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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2019



☐	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

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

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

[x] Yes x [ ] No

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

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

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

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

Number of shares of common stock outstanding as of October 25, 2019 is 89,372,125 shares.

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PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2019

TABLE OF CONTENTS



Definitions		3

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Income and Comprehensive Income	4

	Condensed Consolidated Balance Sheets	5

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58

Item 4.	Controls and Procedures	58

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	59

Item 1A.	Risk Factors	59

Item 6.	Exhibits	60

SIGNATURE		61

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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:



Abbreviation or Acronym		Definition
AFDC		Allowance for funds used during construction
AUT		Annual Power Cost Update Tariff
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		Federal Energy Regulatory Commission
FMBs		First Mortgage Bonds
GAAP		Accounting principles generally accepted in the United States of America
GRC		General Rate Case
IRP		Integrated Resource Plan
Moody’s		Moody’s Investors Service
MW		Megawatts
MWa		Average megawatts
MWh		Megawatt hour
NASDAQ		National Association of Securities Dealers Automated Quotations
NVPC		Net Variable Power Costs
NYSE		New York Stock Exchange
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
RPS		Renewable Portfolio Standard
S&P		S&P Global Ratings
SEC		United States Securities and Exchange Commission
TCJA		United States Tax Cuts and Jobs Act of 2017
Trojan		Trojan nuclear power plant

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PART I — FINANCIAL INFORMATION



Item 1.	Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenues:
Revenues, net	$	538	$	525	$	1,570	$	1,469
Alternative revenue programs, net of amortization	4		—		5		(2		)
Total revenues	542		525		1,575		1,467
Operating expenses:
Purchased power and fuel	165		186		449		420
Generation, transmission and distribution	78		72		241		212
Administrative and other	74		49		223		188
Depreciation and amortization	103		96		305		281
Taxes other than income taxes	34		31		101		95
Total operating expenses	454		434		1,319		1,196
Income from operations	88		91		256		271
Interest expense, net	32		31		95		93
Other income:
Allowance for equity funds used during construction	2		2		7		8
Miscellaneous income, net	3		—		5		—
Other income, net	5		2		12		8
Income before income tax expense	61		62		173		186
Income tax expense	6		9		20		23
Net income	55		53		153		163
Other comprehensive income	—		—		2		—
Comprehensive income	$	55	$	53	$	155	$	163

Weighted-average common shares outstanding (in thousands):
Basic	89,372		89,239		89,346		89,205
Diluted	89,594		89,239		89,555		89,205

Earnings per share:
Basic	$	0.61	$	0.59	$	1.71	$	1.82
Diluted	$	0.61	$	0.59	$	1.70	$	1.82

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)



	September 30, 2019		December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	11	$	119
Accounts receivable, net	161		193
Unbilled revenues	73		96
Inventories	91		84
Regulatory assets—current	26		61
Other current assets	54		90
Total current assets	416		643
Electric utility plant, net	7,014		6,887
Regulatory assets—noncurrent	483		401
Nuclear decommissioning trust	46		42
Non-qualified benefit plan trust	37		36
Other noncurrent assets	158		101
Total assets	$	8,154	$	8,110

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, 2019			December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	128		$	168
Liabilities from price risk management activities—current	26			55
Current portion of long-term debt	50			300
Current portion of finance lease obligation	17			—
Accrued expenses and other current liabilities	293			268
Total current liabilities	514			791
Long-term debt, net of current portion	2,328			2,178
Regulatory liabilities—noncurrent	1,380			1,355
Deferred income taxes	378			369
Unfunded status of pension and postretirement plans	307			307
Liabilities from price risk management activities—noncurrent	100			101
Asset retirement obligations	268			197
Non-qualified benefit plan liabilities	100			103
Finance lease obligations, net of current portion	136			—
Other noncurrent liabilities	79			203
Total liabilities	5,590			5,604
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2019 and December 31, 2018	—			—
Common stock, no par value, 160,000,000 shares authorized; 89,371,974 and 89,267,959 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively	1,217			1,212
Accumulated other comprehensive loss	(7		)	(7		)
Retained earnings	1,354			1,301
Total shareholders’ equity	2,564			2,506
Total liabilities and shareholders’ equity	$	8,154		$	8,110

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,
	2019			2018
Cash flows from operating activities:
Net income	$	153		$	163
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	305			281
Deferred income taxes	3			2
Pension and other postretirement benefits	16			19
Allowance for equity funds used during construction	(7		)	(8		)
Decoupling mechanism deferrals, net of amortization	(6		)	2
(Amortization) Deferral of net benefits due to Tax Reform	(16		)	37
Other non-cash income and expenses, net	38			8
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	50			12
(Increase)/decrease in inventories	(7		)	2
Decrease in margin deposits, net	4			6
(Decrease)/increase in accounts payable and accrued liabilities	(25		)	17
Other working capital items, net	25			19
Other, net	(31		)	(24		)
Net cash provided by operating activities	502			536

Cash flows from investing activities:
Capital expenditures	(407		)	(401		)
Sales of Nuclear decommissioning trust securities	11			11
Purchases of Nuclear decommissioning trust securities	(8		)	(9		)
Proceeds from Carty settlement	—			120
Other, net	(2		)	1
Net cash used in investing activities	(406		)	(278		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt	200			—
Payments on long-term debt	(300		)	—
Dividends paid	(99		)	(93		)
Other	(5		)	(4		)
Net cash used in financing activities	(204		)	(97		)
(Decrease) increase in cash and cash equivalents	(108		)	161
Cash and cash equivalents, beginning of period	119			39
Cash and cash equivalents, end of period	$	11		$	200

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	73		$	72
Cash paid for income taxes	21			20

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its four thousand square mile, state-approved service area allocation, located entirely within the State of Oregon, encompasses 51 incorporated cities. As of September 30, 2019, PGE served 892 thousand retail customers within a service area of 1.9 million residents.

Condensed Consolidated Financial Statements

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

The financial information included herein as of and for the three and nine months ended September 30, 2019 and 2018 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 2018 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2018, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 15, 2019, which should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three and nine months ended September 30, 2019 and 2018.

Use of Estimates

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

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Recent Accounting Pronouncements

In August 2018, the FASB issued 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 disclosure requirements related to fair value measurement disclosures. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2020, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in any interim period. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements and is still evaluating whether it will early adopt.

In August 2018, the FASB issued 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, to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2020. Early adoption is permitted, including adoption in an interim period. The amendments in this update may be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PGE is in the process of evaluating potential impacts of these amendments and does not plan to early adopt.

In August 2018, the FASB issued 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. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2021. Early adoption is permitted. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements and is still evaluating whether it will early adopt.

Recently Adopted Accounting Pronouncements

On January 1, 2019, PGE adopted ASU 2016-02, Leases (Topic 842), which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. The Company elected the practical expedient provided under ASU 2018-11, Leases (Topic 842) Targeted Improvements, which amended ASU 2016-02 to provide entities an optional transition practical expedient to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. As a result, no adjustments were made to the balance sheet prior to January 1, 2019 and amounts are reported in accordance with historical accounting under Topic 840, while the balance sheet as of September 30, 2019 is presented under Topic 842. The Company also elected the practical expedient provided under ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842, which amended ASU 2016-02 to provide entities an optional transition practical expedient to not evaluate under Topic 842, existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. Effective January 1, 2019, PGE evaluates new or modified land easements under Topic 842.

PGE's transition to the new lease standard did not result in a material adjustment to beginning retained earnings and the Company expects the adoption of the new standard to have an immaterial impact to its results of operations on an ongoing basis. Upon transition, PGE elected to reassess all arrangements that may contain a lease and their resulting lease classification which resulted in the following balance sheet adjustments as of January 1, 2019: i) the recognition of right-of-use assets and liabilities from operating and finance leases of $44 million pursuant to the new standard; ii) the derecognition of existing build-to-suit assets and liabilities of $131 million that were no longer

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

considered to meet build-to-suit criteria under Topic 842 and were not recognized on the Company’s balance sheet until commencement, which occurred in the second quarter of 2019; and iii) the derecognition of $49 million in lease assets and liabilities related to an existing gas pipeline lateral capital lease that no longer met the definition of a lease under the new standard. The following table illustrates the adjustments made upon adoption of Topic 842 and the corresponding line items affected on the Company’s condensed consolidated balance sheets (in millions):



	January 1, 2019 Topic 842 Adoption Adjustments
	Increase due to existing operating and finance leases		Decrease due to build-to-suit reassessment			Decrease due to capital lease reassessment			Total Increase/(Decrease)
Assets
Electric utility plant, net	$	2	$	(131	)	$	(49	)	$	(178	)
Other noncurrent assets	42		—			—			42

Liabilities
Accrued expenses and other current liabilities	5		—			(2		)	3
Other noncurrent liabilities	39		(131		)	(47		)	(139		)

For new required disclosures and further information see Note 11, Leases. The transition to the new standard did not have a material impact on the Company's financial position.

On January 1, 2019 PGE adopted ASU 2018-02 Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). ASU 2018-02 allows for a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects resulting from the United States Tax Cuts and Jobs Act of 2017 (TCJA). The amendments only relate to the reclassification of the income tax effects of the TCJA, and therefore the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. As a result, PGE reclassified $2 million from Accumulated other compressive loss to Retained earnings during the period of adoption rather than applying the standard retrospectively. The implementation did not result in a material impact to the results of operation, financial position or statements of 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,
	2019		2018			2019		2018
Retail:
Residential	$	218	$	224		$	713	$	699
Commercial	167		171			479		484
Industrial	50		55			144		138
Direct access customers	13		9			34		32
Subtotal	448		459			1,370		1,353
Alternative revenue programs, net of amortization	4		—			5		(2		)
Other accrued (deferred) revenues, net⁽¹⁾	4		(11		)	17		(38		)
Total retail revenues	456		448			1,392		1,313
Wholesale revenues⁽²⁾	72		67			125		119
Other operating revenues	14		10			58		35
Total revenues	$	542	$	525		$	1,575	$	1,467

(1) Amounts for the three months ended September 30, 2019 and 2018 primarily comprised of $6 million of amortization and $11 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. Amounts for the nine months ended September 30, 2019 and 2018 primarily comprised of $17 million of amortization and $36 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA.

(2) Wholesale revenues include $25 million and $29 million related to electricity commodity contract derivative settlements for the three months ended September 30, 2019 and 2018, respectively, and $38 million and $35 million, respectively, for the nine months ended September 30, 2019 and 2018. 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 consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to 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 are determined through general rate case proceedings and various tariff filings with the Public Utility Commission

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.

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

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

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

Wholesale Revenues

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

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

Other Operating Revenues

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 3: BALANCE SHEET COMPONENTS

Inventories

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

Other Current Assets

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



	September 30, 2019		December 31, 2018
Prepaid expenses	$	28	$	54
Assets from price risk management activities	14		20
Margin deposits	12		16
Other current assets	$	54	$	90

Electric Utility Plant, Net

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



	September 30, 2019			December 31, 2018
Electric utility plant	$	10,778		$	10,344
Construction work-in-progress	258			346
Total cost	11,036			10,690
Less: accumulated depreciation and amortization	(4,022		)	(3,803		)
Electric utility plant, net	$	7,014		$	6,887

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $350 million and $302 million as of September 30, 2019 and December 31, 2018, respectively. Amortization expense related to intangible assets was $16 million and $49 million for the three and nine months ended September 30, 2019, respectively, and $16 million and $43 million for the three and nine months ended September 30, 2018, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Regulatory Assets and Liabilities

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



	September 30, 2019					December 31, 2018
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	12		$	96	$	32		$	99
Pension and other postretirement plans	—			218		—			222
Debt issuance costs	—			18		—			16
Trojan decommissioning activities	—			93		—			26
Other	14			58		29			38
Total regulatory assets	$	26		$	483	$	61		$	401
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,011	$	—		$	979
Deferred income taxes	—			262		—			267
Asset retirement obligations	—			54		—			53
Tax Reform Deferral⁽¹⁾	23			6		23			22
Other	17			47		13			34
Total regulatory liabilities	$	40	⁽²⁾	$	1,380	$	36	⁽²⁾	$	1,355

(1) Related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest.

(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, 2019		December 31, 2018
Accrued employee compensation and benefits	$	63	$	66
Accrued taxes payable	45		34
Accrued interest payable	39		27
Accrued dividends payable	35		34
Regulatory liabilities—current	40		36
Other	71		71
Total accrued expenses and other current liabilities	$	293	$	268

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Asset Retirement Obligations

Asset retirement obligations (AROs) consist of the following (in millions):



	September 30, 2019		December 31, 2018
Trojan decommissioning activities	$	137	$	68
Utility plant	114		112
Non-utility property	17		17
Asset retirement obligations	$	268	$	197

Trojan decommissioning activities represents the present value of future decommissioning costs for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that is licensed by the Nuclear Regulatory Commission (NRC). The ISFSI is to house the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a U.S. Department of Energy facility is complete, which is not expected prior to 2059. In the third quarter of 2019, the NRC issued PGE a renewed license to operate the ISFSI through the first quarter of 2059. PGE updated its ARO to reflect the estimated costs through this date, which increased the Trojan ARO by $69 million as of September 30, 2019.

Credit Facilities

As of December 31, 2018, PGE had a $500 million revolving credit facility scheduled to terminate in November 2021. On January 16, 2019, PGE executed an amendment to the credit facility extending the termination date to November 14, 2022 and allowing for unlimited extensions, provided that lenders with a pro-rata share of more than 50% approve the extension request. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of September 30, 2019, PGE was in compliance with this covenant with a 50.2% debt-to-total capital ratio.

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

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

Under the revolving credit facility, as of September 30, 2019, PGE had no borrowings outstanding or commercial paper issued. As a result, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $60 million

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were outstanding as of September 30, 2019. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2020.

Long-term Debt

On April 12, 2019, PGE issued $200 million of 4.30% Series First Mortgage Bonds (FMBs) due in 2049. Proceeds from the transaction were used to repay the $300 million current portion of long-term debt on April 15, 2019.

On October 25, 2019, PGE entered into an agreement to issue $270 million of privately placed FMBs in two tranches, both of which will bear interest from their issue date at an annual rate of 3.34%. The first tranche, $110 million, with a maturity in 2049, was issued on October 25, 2019, a portion of which was used to redeem $50 million of 6.75% FMBs that had a maturity date in 2023. Due to the anticipated repayment of the $50 million, this amount of long-term debt was classified as current on the Company’s balance sheets as of September 30, 2019. The second tranche, $160 million, with a maturity in 2050, is expected to be issued and funded on or about November 15, 2019.

Defined Benefit Retirement Plan Costs

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Service cost	$	4		$	5		$	12		$	15
Interest cost*	8			8			25			24
Expected return on plan assets*	(10		)	(10		)	(30		)	(31		)
Amortization of net actuarial loss*	3			4			8			12
Net periodic benefit cost	$	5		$	7		$	15		$	20

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

PGE sponsors a health and welfare plan, under which it offers medical and life insurance benefits, as well as health reimbursement arrangements (HRAs). Retirees who participate in the Company’s postretirement health insurance plans are eligible for a Defined Dollar Medical Benefit (DDB), which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees responsible for the additional cost. In the third quarter of 2019, PGE announced an amendment to its HRAs and DDBs for non-represented employees, resulting in a $2 million curtailment gain, which has been recorded in Miscellaneous income, net on the condensed consolidated statement of income and comprehensive income.

NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of September 30, 2019 and December 31, 2018. PGE then classifies these financial assets and liabilities based on a fair

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value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:


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


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


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

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

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 months ended September 30, 2019 and 2018, except those presented in this note.

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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, 2019
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	7		15		—		—		22
Corporate credit	—		12		—		—		12
Money market funds measured at NAV ⁽²⁾	—		—		—		12		12
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	2		—		—		—		2
Equity securities	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Price risk management activities: ^{(1) (4)}
Electricity	—		6		1		—		7
Natural gas	—		10		1		—		11
	$	16	$	43	$	2	$	12	$	73
Liabilities:
Price risk management activities: ^{(1) (4)}
Electricity	$	—	$	5	$	99	$	—	$	104
Natural gas	—		18		4		—		22
	$	—	$	23	$	103	$	—	$	126


(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 5, Risk Management.

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	As of December 31, 2018
	Level 1		Level 2		Level 3		Other ⁽²⁾		Total
Assets:
Cash equivalents	$	112	$	—	$	—	$	—	$	112
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	7		18		—		—		25
Corporate credit	—		10		—		—		10
Money market funds measured at NAV ⁽²⁾	—		—		—		7		7
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	2		—		—		—		2
Equity securities	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Price risk management activities: ^{(1) (4)}
Electricity	—		9		3		—		12
Natural gas	—		8		—		—		8
	$	128	$	45	$	3	$	7	$	183
Liabilities:
Interest rate swap derivatives	$	—	$	4	$	—	$	—	$	4
Price risk management activities: ^{(1) (4)}
Electricity	—		10		84		—		94
Natural gas	—		51		7		—		58
	$	—	$	65	$	91	$	—	$	156


(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 $27 million, which are recorded at cash surrender value.


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

Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of securities holdings of such funds do not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. These cash equivalents are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (NASDAQ) and the New York Stock Exchange (NYSE).

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

Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value

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hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.

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

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

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

The NQBP trust is invested in exchange-traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.

Liabilities from interest rate swap derivatives are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of forward starting interest rate swap lock agreements to hedge a portion of the interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.

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 and foreign currency exchange rate risk and to reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.

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

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

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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		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(in millions)
As of September 30, 2019
Electricity physical forwards	$	—	$	96	Discounted cash flow	Electricity forward price (per MWh)	$	11.57	$	64.41	$	42.98
Natural gas financial swaps	1		4		Discounted cash flow	Natural gas forward price (per Decatherm)	1.23		3.74		1.69
Electricity financial futures	1		3		Discounted cash flow	Electricity forward price (per MWh)	15.50		53.97		36.90
	$	2	$	103
As of December 31, 2018
Electricity physical forwards	$	3	$	84	Discounted cash flow	Electricity forward price (per MWh)	$	14.60	$	69.00	$	45.00
Natural gas financial swaps	—		7		Discounted cash flow	Natural gas forward price (per Decatherm)	0.95		4.64		1.82
	$	3	$	91

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

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Balance as of the beginning of the period	$	72		$	129		$	88		$	139
Net realized and unrealized (gains)/losses^*	30			(2		)	14			(10		)
Transfers out of Level 3 to Level 2	(1		)	(2		)	(1		)	(4		)
Balance as of the end of the period	$	101		$	125		$	101		$	125

* Both realized and unrealized (gains)/losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income 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, 2019 and 2018, 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 out of Level 3 at the end of the reporting period for all of its derivative instruments.

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

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

As of September 30, 2019, the carrying amount of PGE’s long-term debt was $2,378 million, net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,754 million. As of December 31, 2018, the carrying amount of PGE’s long-term debt was $2,478 million, net of $10 million of unamortized debt expense, and its estimated aggregate fair value was $2,760 million.

NOTE 5: RISK MANAGEMENT

Price Risk Management

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

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forward, futures, swaps, and option contracts for electricity,

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natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. The Company does not engage in trading activities for non-retail purposes.

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



	September 30, 2019		December 31, 2018
Current assets:
Commodity contracts:
Electricity	$	6	$	11
Natural gas	8		7
Total current derivative assets⁽¹⁾	14		18
Noncurrent assets:
Commodity contracts:
Electricity	1		1
Natural gas	3		1
Total noncurrent derivative assets⁽¹⁾	4		2
Total derivative assets⁽²⁾	$	18	$	20
Current liabilities:
Commodity contracts:
Electricity	$	12	$	16
Natural gas	14		35
Total current derivative liabilities	26		51
Noncurrent liabilities:
Commodity contracts:
Electricity	92		78
Natural gas	8		23
Total noncurrent derivative liabilities	100		101
Total derivative liabilities⁽²⁾	$	126	$	152

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

(2) As of September 30, 2019 and December 31, 2018, no derivative assets or liabilities were designated as hedging instruments.

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



	September 30, 2019			December 31, 2018
Commodity contracts:
Electricity	6		MWhs	5		MWhs
Natural gas	140		Decatherms	123		Decatherms
Foreign currency	$	21	Canadian	$	18	Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of September 30, 2019, and December 31, 2018, gross amounts included as Price risk management liabilities subject to master netting agreements were $2 million and $88 million, respectively, for which PGE posted no collateral as of September 30, 2019 and $11 million as of December 31, 2018, which consisted entirely of letters of credit. As of September 30, 2019, of the gross amounts recognized, none was for electricity and $2 million was for natural gas compared to $84 million for electricity and $4 million for natural gas recognized as of December 31, 2018.

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,
	2019			2018			2019			2018
Commodity contracts:
Electricity	$	36		$	(3	)	$	18		$	(5	)
Natural Gas	(9		)	(3		)	(13		)	11
Foreign currency exchange	—			—			—			1

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended September 30, 2019 and 2018, net losses of $24 million and net gains of $8 million, respectively, have been offset. Net losses of $5 million and net gains of $2 million have been offset for the nine months ended September 30, 2019 and 2018, respectively.

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Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss (gain) recorded as of September 30, 2019 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):



	2019			2020		2021		2022		2023		Thereafter		Total
Commodity contracts:
Electricity	$	(3	)	$	11	$	9	$	7	$	7	$	66	$	97
Natural gas	2			5		4		—		—		—		11
Net unrealized loss	$	(1	)	$	16	$	13	$	7	$	7	$	66	$	108

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of September 30, 2019 was $118 million, for which PGE has posted $21 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, 2019, the cash requirement to either post as collateral or settle the instruments immediately would have been $109 million. As of September 30, 2019, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheet.

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



	September 30, 2019		December 31, 2018
Assets from price risk management activities:
Counterparty A	35	%	42	%
Counterparty B	—		15
Counterparty C	17		5
Counterparty D	11		9
	63	%	71	%
Liabilities from price risk management activities:
Counterparty E	76	%	56	%

See Note 4, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

Interest Rate Risk

In 2018 PGE entered into interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance.

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As of December 31, 2018, the fair value of the interest rate swaps was a $4 million liability, which was recorded in Liabilities from price risk management activities - current on the Company’s condensed consolidated balance sheets. The swaps settled at a $5 million loss in January 2019, which has been recorded in Regulatory assets - noncurrent on the condensed consolidated balance sheets. As of September 30, 2019, the Company had no outstanding interest rate swaps.

NOTE 6: EARNINGS PER SHARE

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

For the three and nine months ended September 30, 2019, unvested performance-based restricted stock units and related dividend equivalent rights of 265 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 229 thousand shares excluded for the three and nine months ended September 30, 2018.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Weighted-average common shares outstanding—basic	89,372	89,239	89,346	89,205
Dilutive effect of potential common shares	222	—	209	—
Weighted-average common shares outstanding—diluted	89,594	89,239	89,555	89,205

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NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three and nine-month periods ended September 30, 2019 and 2018 was as follows (dollars in millions, except per share amounts):



	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings
	Common Stock
	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	—		—			—			—
Other comprehensive income	—	—		1			—			1
Dividends declared ($0.3625 per share)	—	—		—			(32		)	(32		)
Net income	—	—		—			73			73
Reclassification of stranded tax effects due to Tax Reform	—	—		(2		)	2			—
Balances as of March 31, 2019	89,356,311	$	1,212	$	(8	)	$	1,344		$	2,548
Issuances of shares pursuant to equity-based plans	15,249	1		—			—			1
Stock-based compensation	—	2		—			—			2
Other comprehensive income	—	—		1			—			1
Dividends declared ($0.3850 per share)	—	—		—			(35		)	(35		)
Net income	—	—		—			25			25
Balances as of June 30, 2019	89,371,560	$	1,215	$	(7	)	$	1,334		$	2,542
Issuances of shares pursuant to equity-based plans	414	—		—			—			—
Stock-based compensation	—	2		—			—			2
Dividends declared ($0.3850 per share)	—	—		—			(35		)	(35		)
Net income	—	—		—			55			55
Balances as of September 30, 2019	89,371,974	$	1,217	$	(7	)	$	1,354		$	2,564

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	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Common Stock
	Shares	Amount									Total
Balances as of December 31, 2017	89,114,265	$	1,207		$	(8	)	$	1,217		$	2,416
Issuances of shares pursuant to equity-based plans	99,854	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared ($0.3400 per share)	—	—			—			(30		)	(30		)
Net income	—	—			—			64			64
Balances as of March 31, 2018	89,214,119	$	1,206		$	(8	)	$	1,251		$	2,449
Issuances of shares pursuant to equity-based plans	24,087	—			—			—			—
Stock-based compensation	—	2			—			—			2
Dividends declared ($0.3625 per share)	—	—			—			(32		)	(32		)
Net income	—	—			—			46			46
Balances as of June 30, 2018	89,238,206	$	1,208		$	(8	)	$	1,265		$	2,465
Issuances of shares pursuant to equity-based plans	6,453	—			—			—			—
Stock-based compensation	—	1			—			—			1
Dividends declared ($0.3625 per share)	—	—			—			(33		)	(33		)
Net income	—	—			—			53			53
Balances as of September 30, 2018	89,244,659	$	1,209		$	(8	)	$	1,285		$	2,486

NOTE 8: CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the condensed consolidated financial statements are prepared. Costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

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

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

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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, depending on the nature of the underlying event.

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

EPA Investigation of Portland Harbor

An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.

The Portland Harbor site remedial investigation had been completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

The EPA finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in January 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.1 billion. Remediation construction costs were estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. The EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost. A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of the Portland Harbor Superfund site have improved substantially over the past ten years. In response, the EPA indicated that while it accepted the data and would use it to inform implementation of the ROD, it did not agree that the data collected, or the analysis offered, supported many of the conclusions reached in the sampling update.

PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of

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such an allocation percentage, remedial design, a final allocation methodology, and 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. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position.

In cases in which injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as Natural Resource Damages (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and the Nez Perce Tribe.

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

The impact of such costs to the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account (PHERA) mechanism. As approved by the OPUC in 2017, the PHERA allows the Company to defer and recover incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million, excluding expenses related to contingent liabilities, are subject to an annual earnings test and would be ineligible for recovery to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent general rate case. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices.

Trojan Investment Recovery Class Actions

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

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

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

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

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

In 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement on the class action proceedings and heard oral argument on the Company’s motion for Summary Judgment. In 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. In April 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. A Court of Appeals decision remains pending.

PGE believes that the 2014 OSC decision and the Circuit Court decisions that followed have reduced the risk of any loss to the Company beyond the amounts previously recorded and refunds 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 to the Company 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 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had violated certain conditions contained in PGE’s Water Quality Certification for the Pelton Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleged the violations were related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.

The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements, for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had degraded the fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters.

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

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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. Briefing has been rescheduled to begin in January 2020.

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

Other Matters

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

NOTE 9: GUARANTEES

PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of September 30, 2019, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

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NOTE 10: INCOME TAXES

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Federal statutory tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Federal tax credits^*	(14.8	)	(12.3	)	(13.8	)	(15.8	)
State and local taxes, net of federal tax benefit	6.5		6.5		6.5		6.5
Flow through depreciation and cost basis differences	1.0		(0.1	)	1.2		(2.3	)
Amortization of excess deferred income tax	(3.9	)	—		(3.5	)	—
Other	—		(0.6	)	0.2		3.0
Effective tax rate	9.8	%	14.5	%	11.6	%	12.4	%

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

Carryforwards

Federal tax credit carryforwards as of September 30, 2019 and December 31, 2018 were $55 million and $52 million, respectively. These credits consist of PTCs which will expire at various dates through 2039. PGE believes that it is more likely than not that its deferred income tax assets as of September 30, 2019 will be realized; accordingly, no valuation allowance has been recorded. As of September 30, 2019, and December 31, 2018, PGE had no unrecognized tax benefits.

NOTE 11: LEASES

PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the condensed consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability.

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 and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments will be deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.

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PGE does not record leases with a term of 12-months or less in the condensed consolidated balance sheet. Total short-term lease costs for the three and nine months ended September 30, 2019 are immaterial. PGE has lease agreements with lease and non-lease components, which are accounted for separately.

The Company’s leases relate primarily to the use of land, support facilities, gas storage, and power purchase agreements that rely on identified plant. Variable payments are generally related to gas storage and power purchase agreements for components dependent upon variable factors, such as energy production and property taxes, and are not included in the determination of the present value of lease payments.

The components of lease cost were as follows (in millions):



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

Operating lease cost	$	3	$	6

Finance lease cost:
Amortization of right-of-use assets	$	1	$	2
Interest on lease liabilities	3		4
Total finance lease cost	$	4	$	6

Variable lease cost	$	4	$	15

Supplemental information related to amounts and presentation of leases in the condensed consolidated balance sheets is presented below (in millions):



	Balance Sheet Classification	September 30, 2019
Operating Leases:
Operating lease right-of-use assets	Other noncurrent assets	$	52

Current liabilities	Accrued expenses and other current liabilities	8
Noncurrent liabilities	Other noncurrent liabilities	44
Total operating lease liabilities		$	52

Finance Leases:
Finance lease right-of-use assets	Electric utility plant, net	$	152

Current liabilities	Current portion of finance lease obligations	17
Noncurrent liabilities	Finance lease obligations, net of current portion	136
Total finance lease liabilities		$	153

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Lease term and discount rates were as follows:



	September 30, 2019
Weighted Average Remaining Lease Term
Operating leases	24 years
Finance leases	29 years

Weighted Average Discount Rate
Operating leases	3.5	%
Finance leases	7.3	%

PGE’s gas storage finance lease contains five 10-year renewal periods which have not been included in the finance lease obligation.

As of September 30, 2019, maturities of lease liabilities were as follows (in millions):



	Operating Leases			Finance Leases

2019	$	2		$	4
2020	8			16
2021	8			16
2022	8			16
2023	8			14
Thereafter	53			249
Total lease payments	87			315
Less imputed interest	(35		)	(162		)
Total	$	52		$	153

Supplemental cash flow information related to leases was as follows (in millions):



	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	5
Operating cash flows from finance leases	3
Financing cash flows from finance leases	2

Right-of-use assets obtained in leasing arrangements:
Operating leases	$	56
Finance leases	154

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2018 Lease Obligations

As of December 31, 2018, and pursuant to historical lease accounting under Topic 840, PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions):



	Future Minimum Lease Payments
	Capital Leases			Build-to-Suit		Operating Leases
2019	$	6		$	11	$	4
2020	6			14		5
2021	6			13		5
2022	6			13		6
2023	5			13		7
Thereafter	67			225		97
Total minimum lease payments	96			$	289	$	124
Less imputed interest	(47		)
Present value of net minimum lease payments	49
Less current portion	(2		)
Noncurrent portion	$	47

Capital Leases—PGE entered into agreements to purchase natural gas transportation capacity via a 24-mile natural gas pipeline, Carty Lateral, that was constructed to serve the Carty natural gas-fired generating plant. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175 thousand decatherms per day. At the end of the initial contract term, the Company has the option to renew the agreement in continuous three-year increments with at least 24 months prior written notice.

As of December 31, 2018, a capital lease asset of $57 million and accumulated amortization of such assets of $8 million was reflected within Electric utility plant, net in the condensed consolidated balance sheets. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $47 million in Other noncurrent liabilities on the condensed consolidated balance sheets. For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. Amortization of the leased asset of $3 million and interest expense of $4 million was recorded to Purchased power and fuel expense in the consolidated statements of income through December 31, 2018. Pursuant to the adoption of the new lease accounting standard, Topic 842, PGE derecognized the capital lease obligation and related capital lease asset as it no longer met the definition of a lease.

Build-to-suit—PGE entered into a 30-year lease agreement with a local natural gas company, NW Natural, to expand their current natural gas storage facilities, including the development of an underground storage reservoir and construction of a new compressor station and 13-miles of pipeline, which are collectively designed to provide no-notice storage and transportation services to PGE’s Port Westward and Beaver natural gas-fired generating plants. Construction of the expansion project was completed in the second quarter of 2019 at a cost of $149 million. Due to the level of PGE’s involvement during the construction period, the Company was deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE recorded $131 million to Construction work-in-progress within Electric utility plant, net and a corresponding liability for the same amount to Other noncurrent liabilities in the condensed consolidated balance sheets as of December 31, 2018. Pursuant to the adoption of the new lease accounting standard, Topic 842, PGE derecognized the build-to-suit assets and liabilities as they are no longer considered to meet the build-to-suit criteria under the new standard.

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The table above reflects PGE’s estimated future minimum lease payments pursuant to the agreement based on estimated costs.

Operating leases—PGE has various operating leases associated with leases of land, support facilities, and power purchase agreements that rely on identified plant that expire in various years, extending through 2096. Rent expense was $7 million in 2018. Contingent rents related to power purchase agreements was $14 million in 2018. Sublease income was $4 million in 2018.



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 are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that the 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 forward-looking statements include:

•

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


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


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


•	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;

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


•	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;

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


•	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 any such project costs;


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


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


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


•	ineffective execution of PGE’s risk management policies and procedures;


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


•	cyber security attacks, data security breaches, or other malicious acts that may cause damage to the Company’s generation, transmission, and 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, and transitions in senior management;


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


•	political and economic conditions;


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


•	acts of war or terrorism.

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

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Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. This MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2018, and other periodic and current reports filed with the SEC.

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

PGE is strategically focused on four pillars: i) delivering exceptional customer service; ii) investing in a reliable and clean energy future; iii) building a smarter, more resilient grid; and iv) pursuing excellence in its work.

Delivering Exceptional Customer Service—PGE’s focus on creating value for customers includes responding to customer expectations, envisioning and advocating for a regulatory framework that serves customer’s needs, and ensuring the company contributes to building an equitable society.

PGE’s customers continue to express a commitment to purchasing clean energy, as over 215,000 customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area continue to consider similar goals.

In response, the Company has implemented a new customer product option, the Green Future Impact program, which allows for 100 megawatts (MW) of PGE-provided power purchase agreements for renewable resources and up to 200 MW of customer-provided renewable resources. Approved by the OPUC in the first quarter 2019, the program will provide business customers access to bundled renewable attributes from those resources. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system.

Pursuant to the OPUC order approving the Green Future Impact tariff, program subscribers remain cost of service customer, and pay both the cost of service tariff rate and the rate under the renewable energy option tariff. This structure is intended to avoid stranded cost and cost shifting.

Legislative developments that have recently shaped the regulatory framework include Senate Bill 978 (SB 978), which passed the Oregon legislature in 2017. SB 978 directed the OPUC to investigate and report to the Oregon legislature how developing industry trends, technology, and policy drivers in the electricity sector might impact the existing regulatory system and incentives. The September 2018 report outlined the OPUC’s commitment to:


•	explore performance-based ratemaking and other regulatory tools to align utility incentives with customer goals, industry trends, and statewide goals;


▪	cooperate with other states to support and explore development of an organized, regional market;


▪	develop a strategy for low income and environmental justice groups’ engagement and inclusion in OPUC processes that will carry forward beyond the SB 978 proceeding; and


▪	improve the OPUC’s regulatory tools to value system costs and benefits, which enables customer choice and a strong utility system.

Investing in a Reliable and Clean Energy Future—PGE partners with customers and local and state governments to advance a clean energy future. In pursuit of this future, PGE continues to drive down emissions using a diverse

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portfolio of clean and renewable energy resources, and at the same time promoting economy-wide emission reductions through electrification and smart energy use to help the state meet its greenhouse gas reduction goals.

PGE’s regulatory framework for implementing a clean energy future is informed and enabled by: i) carbon legislation, ii) the resource planning process and iii) the renewable cost recovery framework.

Carbon Legislation—Oregon’s Clean Electricity and Coal Transition Plan (OCEP), enacted in 2016, set a benchmark for how much electricity must come from renewable sources like wind and solar (50 percent by 2040) and requires the elimination of coal from Oregon utility customers’ energy supply no later than 2030.

In response to the OCEP, the Company filed a tariff request in October 2016 to accelerate recovery of PGE’s investment in the Colstrip facility from 2042 to 2030. In late June 2019, the owners of Colstrip Units 1 and 2 announced that they would permanently close those two units at the end of the current year. Although PGE has no direct ownership interest in those two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which share certain common facilities with Units 1 and 2.

Although PGE is currently scheduled to recover the costs of Colstrip by 2030, some co-owners of Units 3 and 4 have taken actions that will enable them to recover their costs by 2025 and 2027. The Company continues to evaluate its ongoing investment in Colstrip.

Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip transmission line, which stretches from eastern Montana to near the western end of the state to serve markets in the Pacific Northwest and beyond. PGE has an ownership interest in, and capacity on, approximately 15% of 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 had previously announced, and continues on schedule with plans to cease coal-fired operation at its Boardman generating plant at the end of 2020.

Recent legislative proposals included a comprehensive cap and trade package known as House Bill (HB) 2020 that would have granted the OPUC direct authority to address climate change. Although HB 2020 was not enacted by the state legislature in 2019, the OPUC, in response, stated that it would continue to collaborate with the legislature and stakeholders to make progress on climate change, noting that their authority is limited to that of an economic regulator. The next state legislative session is scheduled for February 2020 in which similar proposals may be introduced.

Resource Planning—PGE’s 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 MW (MWa) of qualifying renewable resources. The prevailing bid, Wheatridge Renewable Energy Facility (Wheatridge), will be an energy facility in eastern Oregon that combines 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 agreement on the 12th anniversary of the commercial operation date of the wind facility.

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The wind component of the facility is expected to be operational by December 2020 and qualify for federal production tax credits (PTCs) at the 100 percent level. Construction of the solar and battery components is planned for 2021 and is also expected to qualify for federal investment tax credits, which will help reduce the cost of the project and thus reduce costs to PGE’s customers.

In July 2019, PGE submitted its 2019 Integrated Resource Plan (2019 IRP) to the OPUC. The proposed plan sets forth the following actions the Company would undertake over the next four years to acquire the resources identified:


•	Customer actions—cost-effective energy efficiency, reliance on demand response, and dispatchable customer storage and standby generation;


•	Renewable actions—a Renewable RFP to be conducted in 2020, seeking 150 MWa to come online by 2023; and


•	Capacity actions—a multi-stage procurement process that will allow PGE to pursue cost-competitive agreements for existing capacity in the region and to conduct a non-emitting Capacity RFP in 2021 to fill any remaining capacity needs, which the Company estimates will reach 595 MW by 2025, after consideration of the Customer and Renewable actions outlined above.

The regulatory schedule for the 2019 IRP would lead to an OPUC order in the first quarter of 2020.

Renewable Recovery Framework—The Renewable Adjustment Clause (RAC), as previously authorized by the OPUC, allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 General Rate Case (GRC) Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. Although no significant filings have been submitted under the RAC during 2019 or 2018, the Company expects to submit a RAC filing for Wheatridge before the end of 2019.

Building a Smarter, More Resilient Grid—A smart grid allows PGE to work in collaboration with customers to integrate renewable energy and other technologies that improve efficiency and drive decarbonization. PGE is focused on the deployment of new technologies and the use of data analytics to better predict demand and support energy saving customer programs. The Company is currently engaged in energy storage initiatives, advanced communications networks, automation and control systems for flexible loads and distributed generation, and the development of connected neighborhood microgrids and smart communities.

PGE considers the impact of making investments in new, renewable resource generation and energy storage facilities, as well as improvements to its transmission, distribution, and information technology infrastructure when determining capital requirements.

In 2018, PGE filed an energy storage proposal that called for 39 MW of storage to be developed over the next several years at various locations across the grid. In August 2018, the OPUC issued an order that outlined an agreed approach to the development of five energy storage projects by PGE with an expected capital cost of approximately $45 million.

The Company is also working to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of electric vehicles. As required under the OCEP, in September 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to the State of Oregon’s carbon reduction goals.

In July 2019, PGE’s Board approved plans to construct an Integrated Operations Center (IOC) at an estimated total cost of $200 million, excluding the allowance for funds used during construction (AFDC). The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure,

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resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support functions.

Pursuing Excellence in PGE’s Work—PGE’s customer commitment focuses on providing reliable, clean power at low cost while providing a fair return to investors. Central to this strategic initiative is prudent management of key legislative, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion provides detail on several such material matters:

Portland Harbor Environmental Remediation Account Mechanism—PGE’s environmental 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, if necessary, through customer prices. 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.”

Power Costs—Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC in December 2018, the 2019 GRC included a final projected increase in power costs for 2019, and a corresponding increase in annual revenue requirement, of $25 million from 2018 levels, which was reflected in customer prices effective January 1, 2019. The initial filing for the 2020 AUT indicated that power costs are expected to rise in 2020. The final power cost update for 2020 will be filed November 15, 2019.

Under the Power Cost Adjustment Mechanism (PCAM) for 2018, net variable power cost (NVPC) was within the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the results of the PCAM for 2018 during the second half of 2019 with a decision expected in the fourth quarter 2019.

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 is included in rate base and customer prices as of January 1, 2019.

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

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

In response to the Order, PGE and other utilities filed a motion for reconsideration and clarification, which was denied. On April 19, 2019, PGE and the other utilities filed a petition for judicial review of the OPUC Order with the Oregon Court of Appeals. Opening briefs were filed on September 20, 2019. PGE believes that the costs incurred to date associated with the customer information system were prudently incurred and has not withdrawn its deferral application to recover the revenue requirement of this capital project.

During 2018, PGE deferred a total of $12 million of expenses related to the project. However, the Order has impacted the probability of recovery of deferred expenses and, as such, the Company has recorded a reserve for the full amount of the costs related to the capital investment. The reserve was established with an offsetting charge to the results of operations in 2018. Any amounts that may ultimately be approved by the OPUC in subsequent

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proceedings would be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC.

Corporate Activity Tax—In May 2019, the Oregon Legislature passed, and the governor signed, HB 3427, which imposes a new gross receipts tax on companies with annual revenues in excess of $1 million, that will apply to tax years beginning on or after January 1, 2020. The tax will be 0.57% of defined activities, subject to numerous exemptions, less 35% of the greater of “cost inputs” or “labor costs” apportioned to the State of Oregon. As administrative rules develop, PGE continues to evaluate the new law, enacted in September 2019, to determine the expected impact on its results of operations. In anticipation of the incremental annual expense as a result of this new tax, PGE plans to submit a tariff filing with the OPUC in the fourth quarter 2019 to establish a balancing account and allow for an estimated annual recovery of $7 million in future customer prices.

Decoupling—The decoupling mechanism, authorized by the OPUC through 2022, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than that projected in the Company’s most recent general rate case.

The Company recorded revenue for an estimated $14 million collection during the nine months ended September 30, 2019, which resulted from projections established in the 2019 GRC. Any collection from customers for the 2019 year is expected to occur over a one-year period, which would begin January 1, 2021.

In 2018, PGE collected from customers the $3 million of revenue that was recorded in 2016 that resulted from variances between actual weather-adjusted use per customer and that projected in the 2016 GRC. The Company recorded revenue for an estimated collection of $11 million during the year ended December 31, 2017, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2016 GRC. Collection from customers for the 2017 year is set to occur over a one-year period, which began January 1, 2019. The Company recorded revenue for an estimated collection of $2 million during the year ended December 31, 2018, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2018 GRC. Any collection from customers, as approved, for the 2018 year is expected to occur over a one-year period, which would begin January 1, 2020.

Storm Restoration Costs—Beginning in 2011, the OPUC authorized the Company to collect annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. Under the 2019 GRC, the annual collection amount increased to $4 million beginning in 2019.

Due to a series of storm events in the first half of 2017, the Company exhausted the storm collection authorized for 2017. Consequently, PGE was exposed to the incremental costs related to such major storm events, which totaled $9 million, net of the amount collected in 2017.

As a result of the additional costs incurred, PGE filed an application with the OPUC requesting authorization to defer incremental storm related restoration costs from the date of the application, in the first quarter of 2017, through the end of 2017. In the third quarter of 2019, the OPUC issued an order that denied the Company’s application for deferral. Although PGE had deferred the incremental expense in 2017, an offsetting reserve was also recorded at that time, thus the OPUC decision had no impact to the Company’s current results of operations.

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.

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Capital Requirements and Financing

The Company expects 2019 capital expenditures to total $620 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 with cash from operations during 2019, which is expected to range from $475 million to $525 million, and the issuance of debt securities of up to $520 million. For additional information, see “Liquidity” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 2.

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 participates in the California Independent System Operator’s Energy Imbalance Market, which allows the Company to integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market.

The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price 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—Retail energy deliveries for the nine months ended September 30, 2019, increased 0.5% compared with the nine months ended September 30, 2018, as illustrated in the table below. This increase was primarily driven by continued growth in demand for energy deliveries from the Company’s industrial customers along with cooler temperatures during the heating season in the 2019 period, partially offset by milder weather during the summer cooling season.

Retail energy deliveries for the first quarter of 2019 increased 4.3% compared with the prior year as cooler temperatures during the 2019 heating season increased demand from the residential and commercial classes, while growth in demand continued from the Company’s industrial customers.

In the second quarter of 2019, retail energy deliveries increased 0.2% over the same period of 2018. Continued strength in energy deliveries to industrial customers was largely offset by the decreases in the residential and commercial classes, driven primarily by lower average usage per customer and customers’ response to milder temperatures.

In the third quarter of 2019, retail energy deliveries decreased 3.2% as customer demand was influenced by milder temperatures during the summer cooling season in 2019, while 2018 saw excessively warm temperatures. Residential, commercial, and industrial energy deliveries decreased 3.9%, 3.7%, and 1.4%, respectively, compared with the third quarter of 2018. On a weather-adjusted basis, energy deliveries were down 0.4% compared to the third quarter of 2018.

In the third quarter of 2019, total cooling degree-days, an indication of the extent to which customers may have used electricity for air conditioning, were 20% below the third quarter of 2018, although still 5% above 15-year averages. Heating degree-days, an indication of the extent to which customers are likely to have used electricity for heating,

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did not vary much from the prior year, or from 15-year averages, and play a fairly insignificant role in influencing customer demand during the third quarter of the year. See “Revenues” in the Results of Operations section of this Item 2 for further information on heating and cooling degree-days.

After adjusting for the effects of weather, retail energy deliveries for the nine months ended September 30, 2019 were comparable to the same period of 2018. Increased deliveries to high tech manufacturing customers have been largely offset by energy efficiency and conservation efforts and decreased average usage per customer. The financial effects of such energy efficiency and conservation efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See “Decoupling” in this Overview section of Item 2 for further information on the decoupling mechanism.

The following table, which 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,
	2019		2018		% Increase (Decrease) in Energy Deliveries
	Average Number of Customers	Retail Energy Deliveries*	Average Number of Customers	Retail Energy Deliveries*	% Increase (Decrease) in Energy Deliveries
Residential	778,285	5,428	771,336	5,457	(0.5	)%

Commercial (PGE sales only)	109,509	4,999	108,566	5,088	(1.7	)%
Direct Access	566	536	533	481	11.4	%
Total Commercial	110,075	5,535	109,099	5,569	(0.6	)%

Industrial (PGE sales only)	194	2,332	204	2,241	4.1	%
Direct Access	67	1,093	66	1,055	3.6	%
Total Industrial	261	3,425	270	3,296	3.9	%

Total (PGE sales only)	887,988	12,759	880,106	12,786	(0.2	)%
Total Direct Access	633	1,629	599	1,536	6.1	%
Total	888,621	14,388	880,705	14,322	0.5	%


*	In thousands of MWhs.

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 14% of PGE’s total retail energy deliveries for the first nine months of 2019. Actual energy deliveries to Direct Access customers represented 11% of PGE’s total retail energy deliveries for the first nine months of 2019 and for the full year 2018.

During 2018, the OPUC created a New Large Load Direct Access program, capped at approximately 120 MWa, or 6% of total retail energy deliveries, for unplanned, large, new loads and large load growth at existing customer sites. The Company continues to work through the regulatory process to implement the new program.

Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period.

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Plant availability is impacted by planned maintenance and forced, or unplanned, outages, during which the respective plant is unavailable to provide power. Availability of all the plants PGE operates was 94% and 93% during the nine months ended September 30, 2019 and 2018, respectively. Plant availability of Colstrip, which PGE does not operate, was 88% and 80% during the nine months ended September 30, 2019 and 2018, respectively.

During the nine months ended September 30, 2019, the Company’s generating plants provided 87% of its retail load requirement compared with 75% in the nine months ended September 30, 2018. The increase in the proportion of power generated to meet the Company’s retail load requirement was largely due to PGE effectively dispatching its lowest-cost resources in a challenged market and increased plant availability of Colstrip during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.

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, 2019, energy received from these hydro resources decreased by 22% compared to the nine months ended September 30, 2018. Energy received from these hydro resources fell short of the projected levels included in PGE’s AUT by 17% for the nine months ended September 30, 2019 and approximated the projected levels for the nine months ended September 30, 2018, and provided 14% of the Company’s retail load requirement for the nine months ended September 30, 2019 and 18% for the nine months ended September 30, 2018. Energy received from hydro resources is expected to fall short of levels projected in the AUT for 2019 by up to 13%.

Energy expected to be received from PGE-owned wind-powered generating facilities (Biglow Canyon and Tucannon River) is projected annually in the AUT. Any excess in wind-powered 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, 2019, energy received from these wind-powered generating resources decreased 9% compared to the nine months ended September 30, 2018, resulting in the Company incurring additional replacement costs, as well as earning less PTCs than what was estimated in customer prices. Energy received from these wind-powered generating resources fell short of projections in PGE’s AUT by 6% for the nine months ended September 30, 2019 and fell short of projections in the AUT by 1% for the nine months ended September 30, 2018, and provided 10% and 11% of the Company’s retail load requirement during the nine months ended September 30, 2019 and 2018, respectively. Energy received from wind-powered resources is expected to fall short of levels projected in the AUT for 2019 by up to 5%.

Pursuant to the Company’s PCAM, customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts and is net of wholesale revenues, which are classified as Revenues, net in the condensed consolidated statements of income and comprehensive income. PGE’s AUT filings include projected PTCs for the respective calendar year with actual variances subject to the PCAM. To the extent actual annual NVPC, subject to certain adjustments, is above or below the deadband, which is a defined range from $30 million above to $15 million below baseline NVPC, the PCAM provides for 90% of the variance beyond the deadband to be collected from, or refunded to, customers, respectively, subject to a regulated earnings test.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in the Company’s condensed consolidated statements of income and comprehensive 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, 2019, actual NVPC was $5 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2019 is currently estimated to be above the baseline, but

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within the established deadband range. Accordingly, no estimated refund to, or collection from, customers is expected under the PCAM for 2019.

For the nine months ended September 30, 2018, actual NVPC was $3 million below baseline NVPC. For the year ended December 31, 2018, actual NVPC was $3 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded pursuant to the PCAM for 2018.

Fuel Supply—On July 1, 2019, the supplier of coal for Boardman filed for Chapter 11 bankruptcy protection. Past history suggests that it is unlikely that the coal supply agreement will be rejected in the bankruptcy proceedings. If it appears that the supplier is unable to meet coal supply requirements, PGE will make alternate arrangements for coal supply.

Critical Accounting Policies

The Company’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 15, 2019.

Results of Operations

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

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

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



	Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
Total revenues	$	542	100	%	$	525	100	%	$	1,575	100	%	$	1,467	100	%
Purchased power and fuel	165		30		186		35		449		29		420		29
Gross margin⁽¹⁾	377		70		339		65		1,126		71		1,047		71
Other operating expenses:
Generation, transmission and distribution	78		14		72		14		241		15		212		14
Administrative and other	74		14		49		9		223		14		188		13
Depreciation and amortization	103		19		96		18		305		19		281		19
Taxes other than income taxes	34		7		31		6		101		7		95		7
Total other operating expenses	289		54		248		47		870		55		776		53
Income from operations	88		16		91		18		256		16		271		18
Interest expense⁽²⁾	32		6		31		6		95		6		93		6
Other income:
Allowance for equity funds used during construction	2		—		2		—		7		1		8		1
Miscellaneous income, net	3		1		—		—		5		—		—		—
Other income, net	5		1		2		—		12		1		8		1
Income before income tax expense	61		11		62		12		173		11		186		13
Income tax expense	6		1		9		2		20		1		23		2
Net income	$	55	10	%	$	53	10	%	$	153	10	%	$	163	11	%

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

(2) Net of an allowance for borrowed funds used during construction of $1 million for three months ended September 30, 2019 and 2018 and $4 million for the nine months ended September 30, 2019 and 2018.

Net income was $55 million, or $0.61 per diluted share, for the three months ended September 30, 2019, compared with $53 million, or $0.59 per diluted share, for the three months ended September 30, 2018. Gross margin increased $38 million primarily due to a $21 million decrease in Purchased power and fuel expense. A combination of lower retail load due to mild weather, lower wholesale power prices, and improved production from PGE-owned generation drove this decrease. Total revenues also increased by $17 million that included certain regulatory deferrals such as decoupling, which offset lower usage per customer within retail revenues ($7 million). Offsetting the increase in Gross margin were Operating expense increases of $41 million that resulted from a $4 million increase in distribution expenses due to higher vegetation management and wildfire mitigation efforts, higher labor and benefit expenses, and a $10 million gain from the cash settlement of Carty litigation in 2018 that did not recur.

Net income was $153 million, or $1.70 per diluted share, for the nine months ended September 30, 2019, compared with $163 million, or $1.82 per diluted share, for the nine months ended September 30, 2018. Gross margin increased $79 million due the combination of: a) $108 million increase in Total revenues, primarily due to price adjustments for the 2019 GRC, updated power costs and increases in revenues from wholesale market activities; and b) a $29 million increase in Purchased power and fuel expense due to higher average variable power cost.

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Offsetting the increase in Gross Margin were Operating expense increases of $94 million that were a result of increased preventative maintenance expense, higher per-employee benefit costs and higher depreciation from capital additions. Additionally, a $10 million gain from the cash settlement of Carty in 2018 litigation did not recur.

Three Months Ended September 30, 2019 Compared with the Three Months Ended September 30, 2018

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



	Three Months Ended September 30,
	2019				2018
Revenues (dollars in millions):
Retail:
Residential	$	218	40	%	$	224		43	%
Commercial	167		31		171			32
Industrial	50		9		55			10
Direct access	13		2		9			2
Subtotal	448		82		459			87
Alternative revenue programs, net of amortization	4		1		—			—
Other accrued (deferred) revenues, net	4		1		(11		)	(2	)
Total retail revenues	456		84		448			85
Wholesale revenues	72		13		67			13
Other operating revenues	14		3		10			2
Total revenues	$	542	100	%	$	525		100	%

Energy deliveries (MWhs in thousands):
Retail:
Residential	1,646		24	%	1,712			27	%
Commercial	1,738		26		1,837			28
Industrial	822		12		844			13
Subtotal	4,206		62		4,393			68
Direct access:
Commercial	195		3		170			2
Industrial	373		5		368			6
Subtotal	568		8		538			8
Total retail energy deliveries	4,774		70		4,931			76
Wholesale energy deliveries	2,015		30		1,529			24
Total energy deliveries	6,789		100	%	6,460			100	%

Average number of retail customers:
Residential	781,223		88	%	773,514			88	%
Commercial	109,589		12		110,028			12
Industrial	193		—		200			—
Direct access	632		—		604			—
Total	891,637		100	%	884,346			100	%

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Total revenues for the three months ended September 30, 2019 increased $17 million compared with the three months ended September 30, 2018, as Total retail revenues increased $8 million, Wholesale revenues increased $5 million, and Other operating revenues increased $4 million.

The increase in Total retail revenues resulted largely from the following:


•	$16 million increase that resulted from customer price changes; partially offset by


•	$14 million decrease resulting from a 3.2% decrease in retail energy deliveries. Energy deliveries to residential customers decreased 3.9% reflecting decreased average usage per customer driven partially by mild weather, deliveries to commercial customers declined 3.7%, and deliveries to industrial customers decreased 1.4%.

For the three months ended September 30, 2019, cooling degree-days were down 20% from the prior year, illustrating the influence weather had on customer demand during the third quarter of the year. For the three months ended September 30, 2019, total cooling degree-days were 5% above the 15-year average.

The following table indicates the number of heating and cooling degree-days for the three months ended September 30, 2019 and 2018, 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
	2019		2018		Avg.	2019		2018		Avg.
July	3		2		6	176		289		179
August	—		6		6	216		238		190
September	80		61		63	70		48		71
Totals for the quarter	83		69		75	462		575		440
Increase/(decrease) from the 15-year average	11	%	(8	)%		5	%	31	%

Wholesale revenues for the three months ended September 30, 2019 increased $5 million, or 7%, from the three months ended September 30, 2018, as a result of a $20 million increase related to 32% greater wholesale sales volume largely offset by a $17 million decrease as a result of 20% lower average wholesale sales prices. Cooler weather during the quarter contributed to lower wholesale market prices.

Purchased power and fuel expense decreased $21 million, or 11%, for the three months ended September 30, 2019 compared with the three months ended September 30, 2018. This change consisted of a $16 million decrease in the average variable power cost per MWh, and a $5 million decrease due to total system load.

The $16 million decrease due to a change in the average variable power cost per MWh to $25.16 per MWh for the three months ended September 30, 2019 from $29.98 per MWh for the three months ended September 30, 2018, was primarily driven by a 10% decrease in average variable power cost per MWh for PGE’s own generation resources, and a 7% decrease for purchased power.

Although total system load increased 6%, PGE experienced an overall decrease in purchased power and fuel attributable to volume of $5 million as a greater portion of PGE's system load was satisfied by PGE owned resources, which displaced higher cost market purchases when compared to the three months ended September 30, 2018.

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



	Three Months Ended September 30,
	2019				2018
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	2,881		44	%	2,777		45	%
Coal	1,450		22		1,054		17
Total thermal	4,331		66		3,831		62
Hydro	261		4		258		4
Wind	598		9		475		8
Total generation	5,190		79		4,564		74
Purchased power:
Term	1,000		15		1,208		20
Hydro	241		4		325		5
Wind	100		2		85		1
Total purchased power	1,341		21		1,618		26
Total system load	6,531		100	%	6,182		100	%
Less: wholesale sales	(2,015	)			(1,529	)
Retail load requirement	4,516				4,653

Energy received from PGE-owned, wind-powered generating resources increased 26% in the three months ended September 30, 2019 compared with the same period of 2018 as a result of more favorable wind conditions. Energy received from these wind-powered generating resources represented 13% of the Company’s retail load requirements for the three months ended September 30, 2019 and 10% for the three months ended September 30, 2018.

Due to less favorable hydroelectric conditions, energy received from hydro resources during the three months ended September 30, 2019, from both PGE-owned generating plants and purchased from mid-Columbia projects in total, decreased 14% compared with the same period of 2018, and represented 11% and 13% of the Company’s retail load requirement for the three months ended September 30, 2019 and 2018, respectively.

The following table presents the actual April-to-September 2019 and 2018 runoff at particular points of major rivers relevant to PGE’s hydro resources:



	Runoff as a Percent of Normal*
Location	2019		2018
Columbia River at The Dalles, Oregon	94	%	114	%
Mid-Columbia River at Grand Coulee, Washington	87		114
Clackamas River at Estacada, Oregon	114		88
Deschutes River at Moody, Oregon	111		88

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

Actual NVPC for the three months ended September 30, 2019 decreased $26 million when compared with the three months ended September 30, 2018. The decrease was primarily driven by a 7% increase in wholesale revenue. The increase in wholesale revenues was driven by a 32% increase in the wholesale volume. For the three months ended September 30, 2019, actual NVPC was $2 million below the baseline. For the three months ended September 30, 2018, actual

NVPC was $24 million above baseline NVPC. For additional information, see “Purchased power and fuel” section of this Item 2.

Generation, transmission and distribution expense increased $6 million, or 8%, in the three months ended September 30, 2019 compared with the three months ended September 30, 2018, due to $6 million higher distribution expenses for vegetation management, wildfire mitigation and preventative maintenance, $3 million lower expenses at the Company’s generation facilities, and $3 million higher miscellaneous expenses.

Administrative and other expense increased $25 million, or 51%, in the three months ended September 30, 2019 compared with the three months ended September 30, 2018. The increase was primarily due to a $10 million expense reduction in 2018 related to the Carty cash settlement, an $8 million increase in employee benefit costs, and a $7 million increase in other miscellaneous expenses that included system conversion costs, and customer-related charges and injury and damages expenses.

Depreciation and amortization expense increased $7 million in the three months ended September 30, 2019 compared with the three months ended September 30, 2018. The increase was driven by a $6 million increase in amortization of regulatory deferrals (which is offset in revenues) and $5 million higher depreciation and amortization expense resulting from capital additions. In the third quarter 2018, the Company incurred a $4 million charge as a result of an increase to asset retirement obligations.

Other income, net increased $3 million for the three months ended September 30, 2019 compared with the three months ended September 30, 2018, primarily due to a curtailment gain recognized in 2019 due to changes in retiree medical plans.

Income tax expense decreased $3 million in the three months ended September 30, 2019 compared with the three months ended September 30, 2018, reflecting effective tax rates of 9.8% and 14.5%, respectively. The decrease in income tax expense was driven by amortization of excess deferred taxes as a result of TCJA.

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Nine Months Ended September 30, 2019 Compared with the Nine Months Ended September 30, 2018

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



	Nine Months Ended September 30,
	2019				2018
Revenues (dollars in millions):
Retail:
Residential	$	713	45	%	$	699		48	%
Commercial	479		31		484			33
Industrial	144		9		138			9
Direct Access	34		2		32			2
Subtotal	1,370		87		1,353			92
Alternative revenue programs, net of amortization	5		—		(2		)	—
Other accrued (deferred) revenues, net	17		1		(38		)	(3	)
Total retail revenues	1,392		88		1,313			89
Wholesale revenues	125		8		119			8
Other operating revenues	58		4		35			3
Total revenues	$	1,575	100	%	$	1,467		100	%

Energy deliveries (MWhs in thousands):
Retail:
Residential	5,428		31	%	5,457			31	%
Commercial	4,999		28		5,088			29
Industrial	2,332		13		2,241			12
Subtotal	12,759		72		12,786			72
Direct access:
Commercial	536		3		481			3
Industrial	1,093		6		1,055			6
Subtotal	1,629		9		1,536			9
Total retail energy deliveries	14,388		81		14,322			81
Wholesale energy deliveries	3,474		19		3,444			19
Total energy deliveries	17,862		100	%	17,766			100	%

Average number of retail customers:
Residential	778,285		88	%	771,336			88	%
Commercial	109,509		12		108,566			12
Industrial	194		—		204			—
Direct access	633		—		599			—
Total	888,621		100	%	880,705			100	%

Total revenues for the nine months ended September 30, 2019 increased $108 million, or 7%, compared with the nine months ended September 30, 2018, consisting primarily of a $79 million increase in Total retail revenues and $23 million in Other operating revenues.

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The increase in Total retail revenues consisted primarily of the following factors:


•	$38 million as a result of customer price changes in the 2019 GRC;


•	$17 million as a result of price changes due primarily to the 2019 AUT and the amortization in prices for the decoupling mechanism;


•	$11 million resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertain to the demand response pilot program and a major maintenance expense deferral, which was offset in Generation, transmission and distribution expense; and


•	$6 million from higher retail energy deliveries driven by the industrial customers.

Total heating degree-days for the nine months ended September 30, 2019 were 10% above those for the nine months ended September 30, 2018 although 1% below the 15-year average, while cooling degree-days, which usually begin during the second calendar quarters, were 18% below the prior year levels. The following table indicates the number of heating and cooling degree-days by quarter for the nine months ended September 30, 2019 and 2018, 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
	2019		2018		Avg.	2019		2018		Avg.
First Quarter	1,992		1,766		1,830	—		—		—
Second Quarter	467		471		653	102		116		88
Third Quarter	83		69		75	462		575		440
Year-to-date	2,542		2,306		2,558	564		691		528
(Decrease)/increase from the 15-year average	(1	)%	(10	)%		7	%	31	%

Wholesale revenues for the nine months ended September 30, 2019 increased $6 million, or 5%, from the nine months ended September 30, 2018, with the increase attributed largely to a 6% increase in average wholesale sales prices. Higher, and considerably more volatile, wholesale power prices resulted from the high retail demand and natural gas supply constraints in the region during the first half of 2019.

Other operating revenues for the nine months ended September 30, 2019 increased $23 million from the nine months ended September 30, 2018 driven primarily by market conditions that provided $10 million more revenue from sale of natural gas in excess of amounts needed for the Company’s generation portfolio back into the wholesale market during periods of high gas prices.

Purchased power and fuel expense increased $29 million, or 7%, for the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018. This change consisted of $56 million increase related to the average variable power cost per MWh, and a $27 million decrease related to total system load.

The $56 million increase due to a change in the average variable power cost to $26.25 per MWh in the nine months ended September 30, 2019 from $24.57 per MWh in the nine months ended September 30, 2018, which was driven primarily by a 37% increase in the average variable power cost per MWh for purchased power. For the nine months ended September 30, 2019, the region faced a variety of factors that increased both the demand and the price per MWh for the period, including: colder temperatures; lower hydro and wind production; and limited natural gas supply due to pipeline maintenance. This was partially offset as the Company effectively dispatched PGE-owned generating facilities at lower than market prices.

The $27 million decrease related to total system load was driven primarily by a 25% decrease in purchased power, partially offset by 17% higher generation.

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



	Nine Months Ended September 30,
	2019				2018
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas	6,199		36	%	5,468		32	%
Coal	3,163		19		2,020		12
Total thermal	9,362		55		7,488		44
Hydro	1,098		7		1,125		7
Wind	1,418		8		1,563		9
Total generation	11,878		70		10,176		60
Purchased power:
Term	4,177		24		5,339		31
Hydro	807		5		1,331		8
Wind	223		1		237		1
Total purchased power	5,207		30		6,907		40
Total system load	17,085		100	%	17,083		100	%
Less: wholesale sales	(3,474	)			(3,444	)
Retail load requirement	13,611				13,639

Energy received from PGE-owned wind-powered generating resources decreased 9% in the nine months ended September 30, 2019 compared with the same period of 2018 as a result of less favorable wind conditions. Energy received from these wind-powered generating resources represented 10% and 11% of the Company’s retail load requirements for the nine months ended September 30, 2019 and 2018, respectively.

Due to less favorable hydro conditions, energy received from hydro resources during the nine months ended September 30, 2019, from both PGE-owned generating plants and purchased from mid-Columbia projects, decreased 22% compared with the same period of 2018, and represented 14% and 18% of the Company’s retail load requirement for the nine months ended September 30, 2019, and 2018, respectively.

Actual NVPC for the nine months ended September 30, 2019 increased $23 million when compared with the nine months ended September 30, 2018. The overall increase was driven by the $29 million increase in purchased power and fuel, which was the result of a 7% increase in the average variable power cost per MWh. For the nine months ended September 30, 2019 and 2018, actual NVPC was $5 million above and $3 million below baseline NVPC, respectively. For additional information, see “Purchased power and fuel” section of this Item 2.

Generation, transmission and distribution expense increased $29 million, or 14%, in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018 primarily due to $15 million higher distribution expenses for vegetation management, wildfire mitigation and storm restoration, $11 million higher operating and preventative maintenance expenses at the Company’s generation facilities, and $4 million higher miscellaneous expenses.

Administrative and other expense increased $35 million, or 19%, in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018. The increase was primarily due to $16 million higher employee benefit costs, a $10 million expense reduction in 2018 related to the Carty cash settlement, $6 million higher costs related to the new customer billing system (on-going support in 2019 and 2018 deferral of costs, offset by collection in 2019), and $5 million miscellaneous expenses.

Depreciation and amortization expense increased $24 million, or 9%, in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018. The increase was primarily driven by higher depreciation and amortization expense of $18 million from capital additions, partially offset by a $4 million increase in 2018 to asset retirement obligations, and a $9 million increase to amortization of regulatory deferrals (directly offset in revenues).

Taxes other than income taxes increased $6 million, or 6%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, driven by higher property taxes.

Other income, net was $12 million in the nine months ended September 30, 2019 compared with $8 million in the nine months ended September 30, 2018, driven by a curtailment gain recognized in 2019 due to changes in retiree medical plans and decreased pension expense due to changes in actuarial valuations.

Income tax expense was $20 million in the nine months ended September 30, 2019 compared with $23 million in the nine months ended September 30, 2018 with the change primarily due to lower pre-tax income, offset by a decrease in PTCs.

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2019 through 2023 (in millions, excluding AFDC):



	2019		2020		2021		2022		2023
Ongoing capital expenditures*	$	585	$	640	$	500	$	500	$	500
Wheatridge Renewable Energy Facility	5		135		15		—		—
Integrated Operations Center	30		90		80		—		—
Total capital expenditures	$	620	$	865	$	595	$	500	$	500
Long-term debt maturities	$	50	$	—	$	160	$	—	$	—

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

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

Liquidity

PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, 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):



	Nine Months Ended September 30,
	2019			2018
Cash and cash equivalents, beginning of period	$	119		$	39
Net cash provided by (used in):
Operating activities	502			536
Investing activities	(406		)	(278		)
Financing activities	(204		)	(97		)
(Decrease) increase in cash and cash equivalents	(108		)	161
Cash and cash equivalents, end of period	$	11		$	200

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 cash flows from operating activities for the nine months ended September 30, 2019 decreased $34 million when compared with the nine months ended September 30, 2018. Included in the change were:


•	$53 million decrease relating to TCJA as a deferral occurred in 2018 with amortization recorded in 2019;


•	$42 million decrease resulting from changes in Accounts payable and other accrued liabilities; and


•	$10 million decrease in Net income; partially offset by


•	$38 million increase from changes in Accounts receivable and unbilled revenues;


•	$30 million increase in Other non-cash income and expenses, net; and


•	$24 million increase resulting from Depreciation and amortization.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that such charges in 2019 will range from $400 million to $420 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $475 million to $525 million. The range of expected cash provided by operations has decreased primarily due to the planned acceleration of $62 million in pension plan contributions. 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

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distribution systems. Net cash used in investing activities for the nine months ended September 30, 2019 increased $128 million when compared with the nine months ended September 30, 2018, with the difference largely due to $120 million cash received in 2018 as a result of a litigation settlement.

The Company plans to make capital expenditures of $620 million, excluding AFDC, in 2019, which it expects to fund with cash to be generated from operations during 2019, as discussed above, and the issuance of debt securities. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the nine months ended September 30, 2019, a net use of cash resulted from the payment of $300 million of long-term debt that was funded through the issuance of $200 million of FMBs and available cash on hand and payment of $99 million of dividends. During the nine months ended September 30, 2018, net cash used in financing activities consisted primarily of the payment of dividends of $93 million.

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 2019 consist of the following:



			Dividends
			Declared Per
Declaration Date	Record Date	Payment Date	Common Share
February 13, 2019	March 25, 2019	April 15, 2019	$0.3625
April 24, 2019	June 25, 2019	July 15, 2019	0.3850
July 31, 2019	September 25, 2019	October 15, 2019	0.3850
October 30, 2019	December 26, 2019	January 15, 2020	0.3850

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors. Management believes that the availability of its revolving credit facility, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.

For 2019, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $475 million to $525 million, issuances of debt securities of up to $520 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.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $900 million through February 6, 2020.

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As of September 30, 2019, PGE had a $500 million revolving credit facility scheduled to expire in November 2022. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash for general corporate purposes. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the credit facility.

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

Under the revolving credit facility, as of September 30, 2019, PGE had no borrowings or commercial paper outstanding. As a result, the aggregate, unused available credit capacity was $500 million.

In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for a total capacity of $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 $60 million were outstanding as of September 30, 2019.

Long-term Debt. As of September 30, 2019, total long-term debt outstanding, net of $10 million of unamortized debt expense, was $2,378 million, of which $50 million is expected to mature in 2019. On April 12, 2019, PGE issued $200 million FMBs at an interest rate of 4.30%, due in 2049. Proceeds from the transaction were used toward repayment of the $300 million current portion of long-term debt that came due April 15, 2019.

On October 25, 2019, PGE entered into an agreement to issue $270 million of FMBs in two tranches, both of which will bear interest from their issue date at an annual rate of 3.34%. The first tranche, $110 million, with a maturity in 2049, was issued on October 25, 2019, a portion of which was used to redeem $50 million of 6.75% FMBs that had a maturity date in 2023. The second tranche, $160 million, with a maturity in 2050, is expected to be issued and funded on or about November 15, 2019.

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% and 49.8% as of September 30, 2019 and December 31, 2018, respectively.

Credit Ratings and Debt Covenants

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



	Moody’s	S&P
First Mortgage Bonds	A1	A
Senior unsecured debt	A3	BBB+
Commercial paper	P-2	A-2
Outlook	Stable	Positive

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

As of September 30, 2019, PGE had $33 million of collateral posted with these counterparties, consisting of $12 million in cash and $21 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of September 30, 2019, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade was $37 million, and decreases to $23 million by December 31, 2019 and to $7 million by December 31, 2020. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade was $107 million at September 30, 2019 and decreases to $88 million by December 31, 2019 and to $63 million by December 31, 2020.

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, 2019, under the most restrictive issuance test in the Indenture, the Company could have issued up to $908 million of additional

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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 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, 2019, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 50.2%.

Off-Balance Sheet Arrangements

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

For such arrangements set forth in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 15, 2019. there have been no material changes outside the ordinary course of business as of September 30, 2019.

Contractual Obligations

PGE’s contractual obligations for 2019 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, 2018, filed with the SEC on February 15, 2019. For such obligations, there have been no material changes outside the ordinary course of business as of September 30, 2019 except that PGE expects to accelerate previously planned contributions to the pension plan during 2020 and 2021 into 2019, such that it will fund $62 million in 2019 and none in either 2020 or 2021.



Item 3.	Quantitative and Qualitative Disclosures About Market Risk.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 15, 2019.



Item 4.	Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2019, these disclosure controls and procedures were effective.

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Changes in Internal Control over Financial Reporting

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

PART II - OTHER INFORMATION



Item 1.	Legal Proceedings.

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



Item 1A.	Risk Factors.

There have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 15, 2019.



Item 5.	Other Information.

On October 30, 2019, the Company entered into an agreement with William Nicholson, Vice President, Utility Technical Services, in connection with his planned retirement from the Company on December 31, 2019. The agreement includes a standard release of claims against the Company and provides for the following benefits: accelerated vesting of 837 time-based restricted stock units that would otherwise have been forfeited upon Mr. Nicholson’s retirement on December 31, 2019; and amendment of two outstanding performance-based restricted stock unit awards to provide for continued vesting subject to Company performance through the end of the applicable performance period. As a result of the amendment of the performance-based restricted stock units, dependent upon Company performance, Mr. Nicholson will remain eligible to receive up to 7,716 shares of Company common stock (4,354 shares at the target level of performance) that he would have otherwise forfeited.

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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	Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed November 1, 2019, 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.

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SIGNATURE

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



		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)


Date:	October 31, 2019	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)

Exhibit

Exhibit 31.1

CERTIFICATION

I, Maria M. Pope, certify that:


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


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


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


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


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


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


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


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


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


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


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



Date:	October 31, 2019	By:	/s/ Maria M. Pope
			Maria M. Pope
			President and Chief Executive Officer

Exhibit

Exhibit 31.2

CERTIFICATION

I, James F. Lobdell, certify that:


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


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


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


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


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


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


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


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


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


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


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



Date:	October 31, 2019	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer

Exhibit

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

We, Maria M. Pope, President and Chief Executive Officer, and James F. Lobdell, Senior Vice President of Finance, Chief Financial Officer and Treasurer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2019, as filed with the Securities and Exchange Commission on November 1, 2019 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”), fully complies with the requirements of that section.

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



/s/ Maria M. Pope		/s/ James F. Lobdell
Maria M. Pope		James F. Lobdell
President and Chief Executive Officer		Senior Vice President of Finance, Chief Financial Officer and Treasurer


Date:	October 31, 2019	Date:	October 31, 2019