no material changes outside the ordinary course of business as of September 30, ~~2017, except for the First Mortgage Bond long-term debt issuance and the partial repayment under the unsecured credit agreement discussed in the~~ ~~“Debt and Equity Financings”~~ ~~section in this Item 2.~~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, ~~2016,~~2019, filed with the SEC on February ~~17, 2017.~~14, 2020.

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A portion of PGE’s energy portfolio subject to commodity price risk experienced significant losses during the third quarter of 2020. In August 2020, wholesale electricity prices increased substantially at various market hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. As a result of the convergence of these conditions, the Company’s energy portfolio experienced realized losses of $127 million in the third quarter of 2020. PGE no longer has net market exposure related to these positions and will not pursue regulatory recovery of the related losses. For additional information see “Energy Trading” in the Overview section in Item 2.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



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

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by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, ~~2017,~~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.

~~For further~~See Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements,” for information regarding ~~PGE’s~~ legal ~~proceedings, see “Legal Proceedings~~” set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 17, 2017 and Part II, Item 1 of the Company’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, filed with the SEC on April 28, 2017 and July 28, 2017, respectively.proceedings.

~~Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court; and~~ ~~Morgan v. Portland General Electric Company, Marion County Circuit Court.~~

On March 16, 2016, the Marion County Circuit Court entered a general judgment that granted the Company’s motion for summary judgment and dismissed all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the general judgment of the Circuit Court in the Court of Appeals for the State of Oregon. Briefing is now complete, with a Court of Appeals decision pending.

~~In the Matter of an Arbitration Under the Rules of the International Chamber of Commerce’s Court of Arbitration, International Chamber of Commerce’s Court of Arbitration.~~

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

On December 18, 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement, after which PGE, in consultation with the Sureties, brought on new contractors and construction resumed.

On December 31, 2015, Abengoa S.A. filed a Request for Arbitration in the International Chamber of Commerce’s Court of Arbitration (ICC arbitration) seeking a declaration that it owes nothing under the Guaranty it provided to PGE, pursuant to which it guaranteed performance under the Construction Agreement for Carty.

PGE disagreed with the assertions in the Request for Arbitration and in February 2016 filed a complaint and motion for preliminary injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company had not made a demand under the Guaranty, and therefore the matter was not ripe for arbitration. The Contractor has been joined as a party to the arbitration and is seeking damages of $117 million based on a claim that PGE wrongfully terminated the Construction Agreement. The Contractor is also seeking estimated damages of $44 million based on a claim that PGE failed to disclose to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals, certain

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information regarding union labor productivity rates in eastern Oregon, and that this alleged failure caused the Contractor to submit a bid with a contract price that was lower than the contract price that would have been submitted had Contractor known such information. PGE disagrees with both of these claims.

A hearing before the ICC arbitration panel to determine jurisdictional matters, originally scheduled for late October 2017, was rescheduled to the spring of 2018, due to the addition of the Sureties to the ICC arbitration proceeding, as a result of the Ninth Circuit Court of Appeals (Ninth Circuit) decision and denial of the appeal in August 2017, referenced in the U.S. District Court cases described below.

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

On July 27, 2016, the judge denied the Sureties’ motion to stay the case in favor of a pending ICC arbitration (see case above) and granted PGE’s motion for an injunction prohibiting the Sureties from pursuing any Performance Bond claims in the ICC arbitration. The Sureties appealed the rulings to the Ninth Circuit and asked the U.S. District Court to stay the proceedings pending resolution of the appeal.

On July 10, 2017, the Ninth Circuit overturned the U.S. District Court ruling and held that the ICC arbitration panel has jurisdiction to determine what parties can be joined, and what claims can be presented, in the ICC arbitration.

On July 24, 2017, PGE filed a petition requesting en banc rehearing with the Ninth Circuit. On August 28, 2017, the Ninth Circuit issued notice denying the request for rehearing. As a result, this case is stayed, pending the ICC arbitration, discussed above.

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

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

On March 21, 2017, the judge entered an order staying the case. With the August 28, 2017 Ninth Circuit denial of rehearing referenced in the preceding case, the ICC arbitration panel will determine whether these claims must be presented in the ICC arbitration.

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

On August 12, 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company in U.S. District Court. DRA’s claims seek injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. The court denied PGE’s motion to dismiss and PGE then submitted a request on April 6, 2017, for interlocutory appeal to the Ninth Circuit of the order dismissing its motion to dismiss. The request also included a motion for stay of the lower court proceeding. The parties agreed to defer decision on the motion for stay pending a ruling on PGE’s request to file the interlocutory appeal. On May 19, 2017, the District Court granted PGE’s request to file the interlocutory appeal, but the Ninth Circuit denied the appeal on August 14, 2017.

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~~The parties are engaged in settlement discussions and have filed a joint motion, which was granted September 11, 2017, to continue the stay until either party finds settlement negotiations unfruitful.~~



Item 1A.			Risk Factors.

There have been no material changes to PGE’s risk factors set forth in in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2016~~,2019, filed with the SEC on February ~~17, 2017~~.14, 2020, as supplemented in Part II, Item 1A of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020, filed with the SEC on July 31, 2020.

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Item 5.			Other Information.

Increase in Size of Board and Appointment of Two New Directors

On October 28, 2020, the Board of Directors of the Company (the “Board”) increased the size of the Board from twelve to fourteen directors and appointed Michael A. Lewis and James P. Torgerson to serve as directors of the Company, effective January 1, 2021. The Board size will decrease to twelve directors effective as of the 2021 annual shareholders' meeting, at which time John Ballantine and Charles Shivery will retire in accordance with the Company’s director retirement age policy.

Mr. Lewis, 58, has served as interim President of Pacific Gas and Electric Company (“PG&E”) since August 2020. Prior to that, he served as PG&E’s Senior Vice President, Electric Operations from January 2019 to August 2020 and as Vice President, Electric Distribution Operations from August 2018 to January 2019. Before joining PG&E, Lewis held a number of executive leadership positions at Duke Energy, including Senior Vice President and Chief Distribution Officer from 2016 to 2018 and Senior Vice President and Chief Transmission Officer from 2015 to 2016. Lewis worked for Progress Energy from 1985 until its merger with Duke Energy in 2012, most recently serving as Senior Vice President of Energy Delivery.

Mr. Torgerson, 67, served as Chief Executive Officer of AVANGRID, Inc. from 2015 until his retirement in 2020. Mr. Torgerson was President and Chief Executive Officer of UIL Holdings Corporation from 2006 until 2015, when it merged with Iberdrola USA to form AVANGRID. Before joining UIL Holdings, Mr. Torgerson was President and Chief Executive Officer of the Midwest Independent Transmission System Operator, Inc. from 2000 to 2006. He also previously served as chief financial officer for several natural gas and electric utilities in North America, including Puget Sound Energy and Washington Energy Company.

The Board appointed Mr. Lewis to serve on the Audit Committee and Finance Committee of the Board, and appointed Mr. Torgerson to serve on the Compensation and Human Resources Committee and Finance Committee of the Board, effective January 1, 2021.

There are no arrangements or understandings between Mr. Lewis or Mr. Torgerson and any other persons, pursuant to which they were selected as directors, and they are not a party to any transaction with the Company that would require disclosure under Item 404(a) of Regulation S-K.

Each of the new directors will participate in the Company’s standard compensation program for non-employee directors.

Retirement of Chief Financial Officer and Appointment of Successor

On October 29, 2020, the Company announced that James F. Lobdell, Senior Vice President, Finance, Chief Financial Officer and Treasurer, plans to retire from Portland General Electric Company, effective December 31, 2020. The Company thanked Mr. Lobdell for his 36 years of dedicated service and valuable contributions to the Company.The Company also announced the appointment of James. A. Ajello as senior advisor, effective November 30, 2020, and as Senior Vice President, Finance, Chief Financial Officer and Treasurer, effective January 1, 2021.

Mr. Ajello served as Executive Vice President & Chief Financial Officer of Hawaiian Electric Industries (“HEI”) from 2009 to 2017. Prior to joining HEI, Mr. Ajello served as Senior Vice President, Business Development at Reliant Energy, Inc., now NRG Energy, Inc. He also spent approximately 15 years as Managing Director of the Energy & Natural Resources Group of UBS Warburg/UBS Securities LLC. Mr. Ajello currently serves as an independent board member of HEI’s Hawaiian Electric Company and is a member of its Audit Committee. He is a

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former board member of HEI’s American Savings Bank and served on its Risk Committee, as well as Crius Energy Trust, where he served on the Nominating and Governance and Audit committees.

In connection with his appointment, the Company has entered into an employment offer letter with Mr. Ajello, pursuant to which he will receive an initial annual base salary of $550,000, a 2021 target annual cash incentive award opportunity of 60% of his base pay paid in 2021, and a special transition award of restricted stock units with a grant date fair value of $600,000, half of which will vest immediately and half of which will vest on May 30, 2021, subject to the terms of the equity award agreement.Mr. Ajello will also be entitled to participate in the Company’s long-term equity incentive award program for executives, with a target award opportunity of no less than 120% of his 2021 base salary.The foregoing summary is qualified in its entirety by reference to the employment offer letter, which is attached as Exhibit 10.2 to this quarterly report on Form 10-Q and incorporated by reference into this Item 5.

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Item 6.			Exhibits.



Exhibit Number			Description
3.1			Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2			~~Tenth~~Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s ~~Current~~Annual Report on Form ~~8-K~~10-K filed ~~May 9, 2014)~~February 15, 2019).
~~31.1~~10.1			Credit Agreement dated April 9, 2020, between Portland General Electric Company, U.S. Bank National Association, as Administrative Agent and Lender, and CoBank, ACB (incorporated by reference to Exhibit 10.1 to PGE’s Form 8-K filed April 10, 2020).
10.2			Employment offer letter agreement between James A. Ajello and Portland General Electric Company dated October 28, 2020.
31.1			Certification of Chief Executive ~~Officer.~~Officer.
31.2			Certification of Chief Financial ~~Officer.~~Officer.
32			Certifications of Chief Executive Officer and Chief Financial ~~Officer.~~Officer.
~~4.1~~			~~Seventy-third Supplemental Indenture dated August 1, 2017, between the Company and Wells Fargo Bank, National Association, as Trustee~~ ~~(incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on August 3, 2017).~~
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 October 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:

October 29, 2020

~~PORTLAND GENERAL ELECTRIC COMPANY~~

By:

~~(Registrant)~~

~~Date:~~

~~October 26, 2017~~

~~By:~~

/s/ James F. Lobdell

James F. Lobdell

Senior Vice President of Finance,

Chief Financial Officer and Treasurer

(duly authorized officer and principal financial officer)

5563


Definitions		3

~~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	2932

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5259

Item 4.	Controls and Procedures	5260

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	5360

Item 1A.	Risk Factors	5560

Item 6.5.	~~Exhibits~~Other Information	5561

Item 6.	Exhibits	63

SIGNATURE		5563



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Revenues, net	$	515	$	484	$	1,494	$	1,399
Operating expenses:
Purchased power and fuel	184		180		443		455
Generation, transmission and distribution	73		69		235		199
Administrative and other	64		63		197		185
Depreciation and amortization	87		79		257		244
Taxes other than income taxes	30		29		94		89
Total operating expenses	438		420		1,226		1,172
Income from operations	77		64		268		227
Interest expense, net	30		28		90		82
Other income:
Allowance for equity funds used during construction	4		4		9		19
Miscellaneous income, net	2		—		4		—
Other income, net	6		4		13		19
Income before income tax expense	53		40		191		164
Income tax expense	13		6		46		32
Net income and Comprehensive income	$	40	$	34	$	145	$	132


Weighted-average shares outstanding—basic and diluted (in thousands)	89,065		88,921		89,044		88,885

Earnings per share—basic and diluted	$	0.44	$	0.38	$	1.62	$	1.49

Dividends declared per common share	$	0.34	$	0.32	$	1.00	$	0.94

See accompanying notes to condensed consolidated financial statements.



	September 30, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	89	$	6
Accounts receivable, net	151		155
Unbilled revenues	71		107
Inventories	70		82
Regulatory assets—current	42		36
Other current assets	43		77
Total current assets	466		463
Electric utility plant, net	6,638		6,434
Regulatory assets—noncurrent	526		498
Nuclear decommissioning trust	41		41
Non-qualified benefit plan trust	37		34
Other noncurrent assets	51		57
Total assets	$	7,759	$	7,527

See accompanying notes to condensed consolidated financial statements.



	September 30, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	100		$	129
Liabilities from price risk management activities—current	43			44
Current portion of long-term debt	100			150
Accrued expenses and other current liabilities	248			254
Total current liabilities	491			577
Long-term debt, net of current portion	2,277			2,200
Regulatory liabilities—noncurrent	1,002			958
Deferred income taxes	701			669
Unfunded status of pension and postretirement plans	288			281
Liabilities from price risk management activities—noncurrent	150			125
Asset retirement obligations	166			161
Non-qualified benefit plan liabilities	105			105
Other noncurrent liabilities	177			107
Total liabilities	5,357			5,183
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2017 and December 31, 2016	—			—
Common stock, no par value, 160,000,000 shares authorized; 89,091,955 and 88,946,704 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	1,204			1,201
Accumulated other comprehensive loss	(7		)	(7		)
Retained earnings	1,205			1,150
Total equity	2,402			2,344
Total liabilities and equity	$	7,759		$	7,527

See accompanying notes to condensed consolidated financial statements.




As Filed February 28, 2017				$	100
Load and Power Cost Updates				(28		)
Depreciation Study Updates				(8		)
Base Business Revenue Requirement Updates:
Lower return on equity	$	(10	)
Lower labor costs	(9		)
Adjustment to depreciation expense	(8		)
Lower level of plant in service	(5		)
Other reductions to rate base	(4		)
Other various modifications	(8		)
Subtotal				(44		)
As Stipulated				$	20