UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2019

or

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

For the transition period from ____________________ to ____________________

Commission File Number: 001-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and registrant’s telephone number, including area code) 

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

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

[x] Yes x [ ] No

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

Large accelerated filer [x]	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 April 17, 2019 is 89,356,572shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	54
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 5.	Other Information	54
Item 6.	Exhibits	54
SIGNATURE		56

2

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym	Definition
AFDC	Allowance for funds used during construction
AUT	Annual Power Cost Update Tariff
Boardman	Boardman coal-fired generating plant
Carty	Carty natural gas-fired generating plant
Colstrip	Colstrip Units 3 and 4 coal-fired generating plant
CWIP	Construction work-in-progress
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FMBs	First Mortgage Bonds
GAAP	Accounting principles generally accepted in the United States of America
GRC	General Rate Case
IRP	Integrated Resource Plan
Moody’s	Moody’s Investors Service
MW	Megawatts
MWa	Average megawatts
MWh	Megawatt hours
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

3

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(Dollars in millions, except per share amounts)

(Unaudited)

	Three Months Ended March 31,
	2019		2018
Revenues:
Revenues, net	$	570	$	495
Alternative revenue programs, net of amortization	3		(2		)
Total revenues	573		493
Operating expenses:
Purchased power and fuel	179		130
Generation, transmission and distribution	77		69
Administrative and other	71		69
Depreciation and amortization	101		92
Taxes other than income taxes	34		33
Total operating expenses	462		393
Income from operations	111		100
Interest expense, net	32		31
Other income:
Allowance for equity funds used during construction	3		4
Miscellaneous income (expense), net	2		(1		)
Other income, net	5		3
Income before income tax expense	84		72
Income tax expense	11		8
Net income	73		64
Other comprehensive income	1		—
Comprehensive income	$	74	$	64
Weighted-average common shares outstanding—basic and diluted (in thousands)	89,309		89,160
Earnings per share—basic and diluted	$	0.82	$	0.72
See accompanying notes to condensed consolidated financial statements.

4

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	March 31, 2019		December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	89	$	119
Accounts receivable, net	226		193
Unbilled revenues	71		96
Inventories	81		84
Regulatory assets—current	21		61
Other current assets	108		90
Total current assets	596		643
Electric utility plant, net	6,747		6,887
Regulatory assets—noncurrent	380		401
Nuclear decommissioning trust	46		42
Non-qualified benefit plan trust	37		36
Other noncurrent assets	142		101
Total assets	$	7,948	$	8,110
See accompanying notes to condensed consolidated financial statements.

5

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(In millions)

(Unaudited)

	March 31, 2019			December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	136		$	168
Liabilities from price risk management activities—current	32			55
Current portion of long-term debt	300			300
Accrued expenses and other current liabilities	263			268
Total current liabilities	731			791
Long-term debt, net of current portion	2,178			2,178
Regulatory liabilities—noncurrent	1,356			1,355
Deferred income taxes	380			369
Unfunded status of pension and postretirement plans	309			307
Liabilities from price risk management activities—noncurrent	78			101
Asset retirement obligations	198			197
Non-qualified benefit plan liabilities	103			103
Other noncurrent liabilities	67			203
Total liabilities	5,400			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 March 31, 2019 and December 31, 2018	—			—
Common stock, no par value, 160,000,000 shares authorized; 89,356,311 and 89,267,959 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively	1,212			1,212
Accumulated other comprehensive loss	(8		)	(7		)
Retained earnings	1,344			1,301
Total shareholders’ equity	2,548			2,506
Total liabilities and shareholders’ equity	$	7,948		$	8,110
See accompanying notes to condensed consolidated financial statements.

6

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Three Months Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	73		$	64
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	101			92
Deferred income taxes	9			6
Pension and other postretirement benefits	6			6
Allowance for equity funds used during construction	(3		)	(4		)
Decoupling mechanism deferrals, net of amortization	(4		)	3
(Amortization) Deferral of net benefits due to Tax Reform	(5		)	15
Other non-cash income and expenses, net	10			4
Changes in working capital:
(Increase) decrease in accounts receivable and unbilled revenues	(1		)	45
Decrease (increase) in inventories	3			(2		)
Decrease (increase) in margin deposits, net	1			(6		)
(Decrease) in accounts payable and accrued liabilities	(13		)	(17		)
Other working capital items, net	(12		)	(5		)
Other, net	(9		)	(7		)
Net cash provided by operating activities	156			194
Cash flows from investing activities:
Capital expenditures	(150		)	(131		)
Sales of Nuclear decommissioning trust securities	4			3
Purchases of Nuclear decommissioning trust securities	(2		)	(3		)
Other, net	(3		)	1
Net cash used in investing activities	(151		)	(130		)
Cash flows from financing activities:
Dividends paid	(32		)	(30		)
Other	(3		)	(3		)
Net cash used in financing activities	(35		)	(33		)
(Decrease) increase in cash and cash equivalents	(30		)	31
Cash and cash equivalents, beginning of period	119			39
Cash and cash equivalents, end of period	$	89		$	70
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	13		$	13
See accompanying notes to condensed consolidated financial statements.

7

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, of which Portland and Salem are the largest. As of March 31, 2019, PGE served 887 thousand retail customers with a service area population of 1.9 million, comprising 46% of the state’s population.

Condensed Consolidated Financial Statements

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

The financial information included herein for the three months ended March 31, 2019 and 2018 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 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 months ended March 31, 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.

8

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 if it will 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.

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 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 March 31, 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 will evaluate 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 are no longer considered to meet bui

9

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

ld-to-suit criteria under Topic 842 and will not be recognized on the Company’s balance sheet until commencement, which is expected 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 meets 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.

10

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended March 31,
	2019		2018
Retail:
Residential	$	290	$	268
Commercial	154		151
Industrial	44		44
Direct access customers	11		10
Subtotal	499		473
Alternative revenue programs, net of amortization	3		(2		)
Other accrued (deferred) revenues, net(1)	7		(17		)
Total retail revenues	509		454
Wholesale revenues(2)	37		28
Other operating revenues	27		11
Total revenues	$	573	$	493

(1) Balance primarily comprised of $6 million of amortization and $15 million of deferral for the three months ended March 31, 2019 and 2018, respectively, related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under the TCJA.

(2) Wholesale revenues include $11 million and $2 million related to electricity commodity contract derivative settlements for the three months ended March 31, 2019 and 2018, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers pursuant to Topic 606. For further information, see Note 5, Risk Management.

Retail Revenues

The Company’s primary revenue source is generated through the sale of electricity to customers based on 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 season and summer cooling season. 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 OPUC. Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options for residential and small commercial customers.

11

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that 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 goods 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 to transfer each distinct delivery of electricity in the series to the customer.

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 and wind conditions, and daily and seasonal retail demand.

The majority of PGE’s wholesale electricity sales is to utilities and power marketers, is predominantly short-term, and consists of a single performance obligation 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.

12

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

NOTE 3: BALANCE SHEET COMPONENTS

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses 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):

	March 31, 2019		December 31, 2018
Prepaid expenses	$	60	$	54
Assets from price risk management activities	33		20
Margin deposits	15		16
Other current assets	$	108	$	90

Electric Utility Plant, Net

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

	March 31, 2019			December 31, 2018
Electric utility plant	$	10,416		$	10,344
Construction work-in-progress	200			346
Total cost	10,616			10,690
Less: accumulated depreciation and amortization	(3,869		)	(3,803		)
Electric utility plant, net	$	6,747		$	6,887

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $318 million and $302 million as of March 31, 2019 and December 31, 2018, respectively. Amortization expense related to intangible assets was $16 millionfor the three months ended March 31, 2019 and $13 million for the three months ended March 31, 2018. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

13

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):

	March 31, 2019					December 31, 2018
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	—		$	74	$	32		$	99
Pension and other postretirement plans	—			219		—			222
Debt issuance costs	—			20		—			16
Trojan decommissioning activities	—			25		—			26
Other	21			42		29			38
Total regulatory assets	$	21		$	380	$	61		$	401
Regulatory liabilities:
Asset retirement removal costs	$	—		$	991	$	—		$	979
Deferred income taxes	—			266		—			267
Trojan decommissioning activities	2			—		1			—
Asset retirement obligations	—			53		—			53
Tax Reform Deferral(1)	23			16		23			22
Other	16			30		12			34
Total regulatory liabilities	$	41	(2)	$	1,356	$	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):

	March 31, 2019		December 31, 2018
Accrued employee compensation and benefits	$	42	$	66
Accrued taxes payable	37		34
Accrued interest payable	44		27
Accrued dividends payable	33		34
Regulatory liabilities—current	41		36
Other	66		71
Total accrued expenses and other current liabilities	$	263	$	268

Credit Facilities

As of December 31, 2018, PGE had a $500 million revolving credit facility scheduled to expire inNovember 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

14

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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, to65% of total capitalization. As of March 31, 2019, PGE was in compliance with this covenant with a 49.3% debt-to-total capital ratio.

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

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

Under the revolving credit facility, as of March 31, 2019, PGE hadno borrowings outstanding and there wereno commercial paper or letters of credit issued. As a result, as of March 31, 2019, 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$83 million were outstanding as of March 31, 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

During the three months ended March 31, 2019, PGE did not enter into any long-term debt transactions. Due to the upcoming repayment of long-term debt in 2019, $300 million was classified as current on the Company’s condensed consolidated balance sheets as of March 31, 2019.

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

Defined Benefit Pension Plan Costs

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

	Three Months Ended March 31,
	2019			2018
Service cost	$	4		$	5
Interest cost*	8			8
Expected return on plan assets*	(10		)	(10		)
Amortization of net actuarial loss*	3			4
Net periodic benefit cost	$	5		$	7

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

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(Unaudited)

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 March 31, 2019 and December 31, 2018. PGE then classifies these financial assets and liabilities based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. 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 months ended March 31, 2019 and 2018, except those presented in this note.

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(Unaudited)

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

	As of March 31, 2019
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	82	$	—	$	—	$	—	$	82
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	8		14		—		—		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	—		14		4		—		18
Natural gas	—		19		—		—		19
	$	99	$	59	$	4	$	12	$	174
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	6	$	69	$	—	$	75
Natural gas	—		30		5		—		35
	$	—	$	36	$	74	$	—	$	110

(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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(Unaudited)

	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 arehighly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of securities holdings of such funds do not exceed 90 days and investors have 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 NASDAQ and the 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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(Unaudited)

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 exposure to commodity price risk 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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(Unaudited)

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2019:
Electricity physical forwards	$	4	$	69	Discounted cash flow	Electricity forward price (per MWh)	$	12.24	$	75.70	$	50.85
Natural gas financial swaps	—		5		Discounted cash flow	Natural gas forward price (per Decatherm)	1.04		4.10		1.80
	$	4	$	74
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 thecontract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

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

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(Unaudited)

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

	Three Months Ended March 31,
	2019			2018
Balance as of the beginning of the period	$	88		$	139
Net realized and unrealized (gains)/losses*	(19		)	(4		)
Transfers out of Level 3 to Level 2	1			(1		)
Balance as of the end of the period	$	70		$	134

* 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 months ended March 31, 2019 and 2018, there wereno 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 First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement.

As of March 31, 2019, 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 $2,773 million. As of December 31, 2018, the carrying amount of PGE’s long-term debt was $2,478 million, net of $10 millionof 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

21

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(Unaudited)

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

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

	March 31, 2019		December 31, 2018
Current assets:
Commodity contracts:
Electricity	$	17	$	11
Natural gas	16		7
Total current derivative assets*	33		18
Noncurrent assets:
Commodity contracts:
Electricity	1		1
Natural gas	3		1
Total noncurrent derivative assets	4		2
Total derivative assets not designated as hedging instruments	$	37	$	20
Total derivative assets	$	37	$	20
Current liabilities:
Commodity contracts:
Electricity	$	12	$	16
Natural gas	20		35
Total current derivative liabilities	32		51
Noncurrent liabilities:
Commodity contracts:
Electricity	63		78
Natural gas	15		23
Total noncurrent derivative liabilities	78		101
Total derivative liabilities not designated as hedging instruments	$	110	$	152
Total derivative liabilities	$	110	$	152

* Included in Other current assets on the condensed consolidated balance sheets.

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(Unaudited)

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

	March 31, 2019			December 31, 2018
Commodity contracts:
Electricity	7		MWh	5		MWh
Natural gas	134		Decatherms	123		Decatherms
Foreign currency	$	20	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 March 31, 2019, and December 31, 2018, gross amounts included as Price risk management liabilities subject to master netting agreements were $71 million and $88 million, respectively, for which PGE posted collateral of $11 million in each period, which consisted entirelyof letters of credit. As of March 31, 2019, of the gross amounts recognized, $69 million 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 March 31,
	2019			2018
Commodity contracts:
Electricity	$	(24	)	$	1
Natural Gas	(25		)	14

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 months ended March 31, 2019, a netgain of $49 million was offset, while $15 million of the net losses recognized in Net income were offset for the three months ended March 31, 2018.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 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	$	(6	)	$	5	$	6	$	5	$	6	$	41	$	57
Natural gas	8			3		4		1		—		—		16
Net unrealized loss	$	2		$	8	$	10	$	6	$	6	$	41	$	73

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(Unaudited)

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s 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 March 31, 2019 was $107 million, for which PGE has posted $43 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2019, the cash requirement to either post as collateral or settle the instruments immediately would have been $91 million. As of March 31, 2019, PGE hadno 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:

	March 31, 2019		December 31, 2018
Assets from price risk management activities:
Counterparty A	33	%	42	%
Counterparty B	11		15
Counterparty C	13		9
	57	%	66	%
Liabilities from price risk management activities:
Counterparty D	62	%	56	%
	62	%	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

PGE has in the past and may enter 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.

Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. Such amounts are also included as a component of cost of debt for ratemaking purposes.

PGE is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, PGE receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates. Until settlement, the interest rate swaps are carried at fair value as a derivative asset or liability with the corresponding offset recorded as either a regulatory liability or regulatory asset, respectively. The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. As of March

24

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(Unaudited)

31, 2019, the Company had no outstanding interest rate swaps. 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.

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 months ended March 31, 2019, unvested performance-based restricted stock units and related dividend equivalent rights of 263 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 230 thousand shares excluded for the three months ended March 31, 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 March 31,
	2019	2018
Weighted-average common shares outstanding—basic and diluted	89,309	89,160

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(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three-month periods ended March 31, 2019 and 2018 was as follows (dollars in millions, except per share amounts):

	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Shares	Amount									Total
Balances as of December 31, 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
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

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.

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(Unaudited)

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 its nature.

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 is 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.

In 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation, as well as several miles beyond.

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.

PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including the final selection of a proposed remedy by the EPA, results of the pre-remedial design sampling, a final allocation methodology, and data with regard to property specific activities and

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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 such 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 proceeds from third parties such as claims under insurance policies and, if necessary, recovery in customer prices. At this time, PGE is not recovering any Portland Harbor cost from the PHERA mechanism 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.

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

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County 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 the abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, 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 Marion County Circuit Court (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 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 August 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) thatsought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA 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 of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements, for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA 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-owns 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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On August 3, 2018, the Judge 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 Judge 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.

On October 17, 2018, DRA filed an appeal to the Ninth Circuit Court of Appeals. Briefing is scheduled to begin in August 2019.

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 March 31, 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 regulatory flow-through adjustments, tax credits, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory rate and PGE’s effective tax rate for financial reporting purposes are reflected in the following table:

	Three Months Ended March 31,
	2019		2018
Federal statutory tax rate	21.0	%	21.0	%
Federal tax credits*	(12.7	)	(18.0	)
State and local taxes, net of federal tax benefit	6.5		6.5
Flow through depreciation and cost basis differences	1.3		1.0
Excess deferred tax amortization	(3.7	)	—
Other	0.7		0.6
Effective tax rate	13.1	%	11.1	%

* 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 generated for 10 years from the in-service dates of the corresponding facilities. PGE’s PTC generation endsat various dates through 2024.

On February 14, 2018, the FASB issued ASU 2018-02 that allows entities subject to FASB requirements to reclassify stranded tax effects resulting from the TCJA from accumulated other comprehensive income (AOCI) to retained earnings. Stranded tax effects are the result of certain items that were recorded in AOCI, net of tax using a historical 35% federal tax rate, and the removal of those items from AOCI using the current 21% tax rate. Pursuant to ASU 2018-02, PGE reclassified $2 million of stranded tax effects from Accumulated other comprehensive loss to Retained earnings for the period ended March 31, 2019.

Carryforwards

Federal tax credit carryforwards as of March 31, 2019 and December 31, 2018 were$59 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 March 31, 2019 will be realized; accordingly, no valuation allowance has been recorded. As of March 31, 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-

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line basis, while finance leases will result in the separate presentation of interest expense on the lease liability and amortization expense of the right-of-use 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.

PGE does not record leases with a term of 12-months or less in the condensed consolidated balance sheet. Total short-term lease cost for the three months ended March 31, 2019 is 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, and power purchase agreements that rely on identified plant. Variable payments are generally related to power purchase agreements for components dependent upon energy production, 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 March 31, 2019
Operating lease cost	$	1
Variable lease cost	$	9

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

	Balance Sheet Classification	March 31, 2019
Operating Leases:
Operating lease right-of-use assets	Other noncurrent assets	$	41
Current operating lease liabilities	Accrued expenses and other current liabilities	5
Noncurrent operating lease liabilities	Other noncurrent liabilities	36
Total operating lease liabilities		$	41
Finance Leases:
Finance lease right-of-use assets	Electric utility plant, net	$	2
Current finance lease liabilities	Accrued expenses and other current liabilities	—
Noncurrent finance lease liabilities	Other noncurrent liabilities	2
Total finance lease liabilities		$	2

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Lease term and discount rates were as follows:

	March 31, 2019
Weighted Average Remaining Lease Term
Operating leases	30 years
Finance leases	4 years
Weighted Average Discount Rate
Operating leases	3.8	%
Finance leases	3.4	%

As of March 31, 2019, maturities of lease liabilities were as follows (in millions):

	Operating Leases			Finance Leases
2019	$	4		$	—
2020	5			—
2021	5			1
2022	5			1
2023	5			—
Thereafter	53			—
Total lease payments	$	77		$	2
Less imputed interest	(36		)	—
Total	$	41		$	2

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

	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1

As of March 31, 2019, PGE has an additional operating lease for a power purchase agreement and a finance lease for a gas storage agreement, neither of which have commenced, with an estimated present value of future lease payments of $15 million and $130 million, respectively. These operating and finance leases are expected to commence in 2019 with lease terms of five and 30 years, respectively.

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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 facility. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175,000 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 and 2017. 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 PW1, PW2, and Beaver natural gas-fired generating plants. Pursuant to the agreement, in September 2016, PGE issued NW Natural a Notice To Proceed with construction of the expansion project, which the gas company estimates construction will be completed during the second quarter of 2019, at a cost of approximately $149 million. Due to the level of PGE’s involvement during the construction period, the Company is deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE 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,

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(Unaudited)

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.

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 and $9 million in 2017. Contingent rents related to power purchase agreements was $14 millionin 2018.

Sublease income was $4 million in 2018 and 2017.

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

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

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

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

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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;

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

• the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

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

• the 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;

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

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

• acts of war or terrorism.

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

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

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. This MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 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 responding to an evolving landscape of customer expectations, technology changes, and regulatory frameworks by focusing efforts on four strategic initiatives: i) deliver exceptional customer service; ii) invest in a reliable and clean energy future; iii) build a smarter, more resilient grid; and iv) pursue excellence in its work.

PGE’s 2016 Integrated Resource Plan (IRP) addressed the Company’s proposal to meet future customer demand and described PGE’s future energy supply strategy and anticipated resource needs over the next 20 years. The areas of focus for the plan included, among other topics, additional resources needed to meet Oregon’s Renewable Portfolio Standard (RPS) requirements, which led to the agreement for the Wheatridge Renewable Energy Facility (Wheatridge), and to replace energy from Boardman, the Company’s coal-fired generating plant located in Eastern Oregon that will cease coal-fired operations at the end of 2020. For further information regarding the Company’s resource planning, see “Integrated Resource Plan” in this Overview section of Item 2.

PGE’s investments in a reliable and clean energy future are a key element of the IRP, which will require compliance with statutory renewable standards and consideration of state and local government initiatives to decarbonize the local economy. The Company is also working to advance transportation electrification, with projects to expand and increase access to electric vehicle charging stations, and partnering with local mass transit agencies to transition to a greater use of electric vehicles.

Building a smarter, more resilient grid is essential to affordably delivering the clean energy future that customers want. This requires embracing new technologies, continuing to modernize the Company’s existing infrastructure, and utilizing the new customer information system to create a foundation to integrate emerging technologies. PGE’s capital requirements contemplate 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.

Oregon’s Clean Electricity and Coal Transition Plan, 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 by 2035. Local governments are also enacting clean energy policy goals. The 2019 Oregon legislative session has introduced proposed legislation that would implement a carbon cap and trade program. For more information on this initiative, see “Oregon Legislative Initiatives” in the Legal, Regulatory and Environmental section of this Item 2.

In June 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, including the cities of Milwaukie and Hillsboro, are considering similar goals. These commitments reflect the values held by customers. As a result, the

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Company is in the process of implementing a Green Tariff program to address this market. For more information on this program, see “Green Tariff” in the Legal, Regulatory and Environmental section of this Item 2.

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

Integrated Resource Plan—In orders issued in 2017, the OPUC acknowledged PGE’s 2016 IRP, enabling the Company to, among other things, finalize agreements to purchase additional annual and seasonal capacity as well as pursue renewable energy and energy storage as described in the paragraphs that follow.

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

Wheatridge will consist of 120 wind turbines manufactured by GE Renewable Energy, Inc. PGE will own 100 MW of the wind resource with an investment of approximately $160million. Subsidiaries of NextEra Energy Resources, LLC plan to build and operate the facility and 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 for the greater of the book value or fair market value as determined on the date of the purchase option.

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 expected to qualify for federal investment tax credits. Any tax credits will help reduce the cost of the project and thus reduce costs to PGE’s customers.

The agreements signed by PGE and subsidiaries of NextEra Energy Resources, LLC will be subject to prudency review on customers’ behalf by the OPUC.

Energy Storage—Pursuant to the 2016 IRP, 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.

2019 IRP—In preparation for its 2019 IRP, PGE conducted an informal public process throughout the past year. The Company has presented multiple enabling studies to support the 2019 IRP, including a:

• Decarbonization Study evaluating the potential impacts of reducing economy-wide greenhouse gas emissions in the PGE service area by 80% by 2050;

• Market Capacity Study evaluating the potential for shifting regional loads and resources to impact the availability of market capacity in the Pacific Northwest over time;

• Distributed Resource and Flexible Load Study, which provided a holistic view of potential Distributed Energy Resource adoption, electric vehicle adoption, and demand response and flexible load program participation among PGE customers; and

• Supply-Side Option Study that provided costs and performance characteristics for supply-side renewables, storage, and thermal resources.

PGE is using the results of the studies and continuing to engage stakeholders in the informal public process to shape the 2019 IRP along with a proposed action plan, which the Company expects to file with the OPUC in the summer of 2019.

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Capital Requirements and Financing—The Company expects 2019 capital expenditures to total $600 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 $550 million to $600 million, and the issuance of debt securities of up to $450 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, PGE purchases and sells electricity in the wholesale market to meet its retail load requirements and balance its energy supply with customer demand. PGE participates in the California Independent System Operator’s Energy Imbalance Market (western EIM), 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 average MWh 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 three months ended March 31, 2019, increased 4.3% compared with the three months ended March 31, 2018, as illustrated in the table below. This increase was primarily driven by cooler temperatures in the 2019 period, which influenced usage in the residential and commercial classes, and continued growth in demand for energy deliveries from the Company’s industrial customers.

Residential energy deliveries increased 5.8% in the first quarter of 2019 and commercial deliveries were up 2.6% compared with the first quarter of 2018 with the increases driven primarily by the effect of the temperature differences. Energy deliveries to industrial customers were up 4.2% for the quarter compared with the prior year.

In the first quarter of 2019, customer demand was influenced by cooler than average temperatures during the heating season. Heating degree-days, an indication of the extent to which customers are likely to have used electricity for heating, were 13% above the first quarter of 2018, which was 3% below the historical average. See “Revenues” in the Results of Operations section of this Item 2 for further information on heating degree-days.

Although total retail energy deliveries for the three months ended March 31, 2019 increased, after adjusting for the effects of weather, total energy deliveries declined 0.3% from the same period of 2018. Decreased average usage per customer driven by energy efficiency and conservation efforts continues to be partially offset by growth in customer count and increased deliveries to high tech manufacturing customers. The financial effects of such energy efficiency and conservation efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See “Legal, Regulatory and Environmental” in this Overview section of Item 2 for further information on the decoupling mechanism.

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

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the corresponding energy deliveries, for the periods indicated:

	Three Months Ended March 31,
	2019		2018		% Increase (Decrease) in Energy Deliveries
	Average Number of Customers	Retail Energy Deliveries*	Average Number of Customers	Retail Energy Deliveries*
Residential	776,067	2,256	768,886	2,133	5.8	%
Commercial (PGE sales only)	109,750	1,631	106,730	1,597	2.1	%
Direct Access	563	164	530	152	7.9	%
Total Commercial	110,313	1,795	107,260	1,749	2.6	%
Industrial (PGE sales only)	199	708	206	680	4.1	%
Direct Access	68	360	67	345	4.3	%
Total Industrial	267	1,068	273	1,025	4.2	%
Total (PGE sales only)	886,016	4,595	875,822	4,410	4.2	%
Total Direct Access	631	524	597	497	5.4	%
Total	886,647	5,119	876,419	4,907	4.3	%

 * In thousands of MWh.

The Company’s Retail Customer Choice Program caps participation by Direct Access customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy supplied to Direct Access customers. This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE’s total retail energy deliveries for the first three months of 2019. Actual energy deliveries to Direct Access customers represented 10% of the Company’s total retail energy deliveries for the first three months of 2019 and 11% for the full year 2018. During 2018, the OPUC created a New Large Load Direct Access program, capped at approximately 120 MWa, for unplanned, large, new loads and large load growth at existing sites. The Company continues to work through the regulatory process to implement the new program.

Power Operations