10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period.

Plant availability is impacted by planned maintenance and forced, or unplanned, outages, during which the respective plant is unavailable to provide power. Availability of all the plants PGE operates was 98% and 82% during the three months ended March 31,2019 and 2018, respectively. Plant availability of Colstrip, which PGE does not operate, was 93% and 98% during the three months ended March 31,2019 and 2018, respectively.

During the three months ended March 31,2019, the Company’s generating plants provided 82% of its retail load requirement compared with 70% in the three months ended March 31,2018. The increase in the proportion of power generated to meet the Company’s retail load requirement was largely due to PGE effectively dispatched its lowest-cost resources in a challenged market, resulting in a 22% increase in the power generated by the Company’s resources during the three months ended March 31,2019 compared to the three months ended March 31,2018.

Energy expected to be received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects is projected annually in the Annual Power Cost Update Tariff (AUT). Any excess in such hydro generation from that projected in the AUT normally displaces power from higher cost sources, while any

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shortfall is normally replaced with power from higher cost sources. For the three months ended March 31, 2019, energy received from these hydro resources decreased by 36% compared to the three months ended March 31, 2018. Energy received from these hydro resources fell short of the projected levels included in PGE’s AUT by 22% for the three months ended March 31,2019 and exceeded by 11% for the three months ended March 31,2018, and provided 13% of the Company’s retail load requirement for the three months ended March 31,2019 and 20%for the three months ended March 31,2018. Energy received from hydro resources is expected to range from 0% to 5% below levels projected in the AUT for 2019.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT. Any excess in wind generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the three months ended March 31, 2019, energy received from these wind generating resources decreased 55% compared to the three months ended March 31, 2018, resulting in the Company incurring additional replacement costs, as well as generating less Production Tax Credits (PTCs) than what was estimated in customer prices. Energy received from these wind generating resources fell short of projections in PGE’s AUT by 43% for the three months ended March 31,2019 and exceeded projections in the AUT by 16% for the three months ended March 31,2018, and provided 4% and 10% of the Company’s retail load requirement during the three months ended March 31,2019 and 2018, respectively. Energy received from wind resources is expected to fall short of levels projected in the AUT for 2019 by up to 10%.

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

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

For the three months ended March 31,2019, actual NVPC was $12 million abovebaseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2019 is currently estimated to be belowthe baseline, but within the established deadband range. Accordingly, no estimated refund to customers is expected under the PCAM for 2019.

For the three months ended March 31,2018, actual NVPC was $11 million below baseline NVPC. For the year ended December 31, 2018, actual NVPC was $3 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded pursuant to the PCAM for 2018.

Fuel Supply —PGE has contractual access to natural gas storage in Mist, Oregon from which it can draw in the event that natural gas supplies are interrupted or if economic factors require its use. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PGE’s Port Westward Unit 1 and Beaver natural gas-fired generating plants and the Port Westward Unit 2 natural gas-fired flexible capacity generating plant. PGE has entered into a long-term agreement with this gas company to expand the current storage facilities, including the construction of a new reservoir, compressor station, and 13-miles of pipeline, which are collectively designed to provide no-notice storage services to these PGE generating plants. NW Natural

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estimates construction will be completed during the second quarter of 2019, at a cost of approximately $149 million. Upon completion of the facility, the lease will commence and PGE will record a finance lease ROU asset and lease liability on its consolidated balance sheets.

The Colstrip co-owners currently obtain coal to fuel the plant via conveyor belt from a mine that lies adjacent to the facility and is the sole source of coal supply for the plant. The company that owns and operates the mine declared bankruptcy in the fourth quarter of 2018. Debtors in the bankruptcy proceeding filed notice on January 19, 2019 of their intention to reject the co-owners’ current coal supply contract, which currently extends through December 31, 2019. The co-owners filed objections to the proposed rejection of the coal supply contract, and on February 22, 2019, the debtors filed an amended plan of reorganization in which they withdrew the proposal to reject the contract. The court approved the debtors’ amended plan of reorganization on March 2, 2019 which allows the coal supply contract to remain in effect through 2019.

Legal, Regulatory, and Environmental Matters—PGE is a party to certain proceedings, the ultimate outcome of which could have a material impact on the financial position, results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, an investigation of environmental matters regarding Portland Harbor.

For additional details regarding various legal and regulatory proceedings related to Portland Harbor and other matters, see Note 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements.

Oregon Clean Electricity and Coal Transition Plan—The State of Oregon passed Senate Bill (SB) 1547, effective in March 2016, a law referred to as the Oregon Clean Electricity and Coal Transition Plan. The legislation has impacted PGE in several ways, one of which is to prevent the Company from including the costs and benefits associated with coal-fired generation in Oregon retail prices after 2030 (subject to an exception that extends this date until 2035 for PGE’s output from the Colstrip facility). As a result, in October 2016, the Company filed a tariff request, which the OPUC approved, to accelerate recovery of PGE’s investment in the Colstrip facility from 2042 to 2030.

Other future effects under the law include:

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

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

• an allowance for energy storage costs related to renewable energy in the Company’s renewable adjustment clause mechanism (RAC) filings.

The Company continues to consider the potential impacts and incorporate the effects of the legislation into its IRP process.

SB 978—In 2017, Senate Bill 978 (SB 978) directed the OPUC to investigate and provide a report to the Oregon legislature on how developing industry trends, technology, and policy drivers in the electricity sector might impact the existing regulatory system and incentives. In its September 14, 2018 report, the OPUC committed to:

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

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

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

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

The OPUC also stated that it would collaborate with the legislature and stakeholders to make progress on climate change, noting that their authority is limited to that of an economic regulator. The legislature may address the limitation identified by the OPUC for direct authority to address climate change through comprehensive cap and trade legislation during the 2019 legislative session.

HB 2020—In the 2019 session, State of Oregon legislators are giving consideration to a proposal called the Oregon Climate Action Program, House Bill 2020 (HB 2020), which is intended to reduce greenhouse gas emissions that contribute to climate change. Among other things, the legislation, as proposed, would:

• require a program to place a cap on greenhouse gas emissions and provide a market-based mechanism for covered entities to demonstrate compliance with the program (a cap and trade program);

• modify statewide greenhouse gas emissions reduction goals by making them more stringent and the basis for the new mandatory emissions cap;

• provide direct allocation of allowances to regulated electric utilities to protect customers from compliance costs; and

• authorize the OPUC to allow tariffs for, or reflect in customer prices amounts of, programs that enable public utilities to assist low-income residential customers.

The Company continues to monitor the proposed legislation as it progresses through the 2019 legislative session.

Green Tariff —In the first quarter 2019, the OPUC approved PGE’s Green Tariff program, which allows for the procurement of new renewable resources and will provide business customers access to bundled renewable energy from those new resources. Through this voluntary tariff, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system. PGE has structured the tariff so that Green Tariff subscribers continue to pay the existing cost of service tariff rate plus the rate under the renewable energy option tariff. This structure is intended to avoid stranded cost and cost shifting. Renewable power provided under the tariff will be procured through power purchase agreements.

Other Regulatory Matters—The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the first quarter of 2019 compared to the first quarter of 2018, or have affected retail customer prices, as authorized by the OPUC. In some cases, the Company has deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

Power Costs—Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC in December 2018, the 2019 GRC included a final projected increase in power costs for 2019, and a corresponding increase in annual revenue requirement, of $25 million from 2018 levels, which is reflected in customer prices effective January 1, 2019.

Under the PCAM for 2018, NVPC was within the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the results of the PCAM for 2018 during the second half of 2019 with a decision expected in the fourth quarter 2019.

Renewable Resource Costs—Pursuant to the RAC, PGE can recover in customer prices the prudently incurred costs of renewable resources. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings, under certain conditions. The Company may submit a filing to the OPUC by April 1st each year. No significant filings have been submitted under the RAC during 2019 or 2018.

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

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

Collections under the decoupling mechanism are subject to an annual limitation of 2% of the applicable rate schedule, which was $18 million for 2018.

The Company deferred an estimated collection of $8 million during the three months ended March 31, 2019, which resulted from projections established in the 2019 GRC. Any collection from (or refund to) customers for the 2019 year is expected to occur over a one-year period, which would begin January 1, 2021.

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

Due to a series of storm events in the first half of 2017, the Company exhausted the storm collection authorized for 2017. Consequently, PGE was exposed to the incremental costs related to such major storm events, which totaled $9 million, net of the amount collected in 2017. During 2016, due to excessive storm restoration costs, PGE had exhausted the available reserve at the end of the year.

As a result of the additional costs incurred, PGE filed an application with the OPUC requesting authorization to defer incremental storm restoration costs from the date of the application, in the first quarter of 2017, through the end of 2017. An OPUC decision on the application remains pending. The Company is unable to predict how the OPUC will ultimately rule on this application or state with any certainty whether these incremental costs are probable of recovery and, accordingly, no deferral has been recorded to-date. In the event it becomes probable that some or all of these costs are recoverable, the Company will record a deferral for such amounts at such time. The OPUC, in its decision on the Company’s 2019 GRC, directed OPUC Staff to bring this matter before the OPUC within 90 days of the issuance of the decision on the 2019 GRC. The OPUC has opened a docket in this matter and established a procedural schedule that concludes with closing briefs June 27, 2019, with a decision likely during the third quarter of 2019.

Portland Harbor Environmental Remediation Account Mechanism—The Company’s environmental recovery mechanism allows the Company to defer and recover incurred environmental expenditures related to Portland Harbor through a combination of third-party proceeds, such as insurance recoveries, and if necessary through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million, excluding expenses

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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.

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

Consistent with past regulatory precedent, on May 11, 2018, the Company submitted an application to the OPUC to defer the revenue requirement associated with this new customer information system from the time the system went into service through the end of 2018. As a result, PGE began deferring its incurred costs, primarily related to depreciation and amortization, of the new customer information system once it was placed in service.

In November 2017, the OPUC opened docket UM 1909 to conduct an investigation of the scope of its authority under Oregon law to allow the deferral of costs related to capital investments for later inclusion in customer prices. On October 29, 2018, the OPUC issued Order 18-423 (Order) concluding that the OPUC lacks authority under Oregon law to allow deferrals of any costs related to capital investments. In the Order, the OPUC acknowledged that this decision is contrary to its past limited practice of allowing deferrals related to capital investments and will require adjustments to its regulatory practices. The OPUC directed its Staff to meet with the utilities and stakeholders to address the full implications of this decision, and to propose recommendations needed to implement this decision consistent with the OPUC’s legal authority and the public interest.

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

During 2018, PGE deferred a total of $12 million related to the project. However, the Order has impacted the probability of recovery of the customer information system deferral and, as such, the Company has recorded a reserve for the full amount of the capital deferral. The reserve was recognized as a charge to the results of operations in 2018. Any amounts that may ultimately be approved by the OPUC in subsequent proceedings would be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC.

Critical Accounting Policies

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

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Results of Operations

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

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

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

	Three Months Ended March 31,
	2019				2018
Total revenues	$	573	100	%	$	493		100	%
Purchased power and fuel	179		31		130			26
Gross margin(1)	394		69		363			74
Other operating expenses:
Generation, transmission and distribution	77		13		69			14
Administrative and other	71		12		69			14
Depreciation and amortization	101		18		92			19
Taxes other than income taxes	34		6		33			7
Total other operating expenses	283		49		263			54
Income from operations	111		19		100			20
Interest expense(2)	32		6		31			6
Other income:
Allowance for equity funds used during construction	3		1		4			1
Miscellaneous income (expense), net	2		—		(1		)	—
Other income, net	5		1		3			1
Income before income tax expense	84		15		72			15
Income tax expense	11		2		8			2
Net income	$	73	13	%	$	64		13	%
(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE’s Condensed Consolidated Statements of Income and Comprehensive Income. (2) Net of an allowance for borrowed funds used during construction of $1 million and $2 million for the three months ended March 31, 2019 and 2018, respectively.

Net income was $73 million, or $0.82 per diluted share, for the three months ended March 31,2019, compared with $64 million, or $0.72 per diluted share, for the three months ended March 31,2018. The increase was primarily driven by a combination of colder temperatures and continued strength in the industrial sector resulting in higher energy deliveries and an increase in retail revenue. Partially offsetting the revenue increase were higher prices for purchased power and natural gas due to cold temperatures that increased regional demand, lower than average wind and hydropower production, and pipeline maintenance that limited natural gas supply. Net income benefited from the absence of costs associated with Carty litigation in 2019 that was present in 2018. The Company experienced higher plant maintenance, labor, and employee benefit expenses, as well as plant depreciation and software amortization in 2019.

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Three Months EndedMarch 31, 2019 Compared with the Three Months EndedMarch 31, 2018

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

	Three Months Ended March 31,
	2019				2018
Revenues (dollars in millions):
Retail:
Residential	$	290	50	%	$	268		54	%
Commercial	154		27		151			31
Industrial	44		8		44			9
Direct Access	11		2		10			2
Subtotal	499		87		473			96
Alternative revenue programs, net of amortization	3		1		(2		)	—
Other accrued (deferred) revenues, net	7		1		(17		)	(4	)
Total retail revenues	509		89		454			92
Wholesale revenues	37		6		28			6
Other operating revenues	27		5		11			2
Total revenues	$	573	100	%	$	493		100	%
Energy deliveries (MWh in thousands):
Retail:
Residential	2,256		39	%	2,133			37	%
Commercial	1,631		28		1,597			27
Industrial	708		12		680			12
Subtotal	4,595		79		4,410			76
Direct access:
Commercial	164		3		152			3
Industrial	360		6		345			6
Subtotal	524		9		497			9
Total retail energy deliveries	5,119		88		4,907			85
Wholesale energy deliveries	674		12		874			15
Total energy deliveries	5,793		100	%	5,781			100	%
Average number of retail customers:
Residential	776,067		88	%	768,886			88	%
Commercial	109,750		12		106,730			12
Industrial	199		—		206			—
Direct access	631		—		597			—
Total	886,647		100	%	876,419			100	%

Total revenues for the three months ended March 31,2019 increased $80 million, or 16%, compared with the three months ended March 31,2018, consisting primarily of a $55 million increase in Total retail revenues, along with a $9 million increase in Wholesale revenues and $16 million in Other operating revenues.

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The increase in Retail revenues consisted primarily of the following factors:

• $20 million resulted from higher retail energy deliveries due largely to the effects of weather on electricity demand, which is reflected predominantly in the Residential revenue line in the table above. Considerably cooler temperatures in the first quarter of 2019 than experienced in 2018, which saw near average temperatures, produced higher deliveries;

• $16 million due to recording during 2018 of the deferral of revenues for estimated refund to customers as a result of the TCJA, which is reflected in the Other accrued (deferred) revenues, net line in the table above. The reduction in revenues was offset with lower income tax expense, resulting in no overall net income impact; and

• $6 million from the results of the decoupling mechanism. An estimated $8 million collection was recorded in 2019, as opposed to an estimated $3 million refund in 2018, net of amortization of prior deferrals; and

• $8 million increase in revenues as a result of price changes due primarily to the annual AUT update and the decoupling mechanism.

Total heating degree-days for the three months ended March 31,2019 were 13% above those for the three months ended March 31,2018 and 9% above average. The following table indicates the number of heating degree-days for the three months ended March 31,2019 and 2018, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:

	Heating Degree-days
	2019		2018		Avg.
January	670		595		739
February	760		625		581
March	562		546		509
Year-to-date	1,992		1,766		1,829
Increase/(decrease) from the 15-year average	9	%	(3	)%

Wholesale revenues for the three months ended March 31,2019 increased $9 million, or 32%, from the three months ended March 31,2018, with the increase comprised of $16 million related to a 73% increase in average wholesale sales prices partially offset by $6 million related to a 23% decrease in wholesale sales volumes. Higher, and considerably more volatile, wholesale power prices resulted from the high retail demand and natural gas supply constraints in the region.

Other operating revenues for the three months ended March 31, 2019 increased $16 million from the three months ended March 31, 2018 driven primarily by the sale of natural gas in excess of amounts needed for the Company’s generation portfolio back into the wholesale market during periods of high gas prices.

Purchased power and fuel expense increased$49 million, or 38%, for the three months ended March 31,2019 compared with the three months ended March 31,2018. This change consisted of $60 million related to an increase in the average variable power cost per MWh, and an $11 million decrease related to total system load.

The $60 million increase in the average variable power cost to $31.59 per MWh in the three months ended March 31,2019 from $22.96 per MWh in the three months ended March 31,2018, was driven primarily by a 114% increase in the average variable power cost per MWh for purchased power. For the three months ended March 31,2019, the region faced a variety of factors that increased both the demand and the price per MWh for the period, including; colder temperatures, lower hydro and wind production, and limited natural gas supply due to pipeline maintenance. This was partially offset as the Company effectively dispatched PGE-owned generating facilities at lower prices.

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The $11 million decrease related to total system load was driven primarily by a 23% decrease in wholesale deliveries, partially offset by slightly higher retail energy deliveries.

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

	Three Months Ended March 31,
	2019				2018
Sources of energy (MWh in thousands):
Generation:
Thermal:
Natural gas	2,168		38	%	1,863		33	%
Coal	1,335		24		545		10
Total thermal	3,503		62		2,408		43
Hydro	377		7		472		8
Wind	212		4		475		8
Total generation	4,092		73		3,355		59
Purchased power:
Term	1,258		22		1,747		31
Hydro	247		4		506		9
Wind	41		1		58		1
Total purchased power	1,546		27		2,311		41
Total system load	5,638		100	%	5,666		100	%
Less: wholesale sales	(674	)			(874	)
Retail load requirement	4,964				4,792

Energy received from PGE-owned wind generating resources decreased 55% in the three months ended March 31, 2019 compared with the same period of 2018 as a result of less favorable wind conditions. Energy received from these wind generating resources represented 4% and 10% of the Company’s retail load requirements for the three months ended March 31, 2019 and 2018, respectively.

Due to less favorable hydroelectric conditions, energy received from hydro resources during the three months ended March 31, 2019, from both PGE-owned generating plants and purchased from mid-Columbia projects, decreased 36% compared with the same period of 2018, and represented 13% and 20% of the Company’s retail load requirement for the three months ended March 31, 2019, and 2018, respectively.

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

	Runoff as a Percent of Normal*
Location	2019 Forecast		2018 Actual
Columbia River at The Dalles, Oregon	95	%	98	%
Mid-Columbia River at Grand Coulee, Washington	87		99
Clackamas River at Estacada, Oregon	119		97
Deschutes River at Moody, Oregon	110		96

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

Actual NVPC for the three months ended March 31,2019 increased$40 million when compared with the three months ended March 31,2018. The increase in purchased power and fuel was driven by a 38% increase in the average variable power cost per MWh, partially offset by a 32% increase in wholesale revenues. The change in wholesale revenues was due mostly to a 73% increase in wholesale sales price, partially offset by a23% decrease in sales volume. For the three months ended March 31,2019 and 2018, actual NVPC was$12 million above and $11 million below baseline NVPC, respectively. For additional information, see “Purchase power and fuel” section of this Item 2.

Generation, transmission and distribution expense increased$8 million, or 12%, in the three months ended March 31,2019 compared with the three months ended March 31,2018 primarily due to $4 million higher generation facility maintenance expenses and $1 million higher storm and service restoration costs.

Administrative and other expense increased $2 million, or 3%, in the three months ended March 31,2019 compared with the three months ended March 31,2018. The increase was primarily due to $6 million higher labor and employee benefit expenses, partially offset by $3 million lower legal fees.

Depreciation and amortization expense increased $9 million in the three months ended March 31,2019 compared with the three months ended March 31,2018. The increase was primarily driven by $7 million increased plant depreciation and software amortization, and a $2 million increase to amortization of regulatory deferrals, which is offset in revenues.

Other income, net was$5 million in the three months ended March 31,2019 compared with $3 million in the three months ended March 31,2018 with $3 million higher other income due primarily to an improvement in the returns on the non-qualified benefit trust assets partially offset by a $1 million decrease in the allowance for equity funds used during construction.

Income tax expense increased $3 million in the three months ended March 31,2019 compared with the three months ended March 31,2018, with effective tax rates of 13.1% and11.1%, respectively. The increase in income tax expense was driven by lower production tax credits and a higher pre-tax income.

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Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2019through2023 (in millions, excluding AFDC):

	2019		2020		2021		2022		2023
Ongoing capital expenditures (1)	$	600	$	500	$	500	$	500	$	500
Wheatridge Renewable Energy Facility	—		140		15		—		—
Total capital expenditures	$	600	$	640	$	515	$	500	$	500
Long-term debt maturities	$	300	$	—	$	160	$	—	$	—

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

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

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Liquidity

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

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

	Three Months Ended March 31,
	2019			2018
Cash and cash equivalents, beginning of period	$	119		$	39
Net cash provided by (used in):
Operating activities	156			194
Investing activities	(151		)	(130		)
Financing activities	(35		)	(33		)
(Decrease) increase in cash and cash equivalents	(30		)	31
Cash and cash equivalents, end of period	$	89		$	70

Cash Flows from Operating Activities — Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, with adjustments for certain non-cash items, such as depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. Net cash flows from operating activities for the three months ended March 31,2019 decreased $38 million when compared with the three months ended March 31,2018. Included in the change were a number of somewhat offsetting components as follows:

• $46 million decrease in cash provided by changes in accounts receivable and unbilled revenue as colder temperatures in the first quarter of 2019 caused balances to increase whereas balances decreased due to mild temperatures in the first quarter of 2018;

• $17 million net decrease in Deferred income taxes and Deferral of net benefits due to the TCJA; and

• $9 million decrease from Other working capital and Other, net items; partially offset by

• $18 million net increase from the combination of changes in Net income adjusted for non-cash income and expenses;

• $11 million net increase from changes in Margin deposits and accounts payable; and

• $5 million increase due to change in Inventory levels.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that such charges in 2019 will range from $400 millionto $420 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $550 million to $600 million.

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s generation facilities and transmission and distribution systems. Net cash used in investing activities for the three months ended March 31,2019 increased $21 million when compared with the three months ended March 31,2018, as capital project activity was $19 million higher.

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The Company plans to make capital expenditures of $600 million, excluding AFDC, in 2019, which it expects to fund with cash to be generated from operations during 2019, as discussed above, and the issuance of debt securities. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the three months ended March 31,2019, a net use of cash resulted from financing activities primarily for the payment of dividends of $32 million. During the three months ended March 31,2018, net cash used in financing activitiesconsisted primarily of the payment of dividends of $30 million.

Dividends on Common Stock

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

Common stock dividends declared during 2019 consist of the following:

			Dividends
			Declared Per
Declaration Date	Record Date	Payment Date	Common Share
February 13, 2019	March 25, 2019	April 15, 2019	$0.3625
April 24, 2019	June 25, 2019	July 15, 2019	0.3850

Debt and Equity Financings

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

For 2019, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from$550 million to $600 million, issuances of debt securities of up to$450 million, and the issuance of commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures.

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

As of March 31, 2019, PGE had a $500 million revolving credit facility scheduled to expire in November 2022. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash for general corporate purposes. PGE may

52

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

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

Under the revolving credit facility, as of March 31, 2019, PGE had no borrowings outstanding, and no commercial paper or letters of credit issued. As a result, the aggregate, unused available credit capacity was $500 million.

In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for a total capacity of $220 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of$83 million were outstanding as of March 31, 2019.

Long-term Debt. As of March 31, 2019, total long-term debt outstanding, net of $10 million of unamortized debt expense, was $2,478 million, with $300 million scheduled maturities classified as current. During the three months ended March 31, 2019, PGE did not enter into any long-term debt transactions. On April 12, 2019, PGE issued $200 million First Mortgage Bonds at an interest rate of 4.3%, due in 2049. Proceeds from the transaction were used to repay the $300 million current portion of long-term debt on April 15, 2019.

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including any current debt maturities) of approximately 50%, over time. Achievement of this objective helps the Company maintain investment grade credit ratings and facilitates access to long-term capital at favorable interest rates. The Company’s common equity ratio was 50.7% and 49.8% as of March 31, 2019 and December 31, 2018, respectively.

Credit Ratings and Debt Covenants

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

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

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

As of March 31, 2019, PGE had $58 million of collateral posted with these counterparties, consisting of$15 million in cash and$43 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2019, the amount of additional collateral that could be

53

requested upon a single agency downgrade to below investment grade was $43 million, and decreases to$16 million by December 31, 2019 and to$14 million by December 31, 2020. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade was $124 million at March 31, 2019 and decreases to$86 million by December 31, 2019 and to$77 million by December 31, 2020.

PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facility would increase.

The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on March 31, 2019, under the most restrictive issuance test in the Indenture, the Company could have issued up to $1.0 billionof additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of March 31, 2019, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 49.3%.

Off-Balance Sheet Arrangements

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

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

Contractual Obligations

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2019, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

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

Item 5. Other Information.

PGE held its 2019 annual meeting of shareholders on April 24, 2019 in Portland, Oregon. The following proposals were voted on at the meeting by the Company’s shareholders:

1. The election of directors;

2. The ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2019; and

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

There were 89,346,322 shares of common stock issued and outstanding as of February 28, 2019, the record date for the meeting, with 82,677,155shares represented at the annual meeting.

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

Nominee	For	Against	Abstain	Broker Non-votes
John W. Ballantine	75,022,457	1,874,309	53,716	5,726,673
Rodney L. Brown, Jr.	75,915,698	987,343	47,441	5,726,673
Jack E. Davis	76,803,395	95,566	51,521	5,726,673
Kirby A. Dyess	76,252,408	641,375	56,699	5,726,673
Mark B. Ganz	74,910,910	1,979,251	60,321	5,726,673
Kathryn J. Jackson	76,463,625	437,420	49,437	5,726,673
Michael H. Millegan	76,812,847	84,698	52,937	5,726,673
Neil J. Nelson	75,559,294	1,337,340	53,848	5,726,673
M. Lee Pelton	75,842,005	1,059,962	48,515	5,726,673
Maria M. Pope	74,295,122	2,615,714	39,646	5,726,673
Charles W. Shivery	76,809,348	86,278	54,856	5,726,673

Shareholders ratified the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2019. There were 81,887,415 votes cast for the proposal, 733,388 votes cast against the proposal, and 56,352 abstentions.

Shareholders approved the compensation of the Company’s named executive officers. There were 74,357,510votes cast for the proposal, 2,478,554 votes cast against the proposal, 114,418 abstentions, and 5,726,673 broker non-votes.

Item 6. Exhibits.

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Exhibit Number	Description
3.1	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2	Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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

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SIGNATURE

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

		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)
Date:	April 25, 2019	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)

56

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Maria M. Pope, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	April 25, 2019	By:	/s/ Maria M. Pope
			Maria M. Pope
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James F. Lobdell, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	April 25, 2019	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

We, Maria M. Pope, President and Chief Executive Officer, and James F. Lobdell, Senior Vice President of Finance, Chief Financial Officer and Treasurer, of Portland General Electric Company (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2019, as filed with the Securities and Exchange Commission on April 26, 2019 pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”), fully complies with the requirements of that section.

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

/s/ Maria M. Pope		/s/ James F. Lobdell
Maria M. Pope		James F. Lobdell
President and Chief Executive Officer		Senior Vice President of Finance, Chief Financial Officer and Treasurer
Date:	April 25, 2019	Date:	April 25, 2019

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 17, 2019
Entity Information [Line Items]
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	0000784977
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		89,356,572
Trading Symbol	POR

XML

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenue, 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	0
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

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
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
Current liabilities
Accounts payable	136	168
Liabilities from price risk mangement 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	0	0
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

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	160,000,000	160,000,000
Common stock, shares issued	89,356,311	89,267,959
Common stock, shares outstanding	89,356,311	89,267,959

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 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

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Basis of Presentation (Notes)

3 Months Ended

Mar. 31, 2019

Basis of Presentation [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 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.

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 build-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.

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Revenue Recognition (Notes)

3 Months Ended

Mar. 31, 2019

Revenue Recognition and Deferred Revenue [Abstract]

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

REVENUE RECOGNITION

Disaggregated Revenue

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

	Three Months Ended 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.

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.

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Balance Sheet Components (Notes)

3 Months Ended

Mar. 31, 2019

Balance Sheet Components [Abstract]

BALANCE SHEET COMPONENTS

BALANCE SHEET COMPONENTS

Inventories

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

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 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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Fair Value of Financial Instruments (Notes)

3 Months Ended

Mar. 31, 2019

Fair Value of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 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.

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.

	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 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.

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)

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.

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Risk Management (Notes)

3 Months Ended

Mar. 31, 2019

Price Risk Management [Abstract]

PRICE RISK MANAGEMENT

RISK MANAGEMENT

Price Risk Management

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

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

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

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 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.

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Earnings Per Share (Notes)

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

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

For the three 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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Equity (Notes)

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Equity

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

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Contingencies (Notes)

3 Months Ended

Mar. 31, 2019

Contingencies [Abstract]

CONTINGENCIES

CONTINGENCIES

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

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

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

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 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 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.

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.

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Guarantees (Notes)

3 Months Ended

Mar. 31, 2019

Guarantees [Abstract]

GUARANTEES

GUARANTEES

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

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes 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.

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Leases Leases (Notes)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Disclosure Text Block [Abstract]

LEASES

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

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.

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, 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.

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2019

Basis of Presentation [Abstract]

Consolidation, Policy [Policy Text Block]

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

Inventory, Policy [Policy Text Block]

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

Debt, Policy [Policy Text Block]

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of 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.

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

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

Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.

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

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

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

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

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.

Fair Value Transfer, Policy [Policy Text Block]

Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and out of Level 3 at the end of the reporting period for all of its derivative instruments.

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

Derivatives, Policy [Policy Text Block]

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

Commitments and Contingencies, Policy [Policy Text Block]

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

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

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

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.

Guarantees, Indemnifications and Warranties Policies [Policy Text Block]

Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities.

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Revenue Recognition (Policies)

3 Months Ended

Mar. 31, 2019

Revenue Recognition and Deferred Revenue [Abstract]

Revenue Recognition, Multiple-deliverable Arrangements, Description [Policy Text Block]

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

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Leases Leases (Policies)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lessee, Leases [Policy Text Block]

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

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Basis of Presentation Basis of Presentation (Tables)

3 Months Ended

Mar. 31, 2019

Accounting Changes and Error Corrections [Abstract]

Schedule of Changes for Adoption of New Accounting Pronouncements [Table Text Block]

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		)

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Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2019

Revenue Recognition and Deferred Revenue [Abstract]

Disaggregation of Revenue [Table Text Block]

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

	Three Months Ended 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.

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Balance Sheet Components (Tables)

3 Months Ended

Mar. 31, 2019

Balance Sheet Components [Abstract]

Schedule of Other Current Assets [Table Text Block]

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

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

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

Schedule of Regulatory Assets and Liabilities [Text Block]

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.

Other Liabilities Disclosure [Text Block]

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

Pension and Other Postretirement Benefits Disclosure [Text Block]

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

	Three Months Ended March 31,
	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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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value of Financial Instruments [Abstract]

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

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

	As of March 31, 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.

	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.

Fair Value Option, Disclosures [Table Text Block]

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

	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of 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

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

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

	Three Months Ended March 31,
	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.

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Price Risk Management (Tables)

3 Months Ended

Mar. 31, 2019

Derivative [Line Items]

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

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

	March 31, 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.

Schedule of Derivative Instruments [Table Text Block]

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

	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

Derivatives Not Designated as Hedging Instruments [Table Text Block]

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

	Three Months Ended 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.

Schedule of Price Risk Derivatives [Table Text Block]

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 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

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

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

	March 31, 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	%

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2019

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

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

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

	Three Months Ended March 31,
	2019	2018
Weighted-average common shares outstanding—basic and diluted	89,309	89,160

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Equity (Tables)

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

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

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Income tax Income tax (Tables)

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

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

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.

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Leases Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lease Cost [Table Text Block]

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 [Table Text Block]

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

Lease Term and Discount Rate [Table Text Block]

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	%

Maturities of Lease Liabilities [Table Text Block]

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 [Table Text Block]

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

Future Minimum Lease Payments [Table Text Block]

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

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Basis of Presentation Schedule of Changes for Adoption of New Accounting Pronouncements (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 178
Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(42)
Accrued Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(3)
Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	139
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(44)
Accounting Standards Update 2016-02 [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(2)
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(42)
Accounting Standards Update 2016-02 [Member] | Accrued Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(5)
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(39)
Building [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(131)
Building [Member] | Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Building [Member] | Accrued Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Building [Member] | Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	131
Assets Held under Capital Leases [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(49)
Assets Held under Capital Leases [Member] | Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Assets Held under Capital Leases [Member] | Accrued Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	2
Assets Held under Capital Leases [Member] | Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 47

XML

Basis of Presentation (Details) retail_customers in Thousands, mi² in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) mi² retail_customers	Mar. 31, 2018 USD ($)
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4
Incorporated Cities	51
Number of Retail Customers | retail_customers	887
Percent of state population	46.00%
Alternative revenue programs, net of amortization	$ 3	$ (2)
Reclassification of stranded tax effects due to Tax Reform	2
Revenues	573	$ 493
AOCI Attributable to Parent [Member]
Reclassification of stranded tax effects due to Tax Reform	2
Property, Plant and Equipment [Member]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(178)
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	44
Accounting Standards Update 2016-02 [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	2
Building [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	131
Assets Held under Capital Leases [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 49

XML

Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Subtotal	$ 499	$ 473
Alternative revenue programs, net of amortization	3	(2)
Other accrued (deferred) revenues, net	7	17
Total retail revenues	509	454
Wholesale revenues	37	28
Other operating revenue	27	11
Total Revenues	573	493
Gain on Derivative Instruments, Pretax	11	2
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	290	268
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	154	151
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	44	44
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	11	10
Revenue Subject to Refund [Member]
Disaggregation of Revenue [Line Items]
Net tax benefits due to the change in tax rate under the TCJA	$ 6	$ 15

XML

Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Other Current Assets [Line Items]
Prepaid expenses	$ 60	$ 54
Assets from price risk management activities	33	20
Margin deposits	15	16
Other current assets	$ 108	$ 90

XML

Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
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

XML

Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 21	$ 61
Regulatory assets - noncurrent	380	401
Regulatory Liability, Current	41	36
Regulatory liabilities-noncurrent	1,356	1,355
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory liabilities-noncurrent	991	979
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory liabilities-noncurrent	266	267
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	2	1
Regulatory liabilities-noncurrent	0	0
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory liabilities-noncurrent	53	53
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	23	23
Regulatory liabilities-noncurrent	16	22
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	16	12
Regulatory liabilities-noncurrent	30	34
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	32
Regulatory assets - noncurrent	74	99
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	219	222
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	20	16
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory assets - noncurrent	25	26
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	21	29
Regulatory assets - noncurrent	$ 42	$ 38

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Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 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

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Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
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

XML

Balance Sheet Components (Details)		3 Months Ended
	Apr. 12, 2019 USD ($)	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Letters of Credit Outstanding, Amount		$ 0
Finite-Lived Intangible Assets, Accumulated Amortization		318,000,000		$ 302,000,000
Amortization of Intangible Assets		$ 16,000,000	$ 13,000,000
Line of Credit Facility, Maximum Borrowing Capacity				500,000,000
Debt Instrument, Covenant Description		0.65
Ratio of Indebtedness to Net Capital		0.493
Short-term debt		$ 0
Commercial Paper		0
Line of Credit Facility, Remaining Borrowing Capacity		500,000,000
Line of Credit Facility, Current Borrowing Capacity		220,000,000
Letters of credit issued		83,000,000
Authorized Short-Term Debt		900,000,000
Long-term Debt, Current Maturities		$ 300,000,000		$ 300,000,000
Subsequent Event [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Proceeds from Issuance of Long-term Debt	$ 200,000,000

XML

Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2019	Jan. 31, 2019	Dec. 31, 2018
Assets:
Cash equivalents	$ 82		$ 112
Debt securities:
Domestic government	22		25
Corporate credit	12		10
Money market funds measured at NAV (2)	12		7
Non-qualified benefit plan trust: (2)
Money market funds	2		2
Eqauity securities - domestic	6		6
Debt securities—domestic government	1		1
Assets from price risk management activities: (1) (3)
Electricity	18		12
Natural gas	19		8
Total	12		7
Assets, Fair Value Disclosure	174		183
Liabilities from price risk management activities: (1) (3)
Derivative Liability		$ 5	4
Electricity	75		94
Natural gas	35		58
Total	110		156
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	82		112
Debt securities:
Domestic government	8		7
Corporate credit	0		0
Non-qualified benefit plan trust: (2)
Money market funds	2		2
Eqauity securities - domestic	6		6
Debt securities—domestic government	1		1
Assets from price risk management activities: (1) (3)
Electricity	0		0
Natural gas	0		0
Total	99		128
Liabilities from price risk management activities: (1) (3)
Derivative Liability			0
Electricity	0		0
Natural gas	0		0
Total	0		0
Fair Value, Inputs, Level 2 [Member]
Assets:
Cash equivalents	0		0
Debt securities:
Domestic government	14		18
Corporate credit	12		10
Non-qualified benefit plan trust: (2)
Money market funds	0		0
Eqauity securities - domestic	0		0
Debt securities—domestic government	0		0
Assets from price risk management activities: (1) (3)
Electricity	14		9
Natural gas	19		8
Total	59		45
Liabilities from price risk management activities: (1) (3)
Derivative Liability			4
Electricity	6		10
Natural gas	30		51
Total	36		65
Fair Value, Inputs, Level 3 [Member]
Assets:
Cash equivalents	0		0
Debt securities:
Domestic government	0		0
Corporate credit	0		0
Non-qualified benefit plan trust: (2)
Money market funds	0		0
Eqauity securities - domestic	0		0
Debt securities—domestic government	0		0
Assets from price risk management activities: (1) (3)
Electricity	4		3
Natural gas	0		0
Total	4		3
Liabilities from price risk management activities: (1) (3)
Derivative Liability			0
Electricity	69		84
Natural gas	5		7
Total	$ 74		$ 91

XML

Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Mar. 31, 2019	Dec. 31, 2018
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 12.24	$ 14.60
Natural gas financial swaps	1.04	0.95
High [Member]
Commodity Contracts
Electricity physical forwards	75.70	69.00
Natural gas financial swaps	4.10	4.64
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	50.85	45.00
Natural gas financial swaps	1.80	1.82
Assets [Member]
Commodity Contracts
Electricity physical forwards	4,000,000	3,000,000
Natural gas financial swaps	0	0
Total commodity contracts	4,000,000	3,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	69,000,000	84,000,000
Natural gas financial swaps	5,000,000	7,000,000
Total commodity contracts	$ 74,000,000	$ 91,000,000

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Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 88	$ 139
Net realized and unrealized losses (gains)/losses	(19)	(4)
Transfers out of Level 3 to Level 2	1	(1)
Balance as of the end of the period	$ 70	$ 134

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	$ 0	$ 0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net	0	$ 0
Cash Surrender Value, Fair Value Disclosure	28,000,000		$ 27,000,000
Long-term Debt	2,478,000,000		2,478,000,000
Unamortized Debt Issuance Expense	10,000,000		10,000,000
Long-term Debt, Fair Value	$ 2,773,000,000		$ 2,760,000,000

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Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Current Assets, Commodity Contracts:
Electricity	$ 17	$ 11
Natural gas	16	7
Total current derivative assets	33	18
Noncurrent Assets, Commodity Contracts: [Abstract]
Total derivative assets not designated as hedging instruments	37	20
Total derivative assets	37	20
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	12	16
Natural gas	20	35
Total current derivative liabilities	32	51
Noncurrent Liabilities, Commodity Contracts: [Abstract]
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
Commodity Contract Asset, Noncurrent, Electricity	1	1
Commodity Contract Asset, Noncurrent, Natural Gas	3	1
Derivative Asset, Noncurrent	$ 4	$ 2

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Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Mar. 31, 2019 CAD ($) MMBTU MWh	Dec. 31, 2018 CAD ($) MMBTU MWh
Commodity contracts:
Electricity | MWh	7	5
Natural gas | MMBTU	134	123
Foreign currency | $	$ 20	$ 18

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Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Commodity contracts:
Electricity	$ (24)	$ 1
Natural Gas	$ (25)	$ 14

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Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Mar. 31, 2019 USD ($)
Electricity [Member]
Commodity contracts:
2019	$ (6)
2020	5
2021	6
2022	5
2023	6
Thereafter	41
Total	57
Natural Gas [Member]
Commodity contracts:
2019	(8)
2020	3
2021	4
2022	1
2023	0
Thereafter	0
Total	16
Net Unrealized Loss [Member]
Commodity contracts:
2019	(2)
2020	8
2021	10
2022	6
2023	6
Thereafter	41
Total	$ 73

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Risk Management Counterparties Representing 10% or More of Assets and Liabilities from price risk management activities (Details)	Mar. 31, 2019	Dec. 31, 2018
Assets from price risk management activities:
Counterparty A	33.00%	42.00%
Counterparty B	11.00%	15.00%
Counterparty C	13.00%	9.00%
Concentration of Risk, Derivative Instruments, Assets	57.00%	66.00%
Liabilities from price risk management activities:
Counterparty D	62.00%	56.00%

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Risk Management (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Jan. 31, 2019	Dec. 31, 2018
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	$ 11			$ 11
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	49	$ 15
Derivative, Net Liability Position, Aggregate Fair Value	107
Collateral Already Posted, Aggregate Fair Value	43
Collateral cash requirement	91
Deposit Assets	0
Derivative Liability			$ 5	4
Natural Gas [Member]
Derivative Instruments and Hedges, Liabilities	2			4
4911 Electric Services [Member]
Derivative Instruments and Hedges, Liabilities	69			84
Liabilities, Total [Member]
Derivative Instruments and Hedges, Liabilities	$ 71			88
Fair Value, Inputs, Level 2 [Member]
Derivative Liability				$ 4

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Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Weighted-average common shares outstanding-basic and diluted	89,309	89,160

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Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	263	230

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Schedule of Stockholders Equity (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Common Stock, Shares, Outstanding beginning of period	89,267,959
Issuance of shares pursuant to equity-based plans	$ 0	$ 0
Stockholders' Equity	2,506	2,416
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	1
Dividends declared	(32)	(30)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	73	64
Reclassification of stranded tax effects due to Tax Reform	$ (2)
Common Stock, Shares, Outstanding end of period	89,356,311
Stockholders' Equity	$ 2,548	$ 2,449
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	89,267,959	89,114,265
Issuances of shares pursuant to equity-based plans	88,352	99,854
Common Stock, Shares, Outstanding end of period	89,356,311	89,214,119
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 0	$ 0
Adjustments Related to Tax Withholding for Share-based Compensation		(1)
Stockholders' Equity	1,212	1,207
Dividends declared	0	0
Stockholders' Equity	1,212	1,206
AOCI Attributable to Parent [Member]
Stockholders' Equity	(7)	(8)
Stock-based compensation		0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	1
Dividends declared	0	0
Reclassification of stranded tax effects due to Tax Reform	(2)
Stockholders' Equity	(8)	(8)
Retained Earnings [Member]
Stockholders' Equity	1,301	1,217
Stock-based compensation		0
Dividends declared	(32)	(30)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		64
Stockholders' Equity	$ 1,344	$ 1,251

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Equity Equity (Details) - $ / shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 0.3625	$ 0.3400

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Contingencies (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 1993
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties	100
Loss Contingency, Damages Sought, Value	$ 1,200
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500
Investment in Trojan		87.00%
Class action damages sought	260
Loss Contingency, Estimate of Possible Loss	1,700
Environmental Remediation Expense	6
Litigation Settlement, Expense	115
Minimum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 1,100

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Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21.00%	21.00%
Federal tax credits	(12.70%)	(18.00%)
State and local taxes, net of federal tax benefit	6.50%	6.50%
Flow through depreciation and cost basis differences	1.30%	1.00%
Amortization of Deferred Charges	(3.70%)
Other	0.70%	0.60%
Effective tax rate	13.10%	11.10%

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Income tax Income tax (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Reclassification of stranded tax effects due to Tax Reform	$ 2,000,000
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	59,000,000	$ 52,000,000
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	$ 0	$ 0

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Leases Lease Cost (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating Lease, Cost	$ 1
Variable Lease, Cost	$ 9

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Leases Supplemental information (Details) $ in Millions	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 41
Operating Lease, Liability, Current	5
Operating Lease, Liability, Noncurrent	36
Operating Lease, Liability	41
Finance Lease, Right-of-Use Asset	2
Finance Lease, Liability, Current	0
Finance Lease, Liability Noncurrent	2
Finance Lease, Liability	$ 2

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Leases Lease Term and Discount Rate (Details)	Mar. 31, 2019
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	30 years
Finance Lease, Weighted Average Remaining Lease Term	4 years
Operating Lease, Weighted Average Discount Rate, Percent	3.80%
Finance Lease, Weighted Average Discount Rate, Percent	3.40%

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Leases Maturities of Lease Liabilities (Details) $ in Millions	Mar. 31, 2019 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 4
Finance Lease, Liability, Payments, Remainder of Fiscal Year	0
Lessee, Operating Lease, Liability, Payments, Due Year Two	5
Finance Lease, Liability, Payments, Due Year Two	0
Lessee, Operating Lease, Liability, Payments, Due Year Three	5
Finance Lease, Liability, Payments, Due Year Three	1
Lessee, Operating Lease, Liability, Payments, Due Year Four	5
Finance Lease, Liability, Payments, Due Year Four	1
Lessee, Operating Lease, Liability, Payments, Due Year Five	5
Finance Lease, Liability, Payments, Due Year Five	0
Lessee, Operating Lease, Liability, Payments, Due after Year Five	53
Finance Lease, Liability, Payments, Due after Year Five	0
Lessee, Operating Lease, Liability, Payments, Due	77
Finance Lease, Liability, Payments, Due	2
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(36)
Finance Lease, Liability, Undiscounted Excess Amount	0
Operating Lease, Liability	$ 41

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Leases Supplemental Cash Flow Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating Lease, Payments	$ 1

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Leases Future Minimum Lease Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Leases [Abstract]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	$ 6
Contractual Obligation, Due in Next Fiscal Year	11
Operating Leases, Future Minimum Payments Due, Next Twelve Months	4
Capital Leases, Future Minimum Payments Due in Two Years	6
Contractual Obligation, Due in Second Year	14
Operating Leases, Future Minimum Payments, Due in Two Years	5
Capital Leases, Future Minimum Payments Due in Three Years	6
Contractual Obligation, Due in Third Year	13
Operating Leases, Future Minimum Payments, Due in Three Years	5
Capital Leases, Future Minimum Payments Due in Four Years	6
Contractual Obligation, Due in Fourth Year	13
Operating Leases, Future Minimum Payments, Due in Four Years	6
Capital Leases, Future Minimum Payments Due in Five Years	5
Contractual Obligation, Due in Fifth Year	13
Operating Leases, Future Minimum Payments, Due in Five Years	7
Capital Leases, Future Minimum Payments Due Thereafter	67
Contractual Obligation, Due after Fifth Year	225
Operating Leases, Future Minimum Payments, Due Thereafter	97
Capital Leases, Future Minimum Payments Due	96
Contractual Obligation	289
Operating Leases, Future Minimum Payments Due	124
Capital Leases, Future Minimum Payments, Interest Included in Payments	(47)
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	49
Capital Lease Obligations, Current	(2)
Purchase Commitment, Remaining Minimum Amount Committed	$ 47

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Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2019
Leases [Abstract]
Operating Lease, Liability			$ 15
Finance Lease, Liability			$ 130
Operating Leases, Rent Expense	$ 7	$ 9
Long-term Purchase Commitment, Amount	149
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	131
Capital Lease Obligations, Current	2
Capital Leased Assets, Gross	57
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	8
Purchase Commitment, Remaining Minimum Amount Committed	47
Deferred Costs, Leasing, Accumulated Amortization		3
Interest Expense, Lessee, Assets under Capital Lease		4
Operating Leases, Rent Expense, Contingent Rentals	14
Operating Leases, Rent Expense, Sublease Rentals	$ 4	$ 4